Kosmos Energy Ltd. - Quarter Report: 2012 June (Form 10-Q)

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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 June 30, 2012

 

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)

 

 

 

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.

 

 

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.

 

 

 

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KOSMOS ENERGY LTD.

 

INDEX

 

	Page
PART I. FINANCIAL INFORMATION
Glossary and Select Abbreviations	1
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	3
Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011	4
Consolidated Statements of Comprehensive Loss for the three and six months ended June 30, 2012 and 2011	5
Consolidated Statements of Shareholders’ Equity for the six months ended June 30, 2012	6
Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011	7
Notes to Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3. Quantitative and Qualitative Disclosures about Market Risk	36
Item 4. Controls and Procedures	37
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3. Defaults Upon Senior Securities	38
Item 4. Mine Safety Disclosures	38
Item 5. Other Information	38
Item 6. Exhibits	38
Signatures	39
Index to Exhibits	40

 

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KOSMOS ENERGY LTD.

 

GLOSSARY AND SELECT ABBREVIATIONS

 

The following are abbreviations and definitions of certain terms 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.
“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.
“E&P”		Exploration and production.
“FASB”		Financial Accounting Standards Board.
“Farm-in”		An agreement whereby an oil company acquires a portion of the working interest in a block from the owner of such interest, usually in return for cash and for taking on a portion of the drilling of one or more specific wells or other performance by the assignee as a condition of the assignment.
“FPSO”		Floating production, storage and offloading vessel.
“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 from the area in which it was formed to a reservoir rock where it can accumulate.
“Plan of development” or “PoD”		A written document outlining the steps to be undertaken to develop a field.
“Productive well”		An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

 

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“Prospect(s)”		A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least not in commercial volumes.
“Proved reserves”		Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).
“Proved developed reserves”		Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
“Proved undeveloped reserves”		Proved undeveloped reserves are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
“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.
“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)

 

		June 30,			December 31,
		2012			2011
		(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	629,951		$	673,092
Restricted cash		22,954			23,747
Receivables:
Joint interest billings		139,798			199,699
Oil sales		—			109,475
Other		22,529			981
Inventories		50,426			27,101
Prepaid expenses and other		15,257			13,913
Current deferred tax assets		56,281			64,473
Derivatives		1,512			—
Total current assets		938,708			1,112,481
Property and equipment:
Oil and gas properties, net of accumulated depletion of $213,040 and $135,622, respectively		1,444,350			1,367,265
Other property, net of accumulated depreciation of $10,021 and $8,068, respectively		15,562			9,776
Property and equipment, net		1,459,912			1,377,041
Other assets:
Restricted cash		3,800			3,800
Deferred financing costs and other assets, net of accumulated amortization of $10,970 and $6,582, respectively		51,713			54,847
Long-term deferred tax assets		7,520			3,765
Total assets		$	2,461,653		$	2,551,934
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable		$	194,808		$	278,006
Accrued liabilities		31,346			37,194
Derivatives		21,910			24,407
Total current liabilities		248,064			339,607
Long-term liabilities:
Long-term debt		1,110,000			1,110,000
Derivatives		4,941			8,427
Asset retirement obligations		21,992			20,670
Deferred tax liability		76,618			47,608
Other long-term liabilities		10,795			4,896
Total long-term liabilities		1,224,346			1,191,601
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2012 and December 31, 2011		—			—
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 391,411,703 and 390,530,946 issued at June 30, 2012 and December 31, 2011, respectively		3,914			3,905
Additional paid-in capital		1,668,302			1,629,453
Accumulated deficit		(678,532		)	(616,148		)
Accumulated other comprehensive income		3,950			3,522
Treasury stock, at cost, 2,171,410 and 649,818 shares at June 30, 2012 and December 31, 2011, respectively		(8,391		)	(6		)
Total shareholders’ equity		989,243			1,020,726
Total liabilities and shareholders’ equity		$	2,461,653		$	2,551,934

 

See accompanying notes.

 

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KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2012			2011			2012			2011
Revenues and other income:
Oil and gas revenue		$	112,214		$	124,083		$	227,985		$	216,652
Interest income		282			2,613			1,028			4,967
Other income		175			157			205			644
Total revenues and other income		112,671			126,853			229,218			222,263
Costs and expenses:
Oil and gas production		19,592			14,301			26,918			34,296
Exploration expenses		16,901			85,220			56,545			93,652
General and administrative		34,799			19,760			74,122			33,047
Depletion and depreciation		32,999			22,869			64,648			46,367
Amortization - deferred financing costs		2,194			2,194			4,388			11,805
Interest expense		10,446			18,400			23,504			38,658
Derivatives, net		(1,982		)	1,363			1,878			10,234
Loss on extinguishment of debt		—			—			—			59,643
Doubtful accounts expense		—			(39,782		)	—			(39,782		)
Other expenses, net		44			84			792			61
Total costs and expenses		114,993			124,409			252,795			287,981
Income (loss) before income taxes		(2,322		)	2,444			(23,577		)	(65,718		)
Income tax expense (benefit)		22,521			11,535			38,807			(1,976		)
Net loss		(24,843		)	(9,091		)	(62,384		)	(63,742		)
Accretion to redemption value of convertible preferred units		—			(7,595		)	—			(24,442		)
Net loss attributable to common shareholders/unit holders		$	(24,843	)	$	(16,686	)	$	(62,384	)	$	(88,184	)
Net loss per share attributable to common shareholders:
Basic		$	(0.07	)				$	(0.17	)
Diluted		$	(0.07	)				$	(0.17	)
Pro forma basic					$	(0.03	)				$	(0.19	)
Pro forma diluted					$	(0.03	)				$	(0.19	)
Weighted average number of shares used to compute net loss per share:
Basic		370,720						369,973
Diluted		370,720						369,973
Pro forma basic					348,820						340,030
Pro forma diluted					348,820						340,030

 

See accompanying notes.

 

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KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

(Unaudited)

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2012			2011			2012			2011
Net loss		$	(24,843	)	$	(9,091	)	$	(62,384	)	$	(63,742	)
Other comprehensive income:
Reclassification adjustments for derivative losses included in net loss		214			283			428			1,741
Income tax benefit		—			—			—			—
Other comprehensive income		214			283			428			1,741
Comprehensive loss		$	(24,629	)	$	(8,808	)	$	(61,956	)	$	(62,001	)

 

See accompanying notes.

 

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KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)

(Unaudited)

 

													Accumulated
							Additional						Other
		Common Shares					Paid-in			Accumulated			Comprehensive			Treasury
		Shares		Amount			Capital			Deficit			Income			Stock			Total
Balance as of December 31, 2011		390,531		$	3,905		$	1,629,453		$	(616,148	)	$	3,522		$	(6	)	$	1,020,726
Equity-based compensation		—		—			38,851			—			—			—			38,851
Derivatives, net		—		—			—			—			428			—			428
Restricted stock awards		881		9			(9		)	—			—			—			—
Restricted stock forfeitures		—		—			7			—			—			(7		)	—
Purchase of treasury stock		—		—			—			—			—			(8,378		)	(8,378		)
Net loss		—		—			—			(62,384		)	—			—			(62,384		)
Balance as of June 30, 2012		391,412		$	3,914		$	1,668,302		$	(678,532	)	$	3,950		$	(8,391	)	$	989,243

 

See accompanying notes.

 

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KOSMOS ENERGY LTD.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

		Six Months Ended June 30,
		2012			2011
Operating activities
Net loss		$	(62,384	)	$	(63,742	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		69,036			58,172
Deferred income taxes		33,447			(2,291		)
Unsuccessful well costs		19,237			83,317
Derivative related activity		(7,067		)	14,518
Equity-based compensation		38,851			9,120
Doubtful accounts expense		—			(39,782		)
Loss on extinguishment of debt		—			59,643
Other		4,983			1,023
Changes in assets and liabilities:
Decrease in receivables		155,884			11,145
(Increase) decrease in inventories		(14,075		)	547
Increase in prepaid expenses and other		(1,344		)	(8,745		)
Decrease in accounts payable		(66,536		)	(47,728		)
Decrease in accrued liabilities		(9,347		)	(20,698		)
Net cash provided by operating activities		160,685			54,499
Investing activities
Oil and gas assets		(188,075		)	(206,763		)
Other property		(6,912		)	(847		)
Notes receivable		—			3,781
Restricted cash		793			84,286
Net cash used in investing activities		(194,194		)	(119,543		)
Financing activities
Borrowings under long-term debt		—			1,393,000
Payments on long-term debt		—			(1,138,000		)
Net proceeds from the initial public offering		—			580,374
Purchase of treasury stock		(8,378		)	—
Deferred financing costs		(1,254		)	(52,466		)
Net cash provided by (used in) financing activities		(9,632		)	782,908
Net increase (decrease) in cash and cash equivalents		(43,141		)	717,864
Cash and cash equivalents at beginning of period		673,092			100,415
Cash and cash equivalents at end of period		$	629,951		$	818,279
Supplemental cash flow information
Cash paid for:
Interest		$	21,339		$	33,828
Income taxes		$	16,620		$	725

 

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 March 5, 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 when used in the present tense or prospectively or for historical periods since May 16, 2011 refer to Kosmos Energy Ltd. and its wholly owned subsidiaries and for historical periods prior to May 16, 2011 refer to Kosmos Energy Holdings and its wholly owned subsidiaries, unless the context indicates otherwise.

 

We are an independent oil and gas exploration and production company currently focused on frontier and emerging areas in Africa and South America. Our asset portfolio includes existing production, discoveries and exploration prospects offshore Ghana, as well as petroleum contracts offshore Mauritania, Morocco and Suriname and onshore Cameroon. Kosmos Energy Ltd. transitioned from its development stage to operational activities in January 2011. Accordingly, reporting as a development stage company is no longer deemed necessary.

 

We have one business segment, which is the exploration and production of oil and natural gas.

 

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 June 30, 2012, the consolidated results of operations for the three and six months ended June 30, 2012 and 2011, and consolidated cash flows for the six months ended June 30, 2012 and 2011. During the three months ended June 30, 2012, we corrected an immaterial error in our financial statements by capitalizing $3.0 million which was previously recorded as exploration expense during the three months ended March 31, 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. 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, 2011, included in our annual report on Form 10-K.

 

Principles of Consolidation

 

The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly owned subsidiaries. All intercompany transactions have been eliminated.

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.

 

Cash and Cash Equivalents

 

Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.

 

Restricted Cash

 

In accordance with our commercial debt facility, we are required to maintain a balance that is sufficient to meet the payment of interest and fees for the next six-month period. As of June 30, 2012 and December 31, 2011, we had $23.0 million and $23.7 million, respectively, in current restricted cash to meet this requirement. Additionally as of June 30, 2012 and December 31, 2011, we had $3.8 million of long-term restricted cash used to cash collateralize performance guarantees related to our petroleum agreements. See Note 18—Subsequent Events.

 

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Receivables

 

Our receivables consist of joint interest billings, oil sales and other receivables for which the Company generally does not require collateral security. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things. We did not have any allowances for doubtful accounts as of June 30, 2012 and December 31, 2011.

 

Inventories

 

Inventories consisted of $27.7 million and $26.9 million of materials and supplies and $22.7 million and $0.2 million of hydrocarbons as of June 30, 2012 and December 31, 2011, 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.

 

Exploration and Development Costs

 

The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expenses on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed.

 

The Company evaluates unproved property periodically for impairment. These costs are generally related to the acquisition of leasehold costs. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential future reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.

 

Depletion, Depreciation and Amortization

 

Proved properties and support equipment and facilities are depleted using the unit-of-production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are amortized using the unit-of-production method based on estimated proved oil and natural gas reserves for the related field.

 

Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from three to eight years.

 

		Years Depreciated
Leasehold improvements		6 to 8
Office furniture, fixtures and computer equipment		3 to 7
Vehicles		5

 

Amortization of deferred financing costs is computed using the straight-line method over the life of the related debt.

 

Capitalized Interest

 

Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

 

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Asset Retirement Obligations

 

The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations.

 

Variable Interest Entity

 

A variable interest entity (“VIE”), as defined by ASC 810—Consolidation, is an entity that by design has insufficient equity to permit it to finance its activities without additional subordinated financial support or equity holders that lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, which is the entity that has the power to direct the activities of the VIE that most significantly impact the VIE’s performance and will absorb losses or receive benefits from the VIE that could potentially be significant to the VIE.

 

Our wholly owned subsidiary, Kosmos Energy Finance International, meets the definition of a VIE. The Company is the primary beneficiary of this VIE, which is consolidated in these financial statements.

 

Prior to the incorporation of Kosmos Energy Finance International on March 18, 2011, Kosmos Energy Finance International did not have any financial statement activity. Kosmos Energy Finance International’s assets and liabilities are shown separately on the face of the consolidated balance sheet as of June 30, 2012, and December 31, 2011, in the following line items: current restricted cash; current derivatives assets; deferred financing costs and other assets; long-term debt; and current and long-term derivatives liabilities. At June 30, 2012, Kosmos Energy Finance International had $229.6 million in cash and cash equivalents, $1.0 million in accrued liabilities and $6.1 million in other long-term liabilities. At December 31, 2011, Kosmos Energy Finance International had $231.6 million in cash and cash equivalents, $0.1 million in other receivables, $54.8 million in deferred financing costs and other assets, $1.2 million in accrued liabilities and $3.0 million in other long-term liabilities.

 

Impairment of Long-lived Assets

 

The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell.

 

Derivative Instruments and Hedging Activities

 

We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of purchased puts and swaps with calls. We also use interest rate swap contracts to mitigate our exposure to interest rate fluctuations related to our long-term debt. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our oil derivative contracts. Effective June 1, 2010, we discontinued hedge accounting on our interest rate swap contracts. Therefore, from that date forward, the changes in the fair value of the instruments are recognized in earnings during the period of change. See Note 10—Derivative Financial Instruments.

 

Estimates of Proved Oil and Natural Gas Reserves

 

Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with

 

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guidelines established by the Securities and Exchange Commission (“SEC”) and the FASB. The accuracy of these reserve estimates is a function of:

 

·                  the engineering and geological interpretation of available data;

 

·                  estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost;

 

·                  the accuracy of various mandated economic assumptions; and

 

·                  the judgments of the persons preparing the estimates.

 

Revenue Recognition

 

We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance.

 

Stock-based Compensation

 

For stock-based compensation equity awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria.

 

Treasury Stock

 

We record treasury stock purchases at cost. All of our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their minimum tax withholding requirements and were not part of a formal stock repurchase plan. Additionally, treasury stock includes forfeited restricted stock awards granted under our long-term incentive plan.

 

Income Taxes

 

The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. See Note 15—Income Taxes.

 

We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized.

 

Foreign Currency Translation

 

The U.S. dollar is the functional currency for the Company’s foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are de minimis, and as such, the effect of exchange rate changes is not material to any reporting period.

 

Concentration of Credit Risk

 

There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation facilities, demand for oil, the marketing of competitive fuels and the effects of government regulations on oil production and sales. Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long-term material adverse effect on our financial position or results of operations. We have required our marketing agent to post a letter of credit covering the estimated proceeds from our revenue transactions, until such proceeds are received.

 

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Recent Accounting Standards

 

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to improve reporting and transparency of offsetting (netting) assets and liabilities and the related effects on the financial statements. This ASU is effective for fiscal years and interim periods within those years beginning on or after January 1, 2013. We do not expect the adoption of this ASU will have a material effect on our consolidated financial statements.

 

3. Acquisition of FPSO

 

Effective May 7, 2010, Tullow Ghana Limited, a subsidiary of Tullow Oil plc, (“Tullow”) as Unit Operator for and on behalf of the Jubilee Unit partners under the Unitization and Unit Operating Agreement (“Jubilee UUOA”), entered into the Advance Payments Agreement with MODEC, Inc. (“MODEC”) related to partial funding of the construction of the FPSO. The maturity date of the Advance Payments Agreement was extended from September 15, 2011 through the acquisition date of the FPSO.

 

On December 29, 2011, Tullow as Unit Operator for and on behalf of the Jubilee Unit partners under the Jubilee UUOA, acquired the FPSO we are using to produce hydrocarbons from the Jubilee Field from MODEC for $754.5 million, or $202.6 million net to Kosmos. At the time of the acquisition of the FPSO, our note receivable under the Advance Payments Agreement was $102.8 million. To fund the purchase, we paid $99.8 million in cash and applied the note receivable due under the Advance Payments Agreement to the purchase. As of December 31, 2011 the remaining balance under the Advance Payments Agreement was zero. The acquisition was recorded as an increase to oil and gas property. Prior to the acquisition of the FPSO, the Jubilee Unit leased the FPSO from MODEC. The lease costs were recorded as oil and gas production costs.

 

4. Jubilee Field Unitization

 

The Jubilee Field in Ghana, discovered by the Mahogany-1 well in June 2007, covers an area within both the West Cape Three Points (“WCTP”) and Deepwater Tano (“DT”) Blocks. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements (“PAs”) and as required by Ghana’s Ministry of Energy, it was agreed the Jubilee Field would be unitized for optimal resource recovery. Kosmos and its partners negotiated a comprehensive unit operating agreement, the Jubilee UUOA, to unitize the Jubilee Field and govern each party’s respective rights and duties in the Jubilee Unit. On July 13, 2009, the Ministry of Energy provided its written approval of the Jubilee UUOA. The Jubilee UUOA was executed by all parties and was effective July 16, 2009. The tract participations were 50% for each block. Tullow is the Unit Operator, and Kosmos is the Technical Operator for the development of the Jubilee Field. Pursuant to the terms of the Jubilee UUOA, the track participations are subject to a process of redetermination. The initial redetermination process was completed on October 14, 2011. Any party to the Jubilee UUOA with more than a 10% Unit Interest (participating interest in the Jubilee Unit) may call for a second redetermination after December 1, 2013. As a result of the initial redetermination process, the tract participation was determined to be 54.36660% for the WCTP Block and 45.63340% for the DT Block. Our Unit Interest was increased from 23.50868% (our percentage after Tullow’s acquisition of EO Group Limited (“EO Group”) — see Note 5—Joint Interest Billings) to 24.07710%. The consolidated financial statements are based on these re-determined tract participations. As a result of the change in our Unit Interest, we recorded increases in joint interest billings receivables, oil and gas properties, notes receivable, inventories, oil and gas production expenses and general and administrative expenses of $67.6 million, $22.1 million, $2.5 million, $0.4 million, $1.6 million and $0.6 million, respectively, and an increase of $94.9 million in accounts payable as of December 31, 2011. Our capital costs related to the increased Unit Interest is expected to be paid during 2012. Although the Jubilee Field is unitized, Kosmos’ working interest in each block outside the boundary of the Jubilee Unit area did not change. Kosmos remains operator of the WCTP Block outside the Jubilee Unit area.

 

5. Joint Interest Billings

 

The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current or long-term receivables based on when collection is expected to occur. As of June 30, 2012 and December 31, 2011, we had $139.8 million and $199.7 million, respectively, included in current joint interest billings receivable. There were no long-term joint interest billings as of June 30, 2012 and December 31, 2011.

 

EO Group’s share of costs under the WCTP PA incurred attributable to its WCTP Block interest were paid by Kosmos until first production. EO Group was required to reimburse Kosmos for all development costs paid on EO Group’s behalf upon commencement of production in 2010.

 

On July 22, 2011, Tullow acquired EO Group’s entire 3.5% interest in the WCTP PA, including the correlative interest in the Jubilee Unit. As a result of the transaction, we received full repayment of the long-term joint interest billing receivable related to Jubilee Field development costs we paid on EO Group’s behalf. The related valuation allowance of $39.8 million was reversed during the second quarter of 2011. In addition, our participation interest in the Jubilee Unit increased 0.01738%. This resulted from the

 

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elimination of EO Group’s carry by the other Jubilee owners of GNPC’s additional paying interest of 3.75% in the Jubilee Unit. Our working interest in the remainder of the WCTP Block was not changed by the transaction and remains 30.875% (before giving effect to GNPC’s optional additional paying interest).

 

6. Property and Equipment

 

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

 

		June 30, 2012			December 31, 2011
		(In thousands)
Oil and gas properties:
Proved properties		$	666,337		$	607,338
Unproved properties		381,400			294,701
Support equipment and facilities		609,653			600,848
Total oil and gas properties		1,657,390			1,502,887
Less: accumulated depletion		(213,040		)	(135,622		)
Oil and gas properties, net		1,444,350			1,367,265
Other property, net		15,562			9,776
Property and equipment, net		$	1,459,912		S	1,377,041

 

We recorded depletion expense of $31.2 million and $21.7 million for the three months ended June 30, 2012 and 2011, respectively, and $61.3 million and $44.1 million for the six months ended June 30, 2012 and 2011, respectively.  The Company had depletion costs of $16.1 million and nil included in crude oil inventory and other receivables as of June 30, 2012 and December 31, 2011, respectively.

 

7. Suspended Well Costs

 

The Company capitalizes exploratory well costs into oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. The well costs are charged to expense if the exploratory well is determined to be impaired.

 

The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the six months ended June 30, 2012. The table excludes $16.6 million in costs that were capitalized and subsequently expensed in the same period.

 

		June 30, 2012
		(In thousands)
Beginning balance (January 1, 2012)		$	267,592
Additions to capitalized exploratory well costs pending the determination of proved reserves		66,789
Reclassification due to determination of proved reserves		—
Capitalized exploratory well costs charged to expense		(2,627		)
Ending balance (June 30, 2012)		$	331,754

 

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:

 

		June 30, 2012			December 31, 2011
		(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less		$	127,155		$	132,838
Exploratory well costs capitalized for a period one to three years		204,599			134,754
Ending balance		$	331,754		$	267,592
Number of projects with exploratory well costs that have been capitalized for more than one year		6			3

 

As of June 30, 2012, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Mahogany Area (formerly known as the Mahogany East Area), Teak-1 and Teak-2 discoveries in the WCTP Block and the Tweneboa, Enyenra and Ntomme discoveries in the DT Block.

 

Mahogany Area—The Mahogany area, a combined area covering parts of the Mahogany discovery and the Mahogany Deep discovery area was declared commercial in September 2010, and a PoD was submitted to Ghana’s Ministry of Energy as of May 2,

 

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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 GNPC which resolved issues relating to the PoD work program. From May 2011, GNPC and the WCTP Block partners continued working to resolve other differences; however, the WCTP 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 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 of approval of the PoD. We and the WCTP Block partners continue 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 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.

 

Teak-2 Discovery—We have performed a gauge installation on the well and are reprocessing seismic data. Following appraisal and evaluation, a decision regarding commerciality of the Teak-2 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.

 

Ntomme Discovery—One appraisal well has been drilled. Following additional appraisal and evaluation, a decision regarding commerciality of the Ntomme discovery is expected to be made by the DT Block partners by the end of 2012. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the DT PA.

 

Tweneboa Discovery—Three appraisal wells have been drilled. Following additional appraisal and evaluation, a decision regarding commerciality of the Tweneboa discovery is expected to be made by the DT Block partners by January 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 DT PA. However, the DT Block partners have the option to request a new petroleum agreement for the Tweneboa discovery area, thereby extending the period of commercial assessment of the discovery.

 

Enyenra Discovery—Four appraisal wells have been drilled. Following additional appraisal and evaluation, a decision regarding commerciality of the Enyenra discovery is expected to be made by the DT Block partners by the end of 2012. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the DT PA.

 

8. Accounts Payable and Accrued Liabilities

 

At June 30, 2012 and December 31, 2011, $194.8 million and $278.0 million, respectively, were recorded for invoices received but not paid. Accrued liabilities were $31.3 million and $37.2 million at June 30, 2012 and December 31, 2011, respectively, and consisted of the following:

 

		June 30, 2012			December 31, 2011
		(In thousands)
Accrued liabilities:
Accrued exploration, development and production		$	20,352		$	27,666
Accrued general and administrative expenses		7,440			2,159
Accrued interest		986			1,208
Taxes other than income		2,532			1,095
Income taxes		36			5,066
		$	31,346		$	37,194

 

9. Debt

 

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 supports our oil and gas exploration, appraisal and development programs and corporate activities. The total loan commitments of the Facility may be increased up to a maximum of $3.0 billion if the lenders increase their commitments or if loan commitments from new financial institutions are added. The International Finance Corporation entered the Facility in February 2012. The terms and conditions of the Facility remained consistent with the original terms and conditions, and the total commitment under the Facility remained unchanged.

 

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As part of the debt refinancing in March 2011, we recorded a $59.6 million loss on the extinguishment of debt. Additionally, we have $61.3 million of deferred financing costs related to the Facility, which are being amortized over the term of the Facility.

 

As of June 30, 2012, borrowings under the Facility totaled $1.1 billion. As of June 30, 2012, the undrawn availability under the Facility was an additional $50.0 million. Interest expense was $7.9 million and $11.7 million (net of capitalized interest of $3.2 million and $0.8 million), and commitment fees were $1.6 million and $1.3 million for the three months ended June 30, 2012 and 2011, respectively. Interest expense was $18.4 million and $27.3 million (net of capitalized interest of $4.5 million and $2.0 million) and commitment fees were $3.3 million and $3.6 million for the six months ended June 30, 2012 and 2011, respectively.

 

The interest is the aggregate of the applicable margin (3.25% to 4.75%, depending on the amount of the Facility that is being utilized and 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). Kosmos pays commitment fees on the undrawn and unavailable portion of the total commitments. Commitment fees for the lenders 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. The Company recognizes interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility.  Accordingly, we recognized interest expense in excess of interest currently payable of $1.3 million and $1.2 million during the three months ended June 30, 2012 and 2011, respectively, and $3.1 million and $1.2 million during the six months ended June 30, 2012 and 2011, respectively.

 

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), which is March 29, 2018. The available facility amount is subject to borrowing base constraints and also is constrained by the amortization schedule (once repayments under the Facility begin). As of May 15, 2014, outstanding borrowings will be subject to an amortization schedule. The first required payment could be as early as June 15, 2014, subject to the level of outstanding borrowings.

 

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, was previously determined each year on June 15 and December 15 as part of a forecast that is prepared by and agreed to by Kosmos and the Technical and Modeling Banks; however, in April 2012, the lenders agreed to change the borrowing base determination dates to April 15 and October 15. The formula to calculate the borrowing base amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain ratios.

 

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 us.

 

We were in compliance with the financial covenants contained in the Facility as of the April 19, 2012 forecast, which requires the maintenance of:

 

·                  the field life cover ratio, not less than 1.30x; and

 

·                  the loan life cover ratio, not less than 1.10x.

 

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 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. 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.

 

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At June 30, 2012, the scheduled maturities of debt during the five year period and thereafter are as follows:

 

		Payments Due by Year
		2012 (1)			2013			2014			2015			2016			Thereafter
		(In thousands)
Commercial debt facility(2)		$	—		$	—		$	—		$	110,000		$	444,444		$	555,556

(1)   Represents payments for the period July 1, 2012 through December 31, 2012.

(2)         The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of June 30, 2012. 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 five year period and thereafter.

 

10. 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 apply the provisions of ASC 815—Derivatives and Hedging, which require each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. We do not apply hedge accounting treatment to our oil derivative contracts and, therefore, the changes in the fair values of these instruments are recognized in earnings in the period the change occurred. These fair value changes are shown in our statement of operations.

 

Effective June 1, 2010, we discontinued hedge accounting on all interest rate derivative instruments. Therefore, from that date forward, changes in the fair value of the instruments are recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31, 2010, are included in accumulated other comprehensive income or loss (“AOCI”) in the equity section of the accompanying consolidated balance sheets, and are being transferred to earnings when the hedged transaction settles.

 

Oil Derivative Contracts

 

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 purchased puts and swaps with calls.

 

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. We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts as required by ASC 820—Fair Value Measurements and Disclosures.

 

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 June 30, 2012. See Note 18—Subsequent Events.

 

						Weighted Average Price per Bbl
Term		Type of Contract		Bbls per day		Deferred Premium			Puts			Swaps			Calls
2012:
July - December		Purchased puts		4,739		$	6.79		$	61.56		$	—		$	—
August - December		Swaps with calls		6,536		—			—			97.21			110.00
2013 :
January - December		Purchased puts		2,515		$	7.32		$	61.73		$	—		$	—

Interest Rate Swaps Derivative Contracts

 

The following table summarizes our open interest rate swaps as of June 30, 2012:

 

Term		Weighted Average Notional Amount			Weighted Average Fixed Rate		Floating Rate
		(In thousands)
July 2012 – December 2012		$	306,420		1.98	%	6-month LIBOR
January 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

 

Effective June 1, 2010, the Company discontinued hedge accounting on all existing interest rate derivative instruments. Prior to June 1, 2010, any ineffectiveness on the interest rate swaps was immaterial; therefore, no amount was recorded in earnings for ineffectiveness. We have included an estimate of nonperformance risk in the fair value measurement of our interest rate derivative contracts as required by ASC 820—Fair Value Measurements and Disclosures.

 

The following tables disclose the Company’s derivative instruments as of June 30, 2012 and December 31, 2011:

 

				Estimated Fair Value
				Asset (Liability)
				June 30,			December 31,
Type of Contract		Balance Sheet Location		2012			2011
				(In thousands)
Derivatives not designated as hedging instruments:
Derivative asset:
Commodity		Derivatives assets – current		$	1,512		$	—
Derivative liability:
Commodity		Derivatives liabilities – current(1)		(18,402		)	(20,303		)
Interest rate		Derivatives liabilities – current		(3,508		)	(4,104		)
Commodity		Derivatives liabilities – long-term		(1,585		)	(4,457		)
Interest rate		Derivatives liabilities – long-term		(3,356		)	(3,970		)
Total derivatives not designated as hedging instruments				$	(25,339	)	$	(32,834	)

 

(1)                                 Includes $9.2 million and $3.2 million, as of June 30, 2012 and December 31, 2011, of cash settlements made on our purchased puts and compound options which were settled in the month subsequent to period end.

 

				Amount of Gain/(Loss)						Amount of Gain/(Loss)
				Three Months Ended June 30,						Six Months Ended June 30,
Type of Contract		Location of Gain/(Loss)		2012			2011			2012			2011
				(In thousands)
Derivatives in cash flow hedging relationships:
Interest rate(1)		Interest expense		$	(214	)	$	(283	)	$	(428	)	$	(1,741	)
Total derivatives in cash flow hedging relationships				$	(214	)	$	(283	)	$	(428	)	$	(1,741	)
Derivatives not designated as hedging instruments:
Commodity		Derivatives, net		$	1,982		$	(1,363	)	$	(1,878	)	$	(10,234	)
Interest rate		Interest expense		(725		)	(5,085		)	(1,435		)	(6,012		)
Total derivatives not designated as hedging instruments				$	1,257		$	(6,448	)	$	(3,313	)	$	(16,246	)

 

(1)                                 Amounts were reclassified from AOCI into earnings.

 

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