Chesapeake Energy (CHK)

Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

x	Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2009

 

¨	Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                      to                     

Commission File No. 1-13726

Chesapeake Energy Corporation

(Exact name of registrant as specified in its charter)

 

Oklahoma		73-1395733
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

 

6100 North Western Avenue Oklahoma City, Oklahoma		73118
(Address of principal executive offices)		(Zip Code)

(405) 848-8000

Registrant’s telephone number, including area code

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  ¨

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  ¨    No  ¨

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  ¨		Non-accelerated filer  ¨		Smaller reporting company  ¨
				(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  ¨    No  x

As of May 7, 2009, there were 626,171,207 shares of our $0.01 par value common stock outstanding.

 

 

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2009

 

				Page
PART I.
Financial Information
Item 1.		Condensed Consolidated Financial Statements (Unaudited):
		Condensed Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008		1
		Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2009 and 2008		3
		Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008		4
		Condensed Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2009 and 2008		6
		Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2009 and 2008		7
		Notes to Condensed Consolidated Financial Statements		8
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		47
Item 4.		Controls and Procedures		53
PART II.
Other Information
Item 1.		Legal Proceedings		54
Item 1A.		Risk Factors		54
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		54
Item 3.		Defaults Upon Senior Securities		55
Item 4.		Submission of Matters to a Vote of Security Holders		55
Item 5.		Other Information		55
Item 6.		Exhibits		56

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

		March 31, 2009				December 31, 2008
						(Adjusted)
		($ in millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	83			$	1,749
Accounts receivable			1,185				1,324
Short-term derivative instruments			1,446				1,082
Other			139				137
Total Current Assets			2,853				4,292
PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full-cost accounting:
Evaluated natural gas and oil properties			32,861				28,965
Unevaluated properties			9,542				11,379
Less: accumulated depreciation, depletion and amortization of natural gas and oil properties			(21,909	)			(11,866	)
Total natural gas and oil properties, at cost based on full-cost accounting			20,494				28,478
Other property and equipment:
Natural gas gathering systems and treating plants			3,129				2,717
Buildings and land			1,582				1,513
Drilling rigs and equipment			516				430
Natural gas compressors			191				184
Other			499				482
Less: accumulated depreciation and amortization of other property and equipment			(555	)			(496	)
Total Other Property and Equipment			5,362				4,830
Total Property and Equipment			25,856				33,308
OTHER ASSETS:
Investments			378				444
Long-term derivative instruments			275				261
Other assets			299				288
Total Other Assets			952				993
TOTAL ASSETS		$	29,661			$	38,593

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS — (Continued)

(Unaudited)

 

		March 31, 2009				December 31, 2008
						(Adjusted)
		($ in millions)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	1,424			$	1,611
Short-term derivative instruments			107				66
Accrued liabilities			826				880
Deferred income taxes			491				358
Income taxes payable			16				108
Revenues and royalties due others			343				431
Accrued interest			155				167
Total Current Liabilities			3,362				3,621
LONG-TERM LIABILITIES:
Long-term debt, net			12,933				13,175
Deferred income tax liabilities			800				4,200
Asset retirement obligations			275				269
Long-term derivative instruments			271				111
Revenues and royalties due others			54				49
Other liabilities			148				151
Total Long-Term Liabilities			14,481				17,955
CONTINGENCIES AND COMMITMENTS (Note 3)
STOCKHOLDERS’ EQUITY:
Preferred Stock, $0.01 par value, 20,000,000 shares authorized:
4.50% cumulative convertible preferred stock, 2,558,900 shares issued and outstanding as of March 31, 2009 and December 31, 2008, entitled in liquidation to $256 million			256				256
5.00% cumulative convertible preferred stock (series 2005B), 2,095,615 shares issued and outstanding as of March 31, 2009 and December 31, 2008, entitled in liquidation to $209 million			209				209
6.25% mandatory convertible preferred stock, 143,768 shares issued and outstanding as of March 31, 2009 and December 31, 2008, entitled in liquidation to $36 million			36				36
4.125% cumulative convertible preferred stock, 0 and 3,033 shares issued and outstanding as of March 31, 2009 and December 31, 2008, respectively, entitled in liquidation to $0 and $3 million			—				3
5.00% cumulative convertible preferred stock (series 2005), 5,000 shares issued and outstanding as of March 31, 2009 and December 31, 2008, entitled in liquidation to $1 million			1				1
Common Stock, $0.01 par value, 750,000,000 shares authorized, 625,455,108 and 607,953,437 shares issued at March 31, 2009 and December 31, 2008, respectively			6				6
Paid-in capital			11,910				11,680
Retained earnings (deficit)			(1,171	)			4,569
Accumulated other comprehensive income (loss), net of tax of ($355) million and ($163) million, respectively			582				267
Less: treasury stock, at cost; 719,546 and 657,276 common shares as of March 31, 2009 and December 31, 2008, respectively			(11	)			(10	)
Total Stockholders’ Equity			11,818				17,017
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	29,661			$	38,593

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

		Three Months Ended March 31,
		2009				2008
						(Adjusted)
		($ in millions except per share data)
REVENUES:
Natural gas and oil sales		$	1,397			$	773
Natural gas and oil marketing sales			552				796
Service operations revenue			46				42
Total Revenues			1,995				1,611
OPERATING COSTS:
Production expenses			238				201
Production taxes			23				75
General and administrative expenses			90				79
Natural gas and oil marketing expenses			523				774
Service operations expense			40				35
Natural gas and oil depreciation, depletion and amortization			447				515
Depreciation and amortization of other assets			57				36
Impairment of natural gas and oil properties and other assets			9,630				—
Total Operating Costs			11,048				1,715
INCOME (LOSS) FROM OPERATIONS			(9,053	)			(104	)
OTHER INCOME (EXPENSE):
Other income (expense)			8				(9	)
Interest expense			14				(99	)
Impairment of investments			(153	)			—
Total Other Income (Expense)			(131	)			(108	)
INCOME (LOSS) BEFORE INCOME TAXES			(9,184	)			(212	)
INCOME TAX EXPENSE (BENEFIT):
Current			—				—
Deferred			(3,444	)			(82	)
Total Income Tax Expense (Benefit)			(3,444	)			(82	)
NET INCOME (LOSS)			(5,740	)			(130	)
PREFERRED STOCK DIVIDENDS			(6	)			(12	)
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS		$	(5,746	)		$	(142	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic		$	(9.63	)		$	(0.29	)
Assuming dilution		$	(9.63	)		$	(0.29	)
CASH DIVIDEND DECLARED PER COMMON SHARE		$	0.075			$	0.0675
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic			597				493
Assuming dilution			597				493

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		Three Months Ended March 31,
		2009				2008
						(Adjusted)
		($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)		$	(5,740	)		$	(130	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization			504				551
Deferred income taxes			(3,444	)			(82	)
Unrealized (gains) losses on derivatives			(145	)			1,145
Realized (gains) losses on financing derivatives			(19	)			(12	)
Stock-based compensation			34				29
Loss from equity investments			1				—
Impairments			9,783				—
Other			25				31
Change in assets and liabilities			262				(17	)
Cash provided by operating activities			1,261				1,515
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of natural gas and oil properties			(1,347	)			(1,406	)
Acquisitions of natural gas and oil companies, proved and unproved properties and leasehold, net of cash acquired			(413	)			(1,021	)
Divestitures of proved and unproved properties and leasehold			—				243
Additions to other property and equipment			(667	)			(551	)
Additions to investments			(8	)			(9	)
Proceeds from sale of drilling rigs and equipment			—				34
Proceeds from sale of compressors			68				17
Sale of other assets			—				1
Cash used in investing activities			(2,367	)			(2,692	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facility borrowings			1,575				2,591
Payments on credit facility borrowings			(3,120	)			(1,377	)
Proceeds from issuance of senior notes, net of offering costs			1,346				—
Cash paid for common stock dividends			(44	)			(33	)
Cash paid for preferred stock dividends			(6	)			(12	)
Derivative settlements			1				(33	)
Net increase (decrease) in outstanding payments in excess of cash balance			(287	)			44
Excess tax benefit from stock-based compensation			—				11
Cash paid for repurchase of treasury stock			(1	)			—
Cash received from exercise of stock options			1				4
Other financing costs			(25	)			(18	)
Cash provided by (used in) financing activities			(560	)			1,177
Net increase (decrease) in cash and cash equivalents			(1,666	)			—
Cash and cash equivalents, beginning of period			1,749				1
Cash and cash equivalents, end of period		$	83			$	1

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

(Unaudited)

 

		Three Months Ended March 31,
		2009			2008
					(Adjusted)
		($ in millions)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION OF CASH PAYMENTS FOR:
Interest, net of capitalized interest		$	25		$	114
Income taxes, net of refunds received		$	114		$	4

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:

As of March 31, 2009 and 2008, dividends payable on our common and preferred stock were $51 million and $53 million, respectively.

For the three months ended March 31, 2009 and 2008, natural gas and oil properties were adjusted by a nominal amount and $13 million, respectively, for net income tax liabilities related to acquisitions.

For the three months ended March 31, 2009 and 2008, natural gas and oil properties were adjusted by ($62) million and ($6) million, respectively, as a result of an increase (decrease) in accrued exploration and development costs.

For the three months ended March 31, 2009 and 2008, other property and equipment were adjusted by $13 million and $8 million, respectively, as a result of an increase (decrease) in accrued costs.

We recorded non-cash asset additions to natural gas and oil properties of $2 million and $3 million for the three months ended March 31, 2009 and 2008, respectively, for asset retirement obligations.

On March 31, 2009, we converted all of our outstanding 4.125% cumulative convertible preferred stock (3,033 shares) into 182,887 shares of common stock at a conversion price of $16.584 per share.

For the three months ended March 31, 2009, we issued 14,360,642 shares of common stock, valued at $240 million, for the purchase of leasehold and unproved properties pursuant to an acquisition shelf registration statement.

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

 

		Three Months Ended March 31,
		2009				2008
						(Adjusted)
		($ in millions)
PREFERRED STOCK:
Balance, beginning of period		$	505			$	960
Exchange of common stock for 3,033 and 0 shares of 4.125% preferred stock			(3	)			—
Balance, end of period			502				960
COMMON STOCK:
Balance, beginning of period			6				5
Exchange of 182,887 and 0 shares of common stock for preferred stock			—				—
Balance, end of period			6				5
PAID-IN CAPITAL:
Balance, beginning of period			11,680				7,532
Issuance of common stock for the purchase of leasehold and unproved properties			232				—
Stock-based compensation			53				34
Exercise of stock options			1				4
Dividends on common stock			(45	)			—
Dividends on preferred stock			(6	)			—
Exchange of 182,887 and 0 shares of common stock for preferred stock			3				—
Tax benefit (reduction in tax benefit) from exercise of stock options and restricted stock			(8	)			11
Balance, end of period			11,910				7,581
RETAINED EARNINGS (DEFICIT):
Balance, beginning of period			4,569				4,144
Net income (loss)			(5,740	)			(130	)
Dividends on common stock			—				(33	)
Dividends on preferred stock			—				(12	)
Balance, end of period			(1,171	)			3,969
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period			267				(11	)
Hedging activity			266				(533	)
Marketable securities activity			49				1
Balance, end of period			582				(543	)
TREASURY STOCK – COMMON:
Balance, beginning of period			(10	)			(6	)
Purchase of 64,242 shares for company benefit plans			(1	)			—
Release of 1,972 and 1,098 shares for company benefit plans			—				—
Balance, end of period			(11	)			(6	)
TOTAL STOCKHOLDERS’ EQUITY		$	11,818			$	11,966

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

		Three Months Ended March 31,
		2009				2008
						(Adjusted)
		($ in millions)
Net income (loss)		$	(5,740	)		$	(130	)
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income taxes of $296 million and ($303) million			484				(492	)
Reclassification of (gain) loss on settled contracts, net of income taxes of ($112) million and ($51) million			(184	)			(82	)
Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of ($21) million and $25 million			(34	)			41
Unrealized (gain) loss on marketable securities, net of income taxes of $4 million and $1 million			6				1
Reclassification of loss on marketable securities, net of income taxes of $26 million and $0			43				—
Comprehensive income (loss)		$	(5,425	)		$	(662	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1.	Basis of Presentation and Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission. Chesapeake’s annual report on Form 10-K for the year ended December 31, 2008 (“2008 Form 10-K”) includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. The results for the three months ended March 31, 2009 are not necessarily indicative of the results to be expected for the full year. This Form 10-Q relates to the three months ended March 31, 2009 (the “Current Quarter”) and the three months ended March 31, 2008 (the “Prior Quarter”).

Change in Accounting Principle

On January 1, 2009, we adopted and applied retrospectively FASB Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion. As a result, our prior year condensed consolidated financial statements have been retrospectively adjusted. See Note 6 for additional information on the application of this accounting principle.

Natural Gas and Oil Properties – Ceiling Test

We review the carrying value of our natural gas and oil properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. As of March 31, 2009, capitalized costs of natural gas and oil properties exceeded the estimated present value of future net revenues from our proved reserves, net of related income tax considerations, resulting in a write-down in the carrying value of natural gas and oil properties of $9.6 billion. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Based on spot prices for natural gas and oil as of March 31, 2009, these cash flow hedges increased the full-cost ceiling by $1.651 billion, thereby reducing the ceiling test write-down by the same amount. Our qualifying cash flow hedges as of March 31, 2009, which consisted of swaps and collars, covered 292 bcfe, 78 bcfe and 11 bcfe in 2009, 2010 and 2011, respectively. Our natural gas and oil hedging activities are discussed in Note 2 of these condensed consolidated financial statements. Further decreases in market prices from March 31, 2009 levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs and service costs could result in future ceiling test impairments.

Critical Accounting Policies

We consider accounting policies related to hedging, natural gas and oil properties, income taxes and business combinations to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2008 Form 10-K.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

2.	Financial Instruments and Hedging Activities

Natural Gas and Oil Hedging Activities

Our results of operations and operating cash flows are impacted by changes in market prices for natural gas and oil. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. These instruments allow us to predict with greater certainty the effective natural gas and oil prices to be received for our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended. As of March 31, 2009, our natural gas and oil derivative instruments were comprised of the following:

 

•

For swap instruments, Chesapeake receives a fixed price for the hedged commodity and pays a floating market price to the counterparty.

 

•

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

 

•

For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.

 

•

For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a “cap” limiting the counterparty’s exposure. In other words, there is no limit to Chesapeake’s exposure but there is a limit to the downside exposure of the counterparty.

 

•

For call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

 

•

For put options, Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. If the market price falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall. If the market price settles above the fixed price of the put option, no payment is due from Chesapeake.

 

•

Basis protection swaps are arrangements that guarantee a price differential to NYMEX for natural gas or oil from a specified delivery point. For Mid-Continent basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

Chesapeake enters into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, Chesapeake receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is 100% effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap. We refer to this locked-in value as a locked swap. Generally, at the time Chesapeake enters into a counter-swap, Chesapeake removes the original swap’s designation as a cash flow hedge and classifies the original swap as a non-qualifying hedge under SFAS 133. The reason for this new designation is that collectively the swap and the counter-swap no longer hedge the exposure to variability in expected future cash flows. Instead, the swap and counter-swap effectively lock-in a specific gain or loss that will be unaffected by subsequent variability in natural gas and oil prices. Any locked-in gain or loss is recorded in accumulated other comprehensive income and reclassified to natural gas and oil sales in the month of related production.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Gains or losses from certain derivative transactions are reflected as adjustments to natural gas and oil sales on the condensed consolidated statements of operations. Realized gains (losses) are included in natural gas and oil sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within natural gas and oil sales. Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). The components of natural gas and oil sales for the Current Quarter and the Prior Quarter are presented below.

 

		Three Months Ended March 31,
		2009			2008
		($ in millions)
Natural gas and oil sales		$	778		$	1,690
Realized gains (losses) on natural gas and oil derivatives			519			215
Unrealized gains (losses) on non-qualifying natural gas and oil derivatives			46			(1,067	)
Unrealized gains (losses) on ineffectiveness of cash flow hedges			54			(65	)
Total natural gas and oil sales		$	1,397		$	773

The estimated fair values of our natural gas and oil derivative instruments as of March 31, 2009 and December 31, 2008 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

 

		March 31, 2009				December 31, 2008
		($ in millions)
Derivative assets (liabilities)(a):
Fixed-price natural gas swaps		$	905			$	863
Fixed-price natural gas collars			789				402
Fixed-price natural gas knockout swaps			40				141
Natural gas call options			(178	)			(178	)
Natural gas put options			(79	)			(39	)
Natural gas basis protection swaps			(29	)			93
Fixed-price oil swaps			13				31
Fixed-price oil knockout swaps			42				19
Fixed-price oil cap-swaps			2				3
Oil call options			(24	)			(35	)
Fixed-price oil collars			—				5
Estimated fair value		$	1,481			$	1,305

 

(a)	After adjusting for $558 million and $736 million of unrealized premiums, the value to be realized for these derivatives as of March 31, 2009 and December 31, 2008 was $2.039 billion and $2.041 billion, respectively.

The fair values shown above have the following associated volumes as of March 31, 2009 and December 31, 2008:

 

		March 31,			December 31,
		2009			2008
Natural Gas and Oil Volume Hedged:
Natural Gas (bbtu)
Fixed-price natural gas swaps		328,175			466,800
Fixed-price natural gas collars		384,265			457,715
Fixed-price natural gas knockout swaps		98,670			532,660
Natural gas call options		609,470			551,555
Natural gas put options		64,000			73,000
Natural gas basis protection swaps		188,764			219,487
Total gas volume		1,673,344			2,301,217
Oil (mbbls)
Fixed-price oil swaps		(369	)		(310	)
Fixed-price oil knockout swaps		9,512			12,248
Fixed-price oil cap-swaps		182			362
Oil call options		18,095			19,355
Fixed-price oil collars		—			730
Total oil volume		27,420			32,385

To mitigate our exposure to the fluctuation in prices of diesel fuel, we have entered into diesel swaps from April 2009 to March 2010 for a total of 41,475,000 gallons with an average fixed price of $1.60 per gallon. The fair value of these swaps as of March 31, 2009 was a liability of $3 million.

We have six secured hedging facilities, each of which permits us to enter into cash-settled natural gas and oil commodity transactions, valued by the counterparty, for up to a stated maximum value. Outstanding transactions under each facility are collateralized by certain of our natural gas and oil properties that do not secure any of our other obligations. The value of reserve collateral pledged to each facility is required to be at least 1.3 or 1.5 times the fair value of transactions outstanding under each facility. In addition, we may pledge collateral from our revolving bank credit facility, from time to time, to these facilities to meet any additional collateral coverage requirements. The hedging facilities are subject to a per annum exposure fee, which is assessed quarterly based on the average of the daily negative fair value amounts of the hedges, if any, during the quarter. The hedging facilities

 

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contain the standard representations and default provisions that are typical of such agreements. The agreements also contain various restrictive provisions which govern the aggregate natural gas and oil production volumes that we are permitted to hedge under all of our agreements at any one time. The fair value of outstanding transactions, per annum exposure fees and the scheduled maturity dates are shown below.

 

		Secured Hedging Facilities(a)
		#1				#2				#3				#4				#5				#6
		($ in millions)
Fair value of outstanding transactions, as of March 31, 2009		$	165			$	584			$	76			$	(3	)		$	98			$	136
Per annum exposure fee			1	%			1	%			0.8	%			0.8	%			0.8	%			0.8	%
Scheduled maturity date			2010				2013				2020				2012				2012				2012

 

(a)	Chesapeake Exploration, L.L.C. is the named party to the facilities numbered 1 – 3 and Chesapeake Energy Corporation is the named party to the facilities numbered 4 – 6.

Interest Rate Derivatives

We use interest rate derivatives to mitigate our exposure to volatility in interest rates related to our senior notes and credit facility. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value are recorded on the condensed consolidated balance sheets as assets (liabilities), and the debt’s carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Changes in the fair value of non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within interest expense.

Gains or losses from certain derivative transactions are reflected as adjustments to interest expense on the condensed consolidated statements of operations. Realized gains (losses) included in interest expense were $7 million and a nominal amount in the Current Quarter and the Prior Quarter, respectively. Unrealized gains (losses) included in interest expense were $45 million and ($13) million in the Current Quarter and the Prior Quarter, respectively.

As of March 31, 2009, the following interest rate derivatives were outstanding:

 

		Notional Amount ($ in millions)			Weighted Average Fixed Rate			Weighted Average Floating Rate(b)		Fair Value Hedge		Net Premiums ($ in millions)			Fair Value ($ in millions)
Fixed to Floating Interest Rate:
Swaps
January 2008 – November 2020		$	500		6.875	%		6 mL plus 230 bp		Yes		$	—		$	66
April 2008 – August 2015		$	250		6.50	%		6 mL plus 240 bp		No		$	—		$	20
Call Options
May 2009 – August 2009		$	750		6.75	%		6 mL plus 233 bp		No		$	9		$	(77	)
Floating to Fixed Interest Rate:
Swaps
August 2007 – July 2012		$	1,375		4.20	%		1 - 6 mL		No		$	—		$	(47	)
Collars(a)
August 2007 – August 2010		$	250		4.52	%		6 mL		No		$	—		$	(10	)
Swaption
August 2009		$	500		2.56	%		1 mL		No		$	5		$	(12	)
												$	14		$	(60	)

 

(a)	The collars have ceiling and floor fixed interest rates of 5.37% and 4.52%, respectively.

 

(b)	Month LIBOR has been abbreviated “mL” and basis points has been abbreviated “bp”.

 

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In the Current Quarter, we closed interest rate derivatives for gains totaling $12 million of which $7 million was recognized in interest expense. The remaining $5 million was from interest rate derivatives designated as fair value hedges and the settlement amounts received will be amortized as a reduction to interest expense over the remaining term of the related senior notes ranging from eight to nine years.

Foreign Currency Derivatives

On December 6, 2006, we issued €600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the euro-denominated senior notes, we entered into a cross currency swap to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. Under the terms of the cross currency swap, on each semi-annual interest payment date, the counterparties pay Chesapeake €19 million and Chesapeake pays the counterparties $30 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay Chesapeake €600 million and Chesapeake will pay the counterparties $800 million. The terms of the cross currency swap were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Through the cross currency swap, we have eliminated any potential variability in Chesapeake’s expected cash flows related to changes in foreign exchange rates and therefore the swap qualifies as a cash flow hedge under SFAS 133. The euro-denominated debt is recorded in notes payable ($796 million at March 31, 2009) using an exchange rate of $1.3261 to €1.00. The fair value of the cross currency swap is recorded on the condensed consolidated balance sheet as a liability of $74 million at March 31, 2009.

Disclosures About Derivative Instruments and Hedging Activities

In accordance with FASB Interpretation No. 39, to the extent that a legal right of set-off exists, Chesapeake nets the value of its derivative arrangements with the same counterparty in the accompanying condensed consolidated balance sheets. The following table sets forth the fair value of each classification of derivative instrument as of March 31, 2009:

 

		March 31, 2009
		Balance Sheet Location		Fair Value
				($ in millions)
ASSET DERIVATIVES:
Derivatives designated as hedging instruments under SFAS 133:
Interest rate contracts		Long-term derivative instruments		$	66
Commodity contracts		Short-term derivative instruments			958
Commodity contracts		Long-term derivative instruments			138
Total				$	1,162
Derivatives not designated as hedging instruments under SFAS 133:
Interest rate contracts		Long-term derivative instruments		$	20
Commodity contracts		Short-term derivative instruments			658
Commodity contracts		Long-term derivative instruments			138
Total				$	816
LIABILITY DERIVATIVES:
Derivatives designated as hedging instruments under SFAS 133:
Foreign exchange contracts		Long-term derivative instruments			74
Commodity contracts		Short-term derivative instruments			8
Total				$	82
Derivatives not designated as hedging instruments under SFAS 133:
Interest rate contracts		Short-term derivative instruments		$	96
Interest rate contracts		Long-term derivative instruments			50
Commodity contracts		Short-term derivative instruments			173
Commodity contracts		Long-term derivative instruments			234
Total				$	553

 

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A consolidated summary of the effect of derivative instruments on the condensed consolidated statement of operations for the three months ended March 31, 2009 is provided below, separating fair value, cash flow and non-qualifying hedges (as defined by SFAS 133).

The following table presents the gain (loss) recognized in net income (loss) for instruments designated as fair value hedges:

 

Fair Value Derivatives		Location of Gain (Loss)		Gain (Loss)
				($ in millions)
Interest rate contracts		Interest expense(a)		$	8

The following table presents the pre-tax gain (loss) recognized in, and reclassified from, accumulated other comprehensive income (AOCI) and recognized in net income (loss), including any hedge ineffectiveness, for derivative instruments classified as cash flow hedges:

 

Cash Flow Derivatives		Gain (Loss) Recognized in AOCI (Effective Portion)			Location of Gain (Loss) Reclassified from AOCI (Effective Portion)		Gain (Loss) Reclassified from AOCI (Effective Portion)			Location of Gain (Loss) Recognized (Ineffective Portion)		Gain (Loss) Recognized (Ineffective Portion) (b)
Commodity contracts		$	682		Natural gas and oil sales		$	296		Natural gas and oil sales		$	54
Foreign exchange contracts			43		Other income			—		Other income			—
Total		$	725				$	296				$	54

Based upon the market prices at March 31, 2009, we expect to transfer approximately $640 million (net of income taxes) of the gain included in the balance in accumulated other comprehensive income to net income (loss) during the next 12 months in the related month of production. All transactions hedged as of March 31, 2009 are expected to mature by December 31, 2022.

The following table presents the gain (loss) recognized in net income (loss) for derivatives not designated under SFAS 133:

 

Non SFAS 133 Derivatives		Location of Gain (Loss)		Gain (Loss)
				($ in millions)
Commodity contracts		Natural gas and oil sales		$	269
Interest rate contracts		Interest expense			44
		Total		$	313

 

(a)	Interest expense on the hedged item for the current period was $13 million, which is included in the line “Interest expense” on the condensed consolidated statement of operations.

 

(b)	The amount of gain (loss) recognized in net income (loss) represents the ineffective portion of the hedging relationships and none related to the amount excluded from the assessment of hedge effectiveness.

Concentration of Credit Risk

A significant portion of our liquidity is concentrated in derivative instruments that enable us to hedge a portion of our exposure to natural gas and oil price and interest rate volatility. These arrangements expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. On March 31, 2009, our commodity and interest rate derivative instruments were spread among 15 counterparties.

On September 15, 2008, Lehman Brothers Holdings Inc. (“Lehman”) filed for protection under Chapter 11 of the federal Bankruptcy Code in the United States Bankruptcy Court in the Southern District of New York. Chesapeake and its subsidiaries had certain business relationships with Lehman and its subsidiaries.

 

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Lehman Brothers Commercial Bank (“LBCB”), a subsidiary of Lehman, had $75 million of the $3.5 billion in commitments under our revolving bank credit facility. Although LBCB, to date, has not filed for bankruptcy (to our knowledge), LBCB had not funded approximately $13 million of its share of our borrowings under the credit facility as of March 31, 2009 and we have no reason to expect that LBCB will fund borrowings in the future. The loss of up to $75 million in borrowing capacity is not material to us.

Chesapeake was a counterparty with Lehman Brothers Commodity Services Inc. (“LBCS”), a subsidiary of Lehman, in financial transactions. Specifically, we utilized LBCS as a counterparty to hedge a portion of our natural gas and oil production. The obligations of LBCS are guaranteed by Lehman, and the Lehman bankruptcy filing resulted in an event of default under our ISDA agreement with LBCS allowing us to terminate the ISDA on September 18, 2008, and cancel the outstanding transactions. The potential loss associated with the termination of such transactions is not material to us.

Chesapeake will continue to closely monitor the Lehman bankruptcy situation and will assert its rights under the various contractual relationships. We believe the Lehman bankruptcy and its potential impact on subsidiaries of Lehman will not have a material adverse effect on Chesapeake or its subsidiaries individually or collectively.

Other financial instruments which potentially subject us to concentrations of credit risk consist principally of investments in equity instruments and accounts receivable. Our accounts receivable are primarily from purchasers of natural gas and oil and exploration and production companies which own interests in properties we operate. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During the Current Quarter, we recognized an $8 million bad debt expense related potentially to uncollectible receivables.

 

3.	Contingencies and Commitments

Litigation

We are involved in various disputes incidental to our business operations, including claims from royalty owners regarding volume measurements, post-production costs and prices for royalty calculations. In Tawney, et al. v. Columbia Natural Resources, Inc., Chesapeake’s wholly-owned subsidiary Chesapeake Appalachia, L.L.C., formerly known as Columbia Natural Resources, LLC (CNR), is a defendant in a class action lawsuit filed in 2003 in the Circuit Court for Roane County, West Virginia by royalty owners. The plaintiffs allege that CNR underpaid royalties by improperly deducting post-production costs, failing to pay royalty on total volumes of natural gas produced and not paying a fair value for the natural gas produced from their leases. The plaintiff class consists of West Virginia royalty owners receiving royalties after July 31, 1990 from CNR. Chesapeake acquired CNR in November 2005, and its seller acquired CNR in 2003 from NiSource Inc. NiSource, a co-defendant in the case, indemnified Chesapeake against underpayment claims based on the use of fixed prices for natural gas production sold under certain forward sale contracts and other claims with respect to CNR’s operations prior to September 2003.

On January 27, 2007, the Circuit Court jury returned a verdict against the defendants of $404 million, consisting of $134 million in compensatory damages and $270 million in punitive damages. The jury found fraudulent conduct by the defendants with respect to the sales prices used to calculate royalty payments and with respect to the failure of CNR to disclose post-production deductions. The defendants appealed the judgment and on May 22, 2008, the West Virginia Supreme Court of Appeals refused to hear the appeal. On October 22, 2008, the parties in the Tawney matter entered into a settlement agreement providing for the establishment of a settlement fund of $380 million. The Circuit Court for Roane County, West Virginia approved the settlement following a fairness hearing on November 22, 2008, and entered an order to discharge the judgment on January 21, 2009. Chesapeake’s share of the settlement fund was approximately $41 million, which amount had previously been fully reserved. The Circuit Court retains continuing jurisdiction over the case during the claims administration process in which the settlement amount is distributed to the members of the plaintiff class.

Chesapeake is subject to other legal proceedings and claims which arise in the ordinary course of business. In our opinion, the final resolution of these proceedings and claims will not have a material effect on the company.

 

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Employment Agreements with Officers

Chesapeake has employment agreements with its chief executive officer, chief operating officer, chief financial officer and other executive officers, which provide for annual base salaries, various benefits and eligibility for bonus compensation. The agreement with the chief executive officer expires on December 31, 2013 unless extended. The agreement contains a cap on cash salary and bonus compensation for the next five years at 2008 levels. The term of the agreement is automatically extended for one additional year on each December 31 unless the company provides 30 days notice of non-extension. In the event of termination of employment without cause, the chief executive officer’s base compensation (defined as base salary plus bonus compensation received during the preceding 12 months) and benefits would continue during the remaining term of the agreement. The chief executive officer is entitled to receive a payment in the amount of three times his base compensation upon the happening of certain events following a change of control. The agreement further provides that any stock-based awards held by the chief executive officer and deferred compensation will immediately become 100% vested upon termination of employment without cause, incapacity, death or retirement at or after age 55. The agreement also provides for a one-time $75 million well cost incentive award with a five-year clawback. The well cost incentive award was fully applied against Mr. McClendon’s obligations under the Founder Well Participation Program as of March 31, 2009. The agreements with the chief operating officer, chief financial officer and other executive officers expire on September 30, 2009. These agreements provide for the continuation of salary for one year in the event of termination of employment without cause or death and, in the event of a change of control, a payment in the amount of two times the executive officer’s base compensation. These executive officers are entitled to continue to receive compensation and benefits for 180 days following termination of employment as a result of incapacity. Any stock-based awards held by such executive officers will immediately become 100% vested upon termination of employment without cause, a change of control, death, or retirement at or after age 55.

Environmental Risk

Due to the nature of the natural gas and oil business, Chesapeake and its subsidiaries are exposed to possible environmental risks. Chesapeake has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. Chesapeake conducts periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a contingent liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Depending on the extent of an identified environmental problem, Chesapeake may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. Chesapeake has historically not experienced any significant environmental liability, and is not aware of any potential material environmental issues or claims at March 31, 2009.

Rig Leases

In a series of transactions in 2006, 2007 and 2008, our drilling subsidiaries sold 83 drilling rigs and related equipment for $677 million and entered into a master lease agreement under which we agreed to lease the rigs from the buyer for initial terms of seven to ten years for lease payments of approximately $95 million annually. The lease obligations are guaranteed by Chesapeake and its other material restricted subsidiaries. These transactions were recorded as sales and operating leasebacks and any related gain or loss will be amortized to service operations expense over the lease term. Under the rig leases, we can exercise an early purchase option after six or seven years or on the expiration of the lease term for a purchase price equal to the then fair market value of the rigs. Additionally, we have the option to renew the rig lease for a negotiated renewal term at a periodic lease equal to the fair market rental value of the rigs as determined at the time of renewal. As of March 31, 2009, Chesapeake’s drilling subsidiaries had committed to acquire 11 rigs by the end of 2009 and had incurred costs of $68 million as of that date. The total remaining cost of the rigs is estimated to be approximately $83 million. Our intent is to sell and lease back those rigs as they are delivered if acceptable leasing arrangements are available to us. Commitments related to rig lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of March 31, 2009, the minimum aggregate future rig lease payments were approximately $597 million.

 

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Compressor Leases

In a series of transactions in 2007, 2008 and 2009, our compression subsidiary sold a significant portion of its compressor fleet, consisting of 1,685 compressors, for $372 million and entered into a master lease agreement. The term of the agreement varies by buyer ranging from seven to ten years for aggregate lease payments of approximately $46 million annually. The lease obligations are guaranteed by Chesapeake and its other material restricted subsidiaries. These transactions were recorded as sales and operating leasebacks and any related gain or loss will be amortized to natural gas and oil marketing expenses over the lease term. Under the leases, we can exercise an early purchase option after five to nine years or we can purchase the compressors at expiration of the lease for the fair market value at the time. In addition, we have the option to renew the lease for negotiated new terms at the expiration of the lease. As of March 31, 2009, 466 new compressors are on order for approximately $179 million and our intent is to sell and lease back those compressors as they are delivered if acceptable leasing arrangements are available to us. Commitments related to compressor lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of March 31, 2009, the minimum aggregate future compressor lease payments were approximately $379 million.

Transportation Contracts

Chesapeake has various firm pipeline transportation service agreements with expiration dates ranging from 2009 to 2099. These commitments are not recorded in the accompanying condensed consolidated balance sheets. Under the terms of these contracts, we are obligated to pay demand charges as set forth in the transporter’s Federal Energy Regulatory Commission (FERC) gas tariff. In exchange, the company receives rights to flow natural gas production through pipelines located in highly competitive markets. The aggregate amounts of such required demand payments as of March 31, 2009, excluding demand charges for pipeline projects that are currently seeking regulatory approval, were as follows ($ in millions):

 

2009		$	170
2010			219
2011			193
2012			184
2013			166
After 2013			885
Total		$	1,817

Drilling Contracts

Currently, Chesapeake has contracts with various drilling contractors to lease approximately 32 rigs with terms of one to three years. These commitments are not recorded in the accompanying consolidated balance sheets. As of March 31, 2009, the aggregate drilling rig commitment was approximately $235 million.

Natural Gas and Oil Purchase Obligations

Our midstream segment regularly commits to purchase natural gas from other owners in our properties and such commitments typically are short term in nature. We have also committed to purchasers of our volumetric production payment transactions (VPPs) that we will purchase natural gas and oil associated with the VPPs. Our VPP purchase commitments extend over 11 to 15 year terms based on market prices at the time of production. As of March 31, 2009, we were obligated to purchase 438 bcfe under the terms of the VPPs. We resell the natural gas and oil we purchase at market prices.

Other Commitments

We own a 49% interest in Mountain Drilling Company, a company that specializes in hydraulic drilling rigs which are designed for drilling in urban areas. Due to a meaningful decline in the overall activity in the drilling market and poor operating performance of Mountain Drilling Company, we determined that an impairment had occurred and we fully impaired our investment at March 31, 2009. Chesapeake has an agreement to lend Mountain Drilling Company up to $19 million through December 31, 2009. At March 31, 2009, Mountain Drilling owed Chesapeake $19 million under this agreement.

 

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We invested in Ventura Refining and Transmission LLC in early 2007. We have an agreement to guarantee various commitments for Ventura, up to $70 million, to support its operating activities. As of March 31, 2009, we had $3 million of outstanding performance guarantees. Due to worsening economic conditions, the lack of third party credit available to Ventura, and poor operating performance in the second half of 2008, management determined that an impairment had occurred and we wrote off our investment at December 31, 2008.

 

4.	Net Income Per Share

Statement of Financial Accounting Standards No. 128, Earnings Per Share, requires presentation of “basic” and “diluted” earnings per share, as defined, on the face of the statements of operations for all entities with complex capital structures. SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted EPS computations.

For the Current Quarter and the Prior Quarter, there was no difference between basic weighted average shares outstanding, which are used in computing basic EPS, and diluted weighted average shares, which are used in computing EPS assuming dilution.

As a result of the Current Quarter’s net loss to common shareholders, diluted shares for the Current Quarter do not include the effect of (i) outstanding stock options to purchase 1.2 million shares of common stock at a weighted average exercise price of $8.15, (ii) 2.1 million shares of unvested restricted stock at a weighted average grant-date fair value of $35.95, (iii) the assumed conversion of 4.125% convertible preferred stock convertible into 180,854 common shares prior to conversion and (iv) the assumed conversion of the following outstanding preferred stock:

 

•

5.00% (Series 2005) convertible preferred stock convertible into 19,443 common shares,

 

•

5.00% (Series 2005B) convertible preferred stock convertible into 5,367,289 common shares,

 

•

4.50% preferred stock convertible into 5,795,396 common shares, and

 

•

6.25% mandatory convertible preferred stock convertible into 1,237,770 common shares.

As a result of the Prior Quarter’s net loss to common shareholders, diluted shares for the Prior Quarter do not include the effect of (i) outstanding stock options to purchase 2.6 million shares of common stock at a weighted average exercise price of $7.71, (ii) 5.3 million shares of unvested restricted stock at a weighted average grant-date fair value of $34.07 and (iii) the assumed conversion of the following outstanding preferred stock:

 

•

4.125% preferred stock convertible into 184,200 common shares,

 

•

5.00% (Series 2005) convertible preferred stock convertible into 19,432 common shares,

 

•

5.00% (Series 2005B) convertible preferred stock convertible into 14,719,425 common shares,

 

•

4.50% preferred stock convertible into 7,810,800 common shares, and

 

•

6.25% mandatory convertible preferred stock convertible into 1,031,175 common shares.

 

5.	Stockholders’ Equity, Restricted Stock and Stock Options

Common Stock

The following is a summary of the changes in our common shares issued for the three months ended March 31, 2009 and 2008:

 

		2009		2008
		(in thousands)
Shares issued at January 1		607,953		511,648
Stock option exercises		100		621
Restricted stock issuances (net of forfeitures)		2,858		2,296
Preferred stock conversions/exchanges		183		—
Common stock issued for the purchase of leasehold and unproved properties		14,361		—
Shares issued at March 31		625,455		514,565

 

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(Unaudited)

 

Preferred Shares

The following is a summary of the changes in our preferred shares outstanding for the three months ended March 31, 2009 and 2008:

 

		4.125%			5.00% (2005)		4.50%		5.00% (2005B)		6.25%
		(in thousands)
Shares outstanding at January 1, 2009		3			5		2,559		2,096		144
Conversion/exchange of preferred for common stock		(3	)		—		—		—		—
Shares outstanding at March 31, 2009		—			5		2,559		2,096		144
Shares outstanding at January 1, 2008 and March 31, 2008		3			5		3,450		5,750		144

On March 31, 2009, we converted all of our outstanding 4.125% cumulative convertible preferred stock (3,033 shares) into 182,887 shares of common stock pursuant to the company’s mandatory conversion rights.

Dividends

Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings will exist after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, such payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.

Stock-Based Compensation

Chesapeake’s stock-based compensation programs consist of restricted stock and stock options issued to employees and non-employee directors. To the extent compensation cost relates to employees directly involved in natural gas and oil exploration and development activities, such amounts are capitalized to natural gas and oil properties. Amounts not capitalized are recognized as general and administrative expenses, production expenses, natural gas and oil marketing expenses or service operations expense. We recorded the following stock-based compensation during the Current Quarter and the Prior Quarter:

 

		Three Months Ended March 31,
		2009			2008
		($ in millions)
Natural gas and oil properties		$	29		$	26
General and administrative expenses			19			19
Production expenses			9			7
Natural gas and oil marketing expenses			4			2
Service operations expense			2			1
Total		$	63		$	55

Restricted Stock. Chesapeake regularly issues shares of restricted common stock to employees and to non-employee directors. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, which is generally four or five years from the date of grant for employees and three years for non-employee directors.

A summary of the changes in unvested shares of restricted stock during the Current Quarter is presented below:

 

		Number of Unvested Restricted Shares			Weighted-Average Grant-Date Fair Value
Unvested shares as of January 1, 2009		21,622,202			$	38.85
Granted		3,823,904			$	17.25
Vested		(2,013,143	)		$	31.63
Forfeited		(242,745	)		$	35.83
Unvested shares as of March 31, 2009		23,190,218			$	35.95

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The aggregate intrinsic value of restricted stock vested during the Current Quarter was approximately $34 million based on the stock price at the time of vesting.

As of March 31, 2009, there was $635 million of total unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted average period of 2.65 years.

The vesting of certain restricted stock grants results in state and federal income tax benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter, we recognized a reduction in tax benefits related to restricted stock of $8 million. During the Prior Quarter, we recognized excess tax benefits related to restricted stock of $6 million. The reduction in tax benefits and the excess tax benefits were recorded as adjustments to additional paid-in capital and deferred income taxes.

Stock Options. Prior to 2006, we granted stock options under several stock compensation plans. Outstanding options expire ten years from the date of grant and are currently fully vested.

The following table provides information related to stock option activity during the Current Quarter:

 

		Number of Shares Underlying Options			Weighted Average Exercise Price Per Share			Weighted Average Contract Life in Years		Aggregate Intrinsic Value(a) ($ in millions)
Outstanding at January 1, 2009		2,802,421			$	8.13		3.59		$	23
Exercised		(100,188	)		$	7.43				$	1
Forfeited		—			$	—
Expired		—			$	—
Outstanding at March 31, 2009		2,702,233			$	8.15		3.41		$	24
Exercisable at March 31, 2009		2,702,233			$	8.15		3.41		$	24

 

(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

As of March 31, 2009, unrecognized compensation cost related to unvested stock options was not significant.

During the Current Quarter and the Prior Quarter, we recognized excess tax benefits related to stock options of a nominal amount and $5 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

6.	Senior Notes and Revolving Bank Credit Facilities

Our total debt consisted of the following as of March 31, 2009 and December 31, 2008:

 

		March 31, 2009				December 31, 2008
						(Adjusted)
		($ in millions)
7.5% Senior Notes due 2013		$	364			$	364
7.625% Senior Notes due 2013			500				500
7.0% Senior Notes due 2014			300				300
7.5% Senior Notes due 2014			300				300
6.375% Senior Notes due 2015			600				600
9.5% Senior Notes due 2015			1,425				—
6.625% Senior Notes due 2016			600				600
6.875% Senior Notes due 2016			670				670
6.25% Euro-denominated Senior Notes due 2017(a)			796				835
6.5% Senior Notes due 2017			1,100				1,100
6.25% Senior Notes due 2018			600				600
7.25% Senior Notes due 2018			800				800
6.875% Senior Notes due 2020			500				500
2.75% Contingent Convertible Senior Notes due 2035(b)			451				451
2.5% Contingent Convertible Senior Notes due 2037(b)			1,378				1,378
2.25% Contingent Convertible Senior Notes due 2038(b)			1,126				1,126
Revolving bank credit facility			2,225				3,474
Midstream revolving bank credit facility			164				460
Discount on senior notes(c)			(1,129	)			(1,094	)
Interest rate derivatives(d)			163				211
Total notes payable and long-term debt		$	12,933			$	13,175

 

(a)

The principal amount shown is based on the dollar/euro exchange rate of $1.3261 to €1.00 and $1.3919 to €1.00 as of March 31, 2009 and December 31, 2008, respectively. See Note 2 for information on our related cross currency swap.

 

(b)

The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarter by quarter. In the first quarter of 2009, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes during the specified period and, as a result, the holders do not have the option to convert their notes into cash and common stock in the second quarter of 2009 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of such principal amount. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years, under certain conditions. We may redeem the convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. The optional repurchase dates, the common stock price conversion threshold amounts and the ending date of the first six-month period contingent interest may be payable for the contingent convertible senior notes are as follows:

 

Contingent Convertible Senior Notes		Repurchase Dates		Common Stock Price Conversion Thresholds			Contingent Interest First Payable (if applicable)
2.75% due 2035		November 15, 2015, 2020, 2025, 2030		$	48.81		May 14, 2016
2.5% due 2037		May 15, 2017, 2022, 2027, 2032		$	64.47		November 14, 2017
2.25% due 2038		December 15, 2018, 2023, 2028, 2033		$	107.36		June 14, 2019

 

(c)

Discount at December 31, 2008 is adjusted for the retrospective application of FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion. Included in this discount is $988 million and $1.009 billion, respectively, associated with the liability component of our contingent convertible senior notes.

 

 

(d)	See Note 2 for discussion related to these instruments.

No scheduled principal payments are required under our senior notes until 2013 when $864 million is due.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Our outstanding senior notes are unsecured senior obligations of Chesapeake that rank equally in right of payment with all of our existing and future senior indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Senior notes issued before July 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries’ ability to incur additional indebtedness; pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; create restrictions on the payment of dividends or other amounts to us from our restricted subsidiaries; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. Senior notes issued after June 2005 are governed by indentures containing covenants that limit our ability and our subsidiaries’ ability to incur certain secured indebtedness; enter into sale/leaseback transactions; and consolidate, merge or transfer assets.

Chesapeake Energy Corporation is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. As of September 30, 2008, our obligations under our outstanding senior notes and contingent convertible notes were fully and unconditionally guaranteed, jointly and severally, by all of our wholly-owned restricted subsidiaries, other than minor subsidiaries, on a senior unsecured basis. In October 2008, we restructured our non-Appalachian midstream operations. As a result, beginning in the fourth quarter of 2008, our wholly-owned midstream subsidiaries having significant assets and operations do not guarantee our outstanding senior notes.

On January 1, 2009, the company adopted and applied retrospectively FASB Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement). We have three debt issuances affected by this change: our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038. FSP APB 14-1 requires the company to account for the liability and equity components of its convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance (6.86%, 8.0% and 8.0%, respectively). The allocation to the equity component of the convertible notes was $845 million (net of tax) at both March 31, 2009 and December 31, 2008. The accretion of the resulting discount on the debt is recognized as a part of interest expense, thereby increasing the amount of interest expense required to be recognized with respect to such instruments. Given the increase in our overall effective interest rate after adoption of FSP APB 14-1, we also capitalized additional interest which largely offset the increase in interest expense. Additionally, debt issuance costs are required to be allocated in proportion to the liability and equity components and accounted for as debt issuance costs and equity issuance costs, respectively. The applicable nonconvertible debt rates for the issuances are 6.86%, 8.0% and 8.0%, respectively.

The following table summarizes the effect of the change in accounting principle related to our convertible notes on the condensed consolidated balance sheet as of December 31, 2008 ($ in millions):

 

		December 31, 2008
		Previously Reported			Adjustment				Adjusted
Unevaluated properties		$	11,216		$	163			$	11,379
Other long-term assets			1,007			(14	)			993
Long-term debt, net			14,184			(1,009	)			13,175
Deferred income tax liability			3,763			437				4,200
Paid-in-capital			10,835			845				11,680
Retained earnings			4,694			(125	)			4,569

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The following table summarizes the effect of the change in accounting principle related to our convertible notes on the condensed consolidated statement of operations for the three months ended March 31, 2008 ($ in millions, except per share data):

 

		Three Months Ended March 31, 2008
		Previously Reported				Adjustment			Adjusted
Depreciation and amortization of other assets			36			—				36
Interest expense			101			(2	)			99
Income tax expense (benefit)			(82	)		—				(82	)
Net income			(132	)		2				(130	)
Weighted average common and common equivalent shares outstanding – assuming dilution (in millions)			493							493
Earnings per common share:
Basic		$	(0.29	)					$	(0.29	)
Diluted		$	(0.29	)					$	(0.29	)

The following table summarizes the effect of the change in accounting principle related to our convertible notes on the condensed consolidated statement of cash flows for the three months ended March 31, 2008 ($ in millions):

 

		Three Months Ended March 31, 2008
		Previously Reported				Adjustment				Adjusted
Cash flows from operating activities		$	1,498			$	17			$	1,515
Cash flows from investing activities		$	(2,675	)		$	(17	)		$	(2,692	)
Cash flows from financing activities		$	1,177			$	—			$	1,177

We have a $3.5 billion syndicated revolving bank credit facility which matures in November 2012. As of March 31, 2009, we had $2.225 billion in outstanding borrowings under this facility and utilized approximately $7 million of the facility for various letters of credit. The terms of the credit facility agreement summarized below reflect amendments effected on March 31, 2009.

Borrowings under our facility are secured by certain producing natural gas and oil properties and bear interest at our option at either (i) the greater of the reference rate of Union Bank of California, N.A. or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.00% to 0.75% (0.00% prior to the March 31, 2009 amendment) per annum according to our senior unsecured long-term debt ratings, or (ii) the London Interbank Offered Rate (LIBOR), plus a margin that varies from 1.50% to 2.25% (0.75% to 1.50% prior to the March 31, 2009 amendment) per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are determined periodically. The unused portion of the facility is subject to a commitment fee of 0.50% (which varied according to our senior unsecured long-term debt ratings, from 0.125% to 0.30% per annum, prior to the March 31, 2009 amendment). Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires us to maintain an indebtedness to total capitalization ratio (as defined) not to exceed 0.70 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.75 to 1. Pursuant to the March 31, 2009 amendment of the credit facility, the effects of ceiling test write-downs are excluded from the calculation of total capitalization for purposes of the consolidated indebtedness to total capitalization ratio. As defined by the credit facility agreement, our indebtedness to total capitalization ratio was 0.42 to 1 and our indebtedness to EBITDA ratio was 2.91 to 1 at March 31, 2009. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million ($50 million in the case of our senior notes issued after 2004), would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $75 million.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Two of our subsidiaries, Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C., are the borrowers under our revolving bank credit facility. The facility is fully and unconditionally guaranteed, on a joint and several basis, by Chesapeake and all of our other wholly-owned restricted subsidiaries.

We also have a secured revolving bank credit facility for our midstream operations, organized under an unrestricted subsidiary, Chesapeake Midstream Partners, L.P. (CMP) and its operating subsidiary, Chesapeake Midstream Operating, L.L.C. (CMO). CMO is the borrower under the facility, which matures in October 2013, has current availability of $460 million and may be expanded up to $750 million at CMO’s option, subject to additional bank participation. CMO is utilizing the facility to fund capital expenditures associated with building additional natural gas gathering and other systems associated with our drilling program and for general corporate purposes related to our midstream operations. As of March 31, 2009, we had $164 million in outstanding borrowings under the midstream credit facility.

Borrowings under the midstream credit facility are secured by all of the assets of the midstream companies organized under CMP and bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one month London Interbank Offered Rate plus 1.50%, all of which would be subject to a margin that varies from 0.75% to 1.50% per annum according to the most recent indebtedness to EBITDA ratio (as defined) or (ii) the LIBOR plus a margin that varies from 1.75% to 2.50% per annum according to the most recent indebtedness to EBITDA ratio (as defined). The unused portion of the facility is subject to a commitment fee that varies from 0.30% to 0.45% per annum according the most recent indebtedness to EBITDA ratio (as defined). Interest is payable quarterly or, if LIBOR applies, it may be paid at more frequent intervals.

The midstream credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMP and its subsidiaries to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires maintenance of an indebtedness to EBITDA ratio (as defined) not to exceed 3.50 to 1, and an EBITDA (as defined) to interest expense coverage ratio of not less than 2.50 to 1. As defined by the credit facility agreement, our indebtedness to EBITDA ratio was 0.83 to 1 and our EBITDA to interest expense coverage ratio was 10.98 to 1 at March 31, 2009. If CMP or its subsidiaries should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the midstream facility could be declared immediately due and payable. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness CMP and its subsidiaries may have with an outstanding principal amount in excess of $15 million.

Our revolving bank credit facility and the midstream credit facility do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates in our revolving bank credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, neither of our credit facilities contain provisions which would trigger an acceleration of amounts due under the facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

 

7.	Segment Information

In accordance with Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information, we have two reportable operating segments. Our exploration and production operational segment and natural gas and oil midstream segment are managed separately because of the nature of their products and services. The exploration and production segment is responsible for finding and producing natural gas and oil. The midstream segment is responsible for gathering, processing, compressing, transporting and selling natural gas and oil primarily from Chesapeake-operated wells. We also have drilling rig and trucking operations which are responsible for providing drilling rigs primarily used on Chesapeake-operated wells and trucking services utilized in the transportation of drilling rigs on both Chesapeake-operated wells and wells operated by third parties.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the midstream segment’s sale of natural gas and oil related to Chesapeake’s ownership interests are reflected as exploration and production revenues. Such amounts totaled $671 million and $1.289 billion for the Current Quarter and the Prior Quarter. The following table presents selected financial information for Chesapeake’s operating segments. Our drilling rig and trucking service operations are presented in “Other Operations”.

 

		Exploration and Production				Midstream				Other Operations				Intercompany Eliminations				Consolidated Total
		($ in millions)
For the Three Months Ended March 31, 2009:
Revenues		$	1,397			$	1,223			$	154			$	(779	)		$	1,995
Intersegment revenues			—				(671	)			(108	)			779				—
Total revenues		$	1,397			$	552			$	46			$	—			$	1,995
Income (loss) before income taxes		$	(9,193	)		$	18			$	(20	)		$	11			$	(9,184	)
For the Three Months Ended March 31, 2008 (Adjusted):
Revenues		$	773			$	2,085			$	149			$	(1,396	)		$	1,611
Intersegment revenues			—				(1,289	)			(107	)			1,396				—
Total revenues		$	773			$	796			$	42			$	—			$	1,611
Income (loss) before income taxes		$	(226	)		$	15			$	20			$	(21	)		$	(212	)
As of March 31, 2009:
Total assets		$	25,698			$	5,714			$	773			$	(2,524	)		$	29,661
As of December 31, 2008 (Adjusted):
Total assets		$	35,192			$	3,416			$	688			$	(703	)		$	38,593

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

8.	Investments

At March 31, 2009, investments accounted for under the equity method totaled $352 million and investments accounted for under the cost method totaled $26 million. Following is a summary of our investments:

 

						Carrying Value
		Approximate % Owned		Accounting Method		March 31, 2009			December 31, 2008
						($ in millions)
Frac Tech Services, Ltd.(a)		20%		Equity		$	223		$	223
Chaparral Energy, Inc.(b)(c)		32%		Equity			101			152
DHS Drilling Company(b)		47%		Equity			—			19
Sierra Mid-Con, L.P.		50%		Equity			12			12
Gastar Exploration Ltd.(b)		17%		Cost			20			11
Mountain Drilling Company(b)		49%		Equity			—			9
Other		—		—			22			18
						$	378		$	444

 

(a)

The carrying value of our investment in Frac Tech is in excess of our underlying equity in net assets by approximately $165 million as of March 31, 2009. This excess amount is attributed to certain intangibles associated with the specialty services provided by Frac Tech and is being amortized over the estimated life of the intangibles.

 

(b)

Our investees have been impacted by the dramatic slowing of the worldwide economy and the tightening of the credit markets in the fourth quarter of 2008 and into 2009. The economic weakness has resulted in significantly reduced oil and natural gas prices leading to a meaningful decline in the overall level of activity in the markets served by our investees. Associated with the weakness in performance of certain of the investees, as well as an evaluation of their financial condition and near-term prospects, we recognized during the Current Quarter that an other than temporary impairment had occurred on March 31, 2009 on the following investments: Chaparral Energy of $51 million, DHS Drilling Company of $19 million, Gastar Exploration Ltd. of $70 million and Mountain Drilling Company of $9 million. We will continue to monitor the performance of our investments, and it is reasonably possible that we may experience additional impairments, although we do not believe that our exposure to future charges would be material to our consolidated results of operations.

 

(c)

The carrying value of our investment in Chaparral is in excess of our underlying equity in net assets by approximately $55 million as of March 31, 2009. This excess is attributed to the natural gas and oil reserves held by Chaparral and is being amortized over the estimated life of these reserves based on a unit of production rate.

 

9.	Fair Value Measurements

Effective January 1, 2008, we adopted Statement of Financial Accounting Standards No. 157, Fair Value Measurements for our financial assets and liabilities measured on a recurring basis. Our nonfinancial assets and liabilities became subject to the statement effective January 1, 2009. This statement establishes a framework for measuring fair value of assets and liabilities and expands disclosures about fair value measurements.

SFAS 157 defines fair value as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the financial asset or liability and have the lowest priority. Chesapeake uses appropriate valuation techniques based on available inputs, including counterparty quotes, to measure the fair values of its assets and liabilities. Counterparty quotes are generally assessed as a Level 3 input.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2009.

 

		Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)				Total Fair Value
		($ in millions)
Financial Assets (Liabilities):
Derivatives, net		$	—		$	910		$	434			$	1,344
Investments		$	20		$	—		$	—			$	20
Other long-term assets		$	19		$	—		$	—			$	19
Long-term debt		$	—		$	—		$	(1,460	)		$	(1,460	)
Other long-term liabilities		$	19		$	—		$	—			$	19

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 Fair Value Measurements

Investments. The fair value of Chesapeake’s investment in Gastar Exploration Ltd. common stock is based on a quoted market price.

Other Long-Term Assets and Liabilities. The fair value of other long-term assets and liabilities, consisting of obligations under our Deferred Compensation Plan, is based on quoted market prices.

Level 2 Fair Value Measurements

Derivatives. The fair values of our natural gas swaps are measured internally using established index prices and other sources. These values are based upon, among other things, futures prices and time to maturity. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives.

Level 3 Fair Value Measurements

Derivatives. The fair value of our derivative instruments, excluding natural gas swaps, have been established utilizing established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives.

Debt. The fair value of our long-term debt is based on the face amount of the debt along with the value of the related interest rate swaps. The interest rate swap values are based on estimates provided by our respective counterparties and reviewed internally for reasonableness using future interest rate curves and time to maturity.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

A reconciliation of Chesapeake’s assets and liabilities classified as Level 3 measurements is presented below.

 

		Derivatives				Debt				Total
		($ in millions)
Balance of Level 3 as of January 1, 2009		$	292			$	(1,470	)		$	(1,178	)
Total gains or losses (realized/unrealized):
Included in earnings(a)			(68	)			10				(58	)
Included in other comprehensive income (loss)			172				—				172
Purchases, issuances and settlements			38				—				38
Transfers in and out of Level 3			—				—				—
Balance of Level 3 as of March 31, 2009		$	434			$	(1,460	)		$	(1,026	)

 

 

(a)

 

		Natural Gas and Oil Sales				Interest Expense
		($ in millions)
Total gains and (losses) related to derivatives included in earnings for the period		$	(66	)		$	(1	)
Change in unrealized gains or (losses) relating to assets still held at reporting date		$	103			$	5

 

10.	Condensed Consolidating Financial Information

Chesapeake Energy Corporation is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. As of September 30, 2008, our obligations under our outstanding senior notes and contingent convertible notes listed in Note 6 were fully and unconditionally guaranteed, jointly and severally, by all of our wholly-owned subsidiaries, other than minor subsidiaries, on a senior unsecured basis. Since October 2008, following the restructuring of our non-Appalachian midstream operations, certain of our wholly-owned subsidiaries having significant assets and operations have not guaranteed our outstanding notes. The midstream revolving credit facility referred to in Note 6 contains a covenant restricting Chesapeake Midstream Partners, L.P., the parent of our midstream subsidiaries, from paying dividends or distributions or making loans to Chesapeake.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Set forth below are condensed consolidating financial statements for Chesapeake Energy Corporation (the “parent”) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of March 31, 2009 and December 31, 2008 and for the three months ended March 31, 2009 and 2008. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF MARCH 31, 2009

($ in millions)

 

		Parent				Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations				Consolidated
CURRENT ASSETS:
Cash and cash equivalents		$	—			$	83		$	—		$	—			$	83
Other current assets			14				2,670			116			(30	)			2,770
Total Current Assets			14				2,753			116			(30	)			2,853
PROPERTY AND EQUIPMENT:
Total natural gas and oil properties, at cost based on full-cost accounting, net			—				20,490			4			—				20,494
Other property and equipment, net			—				2,535			2,827			—				5,362
Total Property and Equipment			—				23,025			2,831			—				25,856
Other assets			244				694			14			—				952
Investments in subsidiaries and intercompany advance			3,195				142			—			(3,337	)			—
TOTAL ASSETS		$	3,453			$	26,614		$	2,961		$	(3,367	)		$	29,661
CURRENT LIABILITIES:
Current liabilities		$	258			$	2,865		$	271		$	(32	)		$	3,362
Intercompany payable (receivable) from parent			(19,829	)			17,481			2,268			80				—
Total Current Liabilities			(19,571	)			20,346			2,539			48				3,362
Long-term debt, net			10,544				2,225			164			—				12,933
Deferred income tax liability			536				232			110			(78	)			800
Other liabilities			126				616			6			—				748
Total Long-Term Liabilities			11,206				3,073			280			(78	)			14,481
Total Stockholders’ Equity			11,818				3,195			142			(3,337	)			11,818
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	3,453			$	26,614		$	2,961		$	(3,367	)		$	29,661

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2008

Adjusted

($ in millions)

 

		Parent				Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations				Consolidated
CURRENT ASSETS:
Cash and cash equivalents		$	—			$	1,749		$	—		$	—			$	1,749
Other current assets			13				2,372			189			(31	)			2,543
Total Current Assets			13				4,121			189			(31	)			4,292
PROPERTY AND EQUIPMENT:
Total natural gas and oil properties, at cost based on full-cost accounting, net			—				28,463			15			—				28,478
Other property and equipment, net			—				1,918			2,912			—				4,830
Total Property and Equipment			—				30,381			2,927			—				33,308
Other assets			140				838			15			—				993
Investments in subsidiaries and intercompany advance			8,455				140			—			(8,595	)			—
TOTAL ASSETS		$	8,608			$	35,480		$	3,131		$	(8,626	)		$	38,593
CURRENT LIABILITIES:
Current liabilities		$	257			$	3,322		$	133		$	(91	)		$	3,621
Intercompany payable (receivable) from parent			(18,272	)			16,047			2,165			60				—
Total Current Liabilities			(18,015	)			19,369			2,298			(31	)			3,621
Long-term debt, net			9,241				3,474			460			—				13,175
Deferred income tax liability			439				3,534			227			—				4,200
Other liabilities			(74	)			648			6			—				580
Total Long-Term Liabilities			9,606				7,656			693			—				17,955
Total Stockholders’ Equity			17,017				8,455			140			(8,595	)			17,017
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	8,608			$	35,480		$	3,131		$	(8,626	)		$	38,593

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

($ in millions)

 

		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Eliminations				Consolidated
For the Three Months Ended March 31, 2009:
REVENUES:
Natural gas and oil sales		$	—			$	1,397			$	—			$	—			$	1,397
Natural gas and oil marketing sales			—				489				110				(47	)			552
Service operations revenue			—				46				—				—				46
Total Revenues			—				1,932				110				(47	)			1,995
OPERATING COSTS:
Production expenses			—				238				—				—				238
Production taxes			—				23				—				—				23
General and administrative expenses			—				85				5				—				90
Natural gas and oil marketing expenses			—				469				48				6				523
Service operations expense			—				40				—				—				40
Natural gas and oil depreciation, depletion and amortization			—				447				—				—				447
Depreciation and amortization of other assets			(1	)			37				20				1				57
Impairment of natural gas and oil properties and other assets			—				9,626				4				—				9,630
Total Operating Costs			(1	)			10,965				77				7				11,048
INCOME (LOSS) FROM OPERATIONS			1				(9,033	)			33				(54	)			(9,053	)
OTHER INCOME (EXPENSE):
Other income (expense)			162				5				3				(162	)			8
Interest expense			(127	)			(18	)			(3	)			162				14
Impairment of investments			—				(153	)			—				—				(153	)
Equity in net earnings of subsidiary			(5,763	)			(14	)			—				5,777				—
Total Other Income (Expense)			(5,728	)			(180	)			—				5,777				(131	)
INCOME (LOSS) BEFORE INCOME TAXES			(5,727	)			(9,213	)			33				5,723				(9,184	)
INCOME TAX EXPENSE (BENEFIT)			13				(3,450	)			13				(20	)			(3,444	)
NET INCOME (LOSS)		$	(5,740	)		$	(5,763	)		$	20			$	5,743			$	(5,740	)

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

($ in millions)

 

		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Eliminations				Consolidated
For the Three Months Ended March 31, 2008:
REVENUES:
Natural gas and oil sales		$	—			$	773			$	—			$	—			$	773
Natural gas and oil marketing sales			—				758				69				(31	)			796
Service operations revenue			—				41				7				(6	)			42
Total Revenues			—				1,572				76				(37	)			1,611
OPERATING COSTS:
Production expenses			—				201				—				—				201
Production taxes			—				75				—				—				75
General and administrative expenses			—				76				3				—				79
Natural gas and oil marketing expenses			—				747				30				(3	)			774
Service operations expense			—				35				3				(3	)			35
Natural gas and oil depreciation, depletion and amortization			—				515				—				—				515
Depreciation and amortization of other assets			4				27				11				(6	)			36
Total Operating Costs			4				1,676				47				(12	)			1,715