Edgar Filing: CHESAPEAKE ENERGY CORP

Form 10-Q

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, 2010

[ ] 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 [X] 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 [ ]

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 5, 2010, there were 650,913,021 shares of our $0.01 par value common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2010


PART I.
Financial Information
		Page
Item 1.	Condensed Consolidated Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009	1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and 2009	3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	4
	Condensed Consolidated Statements of Equity for the Three Months Ended March 31, 2010 and 2009	6
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2010 and 2009	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 4.	Controls and Procedures	61

PART II.
Other Information

Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 3.	Defaults Upon Senior Securities	62
Item 4.	(Removed and Reserved)	62
Item 5.	Other Information	62
Item 6.	Exhibits	63

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2010			December 31, 2009
	($ in millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	516		$	307
Accounts receivable		1,419			1,325
Short-term derivative instruments		1,297			692
Deferred income tax asset		—			24
Other		103			98

Total Current Assets		3,335			2,446


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full-cost accounting:
Evaluated natural gas and oil properties		35,720			35,007
Unevaluated properties		10,118			10,005
Less: accumulated depreciation, depletion and amortization of natural gas and oil properties		(24,523	)		(24,220	)

Total natural gas and oil properties, at cost based on full-cost accounting		21,315			20,792

Other property and equipment:
Natural gas gathering systems and treating plants		1,590			3,516
Buildings and land		1,674			1,673
Drilling rigs and equipment		723			687
Natural gas compressors		351			325
Other		568			550
Less: accumulated depreciation and amortization of other property and equipment		(566	)		(833	)

Total other property and equipment		4,340			5,918

Total Property and Equipment		25,655			26,710


OTHER ASSETS:
Investments		1,005			404
Long-term derivative instruments		15			60
Other assets		278			294

Total Other Assets		1,298			758


TOTAL ASSETS	$	30,288		$	29,914

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (Continued)

(Unaudited)


	March 31, 2010			December 31, 2009
	($ in millions)
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	1,296		$	957
Short-term derivative instruments		14			27
Accrued liabilities		812			920
Deferred income taxes		212			—
Income taxes payable		—			1
Revenues and royalties due others		637			565
Accrued interest		152			218

Total Current Liabilities		3,123			2,688


LONG-TERM LIABILITIES:
Long-term debt, net		12,204			12,295
Deferred income tax liabilities		1,295			1,059
Asset retirement obligations		283			282
Long-term derivative instruments		699			787
Revenues and royalties due others		78			73
Other liabilities		390			389

Total Long-Term Liabilities		14,949			14,885


CONTINGENCIES AND COMMITMENTS (Note 3)
EQUITY:
Chesapeake 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, 2010 and December 31, 2009, 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, 2010 and December 31, 2009, entitled in liquidation to $209 million		209			209
5.00% cumulative convertible preferred stock (series 2005), 5,000 shares issued and outstanding as of March 31, 2010 and December 31, 2009, entitled in liquidation to $1 million		1			1
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 651,823,247 and 648,549,165 shares issued at March 31, 2010 and December 31, 2009, respectively		7			6
Paid-in capital		12,160			12,146
Retained earnings (deficit)		(665	)		(1,261	)
Accumulated other comprehensive income, net of tax of ($161) million and ($62) million, respectively		265			102
Less: treasury stock, at cost; 943,220 and 877,205 common shares as of March 31, 2010 and December 31, 2009, respectively		(17	)		(15	)

Total Chesapeake Stockholders’ Equity		12,216			11,444

Noncontrolling interest		—			897

Total Equity		12,216			12,341


TOTAL LIABILITIES AND EQUITY	$	30,288		$	29,914

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended March 31,
	2010			2009
	($ in millions except per share data)
REVENUES:
Natural gas and oil sales	$	1,898		$	1,397
Marketing, gathering and compression sales		844			552
Service operations revenue		56			46

Total Revenues		2,798			1,995


OPERATING COSTS:
Production expenses		207			238
Production taxes		48			23
General and administrative expenses		109			90
Marketing, gathering and compression expenses		815			523
Service operations expense		49			40
Natural gas and oil depreciation, depletion and amortization		308			447
Depreciation and amortization of other assets		50			57
Impairment of natural gas and oil properties and other assets		—			9,630

Total Operating Costs		1,586			11,048

INCOME (LOSS) FROM OPERATIONS		1,212			(9,053	)


OTHER INCOME (EXPENSE):
Other income		15			8
Interest expense (income)		(25	)		14
Impairment of investments		—			(153	)
Loss on exchanges of Chesapeake debt		(2	)		—

Total Other Income (Expense)		(12	)		(131	)


INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		1,200			(9,184	)


INCOME TAX EXPENSE (BENEFIT):
Current income taxes		—			—
Deferred income taxes		462			(3,444	)

Total Income Tax Expense (Benefit)		462			(3,444	)


INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX		738			(5,740	)
Cumulative effect of accounting change, net of income taxes of $89 million		(142	)		—


NET INCOME (LOSS)		596			(5,740	)


Net (income) loss attributable to noncontrolling interest		—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		596			(5,740	)
Preferred stock dividends		(6	)		(6	)

NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS	$	590		$	(5,746	)


EARNINGS (LOSS) PER COMMON SHARE – BASIC:
Income before cumulative effect of accounting change	$	1.17		$	(9.63	)
Cumulative effect of accounting change		(0.23	)		—

	$	0.94		$	(9.63	)


EARNINGS (LOSS) PER COMMON SHARE – ASSUMING DILUTION:
Income before cumulative effect of accounting change	$	1.14		$	(9.63	)
Cumulative effect of accounting change		(0.22	)		—

	$	0.92		$	(9.63	)


CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.075		$	0.075

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic		630			597
Assuming dilution		647			597

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
	2010			2009
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	596		$	(5,740	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization		358			504
Deferred income tax expense (benefit)		462			(3,444	)
Unrealized gains on derivatives		(342	)		(145	)
Realized gains on financing derivatives		(94	)		(19	)
Stock-based compensation		32			34
Accretion of discount on contingent convertible notes		19			20
(Gain) loss from equity investments		(13	)		1
Cumulative effect of deconsolidation of investment in CMP		142			—
Loss on exchanges of Chesapeake debt		2			—
Impairment of natural gas and oil properties and other fixed assets		—			9,630
Impairment of investments		—			153
Other		4			5
Change in assets and liabilities		17			262

Cash provided by operating activities		1,183			1,261


CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of natural gas and oil properties		(1,020	)		(1,347	)
Acquisitions of natural gas and oil proved and unproved properties and leasehold		(1,030	)		(413	)
Additions to other property and equipment		(279	)		(667	)
Additions to investments		(6	)		(8	)
Proceeds from divestitures of proved and unproved properties and leasehold		1,044			—
Proceeds from sales of volumetric production payments		180			—
Proceeds from sale of other assets		56			—
Proceeds from sale of compressors		—			68
Deposits for divestitures		21			—
Other		20			—

Cash used in investing activities		(1,014	)		(2,367	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		2,924			1,575
Payments on credit facilities borrowings		(2,944	)		(3,120	)
Proceeds from issuance of senior notes, net of offering costs		—			1,346
Cash paid for common stock dividends		(47	)		(44	)
Cash paid for preferred stock dividends		(6	)		(6	)
Derivative settlements		94			1
Net increase (decrease) in outstanding payments in excess of cash balance		45			(287	)
Other		(26	)		(25	)

Cash provided by (used in) financing activities		40			(560	)

Net increase (decrease) in cash and cash equivalents		209			(1,666	)
Cash and cash equivalents, beginning of period		307			1,749

Cash and cash equivalents, end of period	$	516		$	83

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

(Unaudited)


	Three Months Ended March 31,
	2010			2009
	($ in millions)

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION OF CASH PAYMENTS FOR:
Interest, net of capitalized interest	$	89		$	27
Income taxes, net of refunds received	$	(8	)	$	114

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

SUPPLEMENTAL SCHEDULE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:

As of March 31, 2010 and 2009, dividends payable on our common and preferred stock were $53 million and $51 million, respectively.

For the three months ended March 31, 2010 and 2009, natural gas and oil properties were adjusted by $1 million and ($62) million, respectively, as a result of an increase (decrease) in accrued exploration and development costs.

For the three months ended March 31, 2010 and 2009, other property and equipment were adjusted by $1 million and $13 million, respectively, as a result of an increase in accrued costs.

We recorded non-cash asset additions (reductions) to natural gas and oil properties of ($1) million and $2 million for the three months ended March 31, 2010 and 2009, respectively, for asset retirement obligations.

During the three months ended March 31, 2010, holders of our 2.25% Contingent Convertible Senior Notes due 2038 exchanged approximately $11 million in aggregate principal amount for an aggregate of 298,500 shares of our common stock in privately negotiated exchanges.

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.

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

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)


	Three Months Ended March 31,
	2010			2009
	($ in millions)
PREFERRED STOCK:
Balance, beginning of period	$	466		$	505
Exchange of common stock for 0 and 3,033 shares of 4.125% preferred stock		—			(3	)

Balance, end of period		466			502


COMMON STOCK:
Balance, beginning of period		6			6
Issuance of 0 and 14,360,642 shares of common stock for the purchase of proved and unproved properties and leasehold		—			—
Exchange of 0 and 182,887 shares of common stock for preferred stock		—			—
Exercise of stock options and other		1			—

Balance, end of period		7			6


PAID-IN CAPITAL:
Balance, beginning of period		12,146			11,680
Issuance of 0 and 14,360,642 shares of common stock for the purchase of proved and unproved properties and leasehold		—			232
Exchange of 298,500 and 0 shares of common stock for convertible notes		9			—
Exchange of 0 and 182,887 shares of common stock for preferred stock		—			3
Stock-based compensation		57			53
Exercise of stock options		1			1
Dividends on common stock		(47	)		(45	)
Dividends on preferred stock		(6	)		(6	)
Tax benefit (reduction in tax benefit) from exercise of stock-based compensation		—			(8	)

Balance, end of period		12,160			11,910


RETAINED EARNINGS (DEFICIT):
Balance, beginning of period		(1,261	)		4,569
Net income (loss)		596			(5,740	)

Balance, end of period		(665	)		(1,171	)


ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period		102			267
Hedging activity		166			266
Investment activity		(3	)		49

Balance, end of period		265			582


TREASURY STOCK – COMMON:
Balance, beginning of period		(15	)		(10	)
Purchase of 70,177 and 64,242 shares for company benefit plans		(2	)		(1	)
Release of 4,162 and 1,972 shares for company benefit plans		—			—

Balance, end of period		(17	)		(11	)


TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY		12,216			11,818


NONCONTROLLING INTEREST:
Balance, beginning of period		897			—
Deconsolidation of investment in CMP		(897	)		—

Balance, end of period		—			—


TOTAL EQUITY	$	12,216		$	11,818

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	Three Months Ended March 31,
	2010			2009
	($ in millions)

Net income (loss)	$	596		$	(5,740	)
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income taxes of $152 million and $296 million		249			484
Reclassification of gain on settled contracts, net of income taxes of ($53) million and ($112) million		(87	)		(184	)
Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of $2 million and ($21) million		4			(34	)
Unrealized (gain) loss on marketable securities, net of income taxes of ($2) million and $4 million		(3	)		6
Reclassification of loss on investments, net of income taxes of $0 and $26 million		—			43

Comprehensive income (loss)		759			(5,425	)

(Income) loss attributable to noncontrolling interest		—			—

Comprehensive income (loss) available to Chesapeake	$	759		$	(5,425	)

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

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 (SEC). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2009 (“2009 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, 2010 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, 2010 (the “Current Quarter”) and the three months ended March 31, 2009 (the “Prior Quarter”).

Cumulative Effect of Accounting Change

Beginning January 1, 2010, in accordance with new authoritative guidance for variable interest entities, we no longer consolidate our midstream joint venture, Chesapeake Midstream Partners, L.L.C. (CMP). Because we have shared control with our 50% partner, Global Infrastructure Partners, our investment in CMP is now accounted for under the equity method (See Note 9). Adoption of this new guidance resulted in an after-tax charge of $142 million, which is reflected in our condensed consolidated statement of operations as the cumulative effect of accounting change for the quarter ended March 31, 2010. This charge reflects the difference between the carrying value of our initial investment in the joint venture, which was recorded at carryover basis as an entity under common control, and the fair value of our equity in the joint venture as of the formation date.

Critical Accounting Policies

We consider accounting policies related to hedging, natural gas and oil properties and income taxes to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2009 Form 10-K.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2.	Financial Instruments and Hedging Activities

Natural Gas and Oil Derivatives

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 our risk management objectives. As of March 31, 2010 and December 31, 2009, our natural gas and oil derivative instruments were comprised of the following types of instruments:

•

Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

•

Collars: These instruments 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 put and the call strike price, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the collar. This eliminates the counterparty’s downside exposure below the second put option.

•

Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.

•

Put options: Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. At the time of settlement, if the market price falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.

•

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.

•

Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin 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 ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The estimated fair values of our natural gas and oil derivative instruments as of March 31, 2010 and December 31, 2009 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.


	March 31, 2010					December 31, 2009
	Volume		Fair Value			Volume		Fair Value
Natural gas (bbtu):			($ in millions)					($ in millions)
Fixed-price swaps	501,297		$	1,362		492,053		$	662
Fixed-price collars	31,040			91		74,240			92
Call options	1,129,316			(426	)	996,750			(541	)
Put options	(51,220	)		(57	)	(69,620	)		(50	)
Fixed-price knockout swaps	38,370			15		38,370			17
Basis protection swaps	123,176			(54	)	125,469			(50	)

Total natural gas	1,771,979			931		1,657,262			130


Oil (mbbl):
Fixed-price swaps	10,422			(23	)	5,475			3
Call options	23,302			(243	)	14,975			(144	)
Fixed-price knockout swaps	5,402			34		6,572			32

Total oil	39,126			(232	)	27,022			(109	)


Total estimated fair value			$	699				$	21

Pursuant to accounting guidance for derivatives and hedging, certain derivatives qualify for designation as cash flow hedges. Following this guidance, 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 accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). 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 natural gas and oil sales. Realized gains (losses) are included in natural gas and oil sales in the month of related production.

The components of natural gas and oil sales for the Current Quarter and the Prior Quarter are presented below.


	Three Months Ended March 31,
	2010			2009
	($ in millions)

Natural gas and oil sales	$	1,184		$	778
Realized gains (losses) on natural gas and oil derivatives		399			519
Unrealized gains (losses) on non-qualifying natural gas and oil derivatives		321			46
Unrealized gains (losses) on ineffectiveness of cash flow hedges		(6	)		54

Total natural gas and oil sales	$	1,898		$	1,397

Based upon the market prices at March 31, 2010, we expect to transfer approximately $369 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, 2010 are expected to mature by December 31, 2022.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

outstanding under the facility by at least 1.65 times, and guarantees by certain subsidiaries that also guarantee our corporate revolving bank credit facility and indentures. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. Treasury instruments to the extent that any mark-to-market amounts they owe to Chesapeake exceed defined thresholds. The maximum volume-based trading capacity under the facility is governed by the expected production of the pledged reserve collateral, and volume-based trading limits are applied separately to price and basis hedges. In addition, there are volume-based sub-limits for natural gas and oil hedges. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain collateral coverage and other requirements are met. The facility does not have a maturity date. Counterparties to the agreement have the right to cease trading with the company on a prospective basis as long as obligations associated with any existing trades in the facility continue to be satisfied in accordance with the terms of the agreement.

Interest Rate Derivatives

To mitigate our exposure to volatility in interest rates related to our senior notes and bank credit facilities, we enter into interest rate derivatives. As of March 31, 2010 and December 31, 2009, our interest rate derivative instruments were comprised of the following types of instruments:

•

Swaps: Chesapeake enters into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our bank credit facilities borrowings.

•

Collars: These instruments contain a fixed floor rate (floor) and a ceiling rate (cap). If the floating rate is above the cap, we have a net receivable from the counterparty and if the floating rate is below the floor, we have a net payable to the counterparty. If the floating rate is between the floor and the cap, there is no payment due from either party. Collars are used to manage our interest rate exposure related to our bank credit facilities borrowings.

•

Call options: Occasionally we sell call options for a premium when we think it is more likely that the option will expire unexercised. The option allows the counterparty to terminate an open swap at a specific date.

•

Swaptions: Occasionally we sell an option to a counterparty for a premium which allows the counterparty to enter into a swap with us on a specific date.

The notional amount of debt hedged and the estimated fair value of our interest rate derivatives outstanding as of March 31, 2010 and December 31, 2009 are provided below.


	March 31, 2010					December 31, 2009
	Notional Amount		Fair Value			Notional Amount		Fair Value
	($ in millions)
Interest rate
Swaps	$	2,825	$	(90	)	$	2,925	$	(113	)
Collars		250		(4	)		250		(6	)
Call options		250		(1	)		250		(2	)
Swaptions		650		(2	)		500		(11	)

Totals	$	3,975	$	(97	)	$	3,925	$	(132	)

For interest rate derivative instruments designated as fair value hedges, 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 currently reported in the condensed consolidated statements of operations as unrealized (gains) losses within interest expense.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Realized gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense in the condensed consolidated statements of operations. The components of interest expense for the Current Quarter and the Prior Quarter are presented below.


	Three Months Ended March 31,
	2010			2009
	($ in millions)

Interest expense on senior notes	$	192		$	182
Interest expense on credit facilities		12			12
Capitalized interest		(161	)		(161	)
Realized (gains) losses on interest rate derivatives		(3	)		(7	)
Unrealized (gains) losses on interest rate derivatives		(27	)		(45	)
Amortization of loan discount and other		12			5

Total interest expense	$	25		$	(14	)

Our qualifying interest rate swaps are considered 100% effective and therefore no ineffectiveness was recorded for the periods presented above.

Gains and losses related to terminated qualifying interest rate derivative transactions will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next eleven years we will be recognizing $104 million in gains related to such trades.

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. The fair value of the cross currency swap is recorded on the condensed consolidated balance sheet as a liability of $3 million at March 31, 2010. The euro-denominated debt in notes payable has been adjusted to $811 million at March 31, 2010 using an exchange rate of $1.3526 to €1.00.

Additional Disclosures Regarding Derivative Instruments and Hedging Activities

In accordance with accounting guidance for derivatives and hedging, 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. Derivative instruments reflected as current in the condensed consolidated balance sheet represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the balance sheet date. The derivative settlement amounts are not due until the month in which the related underlying hedged transaction occurs. Cash settlements of our derivative arrangements are generally classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case, all cash settlements are classified as financing cash flows in the accompanying condensed consolidated statements of cash flows.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the fair value of each classification of derivative instrument as of March 31, 2010 and December 31, 2009, on a gross basis without regard to same-counterparty netting:


		Fair Value
	Balance Sheet Location	March 31, 2010			December 31, 2009
		($ in millions)
ASSET DERIVATIVES:
Derivatives designated as hedging instruments:
Commodity contracts	Short-term derivative instruments	$	769		$	417
Commodity contracts	Long-term derivative instruments		70			36
Foreign currency contracts	Long-term derivative instruments		—			43

Total			839			496


Derivatives not designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		569			318
Commodity contracts	Long-term derivative instruments		111			66

Total			680			384


LIABILITY DERIVATIVES:
Derivatives designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		(5	)		(1	)
Commodity contracts	Long-term derivative instruments		(13	)		—
Interest rate contracts	Long-term derivative instruments		(4	)		(11	)
Foreign currency contracts	Long-term derivative instruments		(3	)		—

Total			(25	)		(12	)


Derivatives not designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		(39	)		(42	)
Commodity contracts	Long-term derivative instruments		(763	)		(768	)
Interest rate contracts	Short-term derivative instruments		(11	)		(27	)
Interest rate contracts	Long-term derivative instruments		(82	)		(94	)

Total			(895	)		(931	)


Total derivative instruments		$	599		$	(63	)

A consolidated summary of the effect of derivative instruments on the condensed consolidated statements of operations for the Current Quarter and the Prior Quarter is provided below, separating fair value, cash flow and non-qualifying derivatives.

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


		Three Months Ended March 31,
Fair Value Derivatives	Location of Gain (Loss)	2010		2009

Interest rate contracts	Interest expense^(a)	$	8	$	8

(a)	Interest expense on the hedged items for the Current Quarter and the Prior Quarter was $10 million and $13 million respectively, which is included in interest expense on the condensed consolidated statements of operations.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 designated as cash flow derivatives ($ in millions):


		Three Months Ended March 31,
Cash Flow Derivatives	Location of Gain (Loss)	2010		2009

Gain (Loss) Recognized in AOCI (Effective Portion)
Commodity contracts	AOCI	$	405	$	682
Foreign currency contracts	AOCI		2		43

		$	407	$	725


Gain (Loss) Reclassified from AOCI (Effective Portion)
Commodity contracts	Natural gas and oil sales	$	140	$	296

		$	140	$	296

Gain (Loss) Recognized (Ineffective Portion and Amount Excluded from Effectiveness Testing)^(a)
Commodity contracts	Natural gas and oil sales	$	30	$	54

		$	30	$	54

(a)

In the Current Quarter and the Prior Quarter, the amount of gain (loss) recognized in net income (loss) represents ($6) million and $54 million related to the ineffective portion of our cash flow derivatives and $36 million and $0, respectively, related to the amount excluded from the assessment of hedge effectiveness.

The following table presents the gain (loss) recognized in net income (loss) for instruments not qualifying as cash flow or fair value derivatives ($ in millions):


		Three Months Ended March 31,
Non-Qualifying Derivatives	Location of Gain (Loss)	2010		2009

Commodity contracts	Natural gas and oil sales	$	544	$	269
Interest rate contracts	Interest expense		22		44

	Total	$	566	$	313

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 prices, interest rate volatility and exchange rate exposure. 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, 2010, our derivative instruments were spread among 14 counterparties. Additionally, our multi-counterparty secured hedging facility described previously requires our counterparties to secure their natural gas and oil hedging obligations in excess of defined thresholds. We now use this facility for all of our commodity hedging.

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 and the Prior Quarter we recognized $0 and $8 million, respectively, of bad debt expense related to potentially uncollectible receivables.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3.	Contingencies and Commitments

Litigation

On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the company and certain of its officers and directors along with certain underwriters of the company’s July 2008 common stock offering. Following the appointment of a lead plaintiff and counsel, the plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. The company has filed a motion to dismiss which has been fully briefed. A derivative action was also filed in the District Court of Oklahoma County, Oklahoma on March 10, 2009 against the company’s directors and certain of its officers alleging breaches of fiduciary duties relating to the disclosure matters alleged in the securities case. The derivative action is stayed pending resolution of the motion to dismiss in the class action.

On March 26, 2009, a shareholder filed a petition in the District Court of Oklahoma County, Oklahoma seeking to compel inspection of company books and records relating to compensation of the company’s CEO. On August 20, 2009, the court denied the inspection demand, dismissed the petition and entered judgment in favor of Chesapeake. The shareholder is appealing the court’s ruling in the Civil Court of Appeals of the State of Oklahoma.

Three derivative actions were filed in the District Court of Oklahoma County, Oklahoma on April 28, May 7, and May 20, 2009 against the company’s directors alleging breaches of fiduciary duties relating to compensation of the company’s CEO and alleged insider trading, among other things, and seeking unspecified damages, equitable relief and disgorgement. These three derivative actions were consolidated and a Consolidated Derivative Shareholder Petition was filed on June 23, 2009. Chesapeake is named as a nominal defendant. Chesapeake has filed a motion to dismiss which was heard on February 1, 2010. On February 28, 2010, the court ordered that plaintiffs’ claims be dismissed and granted plaintiffs leave to file an amended petition within 90 days. Plaintiffs chose not to amend and on April 9, 2010, at plaintiffs’ request, the court entered an order certifying that the February 28, 2010 dismissal was a final, appealable order. Plaintiffs are appealing the dismissal in the Supreme Court of the State of Oklahoma.

It is inherently difficult to predict the outcome of litigation, and we are currently unable to estimate the amount of any potential liabilities associated with the foregoing cases, which are all in preliminary stages.

Chesapeake is also involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, claims for underpayment of royalties, property damage claims and contract actions. With regard to the latter, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The company has satisfactorily resolved many of the suits but some remain pending and one case has been taken under advisement by the trial judge following trial in March 2010. The remaining leasehold acquisition cases are in various stages of discovery. The company believes that it has substantial defenses to the claims made in all these cases.

The company records an associated liability when a loss is probable and the amount is reasonably estimable. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to its business operations is likely to have a material adverse effect on the company’s consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 has an initial term of five years which is automatically extended for one additional year on each December 31 unless the company provides 30 days notice of non-extension. The agreement contains a cap on annual cash salary and bonus compensation at 2008 levels through 2013. 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, or in the event of his incapacity, death or retirement at or after age 55. The agreements with the chief operating officer, chief financial officer and other executive officers expire on September 30, 2012. The agreements with our COO, CFO and other executive vice presidents contain a cap on annual cash salary for the three-year term of the agreement. In addition, annual cash bonuses will not exceed the sum of the individual EVP’s cash bonus compensation for (a) the last half of 2008 and (b) the first half of 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 receive a lump sum payment equal to 26 weeks of cash salary 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. The agreements also provide for a 2008 incentive award payable in four equal annual installments, the first of which was paid on September 30, 2009. The payment of each installment of the award is subject to the individual’s continued employment on the date of payment, except that the unpaid installments of the award would be accelerated and paid in lump sum in the event of a change of control or a termination of employment without cause, a voluntary termination by the executive due to a material breach of contract by the company, or termination due to incapacity or death.

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, 2010.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 $88 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 is being 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 payment equal to the fair market rental value of the rigs as determined at the time of renewal. Commitments related to rig lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of March 31, 2010, the minimum aggregate undiscounted future rig lease payments were approximately $500 million.

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 $370 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 is being amortized to marketing, gathering and compression 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. Commitments related to compressor lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of March 31, 2010, the minimum aggregate undiscounted future compressor lease payments were approximately $328 million.

Transportation Contracts

Chesapeake has various firm pipeline transportation service agreements with expiration dates ranging from 2010 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 undiscounted amounts of such required demand payments as of March 31, 2010, were as follows ($ in millions):


2010	$	194
2011		302
2012		296
2013		277
2014		262
After 2014		1,378

Total	$	2,709

Drilling Contracts

Currently, Chesapeake has contracts with various drilling contractors to lease approximately 37 rigs with terms of six months to three years. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of March 31, 2010, the aggregate undiscounted drilling rig commitment was approximately $251 million.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Natural Gas and Oil Purchase Obligations

Our marketing 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 purchase any natural gas and oil associated with certain volumetric production payment transactions. The purchase commitments are based on market prices at the time of production, and the purchased natural gas and oil is resold.

Minimum Volume Commitment

Pursuant to our gas gathering agreement with our equity investee, CMP, we have committed to deliver specified minimum volumes of natural gas from our Barnett Shale production for each year through December 31, 2018 and for the six-month period ending June 30, 2019. At the end of the term or annually, Chesapeake will be invoiced for any shortfalls in such volume commitments at the rate specified in the agreement. Obligations are as follows:


		Mmcf
2010		335,498
2011		312,963
2012		324,908
2013		338,282
2014		351,265
After 2014		1,686,290

Total		3,349,206

In addition, Chesapeake has entered into commitments to deliver a total volume of 630 bcf from July 2010 through September 2021 to third party midstream companies.

4.	Net Income Per Share

Accounting guidance for Earnings Per Share (EPS), requires presentation of “basic” and “diluted” earnings per share on the face of the statements of operations for all entities with complex capital structures as well as a reconciliation of the numerator and denominator of the basic and diluted EPS computations.

For the Current Quarter, no securities were antidilutive in the calculation of diluted EPS. The following securities and associated adjustments to net income comprised of dividends and loss on conversions/exchanges were not included in the calculation of diluted EPS for the Prior Quarter, as the effect was antidilutive.


	Shares	Net Income Adjustments
	(in millions)	($ in millions)

Three Months Ended March 31, 2009:
Outstanding stock options	1	$	—
Unvested restricted stock	2	$	—

Common stock equivalent of our preferred stock outstanding:
4.50% cumulative convertible preferred stock	6	$	3
5.00% cumulative convertible preferred stock (series 2005B)	5	$	3
6.25% mandatory convertible preferred stock	1	$	1

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

A reconciliation of basic EPS and EPS assuming dilution for the Current Quarter is as follows:


	Income (Numerator)		Weighted Average Shares (Denominator)	Per Share Amount
	(in millions, except per share data)
Three Months Ended March 31, 2010:
Basic EPS income available to Chesapeake common stockholders	$	590	630	$	0.94

Effect of Dilutive Securities
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)		3	5
Common shares assumed issued for 4.50% cumulative convertible preferred stock		3	6
Employee stock options		—	1
Restricted stock		—	5


Diluted EPS income available to Chesapeake common stockholders and assumed conversions	$	596	647	$	0.92

For the Prior Quarter, both 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, were 597 million shares as a result of the net loss to common stockholders. The basic and diluted loss per common share was $9.63.

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, 2010 and 2009:


	2010	2009
	(in thousands)

Shares issued at January 1	648,549	607,953
Stock option exercises	133	100
Restricted stock issuances (net of forfeitures)	2,843	2,858
Convertible note exchanges	298	—
Preferred stock conversions/exchanges	—	183
Common stock issued for the purchase of leasehold and unproved properties	—	14,361

Shares issued at March 31	651,823	625,455

In the Current Quarter, we privately exchanged approximately $11 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 298,500 shares of our common stock valued at approximately $9 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 80% of the face value of the notes. Associated with these exchanges, we recorded a loss of $2 million. In connection with accounting guidance for debt with conversion and other options, we are required to account for the liability and equity components of our convertible debt instruments separately. Of the $11 million principal amount of convertible notes exchanged in the Current Quarter, $7 million was allocated to the debt component and the remaining $4 million was allocated to the equity conversion feature and was recorded as an adjustment to paid-in-capital. The difference between the debt component and value of the common stock exchanged in these transactions resulted in the $2 million loss. In addition, we expensed a nominal amount of deferred charges associated with the exchanges.

During the Prior Quarter, we issued 14,360,642 shares of common stock, valued at $240 million, for the purchase of proved and unproved properties and leasehold pursuant to an acquisition shelf registration statement.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Preferred Shares

The following is a summary of the changes in our preferred shares outstanding for the three months ended March 31, 2010 and 2009:


	4.50%	5.00% (2005B)	5.00% (2005)	6.25%	4.125%
	(in thousands)

Shares outstanding at January 1, 2010 and March 31, 2010	2,559	2,096	5	—	—


Shares outstanding at January 1, 2009	2,559	2,096	5	144	3
Conversion/exchange of preferred for common stock	—	—	—	—	(3	)

Shares outstanding at March 31, 2009	2,559	2,096	5	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, marketing, gathering and compression 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,
	2010		2009
	($ in millions)

Natural gas and oil properties	$	37	$	29
General and administrative expenses		22		19
Production expenses		10		9
Marketing, gathering and compression expenses		4		4
Service operations expense		2		2

Total	$	75	$	63

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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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
	(in thousands)

Unvested shares as of January 1, 2010	19,225		$ 31.89
Granted	4,093		$ 28.03
Vested	(2,577	)	$ 28.13
Forfeited	(293	)	$ 32.28

Unvested shares as of March 31, 2010	20,448		$ 31.58

The aggregate intrinsic value of restricted stock vested during the Current Quarter was approximately $66 million based on the stock price at the time of vesting.

As of March 31, 2010, there was $463 million of total unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted average period of 2.47 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 and the Prior Quarter we recognized a reduction in tax benefits related to restricted stock of $1 million and $8 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.

Stock Options. We granted stock options prior to 2006 under several stock compensation plans. Outstanding options expire ten years from the date of grant and vested over a four-year period. All stock options outstanding are fully vested and exercisable.

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 thousands)				($ in millions)

Outstanding at January 1, 2010	2,283		$ 8.36	2.75	$ 40
Exercised	(133	)	$ 5.66		$ —
Expired	—		$ —

Outstanding at March 31, 2010	2,150		$ 8.53	2.58	$ 32


Exercisable at March 31, 2010	2,150		$ 8.53	2.58	$ 32

(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.

During the Current Quarter and the Prior Quarter we recognized excess tax benefits related to stock options of $1 million and a nominal amount, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Debt

Our total debt consisted of the following at March 31, 2010 and December 31, 2009:


	March 31, 2010			December 31, 2009
	($ 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			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)		811			860
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)		752			763
Corporate revolving bank credit facility		1,835			1,892
Midstream revolving bank credit facility		37			—
Midstream joint venture revolving bank credit facility^(c)		—			44
Discount on senior notes⁽^d⁾		(894	)		(921	)
Interest rate derivatives⁽^e⁾		75			69

Total notes payable and long-term debt	$	12,204		$	12,295

(a)	The principal amount shown is based on the dollar/euro exchange rate of $1.3526 to €1.00 and $1.4332 to €1.00 as of March 31, 2010 and December 31, 2009, respectively. See Note 2 for information on our related foreign currency derivatives.

(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 2010, 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 2010 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	$	48.71	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$	64.36	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$	107.36	June 14, 2019

(c)	Effective January 1, 2010, our midstream joint venture, CMP, was no longer consolidated in accordance with the new authoritative guidance. See Note 1 for further details.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(d)	Included in this discount is $771 million at March 31, 2010 and $794 million at December 31, 2009 associated with the equity component of our contingent convertible senior notes.

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

Senior Notes

Our senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our senior note obligations are guaranteed by certain of our wholly owned subsidiaries. See Note 11 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. 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.

We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. These rates for 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 are 6.86%, 8.0% and 8.0%, respectively.

During the Current Quarter, holders of our 2.25% Contingent Convertible Senior Notes due 2038 exchanged approximately $11 million in aggregate principal amount for an aggregate of 298,500 shares of our common stock in privately negotiated exchanges.

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

Bank Credit Facilities

We utilize two bank credit facilities, described below, as sources of liquidity.


	Corporate Credit Facility^(a)	Midstream Credit Facility^(b)
	($ in millions)

Borrowing capacity	$ 3,500	$ 250

Maturity date	November 2012	September 2012

Facility structure	Senior secured revolving	Senior secured revolving

Amount outstanding as of March 31, 2010	$ 1,835	$ 37

Letters of credit outstanding as of March 31, 2010	$ 41	$ —

(a)	Borrowers are Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.

(b)	Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P.

Our credit facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates under our general corporate credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, none 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Corporate Credit Facility

Our $3.5 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the 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, 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% 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% 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%. 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 (excluding discount on senior notes) 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. As defined by the credit facility agreement, our indebtedness to total capitalization ratio was 0.41 to 1 and our indebtedness to EBITDA ratio was 3.05 to 1 at March 31, 2010. 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 of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $75 million.

The facility is fully and unconditionally guaranteed, on a joint and several basis, by Chesapeake and all of our other wholly owned restricted subsidiaries.

Midstream Credit Facility

Our $250 million midstream syndicated revolving bank credit facility is used to fund capital expenditures to build natural gas gathering and other systems for our drilling program and for general corporate purposes associated with our midstream operations. Borrowings under the midstream credit facility are secured by all of the assets of the wholly owned subsidiaries (the restricted subsidiaries) of Chesapeake Midstream Development, L.P. (CMD), itself a wholly owned subsidiary of Chesapeake, 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 LIBOR plus 1.00%, all of which are subject to a margin that varies from 2.00% to 2.75% per annum according to the most recent indebtedness to EBITDA ratio (as defined) or (ii) the LIBOR plus a margin that varies from 3.00% to 3.75% 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 of 0.50% per annum according to the most recent indebtedness to EBITDA ratio (as defined). Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The midstream credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMD and its restricted 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 3.00 to 1. As defined by the credit facility agreement, our indebtedness to EBITDA ratio was 0.49 to 1 and our EBITDA to interest expense coverage ratio was 6.75 to 1 at March 31, 2010. If CMD or its restricted 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 facility could be declared immediately due and payable. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness CMD and its restricted subsidiaries may have with an outstanding principal amount in excess of $15 million.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Other Financings

In 2009, we financed 113 real estate surface assets in the Barnett Shale area for approximately $145 million and entered into a 40-year master lease agreement under which we agreed to lease the sites for approximately $15 million to $27 million annually. This lease transaction was recorded as a financing lease and the cash received was recorded with an offsetting long-term liability on the condensed consolidated balance sheet. Chesapeake exercised its option to repurchase two of the assets in the Current Quarter. As of March 31, 2010, 111 assets were leased and the minimum aggregate undiscounted future lease payments were approximately $840 million.

In 2009, we financed our regional Barnett Shale headquarters building in Fort Worth, Texas for approximately $54 million with a five-year term loan which has a floating rate of prime plus 275 basis points. At our option, we may prepay in full without penalty beginning in year four. The payment obligation is guaranteed by Chesapeake.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7.	Segment Information

In accordance with accounting guidance for 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 marketing, gathering and compression of 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. Our drilling rig and trucking service operations are presented in “Other Operations” in the table below.

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 $1.006 billion and $671 million for the Current Quarter and the Prior Quarter. The following table presents selected financial information for Chesapeake’s operating segments.


	Exploration and Production			Midstream			Other Operations			Intercompany Eliminations			Consolidated Total
	($ in millions)
Three Months Ended March 31, 2010:
Revenues	$	1,898		$	1,850		$	88		$	(1,038	)	$	2,798
Intersegment revenues		—			(1,006	)		(32	)		1,038			—

Total revenues	$	1,898		$	844		$	56		$	—		$	2,798

Income (loss) before income taxes and cumulative effect of accounting change	$	1,177		$	33		$	(11	)	$	1		$	1,200


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	)


As of March 31, 2010:
Total assets	$	27,086		$	3,248		$	686		$	(732	)	$	30,288

As of December 31, 2009:
Total assets	$	25,637		$	4,323		$	660		$	(706	)	$	29,914

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8.	Natural Gas and Oil Properties

Joint Ventures

In January 2010, Chesapeake and Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP) (Total), closed a $2.25 billion Barnett Shale joint venture transaction, whereby Total acquired a 25% interest in our upstream Barnett Shale assets. Total paid us approximately $800 million in cash at closing and will pay a further $1.45 billion over time by funding 60% of our share of future drilling and completion expenditures. We expect this drilling carry to be fully utilized by year-end 2012.

In March 2010, as part of our joint venture agreement with Statoil, we sold approximately 50,000 net acres of leasehold in the Marcellus Shale for approximately $245 million.

During the Current Quarter, we received the benefit of approximately $281 million in drilling carries associated with the Barnett ($189 million) and Marcellus ($92 million) joint ventures.

Volumetric Production Payment

On February 5, 2010, we sold certain Chesapeake-operated long-lived producing assets in East Texas and the Texas Gulf Coast in our sixth volumetric production payment (VPP) transaction for proceeds of $180 million.

9.	Investments

At March 31, 2010, investments accounted for under the equity method totaled $971 million and investments accounted for under the cost method totaled $34 million. Following is a summary of our investments:


			Carrying Value
	Approximate % Owned	Accounting Method	March 31, 2010		December 31, 2009
			($ in millions)

Chesapeake Midstream Partners, L.L.C.	50%	Equity	$	614	$	—
Private oilfield services company	20%	Equity		235		239
Chaparral Energy, Inc.	32%	Equity		96		103
Gastar Exploration Ltd.	14%	Cost		33		32
Other	—	Cost/Equity		27		30

			$	1,005	$	404

Chesapeake Midstream Partners, L.L.C. On September 30, 2009, we formed a joint venture with Global Infrastructure Partners (GIP), a New York-based private equity fund, to own and operate natural gas midstream assets. As part of the transaction, Chesapeake contributed certain natural gas gathering and processing assets to a new entity, Chesapeake Midstream Partners, L.L.C. (CMP), and GIP purchased a 50% interest in CMP. The assets we contributed to the joint venture were substantially all of our midstream assets in the Barnett Shale and also the majority of our non-shale midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. During the fourth quarter of 2009, CMP was consolidated within our financial statements. Effective January 1, 2010, in accordance with new authoritative guidance for variable interest entities, we no longer consolidate our midstream joint venture, CMP. Because we have shared control with our 50% partner, GIP, our investment in CMP is now accounted for under the equity method. Adoption of this new guidance resulted in an after-tax charge of $142 million in the Current Quarter, recorded as a cumulative effect of accounting change. This charge reflects the difference between the carrying value of our initial investment in the joint venture, which was recorded at carryover basis as an entity under common control, and the fair value of our equity in the joint venture as of the formation date. The carrying value of our investment in CMP is less than our underlying equity in net assets by approximately $287 million as of March 31, 2010. This difference is being accreted over 20 years.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Private oilfield services company. The carrying value of our investment in a private oilfield services company is in excess of our underlying equity in net assets by approximately $163 million as of March 31, 2010. This excess amount is attributed to certain intangibles associated with the specialty services provided by the private oilfield services company and is being amortized over the estimated life of the intangibles.

Chaparral Energy, Inc. The carrying value of our investment in Chaparral is in excess of our underlying equity in net assets by approximately $39 million as of March 31, 2010. 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.

10.

Fair Value Measurements

Certain financial instruments are reported at fair value on the condensed consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined 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 a market valuation approach based on available inputs, which may or may not be observable in the market, to measure the fair values of its assets and liabilities.

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of March 31, 2010 ($ in millions):


	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
Financial Assets (Liabilities):
Cash equivalents	$	516		$	—		$	—		$	516
Investments		33			—			—			33
Other long-term assets		36			—			—			36
Long-term debt		—			—			(1,258	)		(1,258	)
Other long-term liabilities		(36	)		—			—			(36	)
Derivatives:
Commodity assets		—			1,377			144			1,521
Commodity liabilities		—			(18	)		(804	)		(822	)
Interest rate liabilities		—			—			(97	)		(97	)
Foreign currency liabilities		—			—			(3	)		(3	)

Total derivatives		—			1,359			(760	)		599


Total	$	549		$	1,359		$	(2,018	)	$	(110	)

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

Cash Equivalents. The fair value of cash equivalents is based on quoted market prices.

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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Derivatives. The fair values of our commodity derivatives are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas and oil forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by our counterparties for reasonableness. Since the commodity swaps do not have options and therefore no unobservable inputs, they are classified as Level 2. All other commodity derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. For interest rate and foreign currency derivatives, we use the fair value estimates provided by our respective counterparties, which are classified as Level 3 inputs. These values are reviewed internally for reasonableness using future interest rate curves and time to maturity. Derivatives are also subject to the risk that counterparties will be unable to meet their obligations. We factor in the non-performance risk in the valuation of our derivatives using current published credit default swaps rates. To date this has not had a material impact on the values of our derivatives.

Debt. The fair value of certain of our long-term debt is based on the face amount of that debt along with the value of the related interest rate swaps.

A summary of the changes in Chesapeake’s assets (liabilities) classified as Level 3 measurements during the Current Quarter and the Prior Quarter is presented below ($ in millions):


	Derivatives
	Commodity			Interest Rate			Foreign Currency			Debt

Balance of Level 3 as of January 1, 2010	$	(666	)	$	(132	)	$	43		$	(1,398	)
Total gains (losses) (realized/unrealized):
Included in earnings (realized)^(a)		103			(2	)		—			—
Included in earnings or change in net assets (unrealized)^(a)		(18	)		35			(48	)		40
Included in other comprehensive income (loss)		6			—			2			—
Purchases, issuances and settlements		(85	)		2			—			100	^(b)
Transfers in and out of Level 3		—			—			—			—

Balance of Level 3 as of March 31, 2010	$	(660	)	$	(97	)	$	(3	)	$	(1,258	)


Balance of Level 3 as of January 1, 2009	$	431		$	(63	)	$	(76	)	$	(1,470	)
Total gains (losses) (realized/unrealized):
Included in earnings (realized)^(a)		(169	)		(7	)		—			—
Included in earnings or change in net assets (unrealized)^(a)		103			44			(39	)		10
Included in other comprehensive income (loss)		130			—			42			—
Purchases, issuances and settlements		74			(36	)		—			—
Transfers in and out of Level 3		—			—			—			—

Balance of Level 3 as of March 31, 2009	$	569		$	(62	)	$	(73	)	$	(1,460	)

(a)	All amounts related to commodity derivatives are included in Natural Gas and Oil Sales, and for interest rate and foreign currency derivatives and debt, the amounts are included in Interest Expense.

(b)	Amount represents a reduction in debt recorded at fair value as a result of terminated interest rate swaps in the Current Quarter.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of financial instruments comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. We estimate the fair value of our long-term debt and our convertible preferred stock primarily using quoted market prices. Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.


	March 31, 2010				December 31, 2009
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	($ in millions)

Long-term debt	$	12,129	$	12,504	$	12,226	$	12,824
Convertible preferred stock	$	466	$	391	$	466	$	401

11.

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. Our obligations under our outstanding senior notes and contingent convertible notes listed in Note 6 are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly owned subsidiaries on a senior unsecured basis. Our midstream subsidiary, CMD, is not a guarantor and is subject to covenants in the midstream revolving credit facility referred to in Note 6 that restricts it from paying dividends or distributions or making loans to Chesapeake.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

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, 2010 and December 31, 2009 and for the three months ended March 31, 2010 and 2009. 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, 2010

($ in millions)


	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	516	$	—		$	—		$	516
Other		8			2,694		134			(17	)		2,819

Total Current Assets		8			3,210		134			(17	)		3,335


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full-cost accounting		—			20,846		469			—			21,315
Other property and equipment, net		—			3,016		1,324			—			4,340

Total Property and Equipment		—			23,862		1,793			—			25,655


Other assets		152			526		620			—			1,298
Investments in subsidiaries and intercompany advance		658			4		—			(662	)		—

TOTAL ASSETS	$	818		$	27,602	$	2,547		$	(679	)	$	30,288


CURRENT LIABILITIES:
Current liabilities	$	184		$	2,799	$	156		$	(16	)	$	3,123
Intercompany payable (receivable) from parent		(22,329	)		19,967		2,394			(32	)		—

Total Current Liabilities		(22,145	)		22,766		2,550			(48	)		3,123


LONG-TERM LIABILITIES:
Long-term debt, net		10,332			1,835		37			—			12,204
Deferred income tax liabilities		264			1,044		(44	)		31			1,295
Other liabilities		151			1,299		—			—			1,450

Total Long-Term Liabilities		10,747			4,178		(7	)		31			14,949


EQUITY:
Chesapeake stockholders’ equity		12,216			658		4			(662	)		12,216
Noncontrolling interest		—			—		—			—			—

Total Equity		12,216			658		4			(662	)		12,216


TOTAL LIABILITIES AND EQUITY	$	818		$	27,602	$	2,547		$	(679	)	$	30,288

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2009

($ in millions)


	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	293	$	14	$	—		$	307
Other		27			2,031		166		(85	)		2,139

Total Current Assets		27			2,324		180		(85	)		2,446


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full-cost accounting		—			20,781		11		—			20,792
Other property and equipment, net		—			2,903		3,015		—			5,918

Total Property and Equipment		—			23,684		3,026		—			26,710


Other assets		197			540		21		—			758
Investments in subsidiaries and intercompany advance		3,029			222		—		(3,251	)		—

TOTAL ASSETS	$	3,253		$	26,770	$	3,227	$	(3,336	)	$	29,914


CURRENT LIABILITIES:
Current liabilities	$	277		$	2,261	$	235	$	(85	)	$	2,688
Intercompany payable (receivable) from parent		(19,388	)		17,501		1,800		87			—

Total Current Liabilities		(19,111	)		19,762		2,035		2			2,688


LONG-TERM LIABILITIES:
Long-term debt, net		10,359			1,892		44		—			12,295
Deferred income tax liabilities		393			727		26		(87	)		1,059
Other liabilities		168			1,360		3		—			1,531

Total Long-Term Liabilities		10,920			3,979		73		(87	)		14,885


EQUITY:
Chesapeake stockholders’ equity		11,444			3,029		222		(3,251	)		11,444
Noncontrolling interest		—			—		897		—			897

Total Equity		11,444			3,029		1,119		(3,251	)		12,341


TOTAL LIABILITIES AND EQUITY	$	3,253		$	26,770	$	3,227	$	(3,336	)	$	29,914

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2010

($ in millions)


	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Natural gas and oil sales	$	—		$	1,898		$	—		$	—		$	1,898
Marketing, gathering and compression sales		—			813			48			(17	)		844
Service operations revenue		—			56			—			—			56

Total Revenues		—			2,767			48			(17	)		2,798


OPERATING COSTS:
Production expenses		—			207			—			—			207
Production taxes		—			48			—			—			48
General and administrative expenses		—			104			5			—			109
Marketing, gathering and compression expenses		—			793			22			—			815
Service operations expense		—			49			—			—			49
Natural gas and oil depreciation, depletion and amortization		—			308			—			—			308
Depreciation and amortization of other assets		—			40			10			—			50

Total Operating Costs		—			1,549			37			—			1,586


INCOME (LOSS) FROM OPERATIONS		—			1,218			11			(17	)		1,212


OTHER INCOME (EXPENSE):
Other income (expense)		192			(6	)		21			(192	)		15
Interest expense (income)		(159	)		(57	)		(1	)		192			(25	)
Loss on exchanges of Chesapeake debt		(2	)		—			—			—			(2	)
Equity in net earnings of subsidiary		577			(262	)		—			(315	)		—

Total Other Income (Expense)		608			(325	)		20			(315	)		(12	)

INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		608			893			31			(332	)		1,200
INCOME TAX EXPENSE (BENEFIT)		12			445			12			(7	)		462

NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX		596			448			19			(325	)		738
Cumulative effect of accounting change, net of income taxes		—			31			(173	)		—			(142	)

NET INCOME (LOSS)		596			479			(154	)		(325	)		596
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	596		$	479		$	(154	)	$	(325	)	$	596

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2009

($ in millions)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Natural gas and oil sales	$	—		$	1,397		$	—		$	—		$	1,397
Marketing, gathering and compression 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		—			86			4			—			90
Marketing, gathering and compression 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	)		38			19			1			57
Impairment of natural gas and oil properties and other assets		—			9,626			4			—			9,630

Total Operating Costs		(1	)		10,967			75			7			11,048

INCOME (LOSS) FROM OPERATIONS		1			(9,035	)		35			(54	)		(9,053	)


OTHER INCOME (EXPENSE):
Other income (expense)		162			7			1			(162	)		8
Interest expense		(127	)		(19	)		(2	)		162			14
Impairment of investments		—			(153	)		—			—			(153	)
Equity in net earnings of subsidiary		(5,763	)		(14	)		—			5,777			—

Total Other Income (Expense)		(5,728	)		(179	)		(1	)		5,777			(131	)


INCOME (LOSS) BEFORE INCOME TAXES		(5,727	)		(9,214	)		34			5,723			(9,184	)
INCOME TAX EXPENSE (BENEFIT)		13			(3,450	)		13			(20	)		(3,444	)

NET INCOME (LOSS)		(5,740	)		(5,764	)		21			5,743			(5,740	)
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(5,740	)	$	(5,764	)	$	21		$	5,743		$	(5,740	)

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2010

($ in millions)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	1,121		$	62		$	—	$	1,183


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to natural gas and oil properties		—			(2,006	)		(44	)		—		(2,050	)
Proceeds from divestitures of natural gas and oil properties		—			1,224			—			—		1,224
Additions to other property and equipment		—			(131	)		(148	)		—		(279	)
Other investing activities		—			39			52			—		91

Cash used in investing activities		—			(874	)		(140	)		—		(1,014	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			2,817			107			—		2,924
Payments on credit facilities borrowings		—			(2,874	)		(70	)		—		(2,944	)
Other financing activities		(78	)		138			—			—		60
Intercompany advances, net		78			(105	)		27			—		—

Cash provided by (used in) financing activities		—			(24	)		64			—		40


Net increase (decrease) in cash and cash equivalents		—			223			(14	)		—		209
Cash and cash equivalents, beginning of period		—			293			14			—		307

Cash and cash equivalents, end of period	$	—		$	516		$	—		$	—	$	516

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2009

($ in millions)


	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	1,140		$	121		$	—	$	1,261


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to natural gas and oil properties		—			(1,766	)		6			—		(1,760	)
Proceeds from divestitures of natural gas and oil properties		—			—			—			—		—
Additions to other property and equipment		—			(276	)		(391	)		—		(667	)
Other investing activities		—			59			1			—		60

Cash used in investing activities		—			(1,983	)		(384	)		—		(2,367	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			1,301			274			—		1,575
Payments on credit facilities borrowings		—			(2,550	)		(570	)		—		(3,120	)
Proceeds from issuance of senior notes, net of offering costs		1,346			—			—			—		1,346
Other financing activities		(72	)		(289	)		—			—		(361	)
Intercompany advances, net		(1,274	)		715			559			—		—

Cash provided by (used in) financing activities		—			(823	)		263			—		(560	)

Net increase (decrease) in cash and cash equivalents		—			(1,666	)		—			—		(1,666	)
Cash and cash equivalents, beginning of period		—			1,749			—			—		1,749

Cash and cash equivalents, end of period	$	—		$	83		$	—		$	—	$	83

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

12.

Recently Issued and Proposed Accounting Standards

The Financial Accounting Standards Board (FASB) recently issued the following standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.

In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance in the Current Quarter.

The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted this guidance effective first quarter 2010. Adoption had no impact on our financial position or results of operations. Required disclosures for the reconciliation of purchases, sales, issuance and settlements of financial instruments valued with a Level 3 method are effective beginning on January 1, 2011 and we do not expect the implementation to have a material impact on our financial position or results of operations. See Note 10 for discussion regarding fair value measurements.

13.

Subsequent Events

On May 3, 2010, we converted all 5,000 shares of our outstanding 5.00% Cumulative Convertible Preferred Stock (Series 2005) into 20,774 shares of common stock pursuant to the company’s mandatory conversion rights.

In September 2009, we formed a joint venture with Global Infrastructure Partners (GIP), a New York-based private equity fund, to own and operate natural gas midstream assets. As part of the transaction, we contributed certain natural gas gathering and processing assets into a new entity, Chesapeake Midstream Partners, L.L.C. (CMP), and GIP purchased a 50% interest in CMP for $588 million in cash. In May 2010, we received a $75 million cash distribution from CMP. Chesapeake Midstream Partners, L.P., which was formed by Chesapeake and GIP to own, operate, develop and acquire midstream assets, has filed a registration statement on Form S-1 with the SEC relating to a proposed underwritten initial public offering of common units, representing limited partnership interests in the partnership. Upon the closing of the offering, Chesapeake and GIP will contribute CMP’s interests to the partnership and the partnership will continue CMP’s business.

Subsequent to March 31, 2010, we entered into an additional transportation service agreement extending through 2026 which will add a total of $1.8 billion to our existing commitments disclosed in Note 3.

On May 10, 2010, we announced a private placement of $600 million of 5.75% cumulative non-voting convertible preferred stock with two investors. The closing of the transaction is scheduled for May 17, 2010 and is subject to customary conditions. We also granted a 30-day option to the two purchasers to place up to $500 million in additional preferred stock of the same series with investors in Asia. We intend to use the net proceeds from the offerings to repay senior indebtedness.

ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

The following table sets forth certain information regarding the production volumes, natural gas and oil sales, average sales prices received, other operating income and expenses for the three months ended March 31, 2010 (the “Current Quarter”) and the three months ended March 31, 2009 (the “Prior Quarter”):


	Three Months Ended
	March 31,
	2010			2009
Net Production:
Natural gas (bcf)		209.6			195.7
Oil (mmbbl)		3.9			2.9
Natural gas equivalent (bcfe)		232.8			213.0

Natural Gas and Oil Sales ($ in millions):
Natural gas sales	$	942		$	674
Natural gas derivatives – realized gains (losses)		379			510
Natural gas derivatives – unrealized gains (losses)		415			68

Total natural gas sales		1,736			1,252


Oil sales		242			104
Oil derivatives – realized gains (losses)		20			9
Oil derivatives – unrealized gains (losses)		(100	)		32

Total oil sales		162			145


Total natural gas and oil sales	$	1,898		$	1,397


Average Sales Price (excluding all gains (losses) on derivatives):
Natural gas ($ per mcf)	$	4.50		$	3.44
Oil ($ per bbl)	$	62.59		$	35.99
Natural gas equivalent ($ per mcfe)	$	5.09		$	3.65

Average Sales Price (excluding unrealized gains (losses) on derivatives):
Natural gas ($ per mcf)	$	6.31		$	6.05
Oil ($ per bbl)	$	67.70		$	39.12
Natural gas equivalent ($ per mcfe)	$	6.80		$	6.09

Other Operating Income^(a) ($ in millions):
Marketing, gathering and compression	$	29		$	29
Service operations	$	7		$	6

Other Operating Income^(a) ($ per mcfe):
Marketing, gathering and compression	$	0.12		$	0.14
Service operations	$	0.03		$	0.03

Expenses ($ per mcfe):
Production expenses	$	0.89		$	1.12
Production taxes	$	0.21		$	0.11
General and administrative expenses	$	0.47		$	0.42
Natural gas and oil depreciation, depletion and amortization	$	1.32		$	2.10
Depreciation and amortization of other assets	$	0.21		$	0.27
Interest expense^(b)	$	0.22		$	0.14

Interest Expense ($ in millions):
Interest expense	$	55		$	38
Interest rate derivatives – realized (gains) losses		(3	)		(7	)
Interest rate derivatives – unrealized (gains) losses		(27	)		(45	)

Total interest expense	$	25		$	(14	)


Net Wells Drilled		243			264
Net Producing Wells as of the End of the Period		22,669			22,691

(a)	Includes revenue and operating costs and excludes depreciation and amortization of other assets.

(b)	Includes the effects of realized (gains) losses from interest rate derivatives, but excludes the effects of unrealized (gains) losses and is net of amounts capitalized.

We are one of the largest producers of natural gas in the United States. We own interests in approximately 44,900 producing natural gas and oil wells that are currently producing approximately 2.7 bcfe per day, 90% of which is natural gas. Our strategy is focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S., primarily in our “Big 6” shale plays: the Barnett Shale in the Fort Worth Basin of north-central Texas, the Haynesville and Bossier Shales in the Ark-La-Tex area of northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas, the Marcellus Shale in the northern Appalachian Basin of West Virginia, Pennsylvania and New York and the Eagle Ford Shale in South Texas. We also have substantial operations in the Granite Wash Plays of western Oklahoma and the Texas Panhandle regions as well as various other plays, both conventional and unconventional, in the Mid-Continent, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the United States. We have vertically integrated our operations and own substantial midstream, compression, drilling and oilfield service assets.

We have recently announced that we are extending our strategy to apply the horizontal drilling expertise we have gained in our natural gas plays to unconventional oil reservoirs. We expect to begin increasing our production of oil and natural gas liquids in 2010 in new developing unconventional oil plays, particularly in the Granite Wash and Eagle Ford Shale. To date, the company has built leasehold positions and established production in 12 liquids-rich plays on approximately 1.9 million net leasehold acres.

Chesapeake began 2010 with estimated proved reserves of 14.254 tcfe and ended the Current Quarter with 14.765 tcfe, an increase of 511 bcfe, or 4%. During the Current Quarter, we replaced 233 bcfe of production with an internally estimated 744 bcfe of new proved reserves, for a reserve replacement rate of 320%. The Current Quarter’s reserve movement included 1.230 tcfe of extensions, 328 bcfe of positive performance revisions and 70 bcfe of positive revisions resulting from an increase in the twelve-month trailing average natural gas and oil prices between December 31, 2009 and March 31, 2010. During the Current Quarter, we acquired 8 bcfe of estimated proved reserves and divested 892 bcfe of estimated proved reserves.

During the Current Quarter, Chesapeake continued the industry’s most active drilling program, drilling 324 gross operated wells (209 net wells with an average working interest of 65%) and participating in another 255 gross wells operated by other companies (34 net wells with an average working interest of 13%). The company’s drilling success rate was 99% for company-operated wells and 97% for non-operated wells. Also during the Current Quarter, we invested $918 million in operated wells (using an average of 118 operated rigs) and $127 million in non-operated wells (using an average of 94 non-operated rigs) for total drilling, completing and equipping costs of $1.045 billion (net of carries).

Our total Current Quarter production was 232.8 bcfe, comprised of 209.6 bcf (90% on a natural gas equivalent basis) and 3.9 mmbbls of oil and natural gas liquids (10% on a natural gas equivalent basis). Daily production for the Current Quarter averaged 2.586 bcfe, an increase of 219 mmcfe, or 9%, over the 2.367 bcfe produced per day in the Prior Quarter. Adjusted for Current Quarter sales of a 25% joint venture interest in the company’s Barnett Shale assets and its sixth volumetric production payment transaction (production averaging approximately 155 mmcfe and 14 mmcfe per day, respectively, during the Current Quarter), our year-over-year production growth rate would have been 19%.

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (13.8 million net acres) and 3-D seismic (24.1 million acres) in the U.S. and the largest inventory of Big 6 shale play leasehold (3.1 million net acres). We are currently using 122 operated drilling rigs to further develop our inventory of approximately 38,000 net drillsites, which represents more than a 10-year inventory of drilling projects. Based on the level of drilling activity we have planned, we anticipate reporting full-year production growth of approximately 8-10% in 2010 and 16-18% in 2011.

Recent Developments

Pending Private Placements of Preferred Stock

As more fully described in Part II, Item 5, on May 7, 2010, we entered into securities purchase agreements with two investors in Asia pursuant to which they agreed to purchase from us in a private placement 600,000 shares of our 5.75% cumulative non-voting convertible preferred stock for an aggregate purchase price of $600 million (representing a purchase price of $1,000 per share of preferred stock). The closing of this private placement is scheduled for May 17, 2010 and is subject to customary closing conditions. We also entered into a letter agreement with such investors pursuant to which we have granted them an option valid through June 9, 2010 to acquire from us and place up to 500,000 additional shares of the same series of preferred stock, which will be offered for sale to certain non-U.S. institutional investors at a purchase price of $1,000 per share.

New Strategic and Financial Plan

On May 10, 2010, we announced a strategic and financial plan designed to increase shareholder value, reduce debt and ultimately achieve an investment grade rating for our debt securities. We are in various stages of implementing our strategic and financial plan as outlined below.

We are investigating the possible sale of up to a 20% equity interest in our subsidiary, Chesapeake Appalachia L.L.C., which includes our Marcellus Shale operations, to private and/or public investors.

We are also exploring various joint venture opportunities to enable us to recover our leasehold expenditures to date and to fund accelerated drilling in our 12 unconventional liquids-rich plays. We will seek to enter into a joint venture on our Eagle Ford Shale play that currently includes approximately 400,000 net acres by the third quarter of 2010, and we are considering entering into joint ventures on certain of our other unconventional liquids-rich plays.

We plan to also pursue additional monetizations of our midstream assets from our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., that primarily owns gas gathering operations in the Haynesville, Fayetteville, Marcellus and Eagle Ford Shales. Some of the monetizations may be completed with a subsidiary of our 50/50 owned midstream joint venture entity, which acquired our gathering assets in the Barnett Shale and certain of our gas gathering assets in the Mid-Continent in 2009.

Finally, we are targeting repayment of up to $3.5 billion of senior indebtedness. We will repay $600 million of certain outstanding senior notes with the proceeds from the private placements of preferred stock referred to above. We also plan to seek to repay up to an additional $2.9 billion of senior notes over the next 24 months using proceeds from the $500 million of additional preferred stock referred to above, the sale of the equity interest in Chesapeake Appalachia referred to above, the potential joint ventures referred to above and/or other asset monetizations.

Each of the foregoing proposed sales, joint ventures and other transactions is subject to changes in market conditions and other factors, and there can be no assurance that we will complete any or all of them on a timely basis or at all. Please read “—Forward Looking Statements.”

Business Strategy

Our exploration, development and acquisition activities require us to make substantial capital expenditures. Our current budgeted drilling and completion capital expenditures, net of drilling carries, are $4.2 billion to $4.5 billion in 2010 and $4.3 billion to $4.6 billion in 2011. While we believe that our anticipated internally generated cash flow, asset monetizations, cash resources and other sources of liquidity will allow us to fully fund our 2010 operating and capital expenditure requirements, further deterioration of the economy and other factors could require us to curtail our spending.

Due to recent low natural gas prices and positive results in the company’s liquids-rich plays, we have revised our 2010 and 2011 drilling plans to redirect capital from our natural gas plays to our liquids-rich plays. In total, the company has reduced planned capital expenditures on natural gas-focused plays by approximately $300 million and $400 million in 2010 and 2011, reductions of 12% and 17%, respectively. We plan to redirect this capital to accelerate drilling activity in our increasingly promising liquids-rich plays, particularly in the Granite Wash, Eagle Ford Shale, Anadarko Basin, Permian Basin and Rocky Mountain unconventional plays. We have acquired approximately 1.9 million net acres of leasehold in these plays, and our goal is to achieve a 50-operated-rig drilling program within the next six to 12 months in these plays, up from our current 21 operated rigs. We are exploring various alternatives to enable us to recover our leasehold expenditures and to fund accelerated drilling in these plays.

In January 2010, Chesapeake completed its fourth joint venture in its Big 6 shale plays. In this joint venture transaction in the Barnett Shale, Total E&P USA, Inc., a wholly owned subsidiary of Total S.A., paid $800 million in cash at closing and agreed to pay $1.45 billion in drilling carries. The following table provides information about our remaining joint venture drilling carries as of March 31, 2010 ($ in millions):


Shale Play	Joint Venture Partner	Joint Venture Date	Drilling Carries Remaining

Marcellus	Statoil	November 2008	$	1,871
Barnett	Total E&P USA, Inc.	January 2010		1,261

			$	3,132

The drilling carries in these joint ventures create a significant cost advantage for us that will allow us to continue to lower finding costs. During the Current Quarter and Prior Quarter, we had the benefit of approximately $281 million and $269 million, respectively, of joint venture drilling carries. Our exploration and development costs for the remainder of 2010 and in 2011 and 2012 will continue to be partially offset by the use of the balance of the drilling carries associated with our joint ventures in the Barnett and Marcellus Shales.

The joint ventures in our Big 6 shale plays and our 50/50 midstream joint venture with GIP are a complementary part of our business strategy to maximize the value of our leasehold inventory and related assets and minimize our investment risk. There are other new assets we are identifying and developing which may create additional joint venture opportunities.

In February 2010, the company completed its sixth volumetric production payment (VPP) for proceeds of $180 million. In March 2010, in accordance with the joint venture arrangement with Statoil, Statoil elected to purchase approximately 50,000 net acres of leasehold in the Marcellus Shale for approximately $245 million.

Subsequent to the Current Quarter, we have sold or agreed to sell leasehold and producing assets for combined proceeds of approximately $750 million in three asset sale transactions and a VPP. The asset sale transactions include $400 million of non-core producing assets in the Permian Basin and the Appalachian Basin with combined production of approximately 30 mmcfe per day and proved reserves of approximately 180 bcfe as well as certain non-core East Texas Haynesville Shale leasehold. In addition, we anticipate completing our seventh VPP transaction on certain Chesapeake-operated long-lived oil and liquids-rich producing assets in the Permian Basin for proceeds of approximately $350 million. The assets in the pending seventh VPP include proved reserves of approximately 40 bcfe and current net production of approximately 6 mmcf and 2,200 bbls per day.

Liquidity and Capital Resources

Sources and Uses of Funds

Cash flow from operations is a significant source of liquidity used to fund operating expenses and capital expenditures. Cash provided by operating activities was $1.183 billion in the Current Quarter compared to $1.261 billion in the Prior Quarter. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding non-cash items such as impairments of assets, depreciation, depletion and amortization, deferred income taxes and unrealized gains and (losses) on derivatives. See the discussion below under Results of Operations.

Changes in market prices for natural gas and oil directly impact the level of our cash flow from operations. To mitigate the risk of declines in natural gas and oil prices and to provide more predictable future cash flow from operations, we currently have hedged through swaps and collars 57% of our expected remaining natural gas and oil production in 2010 at average prices of $8.21 per mcfe. Our natural gas and oil hedges as of March 31, 2010 are detailed in Item 3 of Part I of this report. Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and oil supply and demand trends, we may increase or decrease our current hedging positions.

Our $3.5 billion corporate revolving bank credit facility, our $250 million midstream revolving bank credit facility and cash and cash equivalents are other sources of liquidity. At May 5, 2010, there was $1.689 billion of borrowing capacity available under the corporate credit facility and $213 million of borrowing capacity under the midstream credit facility. We use the facilities and cash on hand to fund daily operating activities and capital expenditures as needed. We borrowed $2.924 billion and repaid $2.944 billion in the Current Quarter, and we borrowed $1.575 billion and repaid $3.120 billion in the Prior Quarter from our revolving credit facilities. A substantial portion of our natural gas and oil properties is currently unencumbered and therefore available to be pledged as additional collateral under our corporate revolving bank credit facility if needed based on our periodic borrowing base and collateral redeterminations. Accordingly, we believe our borrowing capacity under this facility will not be reduced as a result of any such future periodic redeterminations. Our midstream facility is secured by substantially all of our wholly owned midstream assets and is not subject to periodic borrowing base redeterminations.

On February 2, 2009, we completed a public offering of $1.0 billion aggregate principal amount of senior notes due 2015, which have a stated coupon rate of 9.5% per annum. The senior notes were priced at 95.071% of par to yield 10.625%. On February 17, 2009, we completed an offering of an additional $425 million aggregate principal amount of the 9.5% Senior Notes due 2015. The additional senior notes were priced at 97.75% of par plus accrued interest from February 2 to February 17, 2009 to yield 10.0% per annum. Net proceeds of $1.346 billion from these two offerings were used to repay outstanding indebtedness under our corporate revolving bank credit facility, which we reborrow from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes. There were no other debt or equity issuances in the Prior Quarter and none in the Current Quarter.

Our primary use of funds is for capital expenditures related to exploration, development and acquisition of natural gas and oil properties. We refer you to the table under Investing Activities below, which sets forth the components of our natural gas and oil investing activities and our other investing activities for the Current Quarter and the Prior Quarter. We retain a significant degree of control over the timing of our capital expenditures which permits us to defer or accelerate certain capital expenditures if necessary to address any potential liquidity issues. In addition, changes in drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary.

We paid dividends on our common stock of $47 million and $44 million in the Current Quarter and the Prior Quarter, respectively. We paid dividends on our preferred stock of $6 million in both the Current Quarter and the Prior Quarter.

In the Current Quarter and Prior Quarter, we received $94 million and $1 million, respectively, for settlements of derivatives which were classified as financing derivatives.

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 prices 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. During the more than 15 years we have engaged in hedging activities, we have experienced a counterparty default only once (Lehman Brothers in September 2008), and the total loss recorded in that instance was immaterial. On March 31, 2010, our commodity and interest rate derivative instruments were spread among 14 counterparties. Additionally, our multi-counterparty secured hedging facility requires our counterparties to secure their natural gas and oil hedging obligations in excess of defined thresholds. We now use this facility for all of our commodity hedging.

Our accounts receivable are primarily from purchasers of natural gas and oil ($751 million at March 31, 2010) and exploration and production companies which own interests in properties we operate ($523 million at March 31, 2010). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During the Current Quarter and the Prior Quarter, we recognized $0 and $8 million of bad debt expense related to potentially uncollectible receivables.

Investing Activities

Cash used in investing activities declined significantly in the Current Quarter, primarily because of the offsetting proceeds received in the Current Quarter in connection with the closing of the Total joint venture ($800 million) and our sixth VPP ($180 million). Cash used in investing activities decreased to $1.014 billion during the Current Quarter, compared to $2.367 billion during the Prior Quarter. Our natural gas and oil investing activities in the Current Quarter included $867 million of expenditures for leasehold and unproved property acquisitions, an increase of $610 million over Prior Quarter spending, reflecting our efforts to increase our oil and liquids-rich leasehold. Expenditures for exploration and development were $979 million in the Current Quarter, compared to $1.272 billion in the Prior Quarter, a decrease of $293 million or 23%, reflecting our reduced level of drilling activity in response to low natural gas prices over the past year, as well as the receipt of more drilling carries in the Current Quarter. In other investing activities, additions to other property and equipment declined to $279 million in the Current Quarter from $667 million in the Prior Quarter as a result of a reduction in the building of gathering systems. The following table shows our cash used in (provided by) investing activities during these periods:


	Three Months Ended March 31,
	2010			2009
	($ in millions)
Natural Gas and Oil Investing Activities:
Acquisitions of natural gas and oil proved properties	$	8		$	3
Acquisition of leasehold and unproved properties		867			257
Exploration and development of natural gas and oil properties		979			1,272
Geological and geophysical costs^(a)		41			74
Interest capitalized on unproved properties		155			154
Proceeds from sales of volumetric production payments		(180	)		—
Proceeds from divestitures of proved and unproved properties and leasehold		(1,044	)		—

Total natural gas and oil investing activities		826			1,760


Other Investing Activities:
Additions to other property and equipment		279			667
Proceeds from sales of compressors		—			(68	)
Deposits for divestitures		(21	)		—
Additions to investments		6			8
Proceeds from sales of other assets		(56	)		—
Other		(20	)		—

Total other investing activities		188			607


Total cash used in investing activities	$	1,014		$	2,367

(a)	Including related capitalized interest.

In connection with a reduced budget for acquisitions, we used 14,360,642 shares of our common stock to acquire leasehold and mineral interests in the Prior Quarter, pursuant to an acquisition shelf registration statement.

Bank Credit Facilities

We utilize two bank credit facilities, described below, as sources of liquidity.


	Corporate Credit Facility^(a)		Midstream Credit Facility^(b)
	($ in millions)

Borrowing capacity	$	3,500	$	250

Maturity date		November 2012		September 2012

Facility structure		Senior secured revolving		Senior secured revolving

Amount outstanding as of March 31, 2010	$	1,835	$	37

Letters of credit outstanding as of March 31, 2010	$	41	$	—

(a)	Borrowers are Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.

(b)	Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P.

Corporate Credit Facility

Our $3.5 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the 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, 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% 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% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to a commitment fee of 0.50%. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The facility is fully and unconditionally guaranteed, on a joint and several basis, by Chesapeake and all of our other wholly owned restricted subsidiaries.

Midstream Credit Facility

The midstream credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMD and its restricted 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 3.00 to 1. As defined by the credit facility agreement, our indebtedness to EBITDA ratio was 0.49 to 1 and our EBITDA to interest expense coverage ratio was 6.75 to 1 at March 31, 2010. If CMD or its restricted 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 facility could be declared immediately due and payable. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness of CMD and its restricted subsidiaries may have with an outstanding principal amount in excess of $15 million.

Hedging Facility

We have a multi-counterparty hedge facility with 13 counterparties that have committed to provide approximately 3.9 tcfe of trading capacity and an aggregate mark-to-market capacity of $10.4 billion under the terms of the facility. As of March 31, 2010, we had hedged a total of 1.9 tcfe under the facility. The multi-counterparty facility allows us to enter into cash-settled natural gas and oil price and basis hedges with the counterparties. Our obligations under the multi-counterparty facility are secured by natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times, and guarantees by our subsidiaries that also guarantee our corporate revolving bank credit facility and indentures. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. Treasury instruments to the extent that any mark-to-market amounts they owe to Chesapeake exceed defined thresholds. The maximum volume-based trading capacity under the facility is governed by the expected production of the pledged reserve collateral, and volume-based trading limits are applied separately to price and basis hedges. In addition, there are volume-based sub-limits for natural gas and oil hedges. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain collateral coverage and other requirements are met. The facility does not have a maturity date. Counterparties to the agreement have the right to cease trading with the company on a prospective basis as long as obligations associated with any existing trades in the facility continue to be satisfied in accordance with the terms of the agreement.

Senior Note Obligations

In addition to outstanding borrowings under our revolving bank credit facilities discussed above, as of March 31, 2010, senior notes represented approximately $10.3 billion of our total debt and consisted of the following ($ in millions):


7.5% senior notes due 2013	$	364
7.625% senior notes due 2013		500
7.0% senior notes due 2014		300
7.5% senior notes due 2014		300
6.375% senior notes due 2015		600
9.5% senior notes due 2015		1,425
6.625% senior notes due 2016		600
6.875% senior notes due 2016		670
6.25% euro-denominated senior notes due 2017^(a)		811
6.5% senior notes due 2017		1,100
6.25% senior notes due 2018		600
7.25% senior notes due 2018		800
6.875% senior notes due 2020		500
2.75% contingent convertible senior notes due 2035^(b)		451
2.5% contingent convertible senior notes due 2037^(b)		1,378
2.25% contingent convertible senior notes due 2038^(b)		752
Discount on senior notes^(c)		(894	)
Interest rate derivatives^(d)		75

	$	10,332

(a)	The principal amount shown is based on the dollar/euro exchange rate of $1.3526 to €1.00 as of March 31, 2010. See Note 2 of our condensed consolidated financial statements included in this report for information on our related foreign currency derivatives.

(b)


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	$	48.71	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$	64.36	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$	107.36	June 14, 2019

(c)	Included in this discount is $771 million at March 31, 2010 associated with the equity component of our contingent convertible senior notes.

(d)	See Note 2 of our condensed consolidated financial statements included in this report for discussion related to these instruments.

As of March 31, 2010 and currently, debt ratings for the senior notes are Ba3 by Moody’s Investor Service (stable outlook), BB by Standard & Poor’s Ratings Services (stable outlook) and BB by Fitch Ratings (negative outlook).

Our senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Our senior note obligations are guaranteed by certain of our wholly owned subsidiaries. See Note 11 of the financial statements included in this report for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. 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. The debt incurrence covenants do not presently restrict our ability to borrow under or expand our revolving bank credit facilities. As of March 31, 2010, we estimate that secured commercial bank indebtedness of approximately $4.47 billion could have been incurred under the most restrictive indenture covenant.

Other Contractual Obligations

Chesapeake has various financial obligations which are not recorded as liabilities in its condensed consolidated balance sheet at March 31, 2010. These include commitments related to drilling rig, compressor leases, transportation and drilling contracts, natural gas and oil purchase obligations and other commitments. These commitments are discussed in Note 3 of our condensed consolidated financial statements included in this report.

Pursuant to our gas gathering agreement with CMP, which since January 1, 2010 has been accounted for as an equity investment, we have committed to deliver specified minimum volumes of natural gas from the Barnett Shale production for each year through December 31, 2018 and for the six-month period ending June 30, 2019. At the end of the term or annually, Chesapeake will be invoiced for any shortfalls in such volume commitments at the rate specified in the agreement. Obligations are as follows:


		Mmcf
2010		335,498
2011		312,963
2012		324,908
2013		338,282
2014		351,265
After 2014		1,686,290

Total		3,349,206

Results of Operations – Three Months Ended March 31, 2010 vs. March 31, 2009

General. For the Current Quarter, Chesapeake had net income of $596 million, or $0.92 per diluted common share, on total revenues of $2.798 billion. This compares to a net loss of $5.740 billion, or $9.63 per diluted common share, on total revenues of $1.995 billion during the Prior Quarter. The Prior Quarter loss was due to a non-cash impairment expense of approximately $6.0 billion, net of tax, as a result of a 36% decrease in NYMEX natural gas prices from $5.71 per mcf at December 31, 2008 to $3.63 per mcf at March 31, 2009.

Natural Gas and Oil Sales. During the Current Quarter, natural gas and oil sales were $1.898 billion compared to $1.397 billion in the Prior Quarter. In the Current Quarter, Chesapeake produced 232.8 bcfe at a weighted average price of $6.80 per mcfe, compared to 213.0 bcfe produced in the Prior Quarter at a weighted average price of $6.09 per mcfe (weighted average prices exclude the effect of unrealized gains on natural gas and oil derivatives of $315 million and $100 million in the Current Quarter and the Prior Quarter, respectively). In the Current Quarter, the increase in prices resulted in an increase in revenue of $166 million and increased production resulted in a $120 million increase, for a total increase in revenues of $286 million (excluding unrealized gains or losses on natural gas and oil derivatives). The increase in production from the Prior Quarter to the Current Quarter was primarily generated by organic growth.

For the Current Quarter, we realized an average price per mcf of natural gas of $6.31, compared to $6.05 in the Prior Quarter (weighted average prices exclude the effect of unrealized gains or losses on derivatives). Oil prices realized per barrel (excluding unrealized gains or losses on derivatives) were $67.70 and $39.12 in the Current Quarter and Prior Quarter, respectively. Realized gains or losses from our natural gas and oil derivatives resulted in a net increase in natural gas and oil revenues of $399 million, or $1.71 per mcfe, in the Current Quarter and an increase of $519 million, or $2.44 per mcfe, in the Prior Quarter.

Changes in natural gas and oil prices have a significant impact on our natural gas and oil revenues and cash flows. Assuming the Current Quarter production levels, a change of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in revenues and cash flow of approximately $23 million and $22 million, respectively, and a change of $1.00 per barrel of oil sold would have resulted in an increase or decrease in revenues and cash flow of approximately $4 million, without considering the effect of derivative activities.

The following table shows our production by region for the Current Quarter and the Prior Quarter:


	Three Months Ended March 31, 2010
	Natural Gas			Oil			Total
	(Bcf)	($/Mcf)^(a)		(Mmbbl)	($/Bbl)^(a)		(Bcfe)	%	($/Mcfe)^(a)
Big 6 Shales:
Barnett Shale^(b)	49.6	$	3.51	0.1	$	38.33	50.2	22%	$	3.55
Fayetteville Shale	31.1		3.97	—		—	31.1	13		3.97
Haynesville Shale	40.0		4.44	—		—	40.0	17		4.44
Marcellus Shale	7.5		5.11	—		—	7.5	3		5.11
Bossier Shale	—		—	—		—	—	—		—
Eagle Ford Shale	0.1		3.62	—		—	0.1	—		3.62
Other:
Mid-Continent	55.5		5.35	2.9		59.69	72.7	31		6.44
Permian and Delaware Basins	12.4		5.20	0.7		75.57	16.7	7		7.13
South Texas/Gulf Coast/ Ark-La-Tex⁽^c⁾	8.1		5.11	0.1		75.93	8.6	4		5.55
Appalachian Basin	5.3		4.79	0.1		70.07	5.9	3		5.13

Total	209.6	$	4.50	3.9	$	62.59	232.8	100%	$	5.09


	Three Months Ended March 31, 2009
	Natural Gas			Oil			Total
	(Bcf)	($/Mcf)^(a)		(Mmbbl)	($/Bbl)^(a)		(Bcfe)	%	($/Mcfe)^(a)
Big 6 Shales:
Barnett Shale	57.6	$	2.63	—	$	—	57.6	27%	$	2.63
Fayetteville Shale	18.3		3.65	—		—	18.3	9		3.65
Haynesville Shale	10.5		4.15	0.1		40.41	11.0	5		4.20
Marcellus Shale	3.3		6.74	—		—	3.3	2		6.74
Bossier Shale	—		—	—		—	—	—		—
Eagle Ford Shale	—		—	—		—	—	—		—
Other:
Mid-Continent	64.3		3.62	1.8		35.42	75.1	35		3.95
Permian and Delaware Basins	15.1		3.43	0.7		36.26	19.3	9		4.02
South Texas/Gulf Coast/ Ark-La-Tex	21.1		4.11	0.2		39.19	22.3	10		4.25
Appalachian Basin	5.5		3.43	0.1		34.90	6.1	3		3.55

Total	195.7	$	3.44	2.9	$	35.99	213.0	100%	$	3.65

(a)	The average sales price excludes gains (losses) on derivatives.

(b)	Current Quarter production was impacted by the sale of 10.6 bcfe of production related to the Total Barnett Shale joint venture that closed in January 2010.

(c)	Current Quarter production was impacted by the sale of 5.6 bcfe of production related to various VPP transactions that closed in 2009 and 2010.

Natural gas production represented approximately 90% and 92% of our total production volume on a natural gas equivalent basis in the Current Quarter and the Prior Quarter, respectively.

Marketing, Gathering and Compression Sales and Operating Expenses. Marketing, gathering and compression activities are substantially for third parties who are owners in Chesapeake-operated wells. Chesapeake realized $844 million in marketing, gathering and compression sales in the Current Quarter, with corresponding marketing, gathering and compression expenses of $815 million, for a net margin before depreciation of $29 million. This compares to sales of $552 million, expenses of $523 million and a net margin before depreciation of $29 million in the Prior Quarter. In the Current Quarter, Chesapeake realized an increase in marketing, gathering and compression sales and operating expenses primarily due to an increase in third-party marketing, gathering and compression volumes offset by a decrease in revenues, expenses and margin related to the deconsolidation of our midstream joint venture.

Service Operations Revenue and Operating Expenses. Service operations consist of third-party revenue and operating expenses related to our drilling and oilfield trucking operations. Chesapeake recognized $56 million in service operations revenue in the Current Quarter with corresponding service operations expense of $49 million, for a net margin before depreciation of $7 million. This compares to revenue of $46 million, expenses of $40 million and a net margin before depreciation of $6 million in the Prior Quarter.

Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $207 million in the Current Quarter compared to $238 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.89 per mcfe in the Current Quarter compared to $1.12 per mcfe in the Prior Quarter. The decrease in the Current Quarter was primarily due to lower service costs in the field as a result of the economic downturn.

Production Taxes. Production taxes were $48 million in the Current Quarter compared to $23 million in the Prior Quarter. On a unit-of-production basis, production taxes were $0.21 per mcfe in the Current Quarter compared to $0.11 per mcfe in the Prior Quarter. The $25 million increase in production taxes in the Current Quarter is primarily due to an increase in the average realized sales price of natural gas and oil of $1.44 per mcfe (excluding gains or losses on derivatives) as well as an increase in production of 20 bcfe. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas and oil prices are higher.

General and Administrative Expenses. General and administrative expenses, including stock-based compensation but excluding internal costs capitalized to our natural gas and oil properties, were $109 million in the Current Quarter and $90 million in the Prior Quarter. General and administrative expenses were $0.47 and $0.42 per mcfe for the Current Quarter and Prior Quarter, respectively. The increase in the Current Quarter was the result of the company’s continued growth as well as increased spending on advertising and related costs associated with our efforts to educate the public concerning the benefits of natural gas. Included in general and administrative expenses is stock-based compensation of $22 million for the Current Quarter and $19 million for the Prior Quarter.

Our stock-based compensation for employees and non-employee directors is in the form of restricted stock. Prior to 2004, stock-based compensation awards were only in the form of stock options. Employee stock-based compensation awards generally vest over a period of four or five years. Our non-employee director awards vest over a period of three years. The discussion of stock-based compensation in Note 5 of our condensed consolidated financial statements included in Part I of this report provides additional detail on the accounting for and reporting of our restricted stock and stock options.

Chesapeake follows the full-cost method of accounting under which all costs associated with natural gas and oil property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with our exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $100 million and $93 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our natural gas and oil property acquisition, exploration and development efforts.

Natural Gas and Oil Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of natural gas and oil properties was $308 million and $447 million during the Current Quarter and the Prior Quarter, respectively. The average DD&A rate per mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $1.32 and $2.10 in the Current Quarter and in the Prior Quarter, respectively. The $0.78 decrease in the average DD&A rate is due primarily to the reduction of our natural gas and oil full-cost pool resulting from divestitures in 2009 and 2010, the utilization of joint venture drilling carries in 2009 and 2010 and the impairment of natural gas and oil properties in 2008 and 2009.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $50 million in the Current Quarter and $57 million in the Prior Quarter. Depreciation and amortization of other assets was $0.21 and $0.27 per mcfe for the Current Quarter and the Prior Quarter, respectively. The decrease in the Current Quarter is primarily due to the deconsolidation of our midstream joint venture offset by additional depreciation expense associated with assets acquired over the past year. Property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 10 to 39 years, gathering facilities are depreciated over 20 years, drilling rigs are depreciated over 15 years and all other property and equipment are depreciated over the estimated useful lives of the assets, which range from two to twenty years. To the extent company-owned drilling rigs and equipment are used to drill our wells, a substantial portion of the depreciation is capitalized in natural gas and oil properties as exploration or development costs.

Impairment of Natural Gas and Oil Properties and Other Assets. Due to lower commodity prices in the first quarter of 2009, we reported a non-cash impairment charge on our natural gas and oil properties of $9.6 billion in the Prior Quarter. We account for our natural gas and oil properties using the full-cost method of accounting, which limits the amount of costs we can capitalize and requires us to write off these costs if the carrying value of natural gas and oil assets in the evaluated portion of our full-cost pool exceeds the sum of the present value of expected future net cash flows of proved reserves, using a 10% pre-tax discount rate based on constant pricing and cost assumptions, and the present value of certain natural gas and oil hedges. Additionally in the Prior Quarter, we recorded an impairment of $30 million associated with certain of our other assets.

Other Income. Other income was $15 million and $8 million in the Current Quarter and in the Prior Quarter, respectively. The Current Quarter consisted of $1 million of interest income, a $13 million gain related to our equity in certain investments and $1 million of miscellaneous income. The Prior Quarter consisted of $3 million of interest income, a ($1) million loss related to our equity in the net losses of certain investments, a $1 million gain on sale of assets and $5 million of miscellaneous income.

Interest Expense (Income). Interest expense increased to $25 million in the Current Quarter compared to ($14) million in the Prior Quarter as follows:


	Three Months Ended
	March 31,
	2010			2009
	($ in millions)

Interest expense on senior notes	$	192		$	182
Interest expense on credit facilities		12			12
Capitalized interest		(161	)		(161	)
Realized (gain) loss on interest rate derivatives		(3	)		(7	)
Unrealized (gain) loss on interest rate derivatives		(27	)		(45	)
Amortization of loan discount and other		12			5

Total interest expense	$	25		$	(14	)


Average long-term borrowings on senior notes	$	11,143		$	10,802

Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $0.22 per mcfe in the Current Quarter compared to $0.14 in the Prior Quarter. The increase in interest expense per mcfe is primarily due to the February 2009 issuance of $1.425 billion of our 9.5% Senior Notes due 2015.

Impairment of Investments. In the Prior Quarter, we recorded a $153 million impairment of certain investments. Each of our investees has been impacted by the dramatic slowing of the worldwide economy and the freezing of the credit markets in the fourth quarter of 2008 and into 2009. The economic weakness resulted in significantly reduced 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 that an other than temporary impairment had occurred on the following investments: Gastar Exploration Ltd., $70 million; Chaparral Energy, Inc., $51 million; DHS Drilling Company, $19 million; and Mountain Drilling Company, $9 million. Additionally we recognized approximately $4 million of impairment charges related to other investments in the Prior Quarter.

Loss on Exchanges of Chesapeake Debt. In the Current Quarter, we privately exchanged approximately $11 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 298,500 shares of our common stock valued at approximately $9 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 80% of the face value of the notes. Associated with these exchanges, we recorded a loss of $2 million. In connection with accounting guidance for debt with conversion and other options, we are required to account for the liability and equity components of our convertible debt instruments separately. Of the $11 million principal amount of convertible notes exchanged in the Current Quarter, $7 million was allocated to the debt component and the remaining $4 million was allocated to the equity conversion feature and was recorded as an adjustment to paid-in-capital. The difference between the debt component and value of the common stock exchanged in these transactions resulted in the $2 million loss. In addition, we expensed a nominal amount of deferred charges associated with the exchanges.

Income Tax Expense (Benefit). Chesapeake recorded income tax expense of $462 million in the Current Quarter, compared to an income tax benefit of $3.444 billion in the Prior Quarter. Of the $3.906 billion increase in income tax expense recorded in the Current Quarter, $3.894 billion was the result of the increase in net income before income taxes and $12 million was due to an increase in the effective tax rate. Our effective income tax rate was 38.5% in the Current Quarter and 37.5% in the Prior Quarter. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences.

Cumulative Effect of Accounting Change. Effective January 1, 2010, in accordance with new authoritative guidance for variable interest entities, we no longer consolidate our midstream joint venture, CMP. Because we have shared control with our 50% partner, Global Infrastructure Partners, our investment in CMP is now accounted for under the equity method. Adoption of this new guidance resulted in an after-tax charge of $142 million in the Current Quarter. This charge reflects the difference between the carrying value of our initial investment in the joint venture, which was recorded at carryover basis as an entity under common control, and the fair value of our equity in the joint venture as of the formation date.

Critical Accounting Policies

Recently Issued and Proposed Accounting Standards

The Financial Accounting Standards Board (FASB) recently issued the following standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.

Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned capital expenditures, and anticipated asset acquisitions and sales, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the fair values of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.

Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1A of our 2009 Form 10-K. They include:

•

the volatility of natural gas and oil prices;

•

the limitations our level of indebtedness may have on our financial flexibility;

•

declines in the values of our natural gas and oil properties resulting in ceiling test write-downs;

•

the availability of capital on an economic basis, including planned asset monetization transactions, to fund reserve replacement costs;

•

our ability to replace reserves and sustain production;

•

uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures;

•

potential differences in our interpretations of new reserve disclosure rules and future SEC guidance;

•

inability to generate profits or achieve targeted results in our development and exploratory drilling and well operations;

•

leasehold terms expiring before production can be established;

•

hedging activities resulting in lower prices realized on natural gas and oil sales and the need to secure hedging liabilities;

•

a reduced ability to borrow or raise additional capital as a result of lower natural gas and oil prices;

•

drilling and operating risks, including potential environmental liabilities;

•

changes in legislation and regulation adversely affecting our industry and our business;

•

general economic conditions negatively impacting us and our business counterparties;

•

transportation capacity constraints and interruptions that could adversely affect our cash flow; and

•

losses possible from pending or future litigation.

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures made in this report and our other filings with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect our business.

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk

Natural Gas and Oil Hedging Activities

Our results of operations and 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 our risk management objectives.

Our general strategy for attempting to mitigate exposure to adverse natural gas and oil price changes is to hedge into strengthening natural gas and oil futures markets when prices allow us to generate high cash margins and when we view prices to be in the upper range of our predicted most likely future price range. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas import trends, natural gas and oil storage inventory levels, industry decline rates for base production and weather trends.

We use a wide range of derivative instruments to achieve our risk management objectives, including swaps, various collar arrangements and options (puts or calls). All of these are described in more detail below. We typically use swaps or collars for a large portion of the natural gas and oil volume we hedge. Swaps are used when the price level is acceptable and collars are used when the downside protection from the bought put is meaningful and the cap on upside from the sold call is at a satisfactory level. We also sell calls, taking advantage of market volatility for a portion of our projected production volumes when the strike price levels and the premiums are attractive to us. Typically, we sell call options when we would be satisfied to sell our production at the price being capped by the call strike or believe it to be more likely than not that the future natural gas or oil price will stay below the call strike price plus the premium we will receive.

We determine the volume we may potentially hedge by reviewing the company’s estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production (risked) from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not hedge more volumes than we expect to produce, and if production estimates are lowered for future periods and hedges are already executed for some volume above the new production forecasts, the hedges are reversed. The actual fixed hedge price on our derivative instruments is derived from bidding and the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. 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.

Hedging positions, including swaps and collars, are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our hedging positions continuously and if future market conditions change and prices have fallen to levels we believe could jeopardize the effectiveness of a position, we will mitigate such risk by either doing a cash settlement with our counterparty, restructuring the position, or by entering into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original hedge position.

In 2009, we restructured many of our trades that included knockout features as commodity prices decreased. The knockouts were typically restructured into straight swaps or collars based on strip prices at the time of the restructure. In the latter half of 2009 and in 2010, we took advantage of attractive strip prices in 2012 through 2014 and sold natural gas and oil call options to our counterparties in exchange for 2010 and 2011 natural gas swaps with strike prices above the then current market price. This effectively allowed us to sell out-year volatility through call options at terms acceptable to us in exchange for straight natural gas swaps with strike prices well in excess of the then current market price for natural gas.

As of March 31, 2010, our natural gas and oil derivative instruments were comprised of the following:

•

Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

•

As of March 31, 2010, we had the following open natural gas and oil derivative instruments designed to hedge a portion of our natural gas and oil production for periods after March 31, 2010:


			Weighted Average Price									Cash Flow	Net			Fair
	Volume		Fixed		Put		Call		Differential			Hedge	Premiums			Value
*Natural Gas:*	(bbtu)				(per mmbtu)								($ in millions)
Swaps:
Q2 2010	80,979		$	7.41	$	—	$	—	$	—		Yes	$	—		$	285
Q3 2010	68,348			7.48		—		—		—		Yes		—			227
Q4 2010	69,588			7.54		—		—		—		Yes		—			193
2011	38,072			8.22		—		—		—		Yes		—			109

Other Swaps^(a) :
Q2 2010	42,770			7.47		—		—		—		No		—			153
Q3 2010	47,840			7.73		—		—		—		No		—			149
Q4 2010	47,840			8.11		—		—		—		No		—			136
2011	105,860			8.56		—		—		—		No		—			110

Collars:
Q2 2010	7,280			—		7.00		8.25		—		Yes		—			22

Other Collars^(b) :
Q2 2010	9,100			—		4.35/7.07		9.91		—		No		5			27
Q3 2010	3,680			—		7.60		11.75		—		No		4			13
Q4 2010	3,680			—		7.60		11.75		—		No		4			11
2011	7,300			—		7.70		11.50		—		No		7			18

Call Options:
Q2 2010	19,215			—		—		9.94		—		No		40			—
Q3 2010	34,040			—		—		10.01		—		No		42			—
Q4 2010	34,040			—		—		10.08		—		No		42			—
2011	20,988			—		—		8.00		—		No		43			(3	)
2012	262,605			—		—		7.90		—		No		23			(78	)
2013 – 2020	758,428			—		—		8.38				No		119			(345	)

Put Options:
Q3 2010	(7,360	)		—		5.70		—		—		No		6			(12	)
Q4 2010	(7,360	)		—		5.70		—		—		No		6			(9	)
2011	(36,500	)		—		5.75		—		—		No		25			(36	)

Knockout Swaps:
Q3 2010	7,360			8.74		5.50		—		—		No		—			2
Q4 2010	7,360			8.74		6.20		—		—		No		—			2
2011	23,650			9.86		6.29		—		—		No		—			11

Basis Protection Swaps
(Non-Appalachian Basin):
2011	45,090			—		—		—		(0.82	)	No		(3	)		(26	)
2012 – 2018	57,961			—		—		—		(0.90	)	No		(3	)		(30	)

Basis Protection Swaps
(Appalachian Basin):
Q2 2010	2,513			—		—		—		0.27		No		—			—
Q3 2010	2,660			—		—		—		0.26		No		—			—
Q4 2010	2,732			—		—		—		0.26		No		—			—
2011	12,086			—		—		—		0.25		No		—			2
2012 – 2022	134			—		—		—		0.11		No		—			—

	Total Natural Gas													360			931


		Weighted Average Price								Cash Flow	Net			Fair
	Volume	Fixed		Put		Call		Differential		Hedge	Premiums			Value
*Oil:*	(mbbls)			(per bbl)							($ in millions)
Swaps:
Q2 2010	515	$	85.10	$	—	$	—	$	—	Yes	$	—		$	—
Q3 2010	634		84.24		—		—		—	Yes		—			—
Q4 2010	622		84.46		—		—		—	Yes		—			(1	)
2011	572		81.29		—		—		—	Yes		—			(3	)
2012 – 2020	2,869		84.25		—		—		—	Yes		—			(11	)

Other Swaps^(c) :
Q2 2010	637		91.12		—		—		—	No		—			4
Q3 2010	644		91.12		—		—		—	No		—			4
Q4 2010	644		91.12		—		—		—	No		—			4
2011	3,285		91.17		—		—		—	No		—			(20	)

Call Options:
Q2 2010	364		—		—		101.25		—	No		(3	)		—
Q3 2010	368		—		—		101.25		—	No		(3	)		(1	)
Q4 2010	368		—		—		101.25		—	No		(3	)		(1	)
2011	3,650		—		—		105.00		—	No		16			(16	)
2012 – 2015	18,552		—		—		94.30		—	No		16			(225	)

Knock-Out Swaps:
Q2 2010	1,183		90.25		60.00		—		—	No		—			7
Q3 2010	1,196		90.25		60.00		—		—	No		—			5
Q4 2010	1,196		90.25		60.00		—		—	No		—			3
2011	1,095		104.75		60.00		—		—	No		—			12
2012	732		109.50		60.00		—		—	No		—			7

	Total Oil											23			(232	)


*Total Natural Gas and Oil*											$	383		$	699

(a)	Included in Other Swaps are options to extend existing swaps for an additional 12 months. The volume of such extendables in 2010 is 9,200 bbtu at a weighted average fixed swap price of $9.50/mmbtu, and in 2011 is 47,450 bbtu at a weighted average fixed swap price of $10.18/mmbtu.

(b)	Included in Other Collars for 2010 are 3,640 bbtu of three-way collars which have written put options with weighted average prices of $4.35/mmbtu, which limits the counterparty’s exposure.

(c)	Included in Other Swaps are options to extend existing swaps for an additional 12 months. The volume of such extendables in 2011 is 3,285 mbbl at a weighted average fixed price of $91.17/bbl.

We have determined the fair value of our derivative instruments 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. Future risk related to counterparties not being able to meet their obligations has been mitigated under our secured hedging facility which requires counterparties to post collateral if their obligations to Chesapeake are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

The table below reconciles the Current Quarter change in fair value of our natural gas and oil derivatives. Of the $699 million fair value asset, as of March 31, 2010, $1.294 billion relates to contracts maturing in the next 12 months, of which we expect to transfer approximately $369 million (net of income taxes) from accumulated other comprehensive income to net income (loss), and ($595) million relates to contracts maturing after 12 months. All transactions hedged as of March 31, 2010 are expected to mature by December 31, 2022.


	2010
	($ in millions)

Fair value of contracts outstanding, as of January 1	$	21
Change in fair value of contracts		978
Fair value of contracts when entered into		(53	)
Contracts realized or otherwise settled		(321	)
Fair value of contracts when closed		74

Fair value of contracts outstanding, as of March 31	$	699

The change in natural gas and oil prices during the Current Quarter increased the value of our derivative assets by $978 million. This gain is recorded in natural gas and oil sales or in accumulated other comprehensive income. We entered into new contracts which had premiums of $53 million, and a liability was recorded. We settled contracts, reducing our assets by $321 million and we closed out contracts, increasing our assets by $74 million. The realized gain will be recorded in natural gas and oil sales in the month of related production.

Pursuant to accounting guidance for derivatives and hedging, certain derivatives qualify for designation as cash flow hedges. Following these provisions, 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 accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). 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 natural gas and oil sales. Realized gains (losses) are included in natural gas and oil sales in the month of related production.

The components of natural gas and oil sales for the Current Quarter and the Prior Quarter are presented below.


	Three Months Ended March 31,
	2010			2009
	( in millions)

Natural gas and oil sales	$	1,184		$	778
Realized gains (losses) on natural gas and oil derivatives		399			519
Unrealized gains (losses) on non-qualifying natural gas and oil derivatives		321			46
Unrealized gains (losses) on ineffectiveness of cash flow hedges		(6	)		54

Total natural gas and oil sales	$	1,898		$	1,397

Interest Rate Risk

The table below presents principal cash flows ($ in millions) and related weighted average interest rates by expected maturity dates.


	Years of Maturity
	2010		2011		2012			2013			2014			Thereafter			Total
Liabilities:
Long-term debt – fixed rate^(a)	$	—	$	—	$	—		$	864		$	600		$	9,687		$	11,151
Average interest rate		—		—		—			7.6	%		7.3	%		6.0	%		6.2	%

Long-term debt – variable rate	$	—	$	—	$	1,872		$	—		$	—		$	—		$	1,872
Average interest rate		—		—		2.6	%		—			—			—			2.6	%

(a)	This amount does not include the discount included in long-term debt of ($894) million and interest rate derivatives of $75 million.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving bank credit facilities. All of our other long-term indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt.

Interest Rate Derivatives

To mitigate our exposure to volatility in interest rates related to our senior notes and credit facilities, we enter into interest rate derivatives. As of March 31, 2010, our interest rate derivative instruments were comprised of the following types of instruments:

•

Swaps: Chesapeake enters into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and a pay fixed interest rate) to manage our interest rate exposure related to our bank credit facility borrowings.

•

Swaptions: Occasionally we sell an option to a counterparty for a premium which allows the counterparty to enter into a swap with us on a specific date.

As of March 31, 2010, the following interest rate derivatives were outstanding:


	Notional		Weighted Average Rate		Fair Value	Net		Fair
	Amount		Fixed	Floating^(b)	Hedge	Premiums		Value
*Fixed to Floating:*	($ in millions)					($ in millions)
Swaps
Mature 2015 – 2017	$	450	8.50%	1 – 6 mL plus 539 bp	Yes	$	—	$	(4	)
Mature 2013 – 2020	$	1,000	7.06%	3 – 6 mL plus 417 bp	No		9		(45	)
Call Options
Expire Q2 2010	$	250	6.88%	3 mL plus 287 bp	No		4		(1	)

Swaption
Expire Q2 2010	$	650	7.48%	3 mL plus 338 bp	No		6		(2	)

*Floating to Fixed:*
Swaps
Mature Q3 2010 – 2012	$	1,375	3.30%	1 – 6 mL	No		—		(41	)

Collars^(a)
Mature Q3 2010	$	250	4.52%	6 mL	No		—		(4	)

						$	19	$	(97	)

(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”.

In the Current Quarter, we closed interest rate derivatives which were designated as fair value hedges for gains totaling $3 million. These gains are currently reported as an adjustment to our senior note liability, and will be amortized as a reduction to realized interest expense over the remaining four-year term of the related senior notes.

For interest rate derivative instruments designated as fair value hedges 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 interest rate derivative transactions are reflected as adjustments to interest expense on the condensed consolidated statements of operations. The components of interest expense for the Current Quarter and the Prior Quarter are presented below.


	Three Months Ended March 31,
	2010			2009
	($ in millions)

Interest expense on senior notes	$	192		$	182
Interest expense on credit facilities		12			12
Capitalized interest		(161	)		(161	)
Realized (gains) losses on interest rate derivatives		(3	)		(7	)
Unrealized (gains) losses on interest rate derivatives		(27	)		(45	)
Amortization of loan discount and other		12			5

Total interest expense	$	25		$	(14	)

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. The fair value of the cross currency swap is recorded on the condensed consolidated balance sheet as a liability of $3 million at March 31, 2010. The euro-denominated debt in notes payable has been adjusted to $811 million at March 31, 2010 using an exchange rate of $1.3526 to €1.00.

ITEM 4.

Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed by Chesapeake in reports filed or submitted by it under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. At the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of Chesapeake management, including Chesapeake’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Chesapeake’s disclosure controls and procedures pursuant to Securities Exchange Act Rule 13a-15(b). Based upon that evaluation our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

No changes in Chesapeake’s internal control over financial reporting occurred during the Current Quarter that have materially affected, or are reasonably likely to materially affect, Chesapeake’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

Legal Proceedings

We refer you to “Litigation” in Note 3 of the notes to the condensed consolidated financial statements included in Part I, Item 1 of this Form 10-Q.

ITEM 1A.

Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock, preferred stock or senior notes are described under “Risk Factors” in Item 1A of our 2009 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the Securities and Exchange Commission.

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

The information set forth in Item 5 is incorporated herein by reference.

The issuance and sale of the Preferred Stock described in Item 5 is exempt from registration under the Securities Act of 1933 pursuant to Section 4(2) of the Securities Act of 1933 as a transaction not involving any public offering.

The following table presents information about repurchases of our common stock during the three months ended March 31, 2010:


Period	Total Number of Shares Purchased^(a)	Average Price Paid Per Share^(a)		Total Number Of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs^(b)

January 1, 2010 through January 31, 2010	932,532	$	25.78	—	—
February 1, 2010 through February 28, 2010	12,869		26.42	—	—
March 1, 2010 through March 31, 2010	11,799		23.61	—	—

Total	957,200	$	24.61	—	—

(a)	Represents the surrender to the company of shares of common stock to pay withholding taxes in connection with the vesting of employee restricted stock.

(b)

We make matching contributions to our 401(k) plan and deferred compensation plan using Chesapeake common stock which is held in treasury or is purchased by the respective plan trustees in the open market. The plans contain no limitation on the number of shares that may be purchased for purposes of company contributions.

ITEM 3.

Defaults Upon Senior Securities

Not applicable.

ITEM 4.

(Removed and Reserved)

ITEM 5.

Other Information

On May 7, 2010, we entered into securities purchase agreements (together, the “Securities Purchase Agreements”) with each of Maju Investment (Mauritius) Pte Ltd, an affiliate of Temasek Holdings (Private) Limited (“Maju”), and Hampton Asset Holding Ltd, an affiliate of HOPU Investment Management Co., Ltd (“Hampton”), pursuant to which agreements we agreed to issue and sell (i) to Maju, and Maju agreed to purchase, 500,000 shares of a newly created series of preferred stock designated the 5.75% Cumulative Non-Voting Convertible Preferred Stock (the “Preferred Stock”) at a purchase price of $1,000 per share for an aggregate purchase price of $500 million and (ii) to Hampton, and Hampton agreed to purchase, 100,000 shares of the Preferred Stock at a purchase price of $1,000 per share for an aggregate purchase price of $100 million. Completion of these private placements (the “Closing”) is scheduled for May 17, 2010 and is subject to customary closing conditions.

The terms, rights, obligations and preferences of the Preferred Stock will be set forth in a Certificate of Designations. Dividends on the Preferred Stock will be payable, on a cumulative basis, as and if declared by the Board of Directors of the Company, in cash, at the rate per annum of 5.75% of the $1,000 liquidation preference. Declared dividends on the Preferred Stock will be payable quarterly, in arrears, on each February 15, May 15, August 15 and November 15, commencing on August 15, 2010. We will be prohibited from paying any dividend with respect to shares of our common stock or other junior securities or repurchasing or redeeming any shares of common stock or other junior securities in any quarter unless full dividends are paid on the Preferred Stock in such quarter.

We will not be permitted to redeem shares of the Preferred Stock. Each share of the Preferred Stock may be converted at any time, at the option of the holder, into approximately 37.037 shares of our common stock (which is calculated using an initial conversion price of $27.00 per share of common stock) plus cash in lieu of fractional shares, subject to adjustment based on the conversion price. The conversion price is subject to adjustment upon the occurrence of certain customary events. On or after May 17, 2015, we may, at our option, cause the Preferred Stock to be automatically converted into that number of shares of our common stock that are issuable at the then prevailing conversion price. We may exercise this conversion right if, for 20 trading days within any period of 30 consecutive trading days (including the last trading day of such period), the closing price of our common stock exceeds 130% of the then prevailing conversion price of the Preferred Stock. If a fundamental change occurs we may be required to pay a make-whole premium on the Preferred Stock converted in connection with the fundamental change. The make-whole premium will be payable in shares of our common stock or the consideration into which our common stock has been converted or exchanged in connection with the fundamental change. The amount of the make-whole premium, if any, will be based on the price of our common stock and the effective date of the fundamental change.

On May 7, 2010, we also entered into a letter agreement with Maju and Hampton pursuant to which we granted them an option valid through June 9, 2010 to acquire from us and place up to 500,000 additional shares of the Preferred Stock, which will be offered for sale to certain non-U.S. institutional investors at a purchase price of $1,000 per share. Pursuant to the letter agreement, we will pay Maju and Hampton a placement fee equal to 2.5% of the aggregate liquidation preference of the Preferred Stock placed by them pursuant to this arrangement.

The net proceeds received from the sale of the Preferred Stock sold in the private placements described above will be used to repay senior indebtedness.

On May 7, 2010, we also entered into a three-year consulting agreement with Maju, pursuant to which Maju will advise and consult with us with respect to Asian energy markets and opportunities and in exchange for which we will pay Maju a consulting fee of $1.25 million per year.

ITEM 6.

Exhibits

The following exhibits are filed as a part of this report:

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

Furnished

Herewith

3.1.1

Chesapeake’s Restated Certificate of Incorporation, as amended.

10-Q

001-13726

3.1.1

08/10/2009

3.1.2

Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B).

10-Q

001-13726

3.1.4

11/10/2008

3.1.3

Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock.

10-Q

001-13726

3.1.6

08/11/2008

3.2

Chesapeake’s Amended and Restated Bylaws.

8-K

001-13726

3.1

11/17/2008

10.4

Consulting Agreement dated as of February 1, 2010 between J. Mark Lester and Chesapeake Energy Corporation.

10-K

001-13726

10.4

03/01/2010

Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.

31.1

Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

SIGNATURES

Pursuant to the requirement of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	CHESAPEAKE ENERGY CORPORATION

Date: May 10, 2010	By:	/s/ AUBREY K. MCCLENDON
		Aubrey K. McClendon Chairman of the Board and Chief Executive Officer

Date: May 10, 2010	By:	/s/ MARCUS C. ROWLAND
		Marcus C. Rowland Executive Vice President and Chief Financial Officer

INDEX TO EXHIBITS

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

Furnished

Herewith

3.1.1

Chesapeake’s Restated Certificate of Incorporation, as amended.

10-Q

001-13726

3.1.1

08/10/2009

3.1.2

Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B).

10-Q

001-13726

3.1.4

11/10/2008

3.1.3

Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock.

10-Q

001-13726

3.1.6

08/11/2008

3.2

Chesapeake’s Amended and Restated Bylaws.

8-K

001-13726

3.1

11/17/2008

10.4

Consulting Agreement dated as of February 1, 2010 between J. Mark Lester and Chesapeake Energy Corporation.

10-K

001-13726

10.4

03/01/2010

Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.

31.1

Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.