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 June 30, 2012

[  ]    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 August 3, 2012, there were 665,405,451 shares of our common stock, $0.01 par value, outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2012

PART I.

Financial Information

		Page
Item 1.	Condensed Consolidated Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011		1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011		3
	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2012 and 2011		4
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011		5
	Condensed Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2012 and 2011		7
	Notes to Condensed Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		63
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		95
Item 4.	Controls and Procedures		102
PART II.
Other Information
Item 1.	Legal Proceedings		103
Item 1A.	Risk Factors		103
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		103
Item 3.	Defaults Upon Senior Securities		104
Item 4.	Mine Safety Disclosures		104
Item 5.	Other Information		104
Item 6.	Exhibits		105

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
	2012			2011
	($ in millions)
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIEs)		$          1,024		$	351
Restricted cash		224			44
Accounts receivable		2,123			2,505
Short-term derivative assets		112			13
Deferred income tax asset		785			139
Other current assets		149			125
Current assets held for sale ($7 and $0 attributable to our VIEs)		99			—
Total Current Assets		4,516			3,177
PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full cost accounting:
Evaluated natural gas and oil properties ($488 and $498 attributable to our VIEs)		46,773			41,723
Unevaluated properties		17,063			16,685
Natural gas gathering systems and treating plants		—			1,763
Oilfield services equipment		1,844			1,611
Other property and equipment		3,418			3,247
Total Property and Equipment, at Cost		69,098			65,029
Less: accumulated depreciation, depletion and amortization (($30) and ($6) attributable to our VIEs)		(29,431	)		(28,290	)
Property and equipment held for sale, net ($85 and $0 attributable to our VIEs)		2,207			—
Total Property and Equipment, Net		41,874			36,739
LONG-TERM ASSETS:
Investments		544			1,531
Long-term derivative assets ($1 and $0 attributable to our VIEs)		8			—
Other long-term assets		511			388
Long-term assets held for sale		73			—
TOTAL ASSETS		$        47,526		$	41,835

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

1

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (Continued)

(Unaudited)

	June 30,			December 31,
	2012			2011
	($ in millions)
CURRENT LIABILITIES:
Accounts payable		$           2,552		$	3,311
Short-term derivative liabilities ($0 and $9 attributable to our VIEs)		106			191
Accrued interest		244			183
Other current liabilities ($24 and $23 attributable to our VIEs)		3,163			3,397
Current liabilities held for sale ($27 and $0 attributable to our VIEs)		194			—
Total Current Liabilities		6,259			7,082
LONG-TERM LIABILITIES:
Long-term debt, net		14,329			10,626
Deferred income tax liabilities		4,783			3,484
Long-term derivative liabilities ($0 and $10 attributable to our VIEs)		1,042			1,541
Asset retirement obligations		341			323
Other long-term liabilities		982			818
Long-term liabilities held for sale		2			—
Total Long-Term Liabilities		21,479			16,792
CONTINGENCIES AND COMMITMENTS (Note 4)
EQUITY:
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
7,251,515 shares outstanding		3,062			3,062
Common stock, $0.01 par value, 1,000,000,000 shares authorized:
664,194,954 and 660,888,159 shares issued		7			7
Paid-in capital		12,226			12,146
Retained earnings		2,352			1,608
Accumulated other comprehensive income (loss)		(181	)		(166	)
Less: treasury stock, at cost; 1,811,919 and 1,552,533 common shares		(39	)		(33	)
Total Chesapeake Stockholders’ Equity		17,427			16,624
Noncontrolling interests		2,361			1,337
Total Equity		19,788			17,961
TOTAL LIABILITIES AND EQUITY	$	47,526		$	41,835

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

2

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	($ in millions, except per share data)
REVENUES:
Natural gas, oil and NGL	$	2,117		$	1,792		$	3,185		$	2,286
Marketing, gathering and compression		1,113			1,404			2,328			2,421
Oilfield services		159			122			294			223
Total Revenues		3,389			3,318			5,807			4,930
OPERATING EXPENSES:
Natural gas, oil and NGL production		335			262			685			500
Production taxes		41			46			89			91
Marketing, gathering and compression		1,096			1,366			2,292			2,352
Oilfield services		109			92			205			169
General and administrative		156			130			292			259
Natural gas, oil and NGL depreciation, depletion and amortization		588			366			1,094			724
Depreciation and amortization of other assets		83			63			166			131
Losses on sales and impairments of fixed assets		243			8			241			3
Total Operating Expenses		2,651			2,333			5,064			4,229
INCOME FROM OPERATIONS		738			985			743			701
OTHER INCOME (EXPENSE):
Interest expense		(14	)		(25	)		(26	)		(33	)
Earnings (losses) on investments		(59	)		47			(64	)		72
Gain on sale of investment		1,030			—			1,030			—
Losses on purchases or exchanges of debt		—			(174	)		—			(176	)
Other income		5			2			11			5
Total Other Income (Expense)		962			(150	)		951			(132	)
INCOME BEFORE INCOME TAXES		1,700			835			1,694			569
INCOME TAX EXPENSE:
Current income taxes		2			6			2			12
Deferred income taxes		661			319			659			210
Total Income Tax Expense		663			325			661			222
NET INCOME		1,037			510			1,033			347
Net income attributable to noncontrolling interests		(65	)		—			(89	)		—
NET INCOME ATTRIBUTABLE TO CHESAPEAKE		972			510			944			347
Preferred stock dividends		(43	)		(43	)		(86	)		(85	)
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS	$	929		$	467		$	858		$	262
EARNINGS PER COMMON SHARE:
Basic	$	1.45		$	0.74		$	1.34		$	0.41
Diluted	$	1.29		$	0.68		$	1.25		$	0.41
CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.0875		$	0.0875		$	0.175		$	0.1625
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic		642			635			642			635
Diluted		751			751			752			645

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

3

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	($ in millions)
NET INCOME	$	1,037		$	510		$	1,033		$	347
Other comprehensive income, net of income tax:
Gain (loss) on derivative instruments, net of income taxes of ($2) million, $87 million, $0 and $89 million		(3	)		141			—			146
Reclassification of gain on settled derivative instruments, net of income taxes of ($6) million, ($11) million, ($7) million and ($39) million		(11	)		(18	)		(12	)		(64	)
Ineffective portion of derivatives designated as cash flow hedges, net of income taxes of $0, ($3) million, $0 and ($7) million		—			(5	)		—			(11	)
Unrealized gain (loss) on available-for-sale securities, net of income taxes of ($6) million, ($3) million, ($2) million and ($1) million		(9	)		(5	)		(3	)		(2	)
Other comprehensive income (loss)		(23	)		113			(15	)		69
Comprehensive income		1,014			623			1,018			416
Comprehensive income attributable to noncontrolling interests		(65	)		—			(89	)		—
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$	949		$	623		$	929		$	416

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

4

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2012			2011
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	1,033		$	347
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization		1,260			855
Deferred income tax expense		659			210
Unrealized (gains) losses on derivatives		(542	)		1,087
Stock-based compensation		63			79
Losses on sales and impairments of fixed assets		241			3
(Gains) losses on investments		120			(23	)
Gain on sale of investment		(1,030	)		—
Losses on purchases or exchanges of debt		—			33
Other		1			(3	)
Changes in assets and liabilities		(776	)		(495	)
Cash provided by operating activities		1,029			2,093
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs		(5,120	)		(3,395	)
Acquisitions of proved and unproved properties		(1,795	)		(2,529	)
Proceeds from divestitures of proved and unproved properties		1,555			6,173
Additions to other property and equipment		(1,311	)		(863	)
Proceeds from sales of other assets		79			526
Proceeds from (additions to) investments		(128	)		212
Proceeds from sale of midstream investment		2,000			—
Acquisition of drilling company		—			(339	)
Increase in restricted cash		(180	)		—
Other		(21	)		(25	)
Cash used in investing activities		(4,921	)		(240	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		10,104			8,343
Payments on credit facilities borrowings		(11,592	)		(10,235	)
Proceeds from issuance of term loans, net of discount and offering costs		3,789			—
Proceeds from issuance of senior notes, net of discount and offering costs		1,263			977
Cash paid to purchase debt		—			(2,032	)
Cash paid for common stock dividends		(112	)		(95	)
Cash paid for preferred stock dividends		(86	)		(86	)
Cash (paid) received on financing derivatives		(36	)		882
Proceeds from sales of noncontrolling interests		1,039			—
Proceeds from other financings		225			—
Distributions to noncontrolling interest owners		(104	)		—
Net increase in outstanding payments in excess of cash balance		121			448
Other		(39	)		(48	)
Cash provided by (used in) financing activities		4,572			(1,846	)
Change in cash and cash equivalents classified as current assets held for sale		(7	)		—
Net increase in cash and cash equivalents		673			7
Cash and cash equivalents, beginning of period		351			102
Cash and cash equivalents, end of period	$	1,024		$	109

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

5

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

(Unaudited)

	Six Months Ended June 30,
	2012		2011
	($ in millions)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION OF NET CASH PAYMENTS (REFUNDS) FOR:
Interest, net of capitalized interest	$	—	$	—
Income taxes, net of refunds received	$	6	$	(25	)

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

As of June 30, 2012 and 2011, dividends payable on our common and preferred stock were $100 million and $99 million, respectively.

For the six months ended June 30, 2012 and 2011, natural gas and oil properties was adjusted by ($55) million and $92 million, respectively, as a result of an increase (decrease) in accrued acquisition, drilling and completion costs.

For the six months ended June 30, 2012 and 2011, other property and equipment was adjusted by $49 million and $37 million, respectively, as a result of an increase in accrued costs.

As of June 30, 2012 and 2011, we had recorded $62 million and $206 million, respectively, of various liabilities related to the purchase of proved and unproved properties and other assets.

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

6

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

	Six Months Ended
	June 30,
	2012			2011
	($ in millions)
PREFERRED STOCK:
Balance, beginning and end of period	$	3,062		$	3,065
COMMON STOCK:
Balance, beginning and end of period		7			7
PAID-IN CAPITAL:
Balance, beginning of period		12,146			12,194
Stock-based compensation		84			114
Purchase of contingent convertible notes		—			(123	)
(Reduction in) tax benefit from stock-based compensation		(4	)		2
Dividends on common stock		—			(48	)
Dividends on preferred stock		—			(15	)
Exercise of stock options		—			1
Balance, end of period		12,226			12,125
RETAINED EARNINGS:
Balance, beginning of period		1,608			190
Net income attributable to Chesapeake		944			347
Dividends on common stock		(114	)		(56	)
Dividends on preferred stock		(86	)		(70	)
Balance, end of period		2,352			411
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period		(166	)		(168	)
Hedging activity		(12	)		71
Investment activity		(3	)		(2	)
Balance, end of period		(181	)		(99	)
TREASURY STOCK – COMMON:
Balance, beginning of period		(33	)		(24	)
Purchase of 272,640 and 134,300 shares for company benefit plans		(6	)		(4	)
Release of 13,254 and 73,299 shares from company benefit plans		—			2
Balance, end of period		(39	)		(26	)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY		17,427			15,483
NONCONTROLLING INTERESTS:
Balance, beginning of period		1,337			—
Sales of noncontrolling interests		1,039			—
Net income attributable to noncontrolling interests		89			—
Distributions to noncontrolling interest owners		(104	)		—
Balance, end of period		2,361			—
TOTAL EQUITY	$	19,788		$	15,483

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

7

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 (“Chesapeake” or the “Company”) 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, 2011 (2011 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 accompanying condensed consolidated financial statements of Chesapeake include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake holds a controlling interest. All significant intercompany accounts and transactions have been eliminated. The results for the three and six months ended June 30, 2012 are not necessarily indicative of the results to be expected for the full year. This Form 10-Q relates to the three and six months ended June 30, 2012 (the “Current Quarter” and the “Current Period”, respectively) and the three and six months ended June 30, 2011 (the “Prior Quarter” and the “Prior Period”, respectively).

Critical Accounting Policies

We consider accounting policies related to derivatives, variable interest entities, 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 2011 Form 10-K.

Risks and Uncertainties

We have a material exposure to low natural gas prices, which reached 10-year lows in the Current Period. Approximately 83% and 72% of our estimated proved reserves volumes as of December 31, 2011 and June 30, 2012 were natural gas, and natural gas represented approximately 84% and 80% of our natural gas, oil and natural gas liquids (NGL) sales volumes for the full year 2011 and the Current Period, respectively. Although our derivative arrangements serve to mitigate a portion of the effect of price volatility on our cash flows, approximately 35% of our 2012 second half natural gas production is currently not protected by derivative instruments against downward price movement. Our use of oil derivatives to partially mitigate the price risk of our oil and NGL (collectively “liquids”) production is subject to basis risk to the extent oil and NGL prices do not remain highly correlated.

In response to low natural gas prices and, by comparison, strong oil prices, we have shifted our strategy to building a more liquids-focused portfolio, and an increasing amount of our revenue is now derived from liquids production (65% of total natural gas, oil and NGL revenue before the effects of hedging in the Current Period). Sustained low natural gas prices, and volatile natural gas, oil and NGL prices in general, however, could have a material adverse effect on our financial position, results of operations and cash flows, which could adversely impact our ability to comply with financial covenants under our corporate revolving bank credit facility and further limit our ability to fund our planned capital expenditures. In addition, sustained low natural gas, oil and NGL prices could result in a reduction in the estimated quantity of proved reserves we report and in the estimated future net cash flows expected to be generated from our proved reserves. As a result, we may be required to write down the carrying value of our natural gas and oil properties, and such amounts could be material.

In the Current Period, we reduced our estimate of proved reserves by 4.6 tcfe due to the impact of downward natural gas price revisions. Natural gas prices used in estimating proved reserves decreased by $0.97 from $4.12 per mcf for the 12 months ended December 31, 2011 to $3.15 per mcf for the 12 months ended June 30, 2012 using 12-month average prices required by the SEC. The reserve reductions primarily involved the loss of significant proved undeveloped reserves, primarily in the Barnett Shale and the Haynesville Shale plays, for which

8

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

future development is uneconomic at the natural gas prices used in the reserves estimates. As of June 30, 2012, we were not required to impair the carrying value of our natural gas and oil properties; however, based on the expected natural gas prices we will be required to use to estimate proved reserves for the second half of 2012, we anticipate an impairment resulting from downward natural gas price revisions during the second half of 2012. Any such impairment, a non-cash charge that would not impact our liquidity or our ability to comply with financial covenants under our corporate revolving bank credit facility, is subject to a number of factors which could change, including the impact of oil and natural gas asset sales and other factors.

As part of our sales planning and capital expenditure budgeting process, we closely monitor the resulting effects on the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our corporate revolving bank credit facility. While asset sales enhance our ability to reduce debt, sales of producing natural gas and oil properties adversely affect the amount of cash flow and EBITDA we generate and reduce the amount and value of collateral available to secure our obligations, both of which are exacerbated by low natural gas, oil and NGL prices. Thus the assets we select and schedule for sales, our budgeted capital expenditures and our natural gas and oil price forecasts are carefully considered as we project our future ability to comply with the requirements of our corporate revolving bank credit facility. Our ability to obtain capital from asset sales and our ability to achieve our forecasted EBITDA are dependent upon many factors, some of which are beyond our control. Changes in the amount or timing of asset sales necessary to reduce our outstanding debt, or decreases in forecasted EBITDA, could adversely impact our ability to comply with financial covenants under our corporate revolving bank credit facility.

Held for Sale Assets and Liabilities

We are currently pursuing the sale of substantially all of our midstream business in order to narrow our strategic focus and expect to complete the sale in the 2012 third quarter. The midstream business qualified as held for sale as of June 30, 2012. These assets and liabilities are reported under our marketing, gathering and compression operating segment. In addition, we are pursuing the sale of various other property and equipment, including certain drilling rigs and land and buildings primarily in the Fort Worth area, in the next 12 months that also qualified as held for sale as of June 30, 2012. The drilling rigs are reported under the oilfield services operating segment and the land and buildings are reported under our other operating segment. Natural gas and oil properties that we intend to sell are not presented as held for sale as they are only a portion of our full cost pool and are precluded from being presented as held for sale. A summary of the assets and liabilities held for sale on our condensed consolidated balance sheet as of June 30, 2012 is detailed below.

	June 30,
	2012
	($ in millions)
Cash	$	7
Accounts receivable		91
Other assets		1
Current assets held for sale	$	99
Natural gas gathering systems and treating plants, net of accumulated depreciation	$	1,937
Oilfield services equipment, net of accumulated depreciation		27
Other property and equipment, net of accumulated depreciation and amortization		243
Property and equipment held for sale, net	$	2,207
Investments	$	73
Long-term assets held for sale	$	73
Accounts payable	$	41
Accrued liabilities		153
Current liabilities held for sale	$	194
Asset retirement obligations	$	2
Long-term liabilities held for sale	$	2

9

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. 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 Prior Period, the following shares of our cumulative convertible preferred stock and associated adjustments to net income, consisting of dividends on such shares, were not included in the calculation of diluted EPS, as the effect was antidilutive:

	Net Income
	Adjustments		Shares
	($ in millions)		(in millions)
Six Months Ended June 30, 2011:
Common stock equivalent of our preferred stock outstanding:
5.75% cumulative convertible preferred stock		$    43	56
5.75% cumulative convertible preferred stock (series A)		$    32	39
5.00% cumulative convertible preferred stock (series 2005B)		$      5	5
4.50% cumulative convertible preferred stock		$      6	6

A reconciliation of basic EPS and diluted EPS for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:

			Weighted
			Average		Per
	Income		Shares		Share
	(Numerator)		(Denominator)		Amount
	(in millions, except per share data)
Three Months Ended June 30, 2012:
Basic EPS	$	929		642	$	1.45
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 5.75% cumulative convertible preferred stock		21		56
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)		16		39
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
Unvested restricted stock		—		3
Diluted EPS	$	972		751	$	1.29

10

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

			Weighted
			Average		Per
	Income		Shares		Share
	(Numerator)		(Denominator)		Amount
	(in millions, except per share data)
Three Months Ended June 30, 2011:
Basic EPS	$	467		635	$	0.74
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 5.75% cumulative     convertible preferred stock		21		56
Common shares assumed issued for 5.75% cumulative     convertible preferred stock (series A)		16		39
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
Unvested restricted stock		—		9
Outstanding stock options		—		1
Diluted EPS	$	510		751	$	0.68
Six Months Ended June 30, 2012:
Basic EPS	$	858		642	$	1.34
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 5.75% cumulative     convertible preferred stock		43		56
Common shares assumed issued for 5.75% cumulative     convertible preferred stock (series A)		32		39
Common shares assumed issued for 5.00% cumulative     convertible preferred stock (series 2005B)		5		5
Common shares assumed issued for 4.50% cumulative     convertible preferred stock		6		6
Unvested restricted stock		—		4
Diluted EPS	$	944		752	$	1.25
Six Months Ended June 30, 2011:
Basic EPS	$	262		635	$	0.41
Effect of Dilutive Securities:
Unvested restricted stock		—		9
Outstanding stock options		—		1
Diluted EPS	$	262		645	$	0.41

11

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Debt

Our long-term debt consisted of the following as of June 30, 2012 and December 31, 2011:

	June 30,			December 31,
	2012			2011
	($ in millions)
Term loans due 2017	$	4,000		$	—
7.625% senior notes due 2013		464			464
9.5% senior notes due 2015		1,265			1,265
6.25% euro-denominated senior notes due 2017(a)		435			446
6.5% senior notes due 2017		660			660
6.875% senior notes due 2018		474			474
7.25% senior notes due 2018		669			669
6.625% senior notes due 2019(b)		650			650
6.775% senior notes due 2019		1,300			—
6.625% senior notes due 2020		1,300			1,300
6.875% senior notes due 2020		500			500
6.125% senior notes due 2021		1,000			1,000
2.75% contingent convertible senior notes due 2035(c)		396			396
2.5% contingent convertible senior notes due 2037(c)		1,168			1,168
2.25% contingent convertible senior notes due 2038(c)		347			347
Corporate revolving bank credit facility		—			1,719
Midstream revolving bank credit facility		—			1
Oilfield services revolving bank credit facility		262			29
Discount on senior notes and term loans(d)		(584	)		(490	)
Interest rate derivatives(e)		23			28
Total long-term debt, net	$	14,329		$	10,626

(a) The principal amount shown is based on the exchange rate of $1.2668 to €1.00 and $1.2973 to €1.00 as of June 30, 2012 and December 31, 2011, respectively. See Note 7 for information on our related foreign currency derivatives.

(b) Issuers are Chesapeake Oilfield Operating, L.L.C. (COO) and Chesapeake Oilfield Finance, Inc. (COF), a wholly owned subsidiary of COO formed solely to facilitate the offering of the 6.625% Senior Notes due 2019. COF is nominally capitalized and has no operations or revenues. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes.

(c) 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 second quarter of 2012, 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 third quarter of 2012 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

12

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 in which 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	$        48.51	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$        63.93	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$      107.27	June 14, 2019

(d) Discount as of June 30, 2012 and December 31, 2011 included $411 million and $444 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is based on an effective yield method.

(e) See Note 7 for further discussion related to these instruments.

Term Loans

In May 2012, we entered into $4.0 billion of unsecured term loans under a credit agreement that provides for term loans in an aggregate principal amount of $4.0 billion. The net proceeds of the term loans of approximately $3.789 billion after discount, customary fees and syndication costs were used to repay borrowings under our corporate revolving credit facility and for general corporate purposes. The term loans were issued at a discount of 3%, or $120 million, and the customary fees and syndication costs incurred were approximately $91 million. Amounts borrowed under the term loan credit agreement bear interest, at our option, at either (a) the Eurodollar rate, which is based on the London Interbank Offered Rate (LIBOR), plus a margin (as described below) or (b) a base rate equal to the greater of (i) the prime rate quoted in the Wall Street Journal, (ii) the federal funds effective rate plus 0.50% per annum and (iii) the Eurodollar rate that would be applicable to a Eurodollar loan with an interest period of one month plus 1% per annum, in each case, plus a margin. The Eurodollar rate is subject to a floor of 1.50% per annum and the base rate is subject to a floor of 2.50% per annum. Interest is payable quarterly or, if the Eurodollar rate applies, it may be payable at more frequent intervals. The initial applicable margin for Eurodollar loans is 7.0% per annum and the initial applicable margin for base rate loans is 6.0% per annum. If any amounts remain outstanding under the term loan credit agreement following January 1, 2013, the applicable margin under the term loan credit agreement will increase to 10.0% per annum for Eurodollar loans and to 9.0% per annum for base rate loans. Due to the escalating rate characteristic of the loan, we recognize interest expense using the interest method which, based on the current applicable interest rates, yields an 11.16% interest rate over the loan term. To the extent interest rates increase above the current applicable rates, the increase will be accounted for in the respective period.

Amounts outstanding under the term loan credit agreement are unconditionally guaranteed on a joint and several basis by certain of the Company’s direct and indirect wholly owned subsidiaries (including the subsidiaries that are subsidiary guarantors under our corporate revolving bank credit facility). The term loans are not secured by any assets of the Company or its subsidiaries.

The term loans, which rank equally in right of payment with our outstanding senior notes, mature on December 2, 2017 and may be repaid, in whole or in part, at any time in 2012 without premium or penalty. On and following January 1, 2013, we are required to pay a yield maintenance premium, equal to the present value of all interest payments that would have been made in respect of the principal of such loans from the date of such prepayment to maturity, in connection with any prepayment (including the prepayments described in the following paragraph) prior to December 2, 2017.

The term loan credit agreement contains negative covenants substantially similar to those contained in the Company’s corporate revolving bank credit facility, including covenants that limit our ability to incur indebtedness, grant liens, make investments, loans and restricted payments and enter into certain business combination transactions. Other covenants include additional restrictions on the incurrence of certain unsecured indebtedness, the incurrence of secured indebtedness, the increase of dividends or payment of special dividends, investments in unrestricted subsidiaries and designations of subsidiaries as unrestricted subsidiaries. The term loan credit agreement also contains a covenant that requires that the

13

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

net cash proceeds from certain asset dispositions and other asset sales, including assets of the Company or its subsidiaries in the Permian Basin in Texas and New Mexico, and certain financing transactions (both subject to certain thresholds and exceptions) be used to either (a) prepay loans outstanding under the term loan credit agreement or (b) reduce the commitments and repay amounts outstanding under our corporate revolving bank credit facility (or, to the extent the proceeds exceed the commitments under the revolving facility, other senior debt). If, prior to January 1, 2013, we use such designated proceeds to repay amounts outstanding under our corporate revolving bank credit facility, then the applicable margin under the term loan credit agreement will increase to 8.0% per annum for Eurodollar loans and 7.0% per annum for base rate loans. The term loan credit agreement does not contain financial maintenance covenants.

We were in compliance with all covenants under the term loan credit agreement at June 30, 2012. If we should fail to perform our obligations under the agreement, the term loans could be terminated and any outstanding borrowings under the term loan credit agreement could be declared immediately due and payable. The term loan credit 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 $125 million.

On and after May 11, 2013, the lenders will have the option (subject to certain thresholds) to exchange their loans under the term loan credit agreement for fixed rate notes (Exchange Notes). The Exchange Notes will bear interest at a fixed annual rate of 11.50%, payable semi-annually, will mature on December 2, 2017, will not be subject to any sinking fund or amortization and will contain substantially the same call protection (in the form of a customary treasury rate plus 50 basis points bond make-whole), covenants and events of default as the loans under the term loan credit agreement. The Exchange Notes will rank equally in right of payment with the loans under the term loan credit agreement.

Chesapeake Senior Notes and Contingent Convertible Senior Notes

The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured 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. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our wholly owned subsidiaries. COS Holdings, L.L.C. (COS) and its subsidiaries, CHK Utica, L.L.C., CHK Cleveland Tonkawa, L.L.C., Chesapeake Granite Wash Trust, MAC-LP L.L.C., Cardinal Gas Services, L.L.C. (Cardinal), Utica East Ohio Midstream LLC (UEOM) and certain de minimis subsidiaries are not guarantors. See Note 13 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. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale/leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the contingent convertible senior notes do not have any financial or restricted payment covenants.

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 Period, we issued $1.3 billion of 6.775% Senior Notes due 2019 in a registered public offering. We used the net proceeds of $1.263 billion from the offering to repay indebtedness outstanding under our corporate revolving bank credit facility. At any time from and including November 15, 2012 to and including March 15, 2013, we may redeem some or all of the notes at a redemption price equal to 100% of the principal amount of the notes plus accrued and unpaid interest, if any, to the redemption date; provided that upon any redemption of the notes in part (and not in whole) pursuant to this redemption provision, at least $250 million aggregate principal amount of the notes remains outstanding.

14

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

During the Prior Period, we completed and settled tender offers to purchase the following senior notes and contingent convertible senior notes. We funded the purchase of the notes with a portion of the net proceeds we received from the sale of our Fayetteville Shale assets.

	Principal Amount     Purchased
	($ in millions)
7.625% senior notes due 2013	$	36
9.5% senior notes due 2015		160
6.25% euro-denominated senior notes due 2017(a)		380
6.5% senior notes due 2017		440
6.875% senior notes due 2018		126
7.25% senior notes due 2018		131
6.625% senior notes due 2020		100
Total senior notes		1,373
2.75% contingent convertible senior notes due 2035		55
2.5% contingent convertible senior notes due 2037		210
2.25% contingent convertible senior notes due 2038		266
Total contingent convertible senior notes		531
Total	$	1,904

(a) We purchased €256 million in aggregate principal amount of our euro-denominated senior notes which had a value of $380 million based on the exchange rate of $1.4821 to €1.00. Simultaneously with our purchase of the euro-denominated senior notes, we unwound cross currency swaps for the same principal amount. See Note 7 for additional information.

We paid $2.058 billion in cash for the tender offers described above and recorded associated losses of approximately $174 million. The losses included $154 million in cash premiums, $20 million of deferred charges, $160 million of note discounts and $2 million of interest rate hedging losses, offset by $162 million of the equity component of the contingent convertible notes.

During the Prior Period, we issued $1.0 billion of 6.125% Senior Notes due 2021 in a registered public offering. We used the net proceeds of $977 million from the offering to repay indebtedness outstanding under our corporate revolving bank credit facility.

During the Prior Period, we purchased $140 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for approximately $128 million. Associated with these purchases, we recognized a loss of $2 million.

No scheduled principal payments are required under our senior notes until July 2013 when $464 million is due.

15

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

COO Senior Notes

In October 2011, our wholly owned subsidiaries, Chesapeake Oilfield Operating, L.L.C. (COO) and Chesapeake Oilfield Finance, Inc. (COF) issued $650 million principal amount of 6.625% Senior Notes due 2019 in a private placement. COO used the net proceeds of approximately $637 million from the placement to make a cash distribution to its direct parent, COS, to enable it to reduce indebtedness under an intercompany note with Chesapeake. Chesapeake then used the cash distribution to reduce indebtedness under its corporate revolving bank credit facility.

The COO senior notes are the unsecured senior obligations of COO and rank equally in right of payment with all of COO’s other existing and future senior unsecured indebtedness and rank senior in right of payment to all of its future subordinated indebtedness. The COO senior notes are jointly and severally, fully and unconditionally guaranteed by all of COO’s wholly owned subsidiaries, other than de minimis subsidiaries. The notes may be redeemed at any time at specified make-whole or redemption prices and, prior to November 15, 2014, up to 35% of the aggregate principal amount may be redeemed in connection with certain equity offerings. Holders of the COO notes have the right to require COO to repurchase their notes upon a change of control on the terms set forth in the indenture, and COO must offer to repurchase the notes upon certain asset sales. The COO senior notes are subject to covenants that may, among other things, limit the ability of COO and its subsidiaries to make restricted payments, incur indebtedness, issue preferred stock, create liens, and consolidate, merge or transfer assets.

Bank Credit Facilities

During the Current Period, we used three revolving bank credit facilities as sources of liquidity. In June 2012, we paid off and terminated our midstream credit facility. Our two remaining revolving bank credit facilities are described below.

	Corporate Credit      Facility(a)	Oilfield Services Credit       Facility(b)
	($ in millions)
Facility structure	Senior secured revolving	Senior secured revolving
Maturity date	December 2015	November 2016
Borrowing capacity	$    4,000	$    500
Amount outstanding as of June 30, 2012	$         —	$    262
Letters of credit outstanding as of June 30, 2012	$         37	$      —

(a) Borrower is Chesapeake Exploration, L.L.C.

(b) Borrower is COO.

Our corporate and oilfield services credit facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates under our corporate credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, our credit facilities do not contain provisions which would trigger an acceleration of amounts due under the respective facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

Corporate Credit Facility. Our $4.0 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the facility are secured by proved reserves 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 0.50% to 1.25% per annum according to

16

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

our senior unsecured long-term debt ratings, or (ii) the Eurodollar rate, which is based on 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% per annum. 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 and require us to maintain an indebtedness to total capitalization ratio and an indebtedness to EBITDA ratio, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at June 30, 2012. 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 $50 million or more, 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 $125 million.

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

Oilfield Services Credit Facility. Our $500 million oilfield services syndicated revolving bank credit facility is used to fund capital expenditures and for general corporate purposes associated with our oilfield services operations. Borrowings under the oilfield services credit facility are secured by all of the assets of the wholly owned subsidiaries of COO, itself a wholly owned subsidiary of Chesapeake. The facility has initial commitments of $500 million and may be expanded to $900 million at COO’s option, subject to additional bank participation. Borrowings under the credit facility are secured by all of the equity interests and assets of COO and its wholly owned subsidiaries (the restricted subsidiaries), and bear interest at our option at either (i) the greater of the reference rate of Bank of America, N.A., the federal funds effective rate plus 0.50%, and one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.00% to 1.75% per annum, or (ii) the Eurodollar rate, which is based on LIBOR plus a margin that varies from 2.00% to 2.75% per annum. The unused portion of the credit facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum. Both margins and commitment fees are determined according to the most recent leverage ratio described below. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The oilfield services credit facility agreement contains various covenants and restrictive provisions which limit the ability of COO and its restricted subsidiaries to incur additional indebtedness, make investments or loans and create liens. The agreement requires maintenance of a leverage ratio based on the ratio of lease adjusted indebtedness to EBITDAR, a senior secured leverage ratio based on the ratio of secured indebtedness to EBITDA and a fixed charge coverage ratio based on the ratio of EBITDAR to lease adjusted interest expense, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at June 30, 2012. If COO 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 oilfield services credit facility agreement also has cross default provisions that apply to other indebtedness COO and its restricted subsidiaries may have from time to time with an outstanding principal amount in excess of $15 million.

Midstream Credit Facility. Prior to June 15, 2012, we utilized a $600 million midstream syndicated senior secured revolving bank credit facility to fund capital expenditures to build natural gas gathering and other systems in support of our drilling program and for general corporate purposes associated with our midstream operations. With the anticipated sale of our midstream business in the second half of 2012, on June 15, 2012, we paid off and terminated our midstream credit facility.

17

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4. Contingencies and Commitments

Contingencies

Litigation and Regulatory Inquiries

The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek an indeterminate amount of damages. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. We account for legal defense costs in the period the costs are incurred.

July 2008 Common Stock Offering. 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. On September 2, 2010, the court denied the defendants’ motion to dismiss, and the court certified the class on March 30, 2012. Defendants moved for summary judgment on grounds of loss causation and materiality on December 16, 2011, and the plaintiff filed an Opposition on May 18, 2012. Discovery in the case is proceeding. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with the case. A derivative action was also filed in the District Court of Oklahoma County, Oklahoma on March 10, 2009 against certain current and former directors and officers of the Company asserting breaches of fiduciary duties relating to alleged material omissions in the registration statement for the July 2008 offering. The derivative action was stayed pursuant to stipulation. A second derivative action relating to the July 2008 offering was filed against certain current and former directors and officers of the Company in the U.S. District Court for the Western District of Oklahoma on September 6, 2011. This action also asserts breaches of fiduciary duties with respect to alleged material omissions in the offering registration statement. The Company filed a motion to dismiss the action on November 30, 2011, which is pending. Chesapeake is named as a nominal defendant in both derivative actions.

2008 CEO Compensation and Related Party Transaction. 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, among other things, breaches of fiduciary duties relating to the 2008 compensation of the Company’s CEO, Aubrey K. McClendon, and seeking unspecified damages, equitable relief and disgorgement. These three derivative actions were consolidated and a Consolidated Derivative Shareholder Petition naming Chesapeake as a nominal defendant was filed on June 23, 2009. Chesapeake’s motion to dismiss was granted on February 26, 2010, and the Oklahoma Court of Civil Appeals affirmed the dismissal on August 26, 2011. The plaintiffs filed a petition for writ of certiorari with the Oklahoma Supreme Court on September 13, 2011.

On January 30, 2012, the District Court of Oklahoma County, Oklahoma approved a settlement between the parties in the consolidated derivative action, as well as a case on appeal at the Oklahoma Court of Civil Appeals requesting inspection of Company books and records relating to the December 2008 employment agreement with Mr. McClendon. The principal terms of the settlement include the rescission of the sale of an antique map collection that occurred in December 2008 between Mr. McClendon and the Company, whereby Mr. McClendon will pay the Company approximately $12 million plus interest and the Company will reconvey the map collection to Mr. McClendon, and the adoption and/or implementation of a

18

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

variety of corporate governance measures. The court awarded attorney fees and expenses to plaintiffs’ counsel in the amount of $3,750,000 that was paid by Chesapeake. Pursuant to the settlement, the consolidated derivative action and books and records action were dismissed with prejudice against all defendants. On February 29, 2012, certain shareholders filed a petition in error with the Oklahoma Supreme Court opposing the terms of the settlement and on March 20, 2012 Chesapeake responded.

On September 6 and 8, 2011, in separate derivative actions filed in the U.S. District Court for the Western District of Oklahoma against certain of the Company’s current and former directors, two shareholders alleged that the Chesapeake board wrongfully refused their demands to investigate purported breaches of fiduciary duties relating to Mr. McClendon’s 2008 compensation and, as a result, each of these shareholders asserts he is entitled to seek relief on behalf of the Company. These federal derivative actions were consolidated on December 23, 2011 and on March 14, 2012 were stayed until 30 days after the Supreme Court of Oklahoma resolves the appeal of the settlement of the consolidated derivative action and books and records action.

FWPP, Conflict of Interest and Other Matters. From April 19 to June 29, 2012, 13 substantially similar shareholder actions were filed in the U.S. District Court for the Western District of Oklahoma against the Company and its directors alleging, among other things, violations of Section 14 of the Securities Exchange Act of 1934 and Rule 14a-9 promulgated thereunder for purported material misstatements in the Company’s 2009 and subsequent proxy statements related to Mr. McClendon’s participation in the Founder Well Participation Program (FWPP) and breaches of fiduciary duties, corporate waste, and unjust enrichment against the Board for failing to make proper disclosures in the proxy statements and failing to properly monitor Mr. McClendon’s personal use of assets acquired pursuant to the FWPP. On July 13, 2012, these 13 shareholder actions were consolidated into a single case. On April 27, 2012, a shareholder derivative action was filed in the District Court of Oklahoma County, Oklahoma setting forth substantially similar claims to those alleged in the federal shareholder actions.

A putative class action was filed in the U.S. District Court for the Western District of Oklahoma on April 26, 2012 against the Company and certain of its officers and directors alleging violations of Sections 10(b) (and Rule 10b-5 promulgated thereunder) and 20(a) of the Securities Exchange Act of 1934 for purported misstatements and omissions concerning Mr. McClendon’s participation in the FWPP and his related financing arrangements, the Company’s volumetric production payment (VPP) transactions, and potential conflicts of interest related to Mr. McClendon’s personal hedging activities and association with a hedge fund. The action seeks class certification, damages of an unspecified amount and attorneys’ fees and other costs. On July 20, 2012, a lead plaintiff was appointed and a consolidated amended complaint is expected to be filed in the next 60 days. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with the case.

The Board of Directors is conducting an internal review of the financing arrangements between Mr. McClendon (and the entities through which he participates in the FWPP) and any third party that has had or may have a relationship with the Company in any capacity. In conjunction with Mr. McClendon’s employment agreement with the Company, the FWPP provides Mr. McClendon a contractual right through June 2014 to participate and invest as a working interest owner (with up to a 2.5% working interest) in new wells drilled on the Company’s leasehold.

On June 19, July 17 and July 20, 2012, putative class actions were filed in the U.S. District Court for the Western District of Oklahoma against the Company, Chesapeake Energy Savings and Incentive Stock Bonus Plan (the Plan), and certain of the Company’s officers and directors alleging breaches of fiduciary duties under the Employee Retirement Income Security Act (ERISA). The actions are brought on behalf of participants and beneficiaries of the Plan, and allege that as fiduciaries of the Plan, defendants owed fiduciary duties, which they purportedly breached by, among other things, failing to manage and administer the Plan’s assets with appropriate skill and care, failing to disclose material information concerning such matters as Mr. McClendon’s participation in the FWPP and his related financing arrangements and the Company’s VPP transactions, engaging in activities that were in conflict with the best interest of the Plan, and permitting the Plan to over-concentrate in Chesapeake stock. The plaintiffs seek class certification, damages of an unspecified amount, equitable relief, and attorneys’ fees and other costs. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with these cases.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

On May 2, 2012, Chesapeake and Mr. McClendon received notice from the U.S. Securities and Exchange Commission that its Fort Worth Regional Office has commenced an informal inquiry into, among other things, certain of the matters alleged in the foregoing lawsuits. The Company and Mr. McClendon are providing information in response to the SEC’s inquiry. The Company has also received inquiries from other governmental and regulatory agencies and self-regulatory organizations concerning such matters and is responding to such inquiries.

Director and Officer Use of Company Aircraft. On May 8, 2012, a derivative action was filed in the District Court of Oklahoma County, Oklahoma against the Company’s directors alleging, among other things, breaches of fiduciary duties and corporate waste related to the Company’s officers and directors’ use of the Company’s fractionally owned corporate jets. The Company filed a motion to dismiss the action on June 22, 2012. Chesapeake is named a nominal defendant in the derivative action. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with the case.

Antitrust Investigation. On June 29, 2012, Chesapeake received a subpoena duces tecum from the Antitrust Division, Midwest Field Office of the U.S. Department of Justice. The subpoena requires the Company to produce certain documents before a grand jury in the Western District of Michigan, which is conducting an investigation into possible violations of antitrust laws in connection with the purchase and lease of oil and gas rights. The Company has also received demands for documents and information from state governmental agencies in connection with other investigations relating to the Company’s purchase and lease of oil and gas rights. Chesapeake intends to provide information in response to these investigations, and its Board of Directors is conducting an internal review of the matter.

Business Operations. Chesapeake is 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 contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their natural gas and oil 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 successfully defended a number of these cases in various courts, has settled others and believes that it has substantial defenses to the claims made in those pending at the trial court and on appeal. In providing for a loss contingency associated with a lawsuit seeking specific performance of a contract to acquire natural gas and oil properties, we increase natural gas and oil properties by the amount of the purchase price set forth in the contested contract or some lesser amount based on settlement negotiations or other factors relevant to estimating a reasonably possible loss. We have increased natural gas and oil properties by the full amount of a judgment entered in July 2012 against us in an action for specific performance of 2008 contracts to purchase natural gas and oil properties for $101 million in addition to recording prejudgment interest. The action was remanded following the reversal on appeal of the original trial court’s holding that the contracts were not enforceable, Enforcement of the judgment has been stayed, and we intend to file a motion for new trial or motion to amend the judgment.

Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute incidental to the Company’s business operations is likely to have a material adverse effect on its 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.

Environmental Risk

Due to the nature of the natural gas and oil business, Chesapeake and its subsidiaries are exposed to environmental risks. Chesapeake has implemented various policies and procedures to reduce and mitigate such environmental risks. 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. 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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

There are presently pending against us orders for compliance initiated in the 2010 fourth quarter by the U.S. Environmental Protection Agency (EPA) related to our compliance with Clean Water Act (CWA) permitting requirements in West Virginia. We have responded to all pending orders and are actively working with the EPA to resolve these matters. For four of the sites subject to EPA orders for compliance, we have also received and have responded to a subpoena requesting documents issued by the grand jury of the U.S. District Court for the Northern District of West Virginia. We understand that the U.S. Department of Justice is investigating possible criminal violations of and liabilities under the CWA with respect to one of the four sites. We are cooperating with the DOJ’s investigation. The CWA provides authority for significant civil and criminal penalties for the placement of fill in a jurisdictional stream or wetland without a permit from the Army Corps of Engineers. CWA civil penalties can be as high as $37,500 per day, per violation, and possible criminal penalties range from $2,500 to $25,000 per day, per violation, for misdemeanor liability (i.e., criminally negligent conduct) and from $5,000 to $50,000 per day, per violation, for felony liability (i.e., knowing conduct). The CWA sets forth subjective criteria, including degree of fault and history of prior violations, that influence CWA penalty assessments, and the EPA may also seek to recover the economic benefit derived from non-compliance. While we expect that resolution of the EPA’s compliance orders and the DOJ’s investigation under the CWA will each include monetary sanctions exceeding $100,000, following discussions with the DOJ and EPA, we believe the liability with respect to these matters will not have a material effect on the consolidated financial position, results of operations or cash flow of the Company.

Commitments

Rig Leases

In a series of transactions beginning in 2006, our drilling subsidiaries have sold 92 drilling rigs (net of two repurchased rigs) and related equipment for $791 million and entered into master lease agreements under which we agreed to lease the rigs from the buyer for initial terms of five to ten years. The lease obligations are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks and any related net gains are amortized to oilfield services expenses over the lease term. Under the leases, we can exercise an early purchase option or we can purchase the rigs at the expiration of the lease for the fair market value at the time. In addition, in most cases we have the option to renew the lease for negotiated new terms at the expiration of the lease. Commitments related to rig lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of June 30, 2012, the minimum aggregate undiscounted future rig lease payments were approximately $389 million.

Chesapeake has contracts with various drilling contractors to lease approximately 33 rigs with terms ranging from six months to three years. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of June 30, 2012, the aggregate undiscounted minimum future drilling rig commitment was approximately $287 million.

Compressor Leases

Through various transactions beginning in 2007, our compression subsidiary has sold 2,542 compressors (net of 11 repurchased units), a significant portion of its compressor fleet, for $634 million and entered into a master lease agreement. The term of the agreement varies by buyer ranging from four to ten years. The lease obligations are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks and any related net gains are amortized to marketing, gathering and compression expenses over the lease term. Under the leases, we can exercise an early purchase option or we can purchase the compressors at the expiration of the lease for the fair market value at the time. In addition, in most cases 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 June 30, 2012, the minimum aggregate undiscounted future compressor lease payments were approximately $458 million.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Gathering, Processing and Transportation Agreements

We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move certain of our production to market. Working interest owners and royalty interest owners will be responsible for their proportionate share of these costs under joint operating agreements. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying condensed consolidated balance sheets.

The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest owners, are presented below.

	June 30, 2012
	($ in millions)
2012	$	521
2013		1,216
2014		1,387
2015		1,466
2016		1,528
2017 - 2099		10,051
Total	$	16,169

Drilling Commitments

In December 2011, as part of our Utica joint venture development agreement with Total (see Note 8), we committed to spud no less than 90 cumulative Utica wells by December 31, 2012, 270 cumulative wells by December 31, 2013 and 540 cumulative wells by December 31, 2014. Through June 30, 2012, we had spud 47 cumulative Utica wells. If we fail to meet the drilling commitment at any such year end for any reason other than a force majeure event, the drilling carry percentage used to determine our promoted well reimbursement will be reduced from 60% to 45% for a number of wells drilled in the following calendar year equal to the number of wells we were short the drilling commitment. As such, any reduction would only affect the timing of the receipt of the drilling carry but not the total drilling carry to be received.

We have also committed to drill wells in conjunction with our Utica and Cleveland Tonkawa financial transactions and in conjunction with the formation of the Chesapeake Granite Wash Trust. See Note 6 for discussion of these transactions and commitments.

Natural Gas and Oil Purchase Commitments

We regularly commit to purchase natural gas and liquids from other owners in the properties we operate, including owners associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. See Note 8 for further discussion of our VPP transactions.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Net Acreage Maintenance Commitments

Under the terms of our joint venture agreements with Statoil and Total (see Note 8), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas.

Other Commitments

In April 2011, we entered into a master frac service agreement with our equity affiliate, FTS International, Inc. (FTS), which expires on December 31, 2014. Pursuant to this agreement, we are committed to enter into a predetermined number of backstop contracts if utilization of FTS fleets falls below a certain level. We have guaranteed a gross profit margin of 10% to FTS on such backstop contracts. To date, we have not entered into any backstop contracts and, since we use fracing services continuously, we do not anticipate any material payments under this commitment.

In July 2011, we agreed to invest $150 million in newly issued convertible promissory notes of Clean Energy Fuels Corp. (Nasdaq:CLNE), based in Seal Beach, California. The investment is being made in three equal $50 million promissory notes, the first two of which were issued in July 2011 and July 2012, with the remaining note scheduled to be issued in June 2013. The notes bear interest at the annual rate of 7.5%, payable quarterly, and are convertible at our option into shares of Clean Energy’s common stock at a 22.5% conversion premium over the price at the time of our original investment in July 2011, resulting in a conversion price of $15.80 per share. See Note 9 for further discussion of this investment.

In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc., a privately held cellulosic biofuels company based in Longmont, Colorado. As of June 30, 2012, we had funded $65 million of our commitment. The remaining tranches of preferred equity investment will be scheduled around certain funding and operational milestones that are expected to be reached by July 2013. See Note 9 for further discussion of this investment.

In December 2011, we sold Appalachia Midstream Services, L.L.C., a wholly owned subsidiary of our wholly owned subsidiary, Chesapeake Midstream Development, L.P. (CMD), to Chesapeake Midstream Partners, L.P. (now named Access Midstream Partners, L.P. (NYSE:ACMP)) for total consideration of $879 million, subject to a customary post-closing working capital adjustment. In addition, CMD has committed to pay ACMP for any quarterly shortfall between the actual adjusted EBITDA from the assets sold and specified quarterly targets, which total $100 million in 2012 and $150 million in 2013. We recorded this guarantee at an estimated fair value of $27 million at the time of the sale. It is included in other current and non-current liabilities on our consolidated balance sheet as of June 30, 2012. We will release this liability over the two-year term of the guarantee if the assets are meeting the specific quarterly targets. No payment was required for the Current Period, and we recognized a nominal amount of gain associated with the release of the liability related to the quarterly targets achieved in the first half of 2012. To the extent we are required to make payments under the guarantee, we will record the differences between the liability and the associated payments in earnings.

In conjunction with CMD’s investments in the newly formed entities Utica East Ohio Midstream LLC, Cardinal Gas Services L.L.C., Ranch Westex JV, LLC and Glass Mountain Pipeline, LLC, as of June 30, 2012, CMD had committed to make capital contributions to these entities totaling approximately $1.2 billion through 2014. With the anticipated 2012 third quarter sale of substantially all of our midstream business, these commitments will become the responsibility of the acquirer of our midstream business. See Notes 9 and 10 for further discussion of these investments.

In conjunction with the acceleration in October 2011 of the remaining drilling carry owed to us by Total in our Barnett Shale joint venture, we agreed to maintain our operated rig count at no less than 12 rigs in the Barnett Shale through December 31, 2012. In January 2012, Chesapeake and Total agreed to reduce the minimum rig count from 12 to six rigs. In May 2012, Chesapeake and Total agreed to further reduce the minimum rig count from six to two rigs.

23

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As part of our normal course of business, we enter into various agreements providing, or otherwise arranging, financial or performance assurances to third parties on behalf of our consolidated subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.

In connection with our purchase and sale agreements, we have frequently provided for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party or in regards to perfecting title to property. These indemnifications generally have a discrete term and are intended to protect the parties against the risks that are difficult to predict or cannot be quantified at the time of the consummation of a particular transaction.

Certain of our natural gas and oil properties are burdened by non-operating interests such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which such interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to such interests. See Note 8 for further discussion of our VPP transactions

5. Other Long-Term Liabilities

Other long-term liabilities as of June 30, 2012 and December 31, 2011 are detailed below.

	June 30, 2012	December 31,  2011
	($ in millions)
CHK Utica ORRI conveyance obligation(a)	$                 283	$                  290
CHK C-T ORRI conveyance obligation(b)	175	—
Financing lease obligations(c)	143	143
Revenues and royalties due others	114	109
Mortgages payable(d)	56	56
Other	211	220
Total other long-term liabilities	$                 982	$                  818

(a) $15 million and $10 million of the total $298 million and $300 million obligation are recorded in other current liabilities as of June 30, 2012 and December 31, 2011, respectively. See Note 6 for further discussion of the transaction.

(b) $14 million of the total $189 million obligation is recorded in other current liabilities. See Note 6 for further discussion of the transaction.

(c) 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 consolidated balance sheet. Chesapeake exercised its option to repurchase two of the assets in 2010 and one of the assets in 2011.

(d) In 2009, we financed our regional Barnett Shale headquarters building in Fort Worth, Texas for net proceeds of 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. The payment obligation is guaranteed by Chesapeake. As of June 30, 2012, our Barnett Shale headquarters building was classified as property and equipment held for sale on our condensed consolidated balance sheet.

24

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6. Stockholders’ Equity, Restricted Stock, Stock Options and Noncontrolling Interests

Common Stock

The following is a summary of the changes in our common shares issued for the six months ended June 30, 2012 and 2011:

	2012		2011
	(in thousands)
Shares issued at January 1		660,888		655,251
Restricted stock issuances (net of forfeitures)		3,063		3,543
Stock option exercises		244		314
Shares issued at June 30		664,195		659,108

Preferred Stock

The following reflects our preferred shares outstanding for the six months ended June 30, 2012 and 2011:

	5.75%		5.75% (A)		4.50%		5.00%   (2005B)
	(in thousands)
Shares outstanding at January 1, 2012 and June 30, 2012		1,497		1,100		2,559		2,096
Shares outstanding at January 1, 2011 and June 30, 2011		1,500		1,100		2,559		2,096

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.

Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Stock-Based Compensation

Chesapeake’s stock-based compensation program consists of restricted stock and, prior to 2006, stock options issued to employees and non-employee directors. We recognize in our financial statements the cost of employee services received in exchange for awards of equity instruments based on the fair value of the equity instruments at the date of the grant. This value is amortized over the vesting period, which is generally four years from the date of grant for employees and three years for non-employee directors. To the extent compensation cost relates to employees directly involved in natural gas and oil acquisition, divestiture, exploration and development activities, such amounts are capitalized to natural gas and oil properties. Amounts not capitalized to natural gas and oil properties are recognized as general and administrative expenses, natural gas, oil and NGL production expenses, marketing, gathering and compression expenses or oilfield services expenses. We recorded the following stock-based compensation during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	($ in millions)
Natural gas and oil properties	$	18	$	29	$	38	$	60
General and administrative expenses		20		23		38		47
Natural gas, oil and NGL production expenses		5		9		12		18
Marketing, gathering and compression expenses		4		4		8		9
Oilfield services expenses		2		2		5		5
Total	$	49	$	67	$	101	$	139

Restricted Stock. Chesapeake began issuing shares of restricted common stock to employees in January 2004 and to non-employee directors in July 2005. A summary of the changes in unvested shares of restricted stock for the Current Period is presented below.

	Number of     Unvested Restricted Shares			Weighted Average Grant-Date Fair Value
	(in thousands)
Unvested shares as of January 1, 2012		19,544		$  26.97
Granted		4,955		$  23.32
Vested		(3,732	)	$  27.17
Forfeited		(610	)	$  26.10
Unvested shares as of June 30, 2012		20,157		$  26.06

The aggregate intrinsic value of restricted stock vested during the Current Period was approximately $85 million based on the stock price at the time of vesting.

As of June 30, 2012, there was $335 million of total unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted average period of approximately 2.5 years.

The vesting of certain restricted stock grants could result 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, the Current Period and the Prior Period, we recognized reductions in tax benefits related to restricted stock of $1 million, $5 million and $1 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes. During the Prior Quarter, we recognized excess tax benefits of a nominal amount.

26

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 of our outstanding stock options are fully vested and exercisable.

The following table provides information related to stock option activity for the Current Period:

	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, 2012		1,051		$    9.84	1.41	$    13
Exercised		(248	)	$    6.41
Outstanding and exercisable at June 30, 2012		803		$  10.91	1.13	$    6

(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.

There is no remaining unrecognized compensation cost related to unvested stock options.

During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized excess tax benefits related to stock options of $1 million, $2 million, $1 million and $3 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.

Noncontrolling Interests

Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our natural gas and oil assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our corporate credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the Cleveland and Tonkawa plays covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 net wells to be drilled on certain of our Cleveland and Tonkawa play leasehold (approximately 1,144 total net wells). Subject to customary minority interest protections afforded the investors by the terms of the CHK C-T limited liability company agreement (the CHK C-T LLC Agreement), as the holder of all the common shares and the sole managing member of CHK C-T, we maintain voting and managerial control of CHK C-T and therefore include it in our condensed consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $225 million to the ORRI obligation and $1.025 billion to the preferred shares based on estimates of fair values. The ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our condensed consolidated balance sheet. Pursuant to the CHK C-T LLC Agreement, CHK C-T is currently required to retain an amount of cash (as remeasured on a quarterly basis) equal to (x) the next two quarters of preferred dividend payments plus (y) its projected capital and operating expenditures for the next six months (net of its projected net revenues during such six-month period). The amount so retained, approximately $180 million as of June 30, 2012, is reflected as restricted cash on our condensed consolidated balance sheet.

27

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T, as determined in accordance with the CHK C-T LLC Agreement. Any such optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares unless we have not met our drilling commitment at such time, in which case such optional distributions would be allocated 100% to the preferred shares (and applied toward redemption thereof). We may also, at our sole discretion and election, in accordance with the CHK C-T LLC Agreement, cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares will be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid through redemption at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return to the investors. The preferred shares are redeemed on a pro-rata basis in accordance with the then-applicable redemption valuation formula. As of June 30, 2012, the redemption price and the liquidation preference were each $1,335 per preferred share.

We have committed to drill, for the benefit of CHK C-T in the area of mutual interest, a minimum of 37.5 net wells per six-month period through 2013, inclusive of wells drilled in the Current Period, and 25 net wells per six-month period in 2014 through 2016, up to a minimum cumulative total of 300 net wells. If we fail to meet the then-current cumulative drilling commitment in any six-month period, any optional cash distributions would be distributed 100% to the investors. If we fail to meet the then-current cumulative drilling commitment in two consecutive six-month periods, the then-applicable internal rate of return to investors at redemption would increase by 3% per annum. In addition, if we fail to meet the then-current cumulative drilling commitment in four consecutive six-month periods, the then-applicable internal rate of return to investors at redemption would be increased by an additional 3% per annum. Any such increase in the internal rate of return would be effective only until the end of the first succeeding six-month period in which we have met our then-current cumulative drilling commitment. CHK C-T is responsible for all capital and operating costs of the wells drilled for the benefit of the entity.

The CHK C-T investors’ right to receive, proportionately, a 3.75% ORRI in approximately 1,144 net wells, inclusive of contributed wells, on our Cleveland and Tonkawa leasehold is subject to an increase to 5% in any year following a year in which we do not meet our commitment to drill the wells subject to the ORRI obligation, which runs from 2012 through the first quarter of 2025. However, in no event would we deliver to investors more than a total ORRI of 3.75% in 1,144 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 160-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of such remaining net wells. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of such remaining net wells once we have drilled a minimum of 867 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our natural gas and oil properties.

As of June 30, 2012, $1.015 billion was recorded as noncontrolling interests on our condensed consolidated balance sheet representing the third-party investments in CHK C-T. For the Current Quarter and the Current Period, $19 million of income was attributable to the noncontrolling interests of CHK C-T. Under the development agreement, approximately 17 and 39 qualified net wells were added in the Current Quarter and Current Period, respectively, fulfilling the 2012 mid-year drilling obligation.

28

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale natural gas and oil assets. CHK Utica is an unrestricted subsidiary under our corporate credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including under our indentures. In exchange for all of the common shares of CHK Utica, we contributed to CHK Utica approximately 700,000 net acres of leasehold and the existing wells within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold. Subject to customary minority interest protections afforded the investors by the terms of the CHK Utica limited liability company agreement (the CHK Utica LLC Agreement), as the holder of all the common shares and the sole managing member of CHK Utica, we maintain voting and managerial control of CHK Utica and therefore include it in our condensed consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $300 million to the ORRI obligation and $950 million to the preferred shares based on estimates of fair values. The ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our condensed consolidated balance sheet. Pursuant to the CHK Utica LLC Agreement, CHK Utica is required to retain the next two quarters of preferred dividend payments. The amount reserved for paying such dividends, approximately $44 million, is reflected as restricted cash on our condensed consolidated balance sheet as of June 30, 2012.

Dividends on the preferred shares are payable on a quarterly basis at a rate of 7% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. If we fail to meet the then-current drilling commitment in any year, we must pay CHK Utica $5 million for each well we are short of such drilling commitment. As the managing member of CHK Utica, we may, at our sole discretion and election at any time after December 31, 2013, distribute certain excess cash of CHK Utica, as determined in accordance with the CHK Utica LLC Agreement. Any such optional distribution of excess cash is allocated 70% to the preferred shares (which is applied toward redemption of the preferred shares) and 30% to the common shares unless we have not met our drilling commitment at such time, in which case such optional distributions would be allocated 100% to the preferred shares (and applied toward redemption thereof). We may also, at our sole discretion and election, in accordance with the CHK Utica LLC Agreement, cause CHK Utica to redeem the CHK Utica preferred shares for cash, in whole or in part. The preferred shares will be redeemed at a valuation equal to the greater of a 10% internal rate of return or a return on investment of 1.4x, in each case inclusive of dividends paid at the rate of 7% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to October 31, 2018, the optional redemption valuation will increase to the greater of a 17.5% internal rate of return or a return on investment of 2.0x. The preferred shares are redeemed on a pro-rata basis in accordance with the then-applicable redemption valuation formula. As of June 30, 2012, the redemption price and the liquidation preference were each approximately $1,357 per preferred share.

We have committed to drill, for the benefit of CHK Utica in the area of mutual interest, a minimum of 50 net wells per year from 2012 through 2016, up to a minimum cumulative total of 250 net wells. CHK Utica is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. CHK Utica also receives its proportionate share of the benefit of the drilling carry associated with our joint venture with Total in the Utica Shale. See Note 8 for further discussion of the joint venture.

29

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% in any year following a year in which we do not meet our commitment to drill the wells subject to the ORRI obligation, which runs from 2012 through 2023. However, in no event would we deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of such remaining net wells. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of such remaining net wells once we have drilled a minimum of 1,300 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our natural gas and oil properties.

As of June 30, 2012 and December 31, 2011, $950 million was recorded as noncontrolling interests on our condensed consolidated balance sheets representing the third-party investments in CHK Utica. For the Current Quarter and the Current Period, income of approximately $22 million and $44 million, respectively, was attributable to the noncontrolling interests of CHK Utica. Under the development agreement, approximately 19 and 37 qualified net wells were added in the Current Quarter and Current Period, respectively.

Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding.

In connection with the initial public offering of the Trust, we conveyed royalty interests to the Trust that entitle the Trust to receive (i) 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) that we receive from the production of hydrocarbons from 69 producing wells, and, (ii) 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) in 118 development wells that have been or will be drilled on approximately 45,400 gross acres (29,300 net acres) in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma. Pursuant to the terms of a development agreement with the Trust, we are obligated to drill, or cause to be drilled, the development wells at our own expense prior to June 30, 2016, and the Trust will not be responsible for any costs related to the drilling of the development wells or any other operating or capital costs of the Trust properties. In addition, we granted to the Trust a lien on our remaining interests in the undeveloped properties that are subject to the development agreement in order to secure our drilling obligation to the Trust, although the maximum amount that may be recovered by the Trust under such lien could not exceed $263 million initially and is proportionately reduced as we fulfill our drilling obligation over time. As of June 30, 2012, we had drilled or caused to be drilled 32 development wells and the maximum amount recoverable under the drilling support lien was approximately $190 million.

30

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for such quarter. If there is not sufficient cash to fund such a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to satisfy our drilling obligation and perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for such quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold will be paid to Trust unitholders, including Chesapeake, on a pro rata basis. At the end of the fourth full calendar quarter following our satisfaction of our drilling obligation with respect to the development wells, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After such time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis.

On May 10, 2012, the Trust declared a cash distribution of approximately $31 million, or $0.66 per unit, for the three-month period ended March 31, 2012 and covering production for the period from December 1, 2011 to February 29, 2012. The distribution was paid on May 31, 2012 to record unitholders as of May 21, 2012. This distribution was above the subordination threshold and below the incentive threshold. The distribution was allocated equally among all unitholders in proportion to their unit ownership, with $16 million paid to Chesapeake and $15 million paid to third-party unitholders.

We have determined that the Trust constitutes a VIE and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our condensed consolidated financial statements. As of June 30, 2012 and December 31, 2011, $375 million and $380 million, respectively, were recorded as noncontrolling interests on our condensed consolidated balance sheets representing the public unitholders’ investment in common units of the Trust. For the Current Period, approximately $27 million of income was attributable to the Trust’s noncontrolling interests in our condensed consolidated statement of operations. See Note 10 for further discussion of VIEs.

Cardinal Gas Services, L.L.C. Cardinal Gas Services, L.L.C. (Cardinal), an unrestricted, non-guarantor consolidated subsidiary, was formed in December 2011 to acquire, develop, operate and own midstream assets in the Utica Shale. In exchange for the contribution of approximately $14 million in midstream assets to Cardinal, we received 66% of the outstanding membership units of Cardinal. In exchange for approximately $5 million, Total E&P USA, Inc. (Total) received 25% of the outstanding membership units and in exchange for approximately $2 million, CGAS Properties, L.P. (CGAS), an affiliate of Enervest, Ltd., received 9% of the membership units. We have determined that Cardinal constitutes a VIE and that Chesapeake is the primary beneficiary. As a result, Cardinal is included in our condensed consolidated financial statements. The contributions from Total and CGAS were recorded as noncontrolling interests. Each member is responsible for its proportionate share of capital costs. As of June 30, 2012 and December 31, 2011, the noncontrolling interest balances on the condensed consolidated balance sheets associated with the contributions from Total and CGAS were approximately $20 million and $7 million, respectively. For the Current Period, a nominal loss was attributable to Cardinal’s noncontrolling interests in our condensed consolidated statement of operations.

31

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7. Derivative and Hedging Activities

Natural Gas, Oil and NGL Derivatives

Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. 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 prices to be received for our hedged production. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives. As of June 30, 2012 and December 31, 2011, our natural gas, oil and NGL derivative instruments consisted 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.

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

— Swaptions: Chesapeake sells swaptions to counterparties that allow them, on a specific date, to extend an existing fixed-price swap for a certain period of time.

— 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 a certain pre-determined knockout price.

— Basis Protection Swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. Our basis protection swaps 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.

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.

The estimated fair values of our natural gas, oil and NGL derivative instruments as of June 30, 2012 and December 31, 2011 are provided below.

	June 30, 2012					December 31, 2011
	Volume		Fair Value			Volume		Fair Value
			($ in millions)					($ in millions)
Natural gas (tbtu):
Fixed-price swaps		187	$	1			—	$	—
Call options		1,114		(237	)		1,357		(284	)
Basis protection swaps		140		(32	)		106		(42	)
Total natural gas		1,441		(268	)		1,463		(326	)
Oil (mmbbl):
Fixed-price swaps		10.0		123			14.9		15
Call options		74.6		(770	)		94.7		(1,282	)
Swaptions		11.3		(24	)		7.8		(53	)
Fixed-price knockout swaps		—		—			0.8		7
Total oil		95.9		(671	)		118.2		(1,313	)
Total estimated fair value			$	(939	)			$	(1,639	)

32

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 recognized in natural gas, oil and NGL sales. Changes in the fair value of derivatives not designated as cash flow hedges that occur prior to their maturity (i.e., temporary fluctuations in value) are reported in the condensed consolidated statements of operations within natural gas, oil and NGL sales. We have currently elected not to designate any of our qualifying natural gas and oil derivatives as cash flow hedges. Therefore, changes in the fair value of these derivatives for the Current Period are reported in the condensed consolidated statement of operations.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
			($ in millions)
Natural gas, oil and NGL sales	$	1,112	$	1,278	$	2,334	$	2,465
Gains (losses) on natural gas, oil and NGL derivatives		1,005		506		851		(197	)
Gains (losses) on ineffectiveness of cash flow hedges		—		8		—		18
Total natural gas, oil and NGL sales	$	2,117	$	1,792	$	3,185	$	2,286

As of June 30, 2012, we expect to transfer approximately $6 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months in the related month of production. All derivative instruments as of June 30, 2012 are expected to mature by December 31, 2022.

Hedging Facility

We have a multi-counterparty secured hedging facility with 18 counterparties that have committed to provide approximately 6.5 tcfe of hedging capacity for natural gas, oil and NGL price derivatives and 6.5 tcfe for basis derivatives with an aggregate mark-to-market capacity of $17.5 billion under the terms of the facility. As of June 30, 2012, we had hedged under the facility 1.9 tcfe of our future production with price derivatives and 0.1 tcfe with basis derivatives. The multi-counterparty facility allows us to enter into cash-settled natural gas, oil and NGL price and basis derivatives with the counterparties. Our obligations under the multi-counterparty facility are secured by proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times at semi-annual collateral dates and 1.30 times in between those dates, and guarantees by certain subsidiaries that also guarantee our corporate revolving bank credit facility, indentures and sale/leaseback arrangements. 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 derivatives. In addition, there are volume-based sub-limits for natural gas, oil and NGL derivative instruments. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain requirements are met including maintaining specified collateral coverage ratios as well as maintaining credit ratings with either of the designated rating agencies at or above current levels. The facility does not have a maturity date. Counterparties to the agreement have the right to cease entering into derivative instruments with the Company on a prospective basis as long as obligations associated with any existing transactions in the facility continue to be satisfied in accordance with the terms of the agreement.

33

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Interest Rate Derivatives

To mitigate a portion of our exposure to volatility in interest rates related to our senior notes and bank credit facilities, we enter into interest rate derivatives. As of June 30, 2012 and December 31, 2011, our interest rate derivative instruments consisted 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.

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

The notional amount and the estimated fair value of our interest rate derivatives outstanding as of June 30, 2012 and December 31, 2011 are provided below.

	June 30, 2012					December 31, 2011
	Notional     Amount		Fair       Value			Notional     Amount		Fair       Value
			($ in millions)
Interest rate:
Swaps	$	1,050	$	(41	)	$	1,050	$	(42	)
Swaptions		250		—			300		—
Totals	$	1,300	$	(41	)	$	1,350	$	(42	)

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, the Prior Quarter, the Current Period and the Prior Period are presented below.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
				($ in millions)
Interest expense on senior notes	$	185		$	164		$	359		$	342
Interest expense on credit facilities		16			10			37			31
Interest expense on term loans		62			—			62			—
(Gains) losses on interest rate derivatives		(7	)		19			(2	)		18
Amortization of loan discount and other		42			8			42			23
Capitalized interest		(284	)		(176	)		(472	)		(381	)
Total interest expense	$	14		$	25		$	26		$	33

We have terminated certain fair value hedges related to senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next nine years, we will recognize $23 million in gains related to such transactions.

Foreign Currency Derivatives

In December 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 cross currency swaps to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. In May 2011, we purchased and subsequently retired €256 million in aggregate principal amount of these senior notes following a tender offer, and we simultaneously unwound the cross currency swaps for the same

34

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

principal amount. As a result, we reclassified a loss of $38 million from accumulated other comprehensive income to the condensed consolidated statement of operations, $20 million of which related to the unwound notional amount and was included in losses on purchases or exchanges of debt, and $18 million of which related to future interest associated with the unwound principal and was included in interest expense. Under the terms of the remaining cross currency swaps, on each semi-annual interest payment date, the counterparties pay Chesapeake €11 million and Chesapeake pays the counterparties $17 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay Chesapeake €344 million and Chesapeake will pay the counterparties $459 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Through the cross currency swaps, we have eliminated any potential variability in Chesapeake’s expected cash flows related to changes in foreign exchange rates and therefore the swaps qualify as cash flow hedges. The fair values of the cross currency swaps are recorded on the condensed consolidated balance sheet as a liability of $48 million at June 30, 2012. The euro-denominated debt in long-term debt has been adjusted to $435 million at June 30, 2012 using an exchange rate of $1.2668 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 sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. The derivative settlement amounts are not due until the month in which the related underlying hedged transaction occurs. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivative is deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying condensed consolidated statements of cash flows.

The following table presents the fair value and location of each classification of derivative instrument disclosed in the condensed consolidated balance sheets as of June 30, 2012 and December 31, 2011 on a gross basis without regard to same-counterparty netting:

		Fair Value
		June 30,			December 31,
	Balance Sheet Location	2012			2011
		($ in millions)
Asset Derivatives:
Derivatives not designated as hedging instruments:
Commodity contracts	Short-term derivative instruments	$	131		$	54
Commodity contracts	Long-term derivative instruments		21			1
Total			152			55
Liability Derivatives:
Derivatives designated as hedging instruments:
Foreign currency contracts	Long-term derivative instruments		(48	)		(38	)
Total			(48	)		(38	)
Derivatives not designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		(125	)		(232	)
Commodity contracts	Long-term derivative instruments		(966	)		(1,462	)
Interest rate contracts	Long-term derivative instruments		(41	)		(42	)
Total			(1,132	)		(1,736	)
Total derivative instruments		$	(1,028	)	$	(1,719	)

35

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

Fair Value Hedges

For interest rate derivative instruments designated as fair value hedges, the fair values of the hedges are recorded on the condensed consolidated balance sheets as assets or liabilities, with corresponding offsetting adjustments to the debt’s carrying value. We have currently elected not to designate any of our qualifying interest rate derivatives as fair value hedges. Therefore, changes in the fair value of all of our interest rate derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported in the condensed consolidated statements of operations within interest expense in the Current Period.

The following table presents the gain (loss) recognized in the condensed consolidated statements of operations for terminated instruments designated as fair value derivatives:

		Three Months Ended June 30,				Six Months Ended June 30,
Fair Value Derivatives	Location of Gain (Loss)	2012		2011		2012		2011
				($ in millions)
Interest rate contracts	Interest expense	$	2	$	5	$	4	$	11

We include the expense on the hedged item (i.e., fixed-rate borrowings) in the same line item – interest expense – as the offsetting gain or loss on the related interest rate swap listed above. For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, this expense was $0, $9 million, $0 and $21 million respectively.

Cash Flow Hedges

A reconciliation of the changes of accumulated other comprehensive income (loss) in the condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.

	Three Months Ended June 30,
	2012						2011
	Before Tax			After Tax			Before Tax			After Tax
				($ in millions)
Balance, beginning of period	$	(284	)	$	(176	)	$	(368	)	$	(228	)
Net change in fair value		(5	)		(3	)		220			136
Gains reclassified to income		(17	)		(11	)		(29	)		(18	)
Balance, end of period	$	(306	)	$	(190	)	$	(177	)	$	(110	)
	Six Months Ended June 30,
	2012						2011
	Before Tax			After Tax			Before Tax			After Tax
				($ in millions)
Balance, beginning of period	$	(287	)	$	(178	)	$	(291	)	$	(181	)
Net change in fair value		—			—			217			135
Gains reclassified to income		(19	)		(12	)		(103	)		(64	)
Balance, end of period	$	(306	)	$	(190	)	$	(177	)	$	(110	)

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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) related to instruments designated as cash flow derivatives:

		Three Months Ended June  30,						Six Months Ended June  30,
Cash Flow Derivatives	Location of Gain (Loss)	2012			2011			2012		2011
					($ in millions)
Gain (Loss) Recognized in   AOCI (Effective Portion):
Commodity contracts	AOCI	$	—		$	234		$	—	$	250
Foreign currency contracts	AOCI		(5	)		(14	)		—		(33	)
		$	(5	)	$	220		$	—	$	217
Gain (Loss) Reclassified   from AOCI   (Effective Portion):
Commodity contracts	Natural gas, oil and   NGL sales	$	17		$	67		$	19	$	141
Foreign currency contracts	Interest expense		—			(18	)		—		(18	)
Foreign currency contracts	Loss on purchase of debt		—			(20	)		—		(20	)
		$	17		$	29		$	19	$	103
Gain (Loss) Recognized   in Income
Commodity contracts:
Ineffective portion	Natural gas, oil and   NGL sales	$	—		$	8		$	—	$	18
Amount initially excluded   from effectiveness testing	Natural gas, oil and   NGL sales		—			—			—		22
		$	—		$	8		$	—	$	40

Undesignated Derivatives

The following table presents the gain (loss) recognized in the condensed consolidated statements of operations for instruments not designated as either cash flow or fair value derivatives:

		Three Months Ended					Six Months Ended
		June 30,					June 30,
Derivative Contracts	Location of Gain (Loss)	2012		2011			2012			2011
				($ in millions)
Commodity contracts	Natural gas, oil and   NGL sales	$	988	$	439		$	832		$	(360	)
Interest rate contracts	Interest expense		5		(6	)		(2	)		(11	)
Equity contracts	Other income		1		—			—			—
Total		$	994	$	433		$	830		$	(371	)

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Credit Risk

Derivative instruments that enable us to manage our exposure to natural gas and oil prices and interest rate volatility expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment-grade and 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 June 30, 2012, our natural gas, oil, NGL and interest rate derivative instruments were spread among 17 counterparties. Additionally, counterparties to our multi-counterparty secured hedging facility described previously are required to secure their obligations in excess of defined thresholds. We use this facility for the majority of our natural gas, oil, and NGL derivatives.

8. Acquisitions and Divestitures

Acquisition of Bronco Drilling

In June 2011, we acquired Bronco Drilling Company, Inc., a publicly traded contract land drilling services company, for an aggregate purchase price of approximately $339 million, or $11.00 per share of Bronco common stock. The acquisition was accounted for as a business combination which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Pro forma financial information is not presented as it would not be materially different from the information presented in the consolidated statement of operations.

Texoma Woodford Asset Sale

In April 2012, we sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Bryan, Carter, Johnston and Marshall counties in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for approximately $572 million in cash after certain deductions and closing costs. The properties included approximately 25 mmcfe per day of current net production. Under full cost accounting rules, we accounted for the sale of our Texoma Woodford natural gas and oil properties as an adjustment to capitalized costs, with no recognition of gain or loss. In conjunction with this transaction, affiliates of our Chief Executive Officer, Aubrey K. McClendon, sold interests in the same properties and on the same terms as those that applied to the interests sold by the Company, and proceeds were paid to the sellers based on their respective ownership. These interests were acquired through the FWPP which provides Mr. McClendon a contractual right to participate and invest as a working interest owner (with up to a 2.5% working interest) in new wells drilled on the Company’s leasehold through June 2014.

Fayetteville Shale Asset Sale

In March 2011, we sold all of our Fayetteville Shale assets in central Arkansas to BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited (NYSE:BHP; ASX:BHP), for net proceeds of approximately $4.65 billion in cash. The properties sold consisted of approximately 487,000 net acres of leasehold, net production at closing of approximately 415 million cubic feet of natural gas equivalent per day and midstream assets consisting of approximately 420 miles of pipeline. Of the total proceeds received, $350 million was allocated to our Fayetteville Shale midstream assets and a $7 million gain was recorded for the divestiture of those assets. The remainder of the proceeds was allocated to our Fayetteville Shale natural gas and oil properties. Under full cost accounting rules, we accounted for the sale of our Fayetteville Shale natural gas and oil properties as an adjustment to capitalized costs, with no recognition of gain or loss. In conjunction with this transaction, affiliates of Mr. McClendon also sold interests in the same properties that were acquired through the FWPP on the same terms as those that applied to the properties held by the Company.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Joint Ventures

As of June 30, 2012, we had entered into seven significant joint ventures with other leading energy companies pursuant to which we sold a portion of our leasehold, producing properties and other assets located in seven different resource plays and received cash of $7.1 billion and commitments for future drilling and completion cost sharing totaling $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all leasing, drilling, completion, operations and marketing activities for the project. The carry obligations paid by a joint venture partner are for a specified percentage of our drilling and completion cost obligations. In addition, a joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner. We bill our joint venture partners for their drilling carry obligations at the same time we bill them and other joint working interest owners for their share of drilling costs as they are incurred. Our joint venture transactions have allowed us to recover much or all of our initial leasehold investments and reduce our ongoing capital costs in these plays. For accounting purposes, initial cash proceeds from these joint venture transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. The transactions are detailed below.

Primary                  Play	Joint Venture Partner(a)	Joint Venture Date	Interest Sold	Cash Proceeds Received at Closing		Total Drilling Carries			Total Cash and Drilling Carry Proceeds		Drilling Carries Remaining(b)
						($ in millions)
Utica	TOT	December 2011	25.0%	$	610	$	1,422		$	2,032	$	1,351
Niobrara	CNOOC	February 2011	33.3%		570		697			1,267		519
Eagle Ford	CNOOC	November 2010	33.3%		1,120		1,080			2,200		—
Barnett	TOT	January 2010	25.0%		800		1,404	(c)		2,204		—
Marcellus	STO	November 2008	32.5%		1,250		2,125			3,375		—
Fayetteville	BP	September 2008	25.0%		1,100		800			1,900		—
Haynesville     & Bossier	PXP	July 2008	20.0%		1,650		1,508	(d)		3,158		—
				$	7,100	$	9,036		$	16,136	$	1,870

(a) Joint venture partners include Total S.A. (TOT), CNOOC Limited (CNOOC), Statoil (STO), BP America (BP) and Plains Exploration & Production Company (PXP).

(b) As of June 30, 2012. The Utica drilling carries cover 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. The Niobrara drilling carries cover 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize these drilling carry commitments prior to expiration. See Note 4 for further discussion of the Utica drilling carries.

(c) In conjunction with an agreement requiring us to maintain our operated rig count at no less than 12 rigs in the Barnett Shale through December 31, 2012, TOT accelerated the payment of its remaining joint venture drilling carry in exchange for an approximate 9% reduction in the total amount of drilling carry obligation owed to us at that time. As a result, in October 2011, we received $471 million in cash from TOT, which included $46 million of drilling carry obligation billed and $425 million for the remaining drilling carry obligation. In January 2012, Chesapeake and TOT agreed to reduce the minimum rig count from 12 to six rigs. In May 2012, Chesapeake and TOT agreed to further reduce the minimum rig count from six to two rigs.

(d) In September 2009, PXP accelerated the payment of its remaining drilling carry in exchange for an approximate 12% reduction to the remaining drilling carry obligation owed to us at that time.

During the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $518 million and $1.129 billion, respectively, in drilling and completion carries paid by our joint venture partners, CNOOC, TOT and STO.

39

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

During the Current Period, as part of our joint venture agreements with TOT and STO, we sold interests in additional leasehold in the Marcellus, Barnett and Utica shale plays for approximately $137 million. In the Prior Period, as part of our joint venture agreements with CNOOC, TOT, STO and PXP, we sold interests in additional leasehold in the Eagle Ford, Barnett, Marcellus and Haynesville and Bossier shale plays to our joint venture partners for approximately $345 million.

Volumetric Production Payments

From time to time, we have sold certain of our producing assets which are located in more mature producing regions through the sale of volumetric production payments (VPPs). A VPP is a limited-term overriding royalty interest in natural gas and oil reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain the remaining reserves, if any, after the scheduled production volumes have been delivered. We retain drilling rights on the properties below currently producing intervals and outside of producing well bores. We also retain all production beyond the specified volumes sold in the transaction.

As the operator of the properties from which the VPP volumes have been sold, we have the responsibility to bear the cost of producing the reserves attributable to such interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods such costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining the cost center ceiling for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet and the expenses that will apply in the future will depend on the actual production expenses and taxes in effect during the periods in which such production actually occurs, which could differ materially from our current and historical costs.

We have committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

We have completed the following VPP transactions since 2007:

Date of VPP	Division	Proceeds		Proved Reserves (at time of sale)		$ / mcfe		Original Term
		($ in millions)		(bcfe)				(years)
March 2012	Anadarko Basin Granite Wash	$	744		160	$	4.68	10
May 2011	Mid-Continent		853		177	$	4.82	10
September 2010	Barnett Shale		1,150		390	$	2.93	5
June 2010	Permian Basin		335		38	$	8.73	10
February 2010	East Texas and Texas Gulf Coast		180		46	$	3.95	10
August 2009	South Texas		370		68	$	5.46	7.5
December 2008	Anadarko and Arkoma Basins		412		98	$	4.19	8
August 2008	Anadarko Basin		600		93	$	6.38	11
May 2008	Texas, Oklahoma and Kansas		622		94	$	6.53	11
December 2007	Kentucky and West Virginia		1,100		208	$	5.29	15
		$	6,366		1,372	$	4.64

For accounting purposes, cash proceeds from these transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized, and our proved reserves were reduced accordingly.

40

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

9. Investments

At June 30, 2012 and December 31, 2011, we had the following investments:

			Carrying Value
	Approximate Ownership %	Accounting Method	June 30,     2012		December 31, 2011
			($ in millions)
Chesapeake Midstream Partners, L.P.	—	Equity	$	—	$	987
FTS International, Inc.	30%	Equity		203		235
Chaparral Energy, Inc.	20%	Equity		137		143
Sundrop Fuels, Inc.	37%	Equity		63		34
Clean Energy Fuels Corp.	—	Cost		50		50
Twin Eagle Resource Management, LLC	30%	Equity		29		20
Clean Energy Fuels Corp.	1%	Fair Value		16		12
Gastar Exploration Ltd.	10%	Fair Value		13		22
Other	—	—		33		28
Total investments			$	544	$	1,531

Chesapeake Midstream Partners, L.P. In June 2012, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P. (NYSE:ACMP), and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners for cash proceeds of $2.0 billion. We recorded a $1.032 billion gain associated with the transaction, including the recognition of a $13 million deferred gain related to previously sold equipment to ACMP.

During the Current Period, we recorded positive equity method adjustments of $46 million for our share of ACMP’s income, received cash distributions of $56 million from ACMP and recorded accretion adjustments of $4 million related to our share of equity in excess of cost. See Note 10 for further discussion of ACMP.

FTS International, Inc. FTS International, Inc. (FTS), based in Fort Worth, Texas, is the privately held parent company which, through its subsidiaries, provides pressure pumping and well stimulation to oil and gas companies. In the Current Period, we recorded negative equity method adjustments, prior to intercompany profit eliminations, of $55 million for our share of FTS’s net loss and recorded accretion adjustments of $23 million related to our share of equity in excess of cost. The carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $845 million as of June 30, 2012. The value not allocated to goodwill is being accreted over the nine-year estimated useful lives of the underlying assets.

Chaparral Energy, Inc. Chaparral Energy, Inc., based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties.

In the Current Period, we recorded a $4 million charge related to our share of Chaparral’s net loss and depreciation adjustments of $2 million related to the excess of our cost over our proportionate share of Chaparral’s book equity. The carrying value of our investment in Chaparral was in excess of our underlying equity in net assets by approximately $53 million as of June 30, 2012. 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.

41

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Sundrop Fuels, Inc. In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc., a privately held cellulosic biofuels company based in Louisville, Colorado. The investment will fund construction of a nonfood biomass-based “green gasoline” plant, capable of annually producing more than 40 million gallons of gasoline from natural gas and waste cellulosic material. The investment is intended to accelerate the development of an affordable, stable, room-temperature, natural gas-based fuel for immediate use in automobiles, diesel engine vehicles and aircraft. As of June 30, 2012, we had funded $65 million of our commitment. The remaining tranches of preferred equity investment will be scheduled around certain funding and operational milestones that are expected to be reached by July 2013. The full investment will represent 50% of Sundrop Fuels’ equity on a fully diluted basis.

In the Current Period, we recorded a $1 million charge related to our share of Sundrop’s net loss. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $38 million as of June 30, 2012. This excess will be amortized over the life of the plant, once it is placed into service.

Clean Energy Fuels Corp. In July 2011, we agreed to invest $150 million in newly issued convertible promissory notes of Clean Energy Fuels Corp. (Nasdaq:CLNE), based in Seal Beach, California. The investment is being made in three equal $50 million promissory notes, the first two of which were issued in July 2011 and July 2012, with the remaining note scheduled to be issued in June 2013. The notes bear interest at the annual rate of 7.5%, payable quarterly, and are convertible at our option into shares of Clean Energy’s common stock at a 22.5% conversion premium, resulting in a conversion price of $15.80 per share. Under certain circumstances following the second anniversary of the issuance of a note, Clean Energy can force conversion of the debt. The entire principal balance of each note is due and payable seven years following issuance. Clean Energy will use our $150 million investment to accelerate its build-out of LNG fueling infrastructure for heavy-duty trucks at truck stops across interstate highways in the U.S.

In December 2011, we also purchased one million shares of Clean Energy common stock for $10 million. During the Current Period, the common stock price of Clean Energy increased from $12.46 per share as of December 31, 2011 to $15.50 per share as of June 30, 2012.

Twin Eagle Resource Management LLC. In 2010, we invested $20 million in Twin Eagle Resource Management LLC, a natural gas trading and management firm. In February 2012, we invested an additional $9 million. During the Current Period, we recorded a nominal amount in income related to our share of Twin Eagle’s net income. The carrying value of our investment in Twin Eagle was in excess of our equity in net assets by approximately $5 million as of June 30, 2012. This excess is being amortized over the 15-year estimated useful lives of the underlying assets.

Gastar Exploration Ltd. Gastar Exploration Ltd. (NYSE Amex:GST), based in Houston, Texas, is an independent energy company engaged in the exploration, development and production of natural gas and oil in the U.S. During the Current Period, the common stock price of Gastar decreased from $3.18 per share as of December 31, 2011 to $1.93 per share as of June 30, 2012.

Pursuant to our reclassification of certain assets and liabilities to held for sale, the following investments held by our midstream business have been identified as investments held for sale. See Note 1 for further discussion of these sales.

			Carrying Value
	Approximate Ownership %	Accounting Method	June 30,         2012		December 31, 2011
			($ in millions)
Utica East Ohio Midstream, LLC	59%	Equity	$	51	$	—
Ranch Westex JV, LLC	33%	Equity		18		—
Glass Mountain Pipeline, LLC	50%	Equity		4		—
Total investments held for sale			$	73	$	—

42

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Utica East Ohio Midstream LLC. In March 2012, CMD entered into an agreement to form Utica East Ohio Midstream LLC (UEOM) with M3 Midstream, L.L.C. and EV Energy Partners, L.P. to develop necessary infrastructure for the gathering and processing of natural gas and NGL in the Utica Shale play in eastern Ohio. The infrastructure complex will consist of natural gas gathering and compression facilities constructed and operated by CMD, as well as processing, NGL fractionation, loading and terminal facilities constructed and operated by M3 Midstream, L.L.C. CMD ‘s total commitment is $474 million in exchange for an ownership of approximately 59% in UEOM. UEOM is not consolidated because we do not have a controlling interest. As of June 30, 2012, we had funded $50 million of CMD’s total commitment. See Note 10 for further discussion of UEOM.

Ranch Westex, JV LLC. In December 2011, CMD entered into an agreement to form Ranch Westex JV, LLC with two other parties to develop, construct and operate necessary infrastructure for the processing and gathering of natural gas in Ward County, Texas. CMD’s total commitment is $36 million. As of June 30, 2012, we had funded $18 million of this commitment.

Glass Mountain Pipeline, LLC. In April 2012, CMD entered into an agreement with two other parties to form Glass Mountain Pipeline, LLC to construct a 210 mile pipeline in western and north central Oklahoma. CMD’s commitment is approximately $94 million. As of June 30, 2012, we had funded $4 million of this commitment. See Note 10 for further discussion of Glass Mountain Pipeline, LLC.

10. Variable Interest Entities

In accordance with accounting guidance for consolidation, we consolidate the activities of VIEs of which we are the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Consolidated VIEs

Chesapeake Granite Wash Trust. For discussion of the formation, operations and presentation of the Trust, please see Noncontrolling Interests in Note 6. The Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust. Our ownership in the Trust and our obligations under the development agreement and related drilling support lien constitute variable interests. We have determined that we are the primary beneficiary of the Trust as (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our obligations to perform under the development agreement, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that could potentially be significant to the Trust. As a result, we consolidate the Trust in our financial statements and the common units of the Trust owned by third parties are reflected as a noncontrolling interest.

The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake; however, we have certain obligations to the Trust through the development agreement that are secured by a drilling support lien on our retained interest in the development wells up to a specified maximum amount recoverable by the Trust, which could result in the Trust acquiring all or a portion of our retained interest in the undeveloped portion of an area of mutual interest, if we do not meet our drilling commitment. In consolidation, as of June 30, 2012, approximately $458 million of net natural gas and oil properties, $24 million of current liabilities, $1 million of cash and cash equivalents and $1 million of long-term derivative assets were attributable to the Trust. We have presented parenthetically on the face of the condensed consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.

43

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Cardinal Gas Services, L.L.C. We own an approximate 66% interest in Cardinal, a consolidated unrestricted non-guarantor midstream subsidiary (see Note 6 under Noncontrolling Interests for further discussion). Cardinal is considered a VIE because its total equity at risk, as of June 30, 2012, is not sufficient to permit it to finance its activities without additional subordinated financial support. It is expected that we, along with the other equity partners, will make regular capital contributions to Cardinal for our proportionate share of its capital costs. This VIE is consolidated since we have a controlling interest in the VIE through voting rights. In consolidation, as of June 30, 2012, approximately $7 million of current assets, $85 million of net natural gas gathering systems and treating plants and $27 million of current liabilities were attributable to Cardinal, which we have presented parenthetically on the face of the condensed consolidated balance sheets as held for sale.

Unconsolidated VIEs

Chesapeake Midstream Partners, L.P. In two transactions completed on June 15 and June 29, 2012, we sold our limited partner and general partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P. (NYSE:ACMP). See Note 9. Prior to these sales, we had an approximate 46% interest in ACMP through our ownership of common and subordinated limited partner units and general partner interest. ACMP focuses on unregulated business activities in service to both Chesapeake and third-party natural gas producers and its revenues are generated from gathering, compression, dehydration and treating services. Certain Chesapeake employees have provided services to ACMP through an employee secondment agreement, and ACMP has utilized various support functions within Chesapeake, including accounting, human resources and information technology in return for certain cost reimbursements. We have agreed to provide certain transition services to ACMP following the sale of the ACMP interests, including the continuation of general and administrative services until December 31, 2013 and the secondment, pending any transfer, of certain personnel that perform services for ACMP until December 31, 2012, which date may be extended to March 31, 2013.

ACMP is considered a VIE because of the significance of its operations to us and the contractual arrangements between Chesapeake and ACMP that pass certain economic risks to us which are disproportionate to our economic interest. These primarily include certain gas gathering agreements with ACMP pursuant to which we have committed to deliver annually specified minimum volumes of natural gas under firm transportation agreements, and an EBITDA guarantee CMD issued to ACMP in conjunction with our December 2011 sale of Appalachia Midstream Services, L.L.C. (AMS). Our rights and commitments under our contractual arrangements with ACMP constitute variable interests. See Other Commitments in Note 4.

Our risk of loss related to ACMP includes certain commitments to ACMP through the EBITDA guarantee and under our firm transportation agreements that could require us to make shortfall payments in the event we do not meet our minimum volume commitments or ACMP does not meet specific EBITDA targets. The creditors or beneficial holders of ACMP common units have no recourse to the general credit of Chesapeake. This VIE remains unconsolidated since the power to direct the activities which are most significant to ACMP’s economic performance are with the general partner. Prior to June 29, 2012, we used the equity method to account for this investment.

Utica East Ohio Midstream LLC. We have an approximate 59% interest in Utica East Ohio Midstream LLC (UEOM), an unconsolidated non-guarantor entity which we formed with M3 Midstream L.L.C. and EV Energy Partners, L.P. to develop necessary infrastructures for gathering and processing of natural gas and NGL in the Utica shale play in eastern Ohio (see Note 9 for further details). UEOM is considered a VIE because its total equity at risk, as of June 30, 2012, is not sufficient to permit it to finance its activities without additional subordinated financial support. It is expected that we, along with the other equity partners, will make regular capital contributions to UEOM for our proportionate share of its capital costs. This VIE remains unconsolidated since the power to direct the activities which are most significant to UEOM’s economic performance is shared between us and the other equity holders. We are using the equity method to account for this investment.

44

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Mineral Acquisition Company I, L.P. In the Current Period, MAC-LP, L.L.C., a wholly owned non-guarantor unrestricted subsidiary of Chesapeake, entered into a partnership agreement with KKR Royalty Aggregator LLC (KKR) to form Mineral Acquisition Company I, L.P. The purpose of the partnership is to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. We are committed to acquire for our own account (outside the partnership) 10% of any acquisition agreed upon by the partnership up to a maximum of $25 million, and the partnership will acquire the remaining 90% up to a maximum of $225 million, funded entirely by KKR, making KKR the sole equity investor. We will have significant influence over the decisions made by the partnership, as we hold two of five seats on the board of directors. We will receive proportionate distributions from the partnership of any cash received from royalties in excess of expenses paid, ranging from 7% to 22.5%. The partnership is considered a VIE because KKR’s control over the partnership is disproportionate to its economic interest. This VIE remains unconsolidated as the power to direct the activities of the partnership is shared between the Company and KKR. We are using the equity method to account for this investment.

Glass Mountain Pipeline, LLC. We have a 50% interest in Glass Mountain Pipeline, LLC (GMP), an unconsolidated entity which we formed with Gavilon Energy Holdings II, LLC and Glass Mountain Holding, LLC to construct a 210 mile crude oil pipeline in Oklahoma (see Note 9 for further details). GMP has entered into separate agreements with our wholly owned subsidiary, Chesapeake Energy Marketing, Inc., for throughput and deficiency commitments. GMP is considered a VIE because its total equity at risk, as of June 30, 2012, is not sufficient to permit it to finance its activities without additional subordinated financial support. It is expected that all the equity partners will make regular capital contributions to GMP for their proportionate share of capital costs. This VIE remains unconsolidated since the power to direct the activities that are most significant to GMP’s economic performance is shared among the three equity holders. We are using the equity method to account for this investment.

11. Impairments

We test our long-lived assets for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable and recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. In the Current Quarter, we determined that certain of our property, plant and equipment were being carried at values that were not recoverable and in excess of fair value. As a result, we recognized the following impairments in the Current Quarter.

Land and Buildings

In the Current Quarter, we recognized $219 million of impairment losses associated with an office building and surface land located in our Barnett Shale operating area. Due to depressed natural gas prices, we have initiated a significant reduction in our Barnett Shale operations. The change in business climate in the Barnett Shale required us to test these long-lived assets for recoverability in the Current Quarter. We received a purchase offer from a third party that we used to determine the fair value of the office building and measured the fair value of the surface land using prices from orderly sales transactions for comparable properties between market participants. The office building and surface land are included in our other operating segment.

45

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Drilling Rigs and Equipment

In the Current Quarter, we recognized $15 million of impairment losses on five owned drilling rigs. A current expectation that the drilling rigs would have, insufficient cash flow to recover carrying values and a change in the business climate due to depressed natural gas prices led to the testing of the carrying value recoverability. We estimated the fair value of the drilling rigs using prices that would be received to sell each rig in an orderly transaction between market participants. Also in the Current Quarter, we recognized $9 million of impairment losses primarily related to drill pipe. The drilling rigs and equipment are included in our oilfield services operating segment.

12. 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 and the following methods and assumptions to measure the fair values of its assets and liabilities, which may or may not be observable in the market.

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. (NYSE Amex: GST) and Clean Energy Fuels Corporation (NASDAQ:CLNE) 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.

Derivatives. The fair values of our natural gas, oil and NGL derivatives, interest rate swaps and cross currency swaps are based on third-party pricing models which utilize 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 natural gas, oil, NGL, interest rate and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. For interest rate options and swaptions, we use the fair value estimates provided by our respective counterparties. 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 non-performance risk into the valuation of our derivatives using current published credit default swap 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 related designated fair value interest rate swaps. We currently do not have any debt recorded at fair value since we have no open fair value hedges.

46

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of June 30, 2012:

	Quoted Prices in Active Markets     (Level 1)			Significant Other Observable Inputs     (Level 2)			Significant Unobservable Inputs     (Level 3)			Total Fair Value
				($ in millions)
Financial Assets (Liabilities):
Cash and cash equivalents	$	1,024		$	—		$	—		$	1,024
Restricted cash		224			—			—			224
Investments		29			—			—			29
Other long-term assets		70			—			—			70
Other long-term liabilities		(69	)		—			—			(69	)
Derivatives:
Commodity assets		—			138			14			152
Commodity liabilities		—			(13	)		(1,078	)		(1,091	)
Interest rate liabilities		—			(41	)		—			(41	)
Foreign currency liabilities		—			(48	)		—			(48	)
Total derivatives		—			36			(1,064	)		(1,028	)
Total	$	1,278		$	36		$	(1,064	)	$	250

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2011:

	Quoted Prices in Active Markets     (Level 1)			Significant Other Observable Inputs     (Level 2)			Significant Unobservable Inputs      (Level 3)			Total Fair Value
				($ in millions)
Financial Assets (Liabilities):
Cash and cash equivalents	$	351		$	—		$	—		$	351
Restricted cash		44			—			—			44
Investments		34			—			—			34
Other long-term assets		61			—			—			61
Other long-term liabilities		(62	)		—			—			(62	)
Derivatives:
Commodity assets		—			46			9			55
Commodity liabilities		—			(31	)		(1,663	)		(1,694	)
Interest rate liabilities		—			(42	)		—			(42	)
Foreign currency liabilities		—			(38	)		—			(38	)
Total derivatives		—			(65	)		(1,654	)		(1,719	)
Total	$	428		$	(65	)	$	(1,654	)	$	(1,291	)

47

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

A summary of the changes in Chesapeake’s financial assets (liabilities) classified as Level 3 measurements during the Current Period and the Prior Period is presented below.

	Derivatives
	Commodity			Interest Rate			Foreign Currency			Debt
	($ in millions)
Beginning Balance as of January 1, 2012	$	(1,654	)	$	—		$	—		$	—
Total gains (losses) (realized/unrealized):
Included in earnings or change in net   assets(a)		548			2			—			—
Total purchases, issuances, sales and  settlements:
Sales		—			(2	)		—			—
Settlements		42			—			—			—
Ending Balance as of June 30, 2012	$	(1,064	)	$	—		$	—		$	—
Beginning Balance as of January 1, 2011	$	(1,954	)	$	(69	)	$	(43	)	$	(1,371	)
Total gains (losses) (realized/unrealized):
Included in earnings or change in net   assets(a)		(548	)		11			—			—
Total purchases, issuances, sales and  settlements:
Sales		—			(4	)		—			—
Settlements		106			—			—			—
Transfers in and out of Level 3(b)		—			54			43			1,371
Ending Balance as of June 30, 2011	$	(2,396	)	$	(8	)	$	—		$	—

(a)	Natural Gas, Oil					Interest
	and NGL Sales					Expense
	2012		2011			2012		2011
	($ in millions)
Total gains (losses) included in earnings   (or change in net assets) for the period	$	548	$	(548	)	$	2	$	11
Change in unrealized gains (losses) relating to   assets still held at reporting date	$	430	$	(592	)	$	—	$	(8	)

(b) The values related to interest rate and cross currency swaps were transferred from Level 3 to Level 2 as a result of our ability to use data readily available in the public market to corroborate our estimated fair values.

Qualitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

The significant unobservable inputs for Level 3 derivative contracts include forward prices of natural gas, oil and NGL, forward interest rate curves, market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts, e.g. an increase (decrease) in the forward prices and volatility of natural gas, oil and NGL prices will decrease (increase) the fair value of natural gas, oil and NGL derivatives; an increase (decrease) in forward rates and volatility of interest rates will decrease (increase) the fair value of interest rate derivatives; and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

48

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value June 30, 2012
				($ in millions)
Oil Trades(a)	Oil price volatility curve	15.41% - 31.50%	23.10%		$      (794)
Natural Gas Trades(a)	Natural gas price volatility curve	22.09% - 60.47%	29.19%		$      (237)
Natural Gas Basis Swaps(b)	Physical pricing point   forward curves	($1.08) - $0.26	$    (0.19)		$        (32)

(a) Fair value is based on an estimate derived from option models.

(b) Fair value is based on an estimate of discounted cash flows.

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. 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 primarily using quoted market prices (Level 1). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.

	June 30, 2012				December 31, 2011
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
			($ in millions)
Long-term debt	$	14,423	$	14,381	$	10,598	$	11,399

Nonrecurring Fair Value Measurements

Fair value measurements were applied with respect to our non-financial assets, measured on a non-recurring basis, to determine impairments. These assets consist primarily of land, a building, drilling rigs and drill pipe. We have either received a bid from a third party or used a third party to assess the fair value of these assets. Since the inputs used are not observable in the market, these assets are classified as Level 3 in the fair value hierarchy. See Note 11 for additional discussion.

49

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

13. Segment Information

In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have three reportable operating segments. Our exploration and production operating segment, natural gas, oil and NGL marketing, gathering and compression operating segment and oilfield services operating segment are managed separately because of the nature of their products and services. The exploration and production operating segment is responsible for finding and producing natural gas, oil and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of natural gas, oil and NGL primarily from Chesapeake-operated wells. The oilfield services operating segment is responsible for contract drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties.

COO, a wholly owned subsidiary of COS, is a diversified oilfield services company that we formed in October 2011 to own and operate our oilfield service assets. COO provides a wide range of well site services, primarily to Chesapeake and its working interest partners, including contract drilling, hydraulic fracturing, oilfield rentals, transportation and manufacturing of natural gas compressor packages and related production equipment. In connection with the reorganization of our oilfield services subsidiaries and operations, those subsidiaries were released from the guarantees and other credit support obligations that existed for the benefit of Chesapeake and its other subsidiaries, including Chesapeake’s senior notes and contingent convertible senior notes, its corporate revolving bank credit facility and its multi-counterparty hedging facility. In addition, COO and its subsidiaries entered into agreements with Chesapeake pursuant to which they sublease rigs, provide certain oilfield services and obtain certain administrative services.

As a result of the formal reorganization of our oilfield services business in October 2011, we are recognizing our oilfield services business as a reportable segment. Historically, our oilfield services business was presented as part of other operations. All prior year information has been restated to reflect the addition of our oilfield services business as a new reportable segment.

Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of natural gas, oil and NGL related to Chesapeake’s ownership interests by the marketing, gathering and compression operating segment are reflected as exploration and production revenues. Such amounts totaled $1.161 billion, $1.213 billion, $2.336 billion and $2.417 billion for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, respectively. The following table presents selected financial information for Chesapeake’s operating segments.

50

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

	Exploration and  Production		Marketing, Gathering and  Compression			Oilfield   Services			Other   Operations			Intercompany  Eliminations			Consolidated  Total
	($ in millions)
For the Three Months Ended June 30, 2012:
Revenues	$	2,117	$	2,274		$	506		$	—		$	(1,508	)	$	3,389
Intersegment revenues		—		(1,161	)		(347	)		—			1,508			—
Total revenues	$	2,117	$	1,113		$	159		$	—		$	—		$	3,389
Income (loss) before income taxes	$	1,090	$	1,089		$	57		$	(401	)	$	(135	)	$	1,700
For the Three Months Ended June 30, 2011:
Revenues	$	1,792	$	2,617		$	275		$	—		$	(1,366	)	$	3,318
Intersegment revenues		—		(1,213	)		(153	)		—			1,366			—
Total revenues	$	1,792	$	1,404		$	122		$	—		$	—		$	3,318
Income (loss) before income taxes	$	780	$	75		$	21		$	26		$	(67	)	$	835

51

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

	Exploration and  Production		Marketing, Gathering and  Compression			Oilfield   Services			Other   Operations			Intercompany  Eliminations			Consolidated  Total
	($ in millions)
For the Six Months Ended   June 30, 2012:
Revenues	$	3,185	$	4,664		$	953		$	—		$	(2,995	)	$	5,807
Intersegment revenues		—		(2,336	)		(659	)		—			2,995			—
Total revenues	$	3,185	$	2,328		$	294		$	—		$	—		$	5,807
Income (loss) before   income taxes	$	1,178	$	1,156		$	96		$	(502	)	$	(234	)	$	1,694
For the Six Months Ended   June 30, 2011:
Revenues	$	2,286	$	4,838		$	523		$	—		$	(2,717	)	$	4,930
Intersegment revenues		—		(2,417	)		(300	)		—			2,717			—
Total revenues	$	2,286	$	2,421		$	223		$	—		$	—		$	4,930
Income (loss) before   income taxes	$	475	$	160		$	42		$	35		$	(143	)	$	569
As of June 30, 2012:
Total Assets	$	41,947	$	3,484		$	1,971		$	2,279		$	(2,155	)	$	47,526
As of December 31, 2011:
Total Assets	$	35,403	$	4,047		$	1,571		$	2,718		$	(1,904	)	$	41,835

52

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

14. 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 senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly owned subsidiaries on a senior unsecured basis. Our oilfield services subsidiary, COS, and its subsidiaries are not guarantors of our senior notes, contingent convertible senior notes and corporate credit facility but are subject to the covenants and guarantees in their revolving bank credit facility agreement referred to in Note 3 that restrict them from paying dividends or distributions or making loans to Chesapeake. COS and its subsidiaries were released as guarantors of our senior notes and corporate credit facility in October 2011 when they were formally reorganized and capitalized. Our midstream subsidiary, CMD, and its subsidiaries were added as guarantors of our senior notes and corporate credit facility in June 2012 upon the termination of the midstream credit facility. All prior year information has been restated to reflect COS and its subsidiaries as non-guarantor subsidiaries and CMD and its subsidiaries as guarantor subsidiaries. In addition, CHK Utica, CHK C-T, Chesapeake Granite Wash Trust, MAC-LP, L.L.C., Cardinal, UEOM and certain de minimis subsidiaries are also non-guarantors.

53

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 (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2012 and December 31, 2011 and for the three and six months ended June 30, 2012 and 2011. 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 JUNE 30, 2012

($ in millions)

						Non-
				Guarantor		Guarantor
	Parent			Subsidiaries		Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	911	$	113	$	—		$	1,024
Other		1			3,138		746		(492	)		3,393
Current assets held for sale		—			92		7		—			99
Total Current Assets		1			4,141		866		(492	)		4,516
PROPERTY AND EQUIPMENT:
Natural gas and oil properties,   at cost based on full cost   accounting, net		—			32,672		3,005		(134	)		35,543
Other property and equipment   at cost, net		—			2,737		1,387		—			4,124
Property and equipment   held for sale, net		—			2,095		112		—			2,207
Total Property and   Equipment, Net		—			37,504		4,504		(134	)		41,874
LONG-TERM ASSETS:
Other assets		274			1,003		198		(412	)		1,063
Long-term assets held for sale		—			73		—		—			73
Investments in subsidiaries and   intercompany advances		3,943			2,468		—		(6,411	)		—
TOTAL ASSETS	$	4,218		$	45,189	$	5,568	$	(7,449	)	$	47,526
CURRENT LIABILITIES:
Current liabilities	$	345		$	5,802	$	412	$	(494	)	$	6,065
Current liabilities held for sale		—			167		27		—			194
Intercompany payable to   (receivable from) parent		(27,766	)		28,985		657		(1,876	)		—
Total Current Liabilities		(27,421	)		34,954		1,096		(2,370	)		6,259
LONG-TERM LIABILITIES:
Long-term debt, net		13,417			—		912		—			14,329
Deferred income tax liabilities		747			4,453		240		(657	)		4,783
Other liabilities		48			1,837		852		(372	)		2,365
Long-term liabilities held for sale		—			2		—		—			2
Total Long-Term Liabilities		14,212			6,292		2,004		(1,029	)		21,479
EQUITY:
Chesapeake stockholders’ equity		17,427			3,943		2,468		(6,411	)		17,427
Noncontrolling interests		—			—		—		2,361			2,361
Total Equity		17,427			3,943		2,468		(4,050	)		19,788
TOTAL LIABILITIES AND EQUITY	$	4,218		$	45,189	$	5,568	$	(7,449	)	$	47,526

54

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2011

($ in millions)

						Non-
				Guarantor		Guarantor
	Parent(a)			Subsidiaries(a)		Subsidiaries		Eliminations			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	1	$	350	$	—		$	351
Other		1			2,734		303		(212	)		2,826
Total Current Assets		1			2,735		653		(212	)		3,177
PROPERTY AND EQUIPMENT:
Natural gas and oil   properties, at cost,   based on full cost   accounting, net		—			29,659		2,017		(476	)		31,200
Other property and   equipment at cost, net		—			4,287		1,252		—			5,539
Total Property and   Equipment, Net		—			33,946		3,269		(476	)		36,739
LONG-TERM ASSETS:
Other assets		161			2,015		120		(377	)		1,919
Investments in subsidiaries   and intercompany   advances		3,501			1,514		—		(5,015	)		—
TOTAL ASSETS	$	3,663		$	40,210	$	4,042	$	(6,080	)	$	41,835
CURRENT LIABILITIES:
Current liabilities	$	288		$	6,709	$	299	$	(214	)	$	7,082
Intercompany payable to   (receivable from) parent		(21,903	)		22,826		651		(1,574	)		—
Total Current Liabilities		(21,615	)		29,535		950		(1,788	)		7,082
LONG-TERM LIABILITIES:
Long-term debt, net		8,226			1,720		680		—			10,626
Deferred income tax   liabilities		390			3,135		196		(237	)		3,484
Other liabilities		38			2,319		702		(377	)		2,682
Total Long-Term   Liabilities		8,654			7,174		1,578		(614	)		16,792
EQUITY:
Chesapeake stockholders’   equity		16,624			3,501		1,514		(5,015	)		16,624
Noncontrolling interests		—			—		—		1,337			1,337
Total Equity		16,624			3,501		1,514		(3,678	)		17,961
TOTAL LIABILITIES AND   EQUITY	$	3,663		$	40,210	$	4,042	$	(6,080	)	$	41,835

(a) We have revised the amounts presented as long-term debt in the Guarantor Subsidiaries and Parent columns to properly reflect the long-term debt issued by the Parent of $8.2 billion, which was incorrectly presented as long-term debt attributable to the Guarantor Subsidiaries as of December 31, 2011. The impact of this error was not material to our December 31, 2011 financial statements.

55

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2012

(in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES
Natural gas, oil and NGL	$	—		$	2,009		$	107		$	1		$	2,117
Marketing, gathering and compression		—			1,113			—			—			1,113
Oilfield services		—			—			506			(347	)		159
Total Revenues		—			3,122			613			(346	)		3,389
OPERATING EXPENSES
Natural gas, oil and NGL production		—			329			6			—			335
Production taxes		—			40			1			—			41
Marketing, gathering and compression		—			1,096			—			—			1,096
Oilfield services		—			1			339			(231	)		109
General and administrative		—			134			22			—			156
Natural gas, oil and NGL depreciation, depletion and amortization		—			553			35			—			588
Depreciation and amortization of other assets		—			62			56			(35	)		83
Losses on sales and impairments of fixed assets		—			219			24			—			243
Total Operating Expenses		—			2,434			483			(266	)		2,651
INCOME FROM OPERATIONS		—			688			130			(80	)		738
OTHER INCOME (EXPENSE)
Interest expense		(231	)		12			(19	)		224			(14	)
Earnings (losses) on investments		—			(65	)		6			—			(59	)
Gain on sale of investments		—			1,030			—			—			1,030
Losses on purchases or exchanges of debt		—			—			—			—			—
Other income		218			14			(1	)		(226	)		5
Equity in net earnings of subsidiary		980			21			—			(1,001	)		—
Total Other Income (Expense)		967			1,012			(14	)		(1,003	)		962
INCOME BEFORE INCOME TAXES		967			1,700			116			(1,083	)		1,700
INCOME TAX EXPENSE (BENEFIT)		(5	)		655			45			(32	)		663
NET INCOME		972			1,045			71			(1,051	)		1,037
Other comprehensive income (loss), net of income tax		(3	)		(20	)		—			—			(23	)
COMPREHENSIVE INCOME (LOSS)		969			1,025			71			(1,051	)		1,014
Comprehensive income attributable to noncontrolling interests		—			—			—			(65	)		(65	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	969		$	1,025		$	71		$	(1,116	)	$	949

56

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2011

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Natural gas, oil and NGL	$	—		$	1,792		$	—		$	—		$	1,792
Marketing, gathering and compression		—			1,404			—			—			1,404
Oilfield services		—			—			275			(153	)		122
Total Revenues		—			3,196			275			(153	)		3,318
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			262			—			—			262
Production taxes		—			46			—			—			46
Marketing, gathering and compression		—			1,366			—			—			1,366
Oilfield services		—			—			205			(113	)		92
General and administrative		—			123			7			—			130
Natural gas, oil and NGL depreciation, depletion and amortization		—			366			—			—			366
Depreciation and amortization of other assets		—			47			35			(19	)		63
Losses on sales and impairments of fixed assets		—			8			—			—			8
Total Operating Expenses		—			2,218			247			(132	)		2,333
INCOME (LOSS) FROM OPERATIONS		—			978			28			(21	)		985
OTHER INCOME (EXPENSE):
Interest expense		(167	)		(13	)		(10	)		165			(25	)
Earnings (losses) on investments		—			47			—			—			47
Losses on purchases or exchanges of debt		(174	)		—			—			—			(174	)
Other income		163			3			2			(166	)		2
Equity in net earnings of subsidiary		618			(2	)		—			(616	)		—
Total Other Income (Expense)		440			35			(8	)		(617	)		(150	)
INCOME (LOSS) BEFORE INCOME TAXES		440			1,013			20			(638	)		835
INCOME TAX EXPENSE (BENEFIT)		(70	)		395			9			(9	)		325
NET INCOME (LOSS)		510			618			11			(629	)		510
Other comprehensive income (loss), net of income tax		15			98			—			—			113
COMPREHENSIVE INCOME (LOSS)		525			716			11			(629	)		623
Comprehensive income attributable to noncontrolling interests		—			—			—			—			—
COMPREHENSIVE INCOME (LOSS)   ATTRIBUTABLE TO   CHESAPEAKE	$	525		$	716		$	11		$	(629	)	$	623

57

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2012

($ in millions)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
REVENUES:
Natural gas, oil and NGL	$	—		$	3,053		$	130		$	2		$	3,185
Marketing, gathering and   compression		—			2,327			1			—			2,328
Oilfield services		—			—			953			(659	)		294
Total Revenues		—			5,380			1,084			(657	)		5,807
OPERATING EXPENSES:
Natural gas, oil and NGL   production		—			678			7			—			685
Production taxes		—			87			2			—			89
Marketing, gathering and   compression		—			2,291			1			—			2,292
Oilfield services		—			1			665			(461	)		205
General and administrative		—			250			42			—			292
Natural gas, oil and NGL   depreciation, depletion and   amortization		—			1,045			49			—			1,094
Depreciation and amortization of   other assets		—			124			111			(69	)		166
Losses on sales and impairments   of fixed assets		—			217			24			—			241
Total Operating Expenses		—			4,693			901			(530	)		5,064
INCOME FROM OPERATIONS		—			687			183			(127	)		743
OTHER INCOME (EXPENSE):
Interest expense		(392	)		8			(37	)		395			(26	)
Earnings (losses) on investments		—			(69	)		5			—			(64	)
Gain on sale of investment		—			1,030			—			—			1,030
Losses on purchases or   exchanges of debt		—			—			—			—			—
Other income		382			23			7			(401	)		11
Equity in net earnings of   subsidiary		951			16			—			(967	)		—
Total Other Income (Expense)		941			1,008			(25	)		(973	)		951
INCOME BEFORE INCOME TAXES		941			1,695			158			(1,100	)		1,694
INCOME TAX EXPENSE (BENEFIT)		(3	)		655			61			(52	)		661
NET INCOME		944			1,040			97			(1,048	)		1,033
Other comprehensive income   (loss), net of income tax		—			(15	)		—			—			(15	)
COMPREHENSIVE INCOME (LOSS)		944			1,025			97			(1,048	)		1,018
Comprehensive income attributable to   noncontrolling interests		—			—			—			(89	)		(89	)
COMPREHENSIVE INCOME (LOSS)   ATTRIBUTABLE TO   CHESAPEAKE	$	944		$	1,025		$	97		$	(1,137	)	$	929

58

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2011

($ in millions)

							Non-
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
REVENUES:
Natural gas, oil and NGL	$	—		$	2,286		$	—		$	—		$	2,286
Marketing, gathering and   compression		—			2,421			—			—			2,421
Oilfield services		—			—			523			(300	)		223
Total Revenues		—			4,707			523			(300	)		4,930
OPERATING EXPENSES:
Natural gas, oil and NGL   production		—			500			—			—			500
Production taxes		—			91			—			—			91
Marketing, gathering and   compression		—			2,352			—			—			2,352
Oilfield services		—			—			387			(218	)		169
General and administrative		—			245			14			—			259
Natural gas, oil and NGL   depreciation, depletion and   amortization		—			724			—			—			724
Depreciation and amortization of   other assets		—			102			65			(36	)		131
Losses on sales and   impairments of fixed assets		—			3			—			—			3
Total Operating Expenses		—			4,017			466			(254	)		4,229
INCOME (LOSS) FROM   OPERATIONS		—			690			57			(46	)		701
OTHER INCOME (EXPENSE):
Interest expense		(350	)		(10	)		(18	)		345			(33	)
Earnings on investments		—			72			—			—			72
Losses on purchases or   exchanges of debt		(176	)		—			—			—			(176	)
Other income		343			8			2			(348	)		5
Equity in net earnings of subsidiary		458			(5	)		—			(453	)		—
Total Other Income (Expense)		275			65			(16	)		(456	)		(132	)
INCOME (LOSS) BEFORE   INCOME TAXES		275			755			41			(502	)		569
INCOME TAX EXPENSE (BENEFIT)		(72	)		297			15			(18	)		222
NET INCOME (LOSS)		347			458			26			(484	)		347
Other comprehensive income (loss),   net of income tax		4			65			—			—			69
COMPREHENSIVE INCOME (LOSS)		351			523			26			(484	)		416
Comprehensive income attributable to   noncontrolling interests		—			—			—			—			—
COMPREHENSIVE INCOME (LOSS)   ATTRIBUTABLE TO   CHESAPEAKE	$	351		$	523		$	26		$	(484	)	$	416

59

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2012

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	997		$	65		$	(33	)	$	1,029
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to proved and unproved properties		—			(6,689	)		(226	)		—			(6,915	)
Proceeds from divestitures of proved and unproved properties		—			1,555			—			—			1,555
Additions to other property and equipment		—			(936	)		(374	)		(1	)		(1,311	)
Other investing activities		—			2,845			(172	)		(923	)		1,750
Cash used in investing activities		—			(3,225	)		(772	)		(924	)		(4,921	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			8,584			1,520			—			10,104
Payments on credit facilities borrowings		—			(10,304	)		(1,288	)		—			(11,592	)
Proceeds from issuance of term loans, net of discount and offering costs		3,789			—			—			—			3,789
Proceeds from issuance of senior notes, net of discount and offering costs		1,263			—			—			—			1,263
Cash paid to purchase debt		—			—			—			—			—
Proceeds from sales of noncontrolling interests		—			(10	)		1,049			—			1,039
Other financing activities		(230	)		61			(818	)		956			(31	)
Intercompany advances, net		(4,822	)		4,807			14			1			—
Cash provided by (used in) financing activities		—			3,138			477			957			4,572
Change in cash and cash equivalents classified in current assets held for sale		—			—			(7	)		—			(7	)
Net increase (decrease) in cash and cash equivalents		—			910			(237	)		—			673
Cash and cash equivalents, beginning of period		—			1			350			—			351
Cash and cash equivalents, end of period	$	—		$	911		$	113		$	—		$	1,024

60

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2011

($ in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	2,078		$	15		$	—		$	2,093
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to proved and unproved properties		—			(5,924	)		—			—			(5,924	)
Proceeds from divestitures of proved and unproved properties		—			6,173			—			—			6,173
Additions to other property and equipment		—			(472	)		(391	)		—			(863	)
Other investing activities		—			8			—			366			374
Cash used in investing activities		—			(215	)		(391	)		366			(240	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			8,343			—			—			8,343
Payments on credit facilities borrowings		—			(10,235	)		—			—			(10,235	)
Proceeds from issuance of senior notes, net of discount and offering costs		977			—			—			—			977
Cash paid to purchase debt		(2,032	)		—			—			—			(2,032	)
Proceeds from sales of noncontrolling interests		—			—			—			—			—
Other financing activities		(226	)		1,323			370			(366	)		1,101
Intercompany advances, net		1,281			(1,187	)		(94	)		—			—
Cash provided by (used in) financing activities		—			(1,756	)		276			(366	)		(1,846	)
Changes in cash and cash equivalents classified in current assets held for sale		—			—			—			—			—
Net increase (decrease) in cash and cash equivalents		—			107			(100	)		—			7
Cash and cash equivalents, beginning of period		—			2			100			—			102
Cash and cash equivalents, end of period	$	—		$	109		$	—		$	—		$	109

61

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

15. Recently Issued and Proposed Accounting Standards

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

In December 2011, the FASB issued guidance on disclosure of information about offsetting and related arrangements to enable users of a company’s financial statements to understand the effect of those arrangements on its financial position. The standard is effective for annual reporting periods beginning on or after January 1, 2013. This guidance will not have an impact on our financial position or results of operations.

In June 2011, the FASB issued guidance on comprehensive income, which provides two options for presenting items of net income, comprehensive income and total comprehensive income, by either creating one continuous statement of comprehensive income or two separate consecutive statements. We adopted this guidance in 2011. Adoption had no impact on our financial position or results of operations. In December 2011, the FASB deferred the effective date of certain presentation requirements for items reclassified out of accumulated other comprehensive income. This guidance will not have an impact on our financial position or results of operations.

In May 2011, the FASB issued guidance on fair value measurement and disclosure requirements which expands existing fair value disclosure requirements, particularly for Level 3 inputs. The new requirements include quantitative disclosure of the unobservable inputs and assumptions used in the measurement; description of the valuation processes in place and sensitivity of the fair value to changes in unobservable inputs; and the level of items (in the fair value hierarchy) that are not measured at fair value in the balance sheet but whose fair value must be disclosed. The guidance was effective for interim and annual periods beginning on or after December 15, 2011. Adoption had no impact on our financial position or results of operations.

62

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, oil and NGL sales, average sales prices received, other operating income and expenses for the three and six months ended June 30, 2012 (the “Current Quarter” and the “Current Period”, respectively) and the three and six months ended June 30, 2011 (the “Prior Quarter” and the “Prior Period”, respectively):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Net Production:
Natural gas (bcf)		275.4			234.3			546.3			477.7
Oil (mmbbl)		7.3			3.9			13.3			7.1
NGL (mmbbl)		4.5			3.3			8.9			6.2
Natural gas equivalent (bcfe)(a)		346.5			277.5			679.4			557.1
Natural Gas, Oil and NGL Sales ($ in millions):
Natural gas sales	$	336		$	764		$	815		$	1,552
Natural gas derivatives – realized gains (losses)		182			452			339			958
Natural gas derivatives – unrealized gains (losses)		(164	)		(115	)		(311	)		(665	)
Total natural gas sales		354			1,101			843			1,845
Oil sales		656			377			1,247			661
Oil derivatives – realized gains (losses)		15			(34	)		(19	)		(42	)
Oil derivatives – unrealized gains (losses)		955			219			817			(398	)
Total oil sales		1,626			562			2,045			221
NGL sales		120			137			272			252
NGL derivatives – realized gains (losses)		(2	)		(11	)		(9	)		(20	)
NGL derivatives – unrealized gains (losses)		19			3			34			(12	)
Total NGL sales		137			129			297			220
Total natural gas, oil and NGL sales	$	2,117		$	1,792		$	3,185		$	2,286
Average Sales Price (excluding gains (losses) on derivatives):
Natural gas ($ per mcf)	$	1.22		$	3.26		$	1.49		$	3.25
Oil ($ per bbl)	$	89.49		$	96.69		$	93.49		$	93.40
NGL ($ per bbl)	$	26.40		$	41.66		$	30.68		$	40.93
Natural gas equivalent ($ per mcfe)	$	3.21		$	4.61		$	3.43		$	4.43
Average Sales Price (excluding unrealized gains (losses) on derivatives):
Natural gas ($ per mcf)	$	1.88		$	5.19		$	2.11		$	5.25
Oil ($ per bbl)	$	91.58		$	87.99		$	92.06		$	87.39
NGL ($ per bbl)	$	25.94		$	38.37		$	29.68		$	37.74
Natural gas equivalent ($ per mcfe)	$	3.77		$	6.07		$	3.89		$	6.03
Other Operating Income(b) ($ in millions):
Marketing, gathering and compression net margin	$	17		$	38		$	36		$	69
Oilfield services net margin	$	50		$	30		$	89		$	54
Other Operating Income(b) ($ per mcfe):
Marketing, gathering and compression net margin	$	0.05		$	0.14		$	0.05		$	0.12
Oilfield services net margin	$	0.14		$	0.11		$	0.13		$	0.10

63

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2012			2011		2012			2011
Expenses ($ per mcfe):
Natural gas, oil and NGL production	$	0.97		$	0.94	$	1.01		$	0.90
Production taxes	$	0.12		$	0.17	$	0.13		$	0.16
General and administrative expenses	$	0.45		$	0.46	$	0.43		$	0.46
Natural gas, oil and NGL depreciation, depletion and amortization	$	1.70		$	1.32	$	1.61		$	1.30
Depreciation and amortization of other assets	$	0.24		$	0.23	$	0.25		$	0.24
Interest expense(c)	$	0.06		$	0.07	$	0.04		$	0.04
Interest Expense ($ in millions):
Interest expense	$	21		$	6	$	28		$	15
Interest rate derivatives – realized (gains) losses		(1	)		13		—			6
Interest rate derivatives – unrealized (gains) losses		(6	)		6		(2	)		12
Total interest expense	$	14		$	25	$	26		$	33

(a) Natural gas equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of natural gas liquids (NGL). This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given recent natural gas, oil and NGL prices, the price for an mcfe of natural gas is significantly less than the price for an mcfe of oil or NGL.

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

(c) 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 the second-largest producer of natural gas, a top 15 producer of oil and NGL (collectively “liquids”) and the most active driller of new wells in the U.S. We own interests in approximately 46,600 producing natural gas and oil wells that are currently producing approximately 4.1 bcfe per day, net to our interest. The Company has built a large resource base of onshore U.S. natural gas assets in the Haynesville and Bossier Shales in northwestern Louisiana and East Texas; the Marcellus Shale in the northern Appalachian Basin of West Virginia and Pennsylvania; and the Barnett Shale in the Fort Worth Basin of north-central Texas. In addition, we have built leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas; the Utica Shale in Ohio, West Virginia and Pennsylvania; the Granite Wash, Cleveland and Tonkawa plays in the Anadarko Basin in western Oklahoma and the Texas Panhandle; the Mississippi Lime play on the Anadarko Basin Shelf in northern Oklahoma and southern Kansas; and the Niobrara Shale in the Powder River Basin in Wyoming. We have also vertically integrated many of our operations and own substantial midstream, compression and oilfield services assets.

Proved Reserves. Chesapeake began 2012 with estimated proved reserves of 18.789 tcfe and ended the Current Period with 17.392 tcfe, a decrease of 1.397 tcfe, or 7%. The Current Period’s proved reserve movement included 679 bcfe of production, 3.695 tcfe of extensions, 462 bcfe of positive performance revisions and 4.565 tcfe of downward revisions resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended June 30, 2012, compared to the twelve months ended December 31, 2011. During the Current Period, we acquired 9 bcfe of estimated proved reserves and divested 319 bcfe of estimated proved reserves.

In the Current Period, we reduced our estimate of proved reserves by 4.565 tcfe due to the impact of downward natural gas price revisions. Natural gas prices used in estimating proved reserves decreased by $0.97 from $4.12 per mcf for the 12 months ended December 31, 2011 to $3.15 per mcf for the 12 months ended June 30, 2012 using 12-month average prices required by the SEC. The reserve reductions primarily involved the loss of significant proved undeveloped reserves, primarily in the Barnett Shale and the Haynesville Shale plays, for which future development is uneconomic at the natural gas prices used in the reserves estimates. As of June 30, 2012, we were not required to impair the carrying value of our natural gas and oil properties; however, based on the expected natural gas prices we will be required to use to estimate proved reserves for the second half of 2012, we anticipate an impairment resulting from downward natural gas price revisions during the second half of 2012. Any such impairment, a non-cash

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charge that would not impact our liquidity or our ability to comply with financial covenants under our corporate revolving bank credit facility, is subject to a number of factors which could change, including the impact of oil and natural gas asset sales and other factors. We refer you to the risk factor “Declines in the prices of natural gas and oil could result in a write-down of our asset carrying values” included in Item 1A of our 2011 Form 10-K and the discussion of the full cost method of accounting under Application of Critical Accounting Policies – Natural Gas and Oil Properties in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2011 Form 10-K.

Drilling and Completion Expenditures. During the Current Period, we invested $4.315 billion in operated wells (using an average of 156 operated rigs) and $645 million in non-operated wells (using an average of 72 non-operated rigs) for total drilling and completing costs on proved and unproved properties of $4.960 billion, net of drilling and completion carries of $518 million.

Production. Our total Current Quarter production of 347 bcfe consisted of 275 bcf of natural gas (79% on a natural gas equivalent basis), 7.3 mmbbls of oil (13% on a natural gas equivalent basis) and 4.5 mmbbls of NGL (8% on a natural gas equivalent basis). Daily production for the Current Quarter averaged 3.808 bcfe, an increase of 759 mmcfe, or 25%, over the 3.049 bcfe produced per day in the Prior Quarter.

Our total Current Period production of 679 bcfe consisted of 546 bcf of natural gas (80% on a natural gas equivalent basis), 13.3 mmbbls of oil (12% on a natural gas equivalent basis) and 8.9 mmbbls of NGL (8% on a natural gas equivalent basis). Daily production for the Current Period averaged 3.733 bcfe, an increase of 655 mmcfe, or 21%, over the 3.078 bcfe produced per day in the Prior Period.

During the Current Period (beginning in February 2012), Chesapeake curtailed approximately 60 bcf of net natural gas production, or an average of approximately 330 mmcf per day of natural gas spread across the entire period. We undertook these curtailments in response to continued low natural gas prices and to preserve shareholder value. The curtailed volumes were located primarily in the Haynesville and Barnett shale plays. We ended our natural gas production curtailment program at the end of the 2012 second quarter and do not anticipate needing to implement new material curtailments during the remainder of 2012.

Leasehold and Seismic Inventories. Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (15.9 million net acres) and 3-D seismic (33.2 million acres) in the U.S. and owns a leading position in 10 of what we believe are the top 15 unconventional plays in the U.S. We are currently using 125 operated drilling rigs to further develop our leasehold inventory. We are targeting to invest approximately $2.0 billion in net undeveloped leasehold expenditures in 2012, of which approximately 90% will be in liquids-rich plays and 100% will be in plays where the Company is already active. This compares to net undeveloped leasehold expenditures of approximately $3.5 billion and $5.8 billion in 2011 and 2010, respectively.

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Emphasis on Increasing Liquids Production. In recognition of the value gap between liquids and natural gas prices, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise during the past three years to identify, secure and commercialize new unconventional liquids-rich plays. This planned transition will result in a more balanced and likely more profitable portfolio between natural gas and liquids. In the Current Period, our production of liquids averaged approximately 121,900 bbls per day, a 67% increase over the average during the Prior Period, as a result of the increased development of our unconventional liquids-rich plays. We are projecting that the portion of our operated drilling and completion expenditures allocated to liquids development will reach 85% in 2012, and we expect to increase our liquids production through our drilling activities to an average of approximately 130,000 bbls per day in 2012, 170,000 bbls per day in 2013 and 250,000 bbls per day in 2015.

Sales. Our business strategy is to create value for investors by building, developing and now harvesting one of the largest onshore natural gas and liquids-rich resource bases in the U.S. After years of building our resource base, we plan to focus on the 10 plays where we have a #1 or #2 ownership position and to sell assets that are non-core or do not fit our development plans. During the Current Period, we completed sales for proceeds of approximately $4.7 billion, and we have announced our intention to sell other natural gas and oil properties and midstream assets for total proceeds of $8.3 - $9.3 billion in the second half of 2012. Our sales program, together with operating cash flow, is designed to fully fund the Company’s 2012 capital expenditure program and reduce the Company’s long-term debt to the 25/25 Plan goal of $9.5 billion by year-end 2012. In 2013, we expect to complete sales for the same purposes - supplementing operating cash flow to fund capital expenditures and maintaining long-term debt at no more than $9.5 billion - and our budgeted capital expenditures reflect decreases resulting from reduced drilling, leasehold acquisition and midstream capital expenditures. Management and the board of directors are currently reviewing operations for 2013 and beyond, which could result in changes to the company’s drilling activity and production levels in 2013. We refer you to risks associated with our sales plans, as described in Planned Sales below.

Recent Corporate Developments

On June 21, 2012, five new independent directors were appointed to our reconstituted nine-member Board of Directors. Archie W. Dunham was appointed by the Board as Chesapeake’s new independent Non-Executive Chairman. Aubrey K. McClendon relinquished the position of Chairman but remains a director and will continue to serve as Chesapeake’s Chief Executive Officer and as President. Chesapeake’s Board also appointed four other new independent directors: three proposed by Southeastern Asset Management (SAM), which beneficially owns 13.9% of our common stock and is our largest shareholder, and one proposed by Carl C. Icahn, who, through Icahn Capital LP and its affiliates, beneficially owns 7.6% of our common stock and is our second largest shareholder. The new directors proposed by SAM are Bob G. Alexander, R. Brad Martin and Frederic M. Poses. The new director proposed by Mr. Icahn is Vincent J. Intrieri. These five new directors replace Richard K. Davidson, Kathleen M. Eisbrenner, Frank Keating and Don Nickles, who have resigned, and Charles T. Maxwell, who retired at the annual meeting on June 8, 2012. The other directors remaining on our Board of Directors are Mr. McClendon, Louis A. Simpson, who was proposed by SAM in 2011, Merrill A. (“Pete”) Miller, Jr., who was serving as Lead Independent Director, and V. Burns Hargis. With the appointment of an independent Non-Executive Chairman, the role of Lead Independent Director has been eliminated.

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Capital Expenditures

In the Current Period, our capital expenditures for exploration, development and acquisition activities, net of drilling and completion carries of $518 million, were $6.476 billion, including $5.007 billion for drilling and completion costs, $1.452 billion for acquisitions of unproved properties and $17 million for acquisitions of proved properties. A disproportionately high percentage of our total budgeted 2012 capital expenditures was made early in the year as the result of several factors which are discussed further below. Our current budget for 2012 includes drilling and completion capital expenditures, net of drilling and completion carries, of $8.0 – $8.5 billion and net undeveloped leasehold expenditures of $2.0 billion.

Drilling and completion costs during the Current Period reflected the effects of our deliberate transition to liquids-focused drilling and reduced natural gas drilling. During the 2011 fourth quarter, our rig count was as high as 172 rigs as we were rapidly ramping up our liquids-focused drilling while, at the same time, we were gradually ramping down drilling of natural gas wells. As of August 2, 2012, our rig count had been reduced to 125 rigs. Our budget reflects sharp reductions in our natural gas drilling activities, from 50 rigs at the beginning of 2012 to an average of ten rigs in the second half of 2012. The Current Period drilling and completion expenditures also reflected significant well completion costs for natural gas wells that had been drilled in prior periods. These completions, which we expect will represent more than 50% of all natural gas wells we complete during 2012, enabled us to hold the related leasehold according to the terms of our leases. For 2013, we are budgeting $5.750 – $6.250 billion for drilling and completion capital expenditures, net of drilling and completion carries.

Approximately 75% of our leasehold acquisition costs during the Current Period were focused on adding acreage in the Utica, Marcellus and Mid-Continent plays to complete our leasehold acquisition strategies in connection with completed or planned joint ventures in these areas. We anticipate significantly lower leasehold spending in the remainder of 2012, and we are projecting that our 2013 net undeveloped leasehold expenditures will decline to approximately $400 million. Having captured what we believe are the most promising areas of our core plays, we have now shifted our focus to developing these assets.

Capital expenditures related to our midstream, oilfield services and other assets were approximately $1.311 billion during the Current Period and are projected to be $2.8 – $3.1 billion and $850 million – $1.1 billion in 2012 and 2013, respectively. We estimate that the divestiture of our midstream business will enable us to reduce previously budgeted capital expenditures by approximately $1.0 – $1.250 billion in 2013 and approximately $3.0 billion over the three years ending 2015.

Recent Sales

An essential part of our business strategy is using the proceeds from sales to reduce our indebtedness and to fund the capital expenditures needed to transition from a natural gas-focused drilling program to a liquids-focused drilling program. Below we describe transactions completed in 2012 and the continuing benefits of our joint ventures which were completed prior to 2012.

Sale of Investment in Chesapeake Midstream Partners, L.P. In June 2012, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P. (NYSE:ACMP), and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners (GIP) for cash proceeds of $2.0 billion. We recorded a $1.032 billion gain associated with the transaction. This transaction will preserve the strategic relationship we have with ACMP as one of our primary midstream service providers and further strengthen the beneficial relationship we have enjoyed with GIP since 2009.

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Texoma Woodford Asset Sale. In April 2012, we sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Bryan, Carter, Johnston and Marshall counties in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for approximately $572 million in cash after certain deductions and closing costs. The properties included approximately 25 mmcfe per day of current net production. In conjunction with this transaction, affiliates of our Chief Executive Officer, Aubrey K. McClendon, sold interests in the same properties and on the same terms as those that applied to the interests sold by the Company, and proceeds were paid to the sellers based on their respective ownership. These interests were acquired through the Founder Well Participation Program (FWPP) which provides Mr. McClendon a contractual right to participate and invest as a working interest owner (with up to a 2.5% working interest) in new wells drilled on the Company’s leasehold through June 2014.

Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our natural gas and oil assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our corporate credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the Cleveland and Tonkawa plays covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in approximately 1,144 net wells, a portion of which we contributed to CHK C-T at the time of its formation and a portion of which will be drilled on certain of our Cleveland and Tonkawa play leasehold.

Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T. If we are current in our drilling commitment at the time, any such optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares. We may also cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares will be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return. As of June 30, 2012, the redemption price and the liquidation preference were each $1,335 per preferred share.

We have committed to drill, for the benefit of CHK C-T in the area of mutual interest, a minimum of 37.5 net wells per six-month period through 2013, inclusive of wells drilled in the Current Period, and 25 net wells per six-month period in 2014 through 2016, up to a minimum cumulative total of 300 net wells. CHK C-T is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. For further discussion, see Noncontrolling Interests in Note 6 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report.

Volumetric Production Payment (VPP). In March 2012, we monetized certain of our producing assets in the Anadarko Basin Granite Wash through a ten-year VPP for proceeds of approximately $744 million. The transaction included approximately 160 bcfe of proved reserves and approximately 125 mmcfe per day of net production. Chesapeake has retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores and we also retain all production beyond the specified volumes sold in the transaction. This transaction was our tenth VPP. The cash proceeds for this transaction were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. Other VPPs we completed in 2007 – 2011 are detailed in Note 8 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report.

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Joint Ventures. As of June 30, 2012, we had entered into seven significant joint ventures with other leading energy companies pursuant to which we sold a portion of our leasehold, producing properties and other assets located in seven different resource plays and received cash of $7.1 billion and commitments for future drilling and completion cost sharing of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all leasing, drilling, completion, operations and marketing activities for the project. The carry obligations paid by a joint venture partner are for a specified percentage of our drilling and completion cost obligations. In addition, a joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner. We bill our joint venture partners for their drilling carry obligations at the same time we bill them and other joint working interest owners for their share of drilling costs as they are incurred. Our joint venture transactions have allowed us to recover much or all of our initial leasehold investments and reduce our ongoing capital costs in these plays. The transactions are detailed below.

Primary Play	Joint Venture Partner(a)	Joint Venture Date	Interest Sold	Cash Proceeds Received at Closing		Total Drilling Carries			Total Cash and Drilling Carry Proceeds		Drilling Carries Remaining(b)
				($ in millions)
Utica	TOT	December 2011	25.0%	$	610	$	1,422		$	2,032	$	1,351
Niobrara	CNOOC	February 2011	33.3%		570		697			1,267		519
Eagle Ford	CNOOC	November 2010	33.3%		1,120		1,080			2,200		—
Barnett	TOT	January 2010	25.0%		800		1,404	(c)		2,204		—
Marcellus	STO	November 2008	32.5%		1,250		2,125			3,375		—
Fayetteville	BP	September 2008	25.0%		1,100		800			1,900		—
Haynesville & Bossier	PXP	July 2008	20.0%		1,650		1,508	(d)		3,158		—
				$	7,100	$	9,036		$	16,136	$	1,870

(a) Joint venture partners include Total S.A. (TOT), CNOOC Limited (CNOOC), Statoil (STO), BP America (BP) and Plains Exploration & Production Company (PXP).

(b) As of June 30, 2012. The Utica drilling carries cover 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. The Niobrara drilling carries cover 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize these drilling carry commitments prior to expiration. See Note 4 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report for further discussion of the Utica drilling carries.

(c) In conjunction with an agreement requiring us to maintain our operated rig count at no less than 12 rigs in the Barnett Shale through December 31, 2012, TOT accelerated the payment of its remaining joint venture drilling carry in exchange for an approximate 9% reduction in the total amount of drilling carry obligation owed to us at that time. As a result, in October 2011, we received $471 million in cash from TOT, which included $46 million of drilling carry obligation billed and $425 million for the remaining drilling carry obligation. In January 2012, Chesapeake and TOT agreed to reduce the minimum rig count from 12 to six rigs. In May 2012, Chesapeake and TOT agreed to further reduce the minimum rig count from six to two rigs.

(d) In September 2009, PXP accelerated the payment of its remaining drilling carry in exchange for an approximate 12% reduction to the remaining drilling carry obligation owed to us at that time.

The drilling and completion carries in our joint venture agreements create a significant cost advantage that allows us to reduce our future finding costs. During the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $518 million and $1.129 billion, respectively, of drilling and completion carries paid by our joint venture partners, CNOOC, TOT and STO. Our drilling and completion costs for 2012, 2013 and 2014 will continue to be partially offset by the use of the remaining drilling and completion carries associated with our joint venture agreements. Once the remaining carries have been used, we anticipate our net drilling and completion costs to increase.

During the Current Period, as part of our joint venture agreements with TOT and STO, we sold interests in additional leasehold in the Marcellus, Barnett and Utica shale plays for approximately $137 million. The cash proceeds from these transactions are reflected as a reduction of natural gas and oil properties with no gain or loss recognized.

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Planned Sales

We have entered into a letter agreement relating to the potential sale of certain Mid-Continent gathering and processing assets to ACMP and a separate letter agreement with GIP for the potential sale of our wholly owned subsidiary, Chesapeake Midstream Development, L.P. (CMD), to GIP. The parties to the GIP letter agreement have agreed to an exclusive negotiation and we anticipate completing this sale in the 2012 third quarter.

We are planning to sell assets in the Permian Basin in West Texas and southern New Mexico, where we own approximately 1.5 million net acres. During the 2012 third quarter, we expect to enter into agreements to sell all three of our Permian Basin asset packages. A purchase and sale agreement has been signed with affiliates of Houston-based EnerVest, Ltd. for our producing assets in the Midland Basin portion of the Permian Basin. Bids have also been received and accepted on two other packages in the Delaware Basin portion of the Permian Basin. We are currently negotiating sales agreements for the two Delaware Basin packages with the goal of closing the transactions in the 2012 third quarter. We plan to separately sell our non-producing assets in the Midland Basin, which were not included in the EnerVest sale. Our Permian Basin assets represent approximately 5% of the Company’s total proved reserves and current net production.

We are also pursuing a joint venture or sale transaction on a portion of our Mississippi Lime play in northern Oklahoma and southern Kansas, where we own approximately 2.0 million net acres. We anticipate completing this transaction in the 2012 third or fourth quarter.

In April 2012, our wholly owned service industry affiliate, Chesapeake Oilfield Services, Inc., filed a registration statement with the SEC relating to the proposed initial public offering of shares of its Class A common stock. Application will be made to list the Class A common stock on the New York Stock Exchange under the symbol “COS”. There can be no assurance that we will complete this transaction, as it is subject to market conditions and other uncertainties, as well as completion of the SEC review process.

Finally, we plan to continue to sell various non-core natural gas and oil assets and other miscellaneous investments.

Our ability to consummate each of these transactions is subject to changes in market conditions and other factors, some of which are beyond our control. We may not be able to enter into definitive agreements for all of the sales described above, or close the transactions, in the planned time frame, for the amounts projected, or at all. To the extent that proceeds from these potential transactions are less than expected, we may sell different or additional assets.

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Liquidity and Capital Resources

Liquidity Overview

Our business strategy is to continue our reserves and production growth and transition to increased liquids production. As part of this strategy, we plan to make capital expenditures in 2012 and 2013 that will significantly exceed our projected cash flow from operations. During the Current Period, the combination of high front-end capital expenditures and reduced cash flow as a result of low natural gas prices required that we increase our long-term debt, net of unrestricted cash, by approximately $3.0 billion, to $13.3 billion, to fund our capital expenditure needs. As of June 30, 2012, we had approximately $5.3 billion in cash availability compared to $3.1 billion as of December 31, 2011. In addition, our working capital deficit improved during the Current Period, and we expect this deficit to continue to improve based on our projected capital expenditures and cash flow. For the remainder of 2012, we plan to fund capital expenditures with operating cash flow and various sales including the sales described above under Planned Sales. In addition, since early 2011, it has been our plan, which we call the 25/25 Plan, to reduce our net long-term debt to no more than $9.5 billion by December 31, 2012, a 25% reduction from year-end 2010, and increase our production by 25% during the two years ended December 31, 2012.

The following table presents our budgeted sources and uses of cash for 2012:

	Year Ending December 31, 2012
	($ in millions)
Operating cash flow before changes in assets and liabilities(a)	$3,200 – $3,250
Drilling and completion costs	($8,000) – ($8,500)
Acquisition of unproved properties, net	($2,000)
Investment in oilfield services, midstream and other	($2,800) – ($3,100)
Subtotal of net investment	($12,800) – ($13,600)
Asset sales and other transactions	$13,000 – $14,000
Interest, dividends and cash taxes	($1,100) – ($1,350)
Total budgeted cash flow surplus	$2,300

(a) A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. Assumes NYMEX prices on open contracts of $3.00 to $3.25 per mcf and $90.00 per bbl.

We expect that the proceeds from our 2012 closed or planned sales, which we estimate will be $13.0 – $14.0 billion, will be sufficient to fund our budgeted capital expenditures, meet our long-term debt reduction plans by year-end 2012 and provide additional liquidity for 2013. We do not have binding agreements for all of the transactions we are planning to complete in the second half of 2012, however, and our ability to consummate each of them is subject to changes in market conditions and other factors. As a result, there can be no assurance that we will complete any of these transactions on a timely basis or at all. If we are unable to consummate these transactions or if they do not generate the proceeds we are anticipating, we would be required to reduce capital spending and/or seek funds from other sources, including our revolving bank credit facilities. If our access to funds from other sources were limited, our ability to develop and replace our reserves could be reduced. In addition, if we do not repay the term loans by year-end 2012, we will be subject to increased interest rates. See Term Loans below.

As part of our sales planning and capital expenditure budgeting process, we closely monitor the resulting effects on the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our corporate revolving bank credit facility. While sales enhance our ability to reduce debt, sales of producing natural gas and oil properties adversely affect the amount of cash flow and EBITDA we generate and reduce the amount and value of collateral available to secure our obligations, both of which are exacerbated by low natural gas, oil and NGL prices. Thus the assets we select and schedule for sales, our budgeted capital expenditures and our natural gas and oil price forecasts are carefully considered as we project our future ability to comply with the requirements of our corporate credit facility. Our ability to obtain capital from sales and our ability to achieve our forecasted EBITDA, are dependent on many factors, some of which are beyond our control. Changes in the amounts or timing of asset sales necessary to reduce our outstanding debt, or decreases in forecasted EBITDA, could adversely impact our ability to comply with financial covenants under our corporate revolving bank credit facility. In addition, continued compliance is subject to all the risks that may impact our business strategy.

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Through the vertical integration of our oilfield services business and as operator of a substantial number of our properties under development, we retain significant control and flexibility over the development plan and the associated timing, which we believe is instrumental to our business plan and strategy. While our capital raising activities enabled us to fund our capital program in 2011 and pursue our goal of long-term debt reduction, certain recent transactions require us to meet performance obligations and we have significant other contractual cash obligations to third parties pursuant to various lease arrangements, gathering, processing, and transportation agreements, drilling commitments, leasehold maintenance arrangements, fleet utilization agreements, and investments in new ventures (see Note 4 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report). While our business plan assumes that we will meet these commitments in the ordinary course of business, we are required to meet our performance and payment obligations regardless of whether our business plan changes for circumstances beyond our control.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the Current Period and the Prior Period:

	Six Months Ended June 30,
	2012			2011
	($ in millions)
Sources of cash and cash equivalents:
Operating cash flow	$	1,029		$	2,093
Sales of natural gas and oil assets		1,555			6,173
Proceeds from sales of other assets		79			526
Net proceeds from investments		1,872			212
Proceeds from long-term debt		5,052			977
Proceeds from sales of noncontrolling interests		1,039			—
Cash received on financing derivatives		—			882
Other		346			448
Total sources of cash and cash equivalents		10,972			11,311
Uses of cash and cash equivalents:
Natural gas and oil expenditures		(6,915	)		(5,924	)
Additions to other property and equipment		(1,311	)		(863	)
Acquisition of drilling company		—			(339	)
Net decrease in credit facilities		(1,488	)		(1,892	)
Cash paid to purchase debt		—			(2,032	)
Dividends paid		(198	)		(181	)
Distributions to noncontrolling interest owners		(104	)		—
Cash paid on financing derivatives and other		(276	)		(73	)
Total uses of cash and cash equivalents		(10,292	)		(11,304	)
Change in cash and cash equivalents held for sale		(7	)		—
Change in cash and cash equivalents	$	673		$	7

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Sources of Funds

Cash flow from operations is a source of liquidity we use to fund capital expenditures, pay dividends and repay debt. Cash provided by operating activities was $1.029 billion in the Current Period compared to $2.093 billion in the Prior Period. The decline in the cash flow from operations is primarily the result of a decrease in the realized natural gas price (excluding the effect of unrealized gains or losses on derivatives) from $5.25 per mcf in the Prior Period to $2.11 per mcf in the Current Period. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, depletion and amortization, deferred income taxes, mark-to-market changes in our derivative instruments and gains or losses on the sales and impairments of fixed assets. See the discussion below under Results of Operations.

The volatility in the energy markets makes it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty, leaving us exposed to potential reduction in our operating cash flow and therefore affecting our ability to fund our capital expenditures. To mitigate the risk of declines in these prices and to provide more predictable future cash flow from operations, we have entered into various derivative instruments; however, approximately 35% of our 2012 second half natural gas production is currently unhedged. Our natural gas, oil and NGL derivatives as of June 30, 2012 are detailed in Part I, Item 3 of this report. Depending on changes in natural gas, oil and NGL futures markets and management’s view of underlying natural gas, oil and NGL supply and demand trends, we may increase or decrease our current derivative positions. As natural gas, oil and NGL prices dip and reach supportable low prices, however, we may take the opportunity to close out open swap positions in order to lock in mark-to-market gains.

Sustained low natural gas prices, and volatile natural gas, oil and NGL prices in general, could have a material adverse effect on our financial position, results of operations and cash flows, which could adversely impact our ability to comply with financial covenants under our corporate revolving bank credit facility and further limit our ability to fund our planned capital expenditures. In addition, sustained low natural gas, oil and NGL prices could result in a reduction in the estimated quantity of proved reserves we report and in the estimated future net cash flows expected to be generated from our proved reserves. As a result, we may be required to write down the carrying value of our natural gas and oil properties, and such amounts could be material.

Current Period property divestiture proceeds of $1.555 billion included approximately $744 million from our tenth VPP transaction, approximately $572 million from the sale of our Texoma Woodford assets, $137 million of joint venture leasehold sales and approximately $102 million from other property sales. Prior Period property divestiture proceeds of $6.173 billion included $4.310 billion from the sale of our Fayetteville assets, $570 million at the closing of our Niobrara Shale joint venture, $853 million from our ninth VPP transaction, $345 million of joint venture leasehold sales and $95 million from other property sales.

In June 2012, we sold all of our limited partner and general partner interests in ACMP to funds affiliated with GIP for cash proceeds of $2.0 billion. We recorded a $1.0 billion gain associated with the transaction.

Our $4.0 billion corporate revolving bank credit facility, our $500 million oilfield services revolving bank credit facility and cash and cash equivalents are other sources of liquidity. We use the credit facilities and cash on hand to fund daily operating activities and capital expenditures as needed. We borrowed $10.104 billion and repaid $11.592 billion in the Current Period, and we borrowed $8.343 billion and repaid $10.235 billion in the Prior Period under our revolving bank credit facilities. Our corporate facility is secured by natural gas and oil proved reserves. A significant portion of our natural gas and oil reserves are currently unencumbered and therefore available to be pledged as additional collateral if needed to respond to borrowing base and collateral redeterminations our lenders might make in the future. Accordingly, we believe our borrowing capacity under this facility will not be reduced as a result of any such future redeterminations. Our oilfield services facility is secured by substantially all of our wholly owned oilfield services assets and is not subject to periodic borrowing base redeterminations. Our revolving bank credit facilities are described below under Bank Credit Facilities.

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In May 2012, we entered into unsecured term loans aggregating $4.0 billion. The net proceeds of the term loans, after customary fees and syndication costs, of approximately $3.789 billion were used to repay borrowings under our corporate revolving credit facility and for general corporate purposes. The loans carry an initial variable annual interest rate through December 31, 2012 of LIBOR plus 7.0%, which is currently 8.5% given the 1.5% LIBOR floor in the loan agreement. The loans, which rank equally with our outstanding senior notes, mature on December 2, 2017 and may be repaid at any time in 2012 without premium or penalty. Our term loan credit agreement is described below under Term Loans.

During the Current Period, we issued $1.3 billion of 6.775% Senior Notes due 2019 in a registered public offering. We used the net proceeds of $1.263 billion from the offering to repay indebtedness outstanding under our corporate revolving bank credit facility. At any time from and including November 15, 2012 to and including March 15, 2013, we may redeem some or all of the notes at a redemption price equal to 100% of the principal amount of the notes plus accrued and unpaid interest, if any, to the redemption date; provided that upon any redemption of the notes in part (and not in whole) pursuant to this redemption provision, at least $250 million aggregate principal amount of the notes remains outstanding.

During the Prior Period, we issued $1.0 billion of 6.125% Senior Notes due 2021 in a registered public offering. We used the net proceeds of $977 million from the offering to repay indebtedness outstanding under our corporate revolving bank credit facility.

During the Current Period, third-party investors contributed $1.25 billion in cash to CHK C-T, in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest in approximately 1,144 net wells, a portion of which we contributed to CHK C-T at the time of its formation and a portion of which will be drilled on certain of our Cleveland and Tonkawa play leasehold. CHK C-T is an unrestricted, non-guarantor consolidated subsidiary we formed in March 2012 to continue development of a portion of our Cleveland and Tonkawa plays covering Ellis and Roger Mills counties in western Oklahoma.

Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivative is deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows. In the Current Period, we paid $36 million and in the Prior Period, we received $882 million for settlements of derivatives which were classified as cash flows from financing activities.

Uses of Funds

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 $112 million and $95 million in the Current Period and the Prior Period, respectively. We paid dividends on our preferred stock of $86 million in both the Current Period and the Prior Period.

During the Current Period, we distributed $104 million in cash to certain of our noncontrolling interest owners.

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During the Prior Period, we completed and settled tender offers to purchase the following senior notes and contingent convertible senior notes. We funded the purchase of the notes with a portion of the net proceeds we received from the sale of our Fayetteville Shale assets.

	Principal Amount Purchased
	($ in millions)
7.625% senior notes due 2013	$	36
9.5% senior notes due 2015		160
6.25% euro-denominated senior notes due 2017(a)		380
6.5% senior notes due 2017		440
6.875% senior notes due 2018		126
7.25% senior notes due 2018		131
6.625% senior notes due 2020		100
Total senior notes		1,373
2.75% contingent convertible senior notes due 2035		55
2.5% contingent convertible senior notes due 2037		210
2.25% contingent convertible senior notes due 2038		266
Total contingent convertible senior notes		531
Total	$	1,904

(a) We purchased €256 million in aggregate principal amount of our euro-denominated senior notes which had a value of $380 million based on the exchange rate of $1.4821 to €1.00. Simultaneously with our purchase of the euro-denominated senior notes, we unwound cross currency swaps for the same principal amount. See Note 7 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report for additional information.

We paid $2.058 billion in cash for the tender offers described above and recorded associated losses of approximately $174 million. The losses included $154 million in cash premiums, $20 million of deferred charges, $160 million of note discounts and $2 million of interest rate hedging losses, offset by $162 million of the equity component of the contingent convertible notes.

During the Prior Period, we purchased $140 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for approximately $128 million. Associated with these purchases, we recognized a loss of $2 million.

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Investing Activities

Cash used in investing activities increased to $4.921 billion during the Current Period, compared to $240 million during the Prior Period. The majority of the $4.681 billion increase in cash used in investing activities was the result of the sale of our Fayetteville Shale assets in the Prior Period. We made significant additions to our liquids-rich leasehold acreage in both the Current Period and the Prior Period, with acquisitions of unproved properties totaling $1.452 billion and $2.166 billion, respectively. Drilling and completion costs on proved and unproved properties increased $1.708 billion to $5.007 billion in the Current Period compared to $3.299 billion in the Prior Period. This increase is due to increased drilling activity and a reduction in drilling carries received. See Capital Expenditures for a description of our Current Period and budgeted capital expenditures. The following table shows our cash used in investing activities during these periods:

	Six Months Ended
	June 30
	2012			2011
	($ in millions)
Natural Gas and Oil Investing Activities:
Drilling and completion costs (a)	$	(5,007	)	$	(3,299	)
Acquisitions of proved properties		(17	)		(35	)
Acquisitions of unproved properties		(1,452	)		(2,166	)
Proceeds from divestitures of proved and unproved properties		1,555			6,173
Geological and geophysical costs(b)		(113	)		(113	)
Interest capitalized on unproved properties		(326	)		(327	)
Total natural gas and oil investing activities		(5,360	)		233
Other Investing Activities:
Additions to other property and equipment		(1,311	)		(863	)
Proceeds from sales of other assets		79			526
Proceeds from (additions to) investments		(128	)		212
Proceeds from sale of midstream investment		2,000			—
Acquisition of drilling company		—			(339	)
Other		(201	)		(9	)
Total other investing activities		439			(473	)
Total cash used in investing activities	$	(4,921	)	$	(240	)

(a) Net of $518 million and $1.129 billion in drilling and completion carry credits received from our joint venture partners during the Current Period and the Prior Period, respectively.

(b) Including related capitalized interest.

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Bank Credit Facilities

During the Current Period, we used three revolving bank credit facilities as sources of liquidity. In June 2012, we paid off and terminated our midstream credit facility. Our two remaining revolving bank credit facilities are described below.

	Corporate Credit Facility(a)		Oilfield Services Credit Facility(b)
	($ in millions)
Facility structure		Senior secured revolving		Senior secured revolving
Maturity date		December 2015		November 2016
Borrowing capacity		$    4,000		$    500
Amount outstanding as of June 30, 2012		$         —		$    262
Letters of credit outstanding as of June 30, 2012		$         37		$      —

(a) Borrower is Chesapeake Exploration, L.L.C.

(b) Borrower is Chesapeake Oilfield Operating, L.L.C.

Our corporate and oilfield services credit facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates under our corporate credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, our credit facilities do not contain provisions which would trigger an acceleration of amounts due under the respective facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

Corporate Credit Facility. Our $4.0 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the facility are secured by proved reserves 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 0.50% to 1.25% per annum according to our senior unsecured long-term debt ratings, or (ii) the Eurodollar rate, which is based on 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% per annum. 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 and require us to maintain an indebtedness to total capitalization ratio and an indebtedness to EBITDA ratio, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at June 30, 2012. 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 $50 million or more, 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 $125 million.

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

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Oilfield Services Credit Facility. Our $500 million oilfield services syndicated revolving bank credit facility is used to fund capital expenditures and for general corporate purposes associated with our oilfield services operations. The facility has initial availability of $500 million and may be expanded to $900 million at COO’s option, subject to additional bank participation. Borrowings under the credit facility are secured by all of the equity interests and assets of COO and its wholly owned subsidiaries (the restricted subsidiaries), and bear interest at our option at either (i) the greater of the reference rate of Bank of America, N.A., the federal funds effective rate plus 0.50%, and one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.00% to 1.75% per annum or (ii) the Eurodollar rate, which is based on LIBOR plus a margin that varies from 2.00% to 2.75% per annum. The unused portion of the credit facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum. Both margins and commitment fees are determined according to the most recent leverage ratio described below. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The oilfield services credit facility agreement contains various covenants and restrictive provisions which limit the ability of COO and its restricted subsidiaries to incur additional indebtedness, make investments or loans and create liens. The agreement requires maintenance of a leverage ratio based on the ratio of lease adjusted indebtedness to EBITDAR, a senior secured leverage ratio based on a ratio of secured indebtedness to EBITDA and a fixed charge coverage ratio based on the ratio of EBITDAR to lease adjusted interest expense, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at June 30, 2012. If COO 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 oilfield services credit facility agreement also has cross default provisions that apply to other indebtedness COO and its restricted subsidiaries may have from time to time with an outstanding principal amount in excess of $15 million.

Midstream Credit Facility. Prior to June 15, 2012, we utilized a $600 million midstream syndicated senior secured revolving bank credit facility to fund capital expenditures to build natural gas gathering and other systems in support of our drilling program and for general corporate purposes associated with our midstream operations. With the anticipated sale of our midstream business in the second half of 2012, on June 15, 2012, we paid off and terminated our midstream credit facility.

Hedging Facility

We have a multi-counterparty secured hedging facility with 18 counterparties that have committed to provide approximately 6.5 tcfe of hedging capacity for natural gas, oil and NGL price derivatives and 6.5 tcfe for basis derivatives with an aggregate mark-to-market capacity of $17.5 billion under the terms of the facility. As of June 30, 2012, we had hedged under the facility 1.9 tcfe of our future production with price derivatives and 0.1 tcfe with basis derivatives. The multi-counterparty facility allows us to enter into cash-settled natural gas, oil and NGL price and basis derivatives with the counterparties. Our obligations under the multi-counterparty facility are secured by proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times at semi-annual collateral dates and 1.30 times in between these dates, and guarantees by certain subsidiaries that also guarantee our corporate revolving bank credit facility, indentures and sale/leaseback arrangements. 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 derivative instruments. In addition, there are volume-based sub-limits for natural gas, oil and NGL derivative instruments. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain requirements are met including maintaining specified collateral coverage ratios as well as maintaining credit ratings with either of the designated rating agencies at or above current levels. The facility does not have a maturity date. Counterparties to the agreement have the right to cease entering into derivative instruments with the Company on a prospective basis as long as obligations associated with any existing transactions in the facility continue to be satisfied in accordance with the terms of the agreement.

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Term Loans

In May 2012, we entered into $4.0 billion of unsecured term loans under a credit agreement that provides for term loans in an aggregate principal amount of $4.0 billion. The net proceeds of the term loans of approximately $3.789 billion after discount, customary fees and syndication costs were used to repay borrowings under our corporate revolving credit facility and for general corporate purposes. The term loans were issued at a discount of 3%, or $120 million, and the customary fees and syndication costs incurred were approximately $91 million. Amounts borrowed under the term loan credit agreement bear interest, at our option, at either (a) the Eurodollar rate, which is based on the London Interbank Offered Rate (LIBOR), plus a margin (as described below) or (b) a base rate equal to the greater of (i) the prime rate quoted in the Wall Street Journal, (ii) the federal funds effective rate plus 0.50% per annum and (iii) the Eurodollar rate that would be applicable to a Eurodollar loan with an interest period of one month plus 1% per annum, in each case, plus a margin. The Eurodollar rate is subject to a floor of 1.50% per annum and the base rate is subject to a floor of 2.50% per annum. Interest is payable quarterly or, if the Eurodollar rate applies, it may be payable at more frequent intervals. The initial applicable margin for Eurodollar loans is 7.0% per annum and the initial applicable margin for base rate loans is 6.0% per annum. If any amounts remain outstanding under the term loan credit agreement following January 1, 2013, the applicable margin under the term loan credit agreement will increase to 10.0% per annum for Eurodollar loans and to 9.0% per annum for base rate loans. Due to the escalating rate characteristic of the loan, we recognize interest expense using the interest method which based on the current applicable interest rates, yields an 11.16% interest rate over the loan term. To the extent interest rates increase above the current applicable rates, the increase will be accounted for in the respective period.

Amounts outstanding under the term loan credit agreement are unconditionally guaranteed on a joint and several basis by certain of the Company’s direct and indirect wholly owned subsidiaries (including the subsidiaries that are subsidiary guarantors under our corporate revolving bank credit facility). The term loans are not secured by any assets of the Company or its subsidiaries.

The term loans, which rank equally in right of payment with our outstanding senior notes, mature on December 2, 2017 and may be repaid, in whole or in part, at any time in 2012 without premium or penalty. On and following January 1, 2013, we are required to pay a yield maintenance premium, equal to the present value of all interest payments that would have been made in respect of the principal of such loans from the date of such prepayment to maturity, in connection with any prepayment (including the prepayments described in the following paragraph) prior to December 2, 2017.

The term loan credit agreement contains negative covenants substantially similar to those contained in the Company’s corporate revolving bank credit facility, including covenants that limit our ability to incur indebtedness, grant liens, make investments, loans and restricted payments and enter into certain business combination transactions. Other covenants include additional restrictions regarding the incurrence of certain unsecured indebtedness, the incurrence of secured indebtedness, the increase of dividends or payment of special dividends, investments in unrestricted subsidiaries and designations of subsidiaries as unrestricted subsidiaries. The term loan credit agreement also contains a covenant that requires that the net cash proceeds from certain asset dispositions and other asset sales, including assets of the Company or its subsidiaries in the Permian Basin in Texas and New Mexico, and certain financing transactions (subject to certain thresholds and exceptions) be used to either (a) prepay loans outstanding under the term loan credit agreement or (b) reduce the commitments and repay amounts outstanding under our corporate revolving bank credit facility (or, to the extent the proceeds exceed the commitments under the revolving facility, other senior debt). If, prior to January 1, 2013, we use such designated proceeds to repay amounts outstanding under our corporate revolving bank credit facility, then the applicable margin under the term loan credit agreement will increase to 8.0% per annum for Eurodollar loans and 7.0% per annum for base rate loans. The term loan credit agreement does not contain financial maintenance covenants.

We were in compliance with all covenants under the term loan credit agreement at June 30, 2012. If we should fail to perform our obligations under the agreement, the term loans could be terminated and any outstanding borrowings under the term loan credit agreement could be declared immediately due and payable. The term loan credit 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 $125 million.

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On or after May 11, 2013, the lenders will have the option (subject to certain thresholds) to exchange their loans under the term loan credit agreement for fixed rate notes (Exchange Notes). The Exchange Notes will bear interest at a fixed annual rate of 11.50%, payable semi-annually, will mature on December 2, 2017, will not be subject to any sinking fund or amortization and will contain substantially the same call protection (in the form of a customary treasury rate plus 50 basis points bond make-whole), covenants and events of default as the loans under the term loan credit agreement. The Exchange Notes will rank equally in right of payment with the loans under the term loan credit agreement.

Senior Note Obligations

In addition to outstanding borrowings under our revolving bank credit facilities and the term loans discussed above, our long-term debt consisted of the following:

	June 30, 2012
	($ in millions)
7.625% senior notes due 2013	$	464
9.5% senior notes due 2015		1,265
6.25% euro-denominated senior notes due 2017(a)		435
6.5% senior notes due 2017		660
6.875% senior notes due 2018		474
7.25% senior notes due 2018		669
6.625% senior notes due 2019(b)		650
6.775% senior notes due 2019		1,300
6.625% senior notes due 2020		1,300
6.875% senior notes due 2020		500
6.125% senior notes due 2021		1,000
2.75% contingent convertible senior notes due 2035(c)		396
2.5% contingent convertible senior notes due 2037(c)		1,168
2.25% contingent convertible senior notes due 2038(c)		347
Discount on senior notes(d)		(466	)
Interest rate derivatives(e)		23
	$	10,185

(a) The principal amount shown is based on the exchange rate of $1.2668 to €1.00 as of June 30, 2012. See Note 7 of our condensed consolidated financial statements included in this report for information on our related foreign currency derivatives.

(b) Issuers are COO and Chesapeake Oilfield Finance, Inc. (COF), a wholly owned subsidiary of COO formed solely to facilitate the offering of the 6.625% Senior Notes due 2019. COF is nominally capitalized and has no operations or revenues. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes.

(c) 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 second quarter of 2012, 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 third quarter of 2012 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

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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 in which 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		$    48.51	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032		$    63.93	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033		$  107.27	June 14, 2019

(d) Included in this discount is $411 million at June 30, 2012 associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method.

(e) See Note 7 of our condensed consolidated financial statements included in this report for discussion related to these instruments.

Chesapeake Senior Notes and Contingent Convertible Notes

The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured 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. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our wholly owned subsidiaries. COS Holdings, L.L.C. (COS) and its subsidiaries, CHK Utica, CHK C-T, Chesapeake Granite Wash Trust, MAC-LP, L.L.C., Cardinal Gas Services, L.L.C. (Cardinal), Utica East Ohio Midstream LLC (UEOM) and certain de minimis subsidiaries are not guarantors. See Note 13 of the notes to our condensed consolidated financial statements in Part 1, Item 1 of 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. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale/leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the contingent convertible senior notes do not have any financial or restricted payment covenants.

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.

No scheduled principal payments are required under our senior notes until July 2013 when $464 million is due.

COO Senior Notes

In October 2011, our wholly owned subsidiaries, COO and COF, issued $650 million principal amount of 6.625% Senior Notes due 2019 in a private placement. COO used the net proceeds of approximately $637 million from the placement to make a cash distribution to its direct parent, COS, to enable it to reduce indebtedness under an intercompany note with Chesapeake. Chesapeake then used the cash distribution to reduce indebtedness under its corporate revolving bank credit facility.

The COO senior notes are the unsecured senior obligations of COO and rank equally in right of payment with all of COO’s other existing and future senior unsecured indebtedness and rank senior in right of payment to all of its future subordinated indebtedness. The COO senior notes are jointly and severally, fully and unconditionally guaranteed by all of COO’s wholly owned subsidiaries, other than de minimis subsidiaries. The notes may be redeemed at any time at specified make-whole or redemption prices and, prior to November 15, 2014, up to 35% of the aggregate principal amount may be redeemed in connection with certain equity offerings. Holders of the COO notes have the right to require COO to repurchase their

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notes upon a change of control on the terms set forth in the indenture, and COO must offer to repurchase the notes upon certain asset sales. The COO senior notes are subject to covenants that may, among other things, limit the ability of COO and its subsidiaries to make restricted payments, incur indebtedness, issue preferred stock, create liens, and consolidate, merge or transfer assets.

Credit Risk

Derivative instruments that enable us to manage our exposure to natural gas, oil and NGL prices and interest rate volatility expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment-grade and 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 June 30, 2012, our natural gas, oil and NGL and interest rate derivative instruments were spread among 17 counterparties. Additionally, the counterparties under our multi-counterparty secured hedging facility are required to secure their obligations in excess of defined thresholds. We use this facility for the majority of our natural gas, oil and NGL derivatives.

Our accounts receivable are primarily from purchasers of natural gas, oil and NGL ($803 million at June 30, 2012) and exploration and production companies which own interests in properties we operate ($1.069 billion at June 30, 2012). 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 Period and the Prior Period, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables.

Contractual Obligations and Off-balance Sheet Arrangements

From time to time, we enter into arrangements and transactions that can give rise to off-balance sheet obligations. As of June 30, 2012, these arrangements and transactions included (i) operating lease agreements, (ii) VPP obligations (to physically deliver and purchase volumes and pay related production expenses and taxes in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit, (vii) variable interests held in VIEs and (viii) various other commitments we enter into in the ordinary course of business that could result in a future cash obligation.

As the operator of the properties from which the VPP volumes have been sold, we have the responsibility to bear the cost of producing the reserves attributable to such interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods such costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining the cost center ceiling for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet and the costs that will apply in the future will depend on the actual production costs and taxes in effect during the periods in which such production actually occurs, which could differ materially from our current and historical costs. We have committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

See Notes 4, 8 and 10 of the notes to our consolidated financial statements in Part I, Item 1 of this report for further discussion of commitments, VPPs and VIEs, respectively.

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Results of Operations – Three Months Ended June 30, 2012 vs. June 30, 2011

General. For the Current Quarter, Chesapeake had net income of $1.037 billion, or $1.29 per diluted common share, on total revenues of $3.389 billion. This compares to net income of $510 million, or $0.68 per diluted common share, on total revenues of $3.318 billion during the Prior Quarter.

Natural Gas, Oil and NGL Sales. During the Current Quarter, natural gas, oil and NGL sales were $2.117 billion compared to $1.792 billion in the Prior Quarter. In the Current Quarter, Chesapeake produced and sold 346.5 bcfe at a weighted average price of $3.77 per mcfe, compared to 277.5 bcfe produced and sold in the Prior Quarter at a weighted average price of $6.07 per mcfe (weighted average prices exclude the effect of unrealized gains on derivatives of $810 million and $107 million in the Current Quarter and the Prior Quarter, respectively). In the Current Quarter, the decrease in prices resulted in a decrease in revenues of $799 million and increased production resulted in a $420 million increase, for a total decrease in revenues of $379 million (excluding unrealized gains or losses on natural gas, oil and NGL derivatives). The increase in production from the Prior Quarter to the Current Quarter was primarily generated through the drillbit.

For the Current Quarter, we realized an average price per mcf of natural gas of $1.88, compared to $5.19 in the Prior Quarter (weighted average prices exclude the effect of unrealized gains or losses on derivatives). In the Prior Quarter, realized prices of natural gas include gains related to swaps that had an above-market fixed price on the origination date. We obtained these above-market swaps by selling out-year call options on a portion of our projected natural gas and oil production. Oil prices realized per barrel (excluding unrealized gains or losses on derivatives) were $91.58 and $87.99 in the Current Quarter and Prior Quarter, respectively. NGL prices realized per barrel (excluding unrealized gains or losses on derivatives) were $25.94 and $38.37 in the Current Quarter and the Prior Quarter, respectively. Realized gains or losses from our natural gas, oil and NGL derivatives resulted in a net increase in natural gas, oil and NGL revenues of $195 million, or $0.56 per mcfe, in the Current Quarter and a net increase of $407 million, or $1.46 per mcfe, in the Prior Quarter. See Part I, Item 3 of this report for a complete listing of all of our derivative instruments as of June 30, 2012.

A change in natural gas, oil and NGL prices has a significant impact on our revenues and cash flows. Assuming the Current Quarter production levels, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $28 million and $27 million, respectively, and an increase or decrease of $1.00 per barrel of liquids sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $12 million and $11 million, respectively, without considering the effect of hedging activities.

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The following tables show our production and prices received by operating division for the Current Quarter and the Prior Quarter:

	Three Months Ended
	June 30, 2012
	Natural Gas				Oil				NGL				Total
	(bcf)		($/mcf)(a)		(mmbbl)		($/bbl)(a)		(mmbbl)		($/bbl)(a)		(bcfe)		%			($/mcfe)(a)
Southern(b)		152.0		1.05		0.7		92.66		0.4		28.23		159.0		46			1.51
Northern		50.5		1.70		3.4		88.70		2.9		25.67		88.3		25			5.22
Eastern(c)		61.1		1.33		—		—		0.3		40.52		63.1		18			1.58
Western(d)		11.8		0.92		3.2		89.86		0.9		22.41		36.1		11			8.65
Total(e)		275.4		1.22		7.3		89.50		4.5		26.40		346.5		100	%		3.21
	Three Months Ended
	June 30, 2011
	Natural Gas				Oil				NGL				Total
	(bcf)		($/mcf)(a)		(mmbbl)		($/bbl)(a)		(mmbbl)		($/bbl)(a)		(bcfe)		%			($/mcfe)(a)
Southern(b)		133.5		2.92		—		—		0.2		35.69		135.0		49			2.96
Northern		56.4		3.80		2.5		97.44		2.5		41.61		86.7		31			6.52
Eastern(c)		30.3		3.64		—		—		0.2		52.15		31.8		12			3.96
Western		14.1		3.52		1.3		95.64		0.4		38.74		24.0		8			7.81
Total		234.3		3.26		3.8		96.69		3.3		41.66		277.5		100	%		4.61

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

(b) Our Southern division primarily includes the Haynesville/Bossier Shale and the Barnett Shale which held approximately 11% and 15%, respectively, of our estimated proved reserves by volume as of June 30, 2012. Production from the Haynesville/Bossier Shale and the Barnett Shale was 103.4 bcfe and 46.3 bcfe, respectively, for the Current Quarter and 98.6 bcfe and 33.8 bcfe, respectively, for the Prior Quarter.

Our Barnett Shale production is concentrated in urban areas where the cost to develop the necessary infrastructure to gather and deliver the natural gas to intrastate pipelines significantly exceeds the cost of similar infrastructure in non-urban areas. Additionally, the rapid development of the Barnett Shale required the construction of new pipelines to provide an adequate market for these new gas reserves. In order to support the timely construction of these new pipelines, we entered into firm transportation contracts that have resulted in lower natural gas price realizations in the Barnett Shale.

(c) Our Eastern division primarily includes the Marcellus Shale which held approximately 19% of our estimated proved reserves by volume as of June 30, 2012. Production from the Marcellus Shale for the Current Quarter and Prior Quarter was 55.5 bcfe and 26.4 bcfe, respectively.

(d) As the Eagle Ford Shale continues to be a developing play where additional infrastructure is being added to meet the growing production, we experienced lower natural gas and NGL price realizations in the Current Quarter as a result of higher transportation costs compared to more developed plays.

(e) The Current Quarter and Prior Quarter production reflects various asset sales. See Note 8 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report for information on our divestitures. In addition, we curtailed our production of natural gas in the Current Quarter. See discussion below.

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We curtailed our production of natural gas in the Current Quarter because of low natural gas prices. Curtailed natural gas volumes in the Current Quarter averaged approximately 330 mmcf per day net to Chesapeake compared to no curtailments in the Prior Quarter. We ended our natural gas production curtailment program at the end of the Current Quarter and do not anticipate needing to implement new curtailments during the remainder of 2012. As a result of reduced drilling activity planned for 2012 and 2013 in our dry natural gas plays, we are projecting a decline in our natural gas production of 7% in 2013.

Our average daily production of 3.808 bcfe for the Current Quarter consisted of 3.027 bcf of natural gas (79% on a natural gas equivalent basis) and approximately 130,200 bbls of liquids, consisting of approximately 80,500 bbls of oil (13% on a natural gas equivalent basis) and approximately 49,700 bbls of NGL (8% on a natural gas equivalent basis). Our year-over-year growth rate of natural gas production was 18% and our year-over-year growth rate of liquids production was 65%. Our percentage of revenues from liquids in the Current Quarter was 70% of unhedged natural gas, oil and NGL revenues compared to 40% in the Prior Quarter.

Marketing, Gathering and Compression Sales and Expenses. Marketing, gathering and compression sales and expenses consist of third-party revenue and expenses related to our marketing, gathering and compression operations. Marketing, gathering and compression activities are performed by Chesapeake primarily for owners in Chesapeake-operated wells. Chesapeake recognized $1.113 billion in marketing, gathering and compression sales in the Current Quarter with corresponding expenses of $1.096 billion, for a net margin before depreciation of $17 million. This compares to sales of $1.404 billion, expenses of $1.366 billion and a net margin before depreciation of $38 million in the Prior Quarter. In the Current Quarter, the decrease in revenues and expenses is due primarily to lower natural gas prices and the sale of certain of our Appalachian midstream assets in December 2011, partially offset by an increase in volumes marketed. In addition, we realized lower margins per mcfe during the Current Quarter primarily as a result of certain marketing arrangements whereby we resold natural gas and NGL at marginally lower market prices as compared to the contract price purchases of the natural gas and NGL.

Oilfield Services Revenues and Expenses. Oilfield services consist of third-party revenue and expenses related to our oilfield services operations. Chesapeake recognized $159 million in oilfield services revenues in the Current Quarter with corresponding expenses of $109 million, for a net margin before depreciation of $50 million. This compares to revenue of $122 million, expenses of $92 million and a net margin before depreciation of $30 million in the Prior Quarter. Oilfield services revenues, expenses and margins have increased as our oilfield services business has grown.

Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $335 million in the Current Quarter and $262 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.97 per mcfe in the Current Quarter compared to $0.94 per mcfe in the Prior Quarter. The per unit expense increase in the Current Quarter was primarily the result of an overall increase in field rates and the lifting costs associated with VPP production for VPP #10 and #9 completed in March 2012 and May 2011, respectively. Production expenses in the Current Quarter and Prior Quarter included approximately $58 million and $56 million, or $0.17 and $0.20 per mcfe, respectively, associated with VPP production volumes.

Production Taxes. Production taxes were $41 million in the Current Quarter compared to $46 million in the Prior Quarter. On a unit-of-production basis, production taxes were $0.12 per mcfe in the Current Quarter compared to $0.17 per mcfe in the Prior Quarter. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas and oil prices are higher. The $5 million decrease in production taxes in the Current Quarter was primarily due to a decrease in the average realized sales price of natural gas and liquids of $1.40 per mcfe (excluding gains or losses on derivatives), which was offset by an increase in production of 69 bcfe. Production taxes in the Current Quarter and Prior Quarter included approximately $5 million and $8 million, or $0.01 and $0.03 per mcfe, respectively, associated with VPP production volumes.

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General and Administrative Expenses. General and administrative expenses, including stock-based compensation but excluding internal costs capitalized to our natural gas and oil properties and other property, plant and equipment, were $156 million in the Current Quarter and $130 million in the Prior Quarter. General and administrative expenses were $0.45 and $0.46 per mcfe for the Current Quarter and Prior Quarter, respectively. Included in general and administrative expenses is stock-based compensation of $20 million for the Current Quarter and $23 million for the Prior Quarter. Restricted stock expense is based on the price of our common stock on the grant date of the award.

Our stock-based compensation for employees and non-employee directors is in the form of restricted stock and helps offset the fact that we do not have a pension plan. Employee restricted stock awards generally vest over a period of four years. Our non-employee director awards vest over a period of three years. The discussion of stock-based compensation in Note 6 of our condensed consolidated financial statements included in Part I, Item 1 of this report provides additional detail on the accounting for and reporting of our stock-based compensation.

Chesapeake follows the full cost method of accounting under which all costs associated with natural gas and oil property acquisition, divestiture, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, divestiture, drilling and completion activities and do not include any costs related to production, general corporate overhead or similar activities. In addition, we capitalize internal costs that can be identified with the construction of certain of our property, plant and equipment. We capitalized $119 million and $102 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our natural gas and oil property acquisition, divestiture, drilling and completion efforts and the construction of our property, plant and equipment.

Natural Gas, Oil and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of natural gas, oil and NGL properties was $588 million and $366 million during the Current Quarter and the Prior Quarter, respectively. The $222 million increase is primarily the result of a 25% increase in production from the Prior Quarter compared to the Current Quarter, an increase in estimated future development costs and capitalized costs compared to the additions in estimated proved reserves and the decrease in Barnett Shale and Haynesville Shale proved undeveloped reserves as a result of downward price revisions. 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 $1.70 and $1.32 in the Current Quarter and the Prior Quarter, respectively.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $83 million in the Current Quarter and $63 million in the Prior Quarter. Depreciation and amortization of other assets was $0.24 and $0.23 per mcfe for the Current Quarter and the Prior Quarter, respectively. The increase in the Current Quarter is primarily due to additional depreciation expense associated with assets acquired over the past year, offset by assets sold 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 drilling and completion costs.

Losses on Sales and Impairments of Fixed Assets. In the Current Quarter we determined that certain of our fixed assets were being carried at a value that was not recoverable and in excess of fair value. As a result, we recorded impairments of $243 million. These impairments consisted of $219 million related to surface land and an office building located in our Barnett Shale operating area, $15 million related to five owned drilling rigs and $9 million related to drill pipe. In the Prior Quarter, we recorded impairments of $4 million for certain fixed assets. Additionally, in the Prior Quarter we recorded losses on sales of $4 million for certain fixed assets.

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Interest Expense. Interest expense was $14 million in the Current Quarter compared to $25 million in the Prior Quarter as follows:

	Three Months Ended
	June 30,
	2012			2011
	($ in millions)
Interest expense on senior notes	$	185		$	164
Interest expense on credit facilities		16			10
Interest expense on term loans		62			—
Realized (gains) losses on interest rate derivatives		(1	)		13
Unrealized (gains) losses on interest rate derivatives		(6	)		6
Amortization of loan discount, issuance costs and other		42			8
Capitalized interest		(284	)		(176	)
Total interest expense	$	14		$	25
Average long-term borrowings	$	12,848		$	9,633

Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $0.06 per mcfe in the Current Quarter compared to $0.07 per mcfe in the Prior Quarter.

Earnings (Losses) on Investments. Earnings (losses) on investments were ($59) million and $47 million in the Current Quarter and the Prior Quarter, respectively, primarily as result of our equity in the net income (loss) of certain investments.

Gain on Sale of Investment. In the Current Quarter, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P. (NYSE:ACMP), and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners for cash proceeds of $2.0 billion. We recorded a $1.032 billion gain associated with the transaction.

Losses on Purchases or Exchanges of Debt. During the Prior Quarter, we completed tender offers to purchase $1.373 billion in aggregate principal amount of certain of our senior notes and $531 million in aggregate principal amount of certain of our contingent convertible senior notes. Associated with the tender offers, we recorded losses of approximately $166 million related to the senior notes and $8 million related to the contingent convertible senior notes.

Other Income. Other income was $5 million in the Current Quarter and $2 million in the Prior Quarter. The Current Quarter consisted of $5 million of miscellaneous income and the Prior Quarter included $2 million of miscellaneous income.

Income Taxes. Chesapeake recorded income tax expense of $663 million in the Current Quarter compared to income tax expense of $325 million in the Prior Quarter. Our effective income tax rate was 39% in both the Current Quarter and the Prior Quarter. Our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences.

Net Income Attributable to Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $65 million in the Current Quarter related to third-party ownership in CHK Utica, CHK C-T, the Chesapeake Granite Wash Trust and Cardinal Gas Services, L.L.C., all of which were formed in the fourth quarter of 2011 or the first quarter of 2012. There was no net income attributable to noncontrolling interests in the Prior Quarter.

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Results of Operations – Six Months Ended June 30, 2012 vs. June 30, 2011

General. For the Current Period, Chesapeake had net income of $1.033 billion, or $1.25 per diluted common share, on total revenues of $5.807 billion. This compares to net income of $347 million, or $0.41 per diluted common share, on total revenues of $4.930 billion during the Prior Period.

Natural Gas, Oil and NGL Sales. During the Current Period, natural gas, oil and NGL sales were $3.185 billion compared to $2.286 billion in the Prior Period. In the Current Period, Chesapeake produced and sold 679.4 bcfe at a weighted average price of $3.89 per mcfe, compared to 557.1 bcfe produced and sold in the Prior Period at a weighted average price of $6.03 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on derivatives of $540 million and ($1.075) billion in the Current Period and the Prior Period, respectively). In the Current Period, the decrease in prices resulted in a decrease in revenues of $1.454 billion and increased production resulted in a $738 million increase, for a total decrease in revenues of $716 million (excluding unrealized gains or losses on natural gas, oil and NGL derivatives). The increase in production from the Prior Period to the Current Period was primarily generated through the drillbit.

For the Current Period, we realized an average price per mcf of natural gas of $2.11, compared to $5.25 in the Prior Period (weighted average prices exclude the effect of unrealized gains or losses on derivatives). In the Prior Period, realized prices of natural gas included gains related to swaps that had an above-market fixed price on the origination date. We obtained these above-market swaps by selling out-year call options on a portion of our projected natural gas and oil production. Oil prices realized per barrel (excluding unrealized gains or losses on derivatives) were $92.06 and $87.39 in the Current Period and Prior Period, respectively. NGL prices realized per barrel (excluding unrealized gains or losses on derivatives) were $29.68 and $37.74 in the Current Period and the Prior Period, respectively. Realized gains or losses from our natural gas, oil and NGL derivatives resulted in a net increase in natural gas, oil and NGL revenues of $311 million, or $0.46 per mcfe, in the Current Period and a net increase of $896 million, or $1.60 per mcfe, in the Prior Period. See Part I, Item 3 of this report for a complete listing of all of our derivative instruments as of June 30, 2012.

A change in natural gas, oil and NGL prices has a significant impact on our revenues and cash flows. Assuming the Current Period production levels, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in Current Period revenues and cash flows of approximately $55 million and $53 million, respectively, and an increase or decrease of $1.00 per barrel of liquids sold would result in an increase or decrease in Current Period revenues and cash flows of approximately $22 million and $21 million, respectively, without considering the effect of hedging activities.

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The following tables show our production and prices received by operating division for the Current Period and the Prior Period:

	Six Months Ended June 30, 2012
	Natural Gas				Oil				NGL				Total
	(bcf)		($/mcf)(a)		(mmbbl)		($/bbl)(a)		(mmbbl)		($/bbl)(a)		(bcfe)		%			($/mcfe)(a)
Southern(b)		301.8		1.32		1.0		96.63		0.8		30.53		312.7		46			1.67
Northern		103.8		1.94		6.6		92.94		5.8		28.09		178.1		26			5.49
Eastern(c)		114.9		1.59		0.1		70.48		0.7		46.72		119.5		18			1.90
Western(d)		25.8		1.30		5.6		93.95		1.6		32.76		69.1		10			8.85
Total(e)		546.3		1.49		13.3		93.49		8.9		30.68		679.4		100	%		3.43
	Six Months Ended June 30, 2011
	Natural Gas				Oil				NGL				Total
	(bcf)		($/mcf)(a)		(mmbbl)		($/bbl)(a)		(mmbbl)		($/bbl)(a)		(bcfe)		%			($/mcfe)(a)
Southern(b)		244.8		2.88		—		—		0.5		33.62		247.7		45			2.94
Northern		147.9		3.61		4.7		93.69		4.7		40.56		204.9		37			5.69
Eastern(c)		58.0		3.58		0.1		76.32		0.4		54.32		60.7		11			3.90
Western		27.0		3.87		2.3		92.98		0.5		39.01		43.8		7			7.69
Total		477.7		3.25		7.1		93.40		6.1		40.93		557.1		100	%		4.43

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

(b) Our Southern division primarily includes the Haynesville/Bossier Shale and the Barnett Shale which held approximately 11% and 15%, respectively, of our estimated proved reserves by volume as of June 30, 2012. Production from the Haynesville/Bossier Shale and Barnett Shale was 205.8 bcfe and 92.8 bcfe, respectively, for the Current Period and 184.0 bcfe and 59.1 bcfe, respectively, for the Prior Period.

Our Barnett Shale production is concentrated in urban areas where the cost to develop the necessary infrastructure to gather and deliver the natural gas to intrastate pipelines significantly exceeds the cost of similar infrastructure in non-urban areas. Additionally, the rapid development of the Barnett Shale required the construction of new pipelines to provide an adequate market for these new gas reserves. In order to support the timely construction of these new pipelines, we entered into firm transportation contracts that have resulted in lower natural gas price realizations in the Barnett Shale.

(c) Our Eastern division primarily includes the Marcellus Shale which held approximately 19% of our estimated proved reserves by volume as of June 30, 2012. Production from the Marcellus Shale for the Current Period and Prior Period was 107.0 bcfe and 50.3 bcfe, respectively.

(d) As the Eagle Ford Shale continues to be a developing play where additional infrastructure is being added to meet the growing production, we experienced lower natural gas and NGL price realizations in the Current Period as a result of higher transportation costs compared to more developed plays.

(e) The Current Period and the Prior Period production reflects the sale of all of our Fayetteville Shale assets, which closed in March 2011 and various other asset sales. See Note 8 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report for information on divestitures. In addition, we curtailed our production of natural gas in the Current Period. See discussion below.

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We curtailed our production of natural gas in the Current Period, beginning in February, because of low natural gas prices. Curtailed natural gas volumes in the Current Period averaged approximately 330 mmcf per day net to Chesapeake compared to no curtailments in the Prior Period. We ended our natural gas production curtailment program at the end of the Current Period and do not anticipate needing to implement new curtailments during the remainder of 2012. As a result of reduced drilling activity planned for 2012 and 2013 in our dry natural gas plays, we are projecting a decline in our natural gas production of 7% in 2013.

Our average daily production of 3.733 bcfe for the Current Period consisted of 3.001 bcf of natural gas (80% on a natural gas equivalent basis) and approximately 121,900 bbls of liquids, consisting of approximately 73,300 bbls of oil (12% on a natural gas equivalent basis) and approximately 48,600 bbls of NGL (8% on a natural gas equivalent basis). Our year-over-year growth rate of natural gas production was 14% and our year-over-year growth rate of liquids production was 67%. Our percentage of revenues from liquids in the Current Period was 65% of unhedged natural gas, oil and NGL revenues compared to 37% in the Prior Period.

Marketing, Gathering and Compression Sales and Expenses. Marketing, gathering and compression sales and expenses consist of third-party revenue and expenses related to our marketing, gathering and compression operations. Marketing, gathering and compression activities are performed by Chesapeake primarily for owners in Chesapeake-operated wells. Chesapeake recognized $2.328 billion in marketing, gathering and compression sales in the Current Period with corresponding expenses of $2.292 billion, for a net margin before depreciation of $36 million. This compares to sales of $2.421 billion, expenses of $2.352 billion and a net margin before depreciation of $69 million in the Prior Period. In the Current Period, the decrease in revenues and expenses is due primarily to lower natural gas prices and the sale of certain of our Appalachian midstream assets in December 2011, partially offset by an increase in volumes marketed. In addition, we realized lower margins per mcfe during the Current Period primarily as a result of certain marketing arrangements whereby we resold natural gas and NGL at marginally lower market prices as compared to the contract price purchases of the natural gas and NGL.

Oilfield Services Revenues and Expenses. Oilfield services consist of third-party revenue and expenses related to our oilfield services operations. Chesapeake recognized $294 million in oilfield services revenues in the Current Period with corresponding expenses of $205 million, for a net margin before depreciation of $89 million. This compares to revenue of $223 million, expenses of $169 million and a net margin before depreciation of $54 million in the Prior Period. Oilfield services revenues, expenses and margins have increased as our oilfield services business has grown.

Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $685 million in the Current Period and $500 million in the Prior Period. On a unit-of-production basis, production expenses were $1.01 per mcfe in the Current Period compared to $0.90 per mcfe in the Prior Period. The per unit expense increase in the Current Period was primarily the result of a new fee retroactively imposed in Pennsylvania on spud wells, which had a $17 million, or $0.02 per mcfe effect, an overall increase in field rates and the lifting costs associated with VPP production for VPP #10 and #9 completed in March 2012 and May 2011, respectively. Production expenses in the Current Period and Prior Period included approximately $117 million and $110 million, or $0.17 and $0.20 per mcfe, respectively, associated with VPP production volumes.

Production Taxes. Production taxes were $89 million in the Current Period compared to $91 million in the Prior Period. On a unit-of-production basis, production taxes were $0.13 per mcfe in the Current Period compared to $0.16 per mcfe in the Prior Period. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas and oil prices are higher. The $2 million decrease in production taxes in the Current Period was primarily due to a decrease in the average realized sales price of natural gas and liquids of $1.00 per mcfe (excluding gains or losses on derivatives), which was offset by an increase in production of 122 bcfe. Production taxes in the Current Period and Prior Period included approximately $11 million and $15 million, or $0.02 and $0.03 per mcfe, respectively, associated with Current Period and Prior Period VPP production volumes.

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General and Administrative Expenses. General and administrative expenses, including stock-based compensation but excluding internal costs capitalized to our natural gas and oil properties and other property, plant and equipment, were $292 million in the Current Period and $259 million in the Prior Period. General and administrative expenses were $0.43 and $0.46 per mcfe for the Current Period and Prior Period, respectively. Included in general and administrative expenses is stock-based compensation of $38 million for the Current Period and $46 million for the Prior Period. Restricted stock expense is based on the price of our common stock on the grant date of the award.

Our stock-based compensation for employees and non-employee directors is in the form of restricted stock and helps offset the fact that we do not have a pension plan. Employee restricted stock awards generally vest over a period of four years. Our non-employee director awards vest over a period of three years. The discussion of stock-based compensation in Note 6 of our condensed consolidated financial statements included in Part I, Item 1 of this report provides additional detail on the accounting for and reporting of our stock-based compensation.

Chesapeake follows the full cost method of accounting under which all costs associated with natural gas and oil property acquisition, divestiture, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, divestiture, drilling and completion activities and do not include any costs related to production, general corporate overhead or similar activities. In addition, we capitalize internal costs that can be identified with the construction of certain of our property, plant and equipment. We capitalized $234 million and $211 million of internal costs in the Current Period and the Prior Period, respectively, directly related to our natural gas and oil property acquisition, divestiture, drilling and completion efforts and the construction of our property, plant and equipment.

Natural Gas, Oil and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of natural gas and oil properties was $1.094 billion and $724 million during the Current Period and the Prior Period, respectively. The $370 million increase is primarily the result of a 22% increase in production from the Prior Period compared to the Current Period, an increase in estimated future development costs and capitalized costs compared to the additions in estimated proved reserves and the decrease in Barnett Shale and Haynesville Shale proved undeveloped reserves as a result of downward price revisions. 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 $1.61 and $1.30 in the Current Period and the Prior Period, respectively.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $166 million in the Current Period and $131 million in the Prior Period. Depreciation and amortization of other assets was $0.25 and $0.24 per mcfe for the Current Period and the Prior Period, respectively. The increase in the Current Period is primarily due to additional depreciation expense associated with assets acquired over the past year, offset by assets sold 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 drilling and completion costs.

Losses on Sales and Impairments of Fixed Assets. In the Current Period, we recorded a ($2) million net gain on the sales of fixed assets. The gains in the Current Period were related to various sales of other fixed assets, including the sale of pipe, gas gathering systems and other miscellaneous assets. Also in the Current Period, we determined that certain of our fixed assets were being carried at a value that was not recoverable and in excess of fair value. As a result, we recorded impairments of $243 million. These impairments consisted of $219 million related to surface land and an office building located in our Barnett Shale operating area, $15 million related to five owned drilling rigs and $9 million related to drill pipe. In the Prior Period, we recorded $4 million of impairments for certain fixed assets. Also in the Prior Period, we recorded a ($1) million net gain associated with the sales of other fixed assets.

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Interest Expense. Interest expense was $26 million in the Current Period compared to $33 million in the Prior Period as follows:

	Six Months Ended June 30,
	2012			2011
	($ in millions)
Interest expense on senior notes	$	359		$	342
Interest expense on credit facilities		37			31
Interest expense on term loans		62			—
Realized (gains) losses on interest rate derivatives		—			6
Unrealized (gains) losses on interest rate derivatives		(2	)		12
Amortization of loan discount and other		42			23
Capitalized interest		(472	)		(381	)
Total interest expense	$	26		$	33
Average long-term borrowings	$	11,421		$	9,807

Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $0.04 per mcfe in both the Current Period and the Prior Period.

Earnings (Losses) on Investments. Earnings (losses) on investments were ($64) million and $72 million in the Current Period and the Prior Period, respectively, primarily as result of our equity in the net income (loss) of certain investments.

Gain on Sale of Investment. In the Current Period, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P. (NYSE:ACMP), and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners for cash proceeds of $2.0 billion. We recorded a $1.032 billion gain associated with the transaction.

Losses on Purchases or Exchanges of Debt. During the Prior Period, we completed tender offers to purchase $1.373 billion in aggregate principal amount of certain of our senior notes and $531 million in aggregate principal amount of certain of our contingent convertible senior notes. Associated with the tender offers, we recorded losses of approximately $166 million related to the senior notes and $8 million related to the contingent convertible senior notes. Also, during the Prior Period, we purchased $140 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for approximately $128 million, including accrued interest. Associated with these repurchases, we recognized a loss of $2 million in the Prior Period.

Other Income. Other income was $11 million in the Current Period and $5 million in the Prior Period. The Current Period consisted of $1 million of interest income and $10 million of miscellaneous income. The Prior Period included $1 million of interest income and $4 million of miscellaneous income.

Income Taxes. Chesapeake recorded income tax expense of $661 million in the Current Period compared to income tax expense of $222 million in the Prior Period. Our effective income tax rate was 39% in both the Current Period and the Prior Period. Our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences.

Chesapeake’s federal and state income tax returns are routinely audited by federal and state fiscal authorities. The Internal Revenue Service (IRS) is currently auditing our federal income tax returns for 2007 through 2009. As part of the administrative review process, in the first quarter of 2012, the IRS completed the field work related to its examination of our federal income tax returns and issued revenue agent reports for these tax years. As a result of these events, we reduced the balance of our unrecognized tax benefits related to NOL carryforwards and alternative minimum tax by approximately $269 million in the Current Period. This had no impact on our income tax expense or the effective income tax rate for the Current Period. At this time, we believe that the administrative review will be concluded without material impact on the Company.

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Net Income Attributable to Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $89 million in the Current Period related to third-party ownership in CHK Utica, CHK C-T, the Chesapeake Granite Wash Trust and Cardinal Gas Services, L.L.C., all of which were formed in the fourth quarter of 2011 or the first quarter of 2012. There was no net income attributable to noncontrolling interests in the Prior Period.

Application of Critical Accounting Policies

We consider accounting policies related to derivatives, variable interest entities, 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 2011 Form 10-K.

Recently Issued and Proposed Accounting Standards

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

In December 2011, the FASB issued guidance on disclosure of information about offsetting and related arrangements to enable users of a company’s financial statements to understand the effect of those arrangements on its financial position. The standard is effective for annual reporting periods beginning on or after January 1, 2013. This guidance will not have an impact on our financial position or results of operations.

In June 2011, the FASB issued guidance on comprehensive income, which provides two options for presenting items of net income, comprehensive income and total comprehensive income, by either creating one continuous statement of comprehensive income or two separate consecutive statements. We adopted this guidance in 2011. Adoption had no impact on our financial position or results of operations. In December 2011, the FASB deferred the effective date of certain presentation requirements for items reclassified out of accumulated other comprehensive income. This guidance will not have an impact on our financial position or results of operations.

In May 2011, the FASB issued guidance on fair value measurement and disclosure requirements which expands existing fair value disclosure requirements, particularly for Level 3 inputs. The new requirements include quantitative disclosure of the unobservable inputs and assumptions used in the measurement; description of the valuation processes in place and sensitivity of the fair value to changes in unobservable inputs; and the level of items (in the fair value hierarchy) that are not measured at fair value in the balance sheet but whose fair value must be disclosed. The guidance was effective for interim and annual periods beginning on or after December 15, 2011. Adoption had no impact on our financial position or results of operations.

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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, as amended (the “Exchange Act”). Forward-looking statements give our current expectations or forecasts of future events. They include estimates of natural gas and oil reserves, expected natural gas, oil and NGL production and future expenses, assumptions regarding future natural gas, oil and NGL prices, planned drilling activity and drilling and completion capital expenditures, and anticipated 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 2011 Form 10-K. They include:

• the volatility of natural gas, oil and NGL 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 sales, 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;

• 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, oil and NGL sales and the need to secure hedging liabilities;

• 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;

• oilfield services shortages, pipeline and gathering system capacity constraints and transportation 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 SEC that attempt to advise interested parties of the risks and factors that may affect our business.

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Natural Gas, Oil and NGL Derivatives

Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. 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 prices to be received for our hedged production. 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, oil and NGL 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 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 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 and options (calls and swaptions). All of these are described in more detail below. We typically use swaps for a large portion of the natural gas and oil volume we hedge. Swaps are used when the price level is acceptable. We also sell calls, taking advantage of market volatility for a portion of our projected production volumes. We do this when we would be satisfied to sell our production at the price being capped by the call strike price or believe it would 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. In the second half of 2011 and in the Current Period, we bought natural gas and oil calls to, in effect, lock in sold call positions. Due to lower natural gas, oil and NGL prices, we were able to achieve this at a low cost to us. We deferred the payment of the premium on these trades to the related month of production being hedged. At times, we have taken advantage of attractive strip prices in out-years and sold natural gas and oil call options to our counterparties in exchange for near-term natural gas swaps with fixed 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 natural gas swaps with fixed prices in excess of the market price for natural gas at that time. In the fourth quarter of 2011, we entered into oil swaps that can be extended at the option of the counterparty. This allows us to receive a higher fixed price on these swaps than what the market would have offered without such an option. Some of our derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception and the cash settlements associated with these instruments are classified as financing cash flows in the accompanying consolidated statement of cash flows.

We determine the volume we may potentially hedge by reviewing our 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 derivative instruments are already executed for some volume above the new production forecasts, the positions are reversed. The actual fixed 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 as stated in the contract and the floating-price payment, resulting in a net amount due to or from the counterparty.

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We adjust our derivative positions in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change and prices are at 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 trade that effectively reverses the current position. 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 derivative position. Gains or losses related to closed positions will be realized in the month of related production based on the terms specified in the original contract.

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 partially 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. See Note 12 of the notes to our consolidated financial statements in Part I, Item 1 of this report for further discussion of the fair value measurements associated with our derivatives.

As of June 30, 2012, our natural gas, oil and NGL derivative instruments consisted of the following:

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

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

• Swaptions: Chesapeake sells swaptions to counterparties that allow them, on a specific date, to extend an existing fixed-price swap for a certain period of time.

• Basis protection Swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. Our basis protection swaps 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.

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As of June 30, 2012, we had the following open natural gas, oil and NGL derivative instruments:

				Weighted Average Price							Designated Hedge	Fair Value
	Volume			Fixed		Call		Differential
	(tbtu)					(per mmbtu)						($ in millions)
Natural Gas:
Swaps:
Q3 2012		94		$	2.97	$	—	$	—		No	$	15
Q4 2012		93			2.97		—		—		No		(14	)
Call Options (sold):
Q3 2012		67			—		6.05		—		No		(2	)
Q4 2012		102			—		6.05		—		No		(11	)
2013		269			—		6.39		—		No		(9	)
2014		330			—		6.43		—		No		(32	)
2015		227			—		6.31		—		No		(41	)
2016		279			—		6.72		—		No		(74	)
2017 – 2020		114			—		10.92		—		No		(15	)
Call Options (bought)(a):
2012		(102	)		—		7.90		—		No		—
2013		(18	)		—		7.58		—		No		—
2015		(110	)		—		6.16		—		No		(39	)
2016		(44	)		—		6.00		—		No		(14	)
Basis Protection Swaps
Q3 2012		21			—		—		(0.80	)	No		(14	)
Q4 2012		8			—		—		(0.74	)	No		(5	)
2013		44			—		—		(0.21	)	No		(1	)
2014		28			—		—		(0.32	)	No		(3	)
2015		31			—		—		(0.34	)	No		(3	)
2016 – 2022		8			—		—		(1.02	)	No		(6	)
Total Natural Gas												$	(268	)

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				Weighted Average Price						Designated	Fair
	Volume			Fixed		Call		Differential		Hedge	Value
	(mmbbl)					(per bbl)					($ in millions)
Oil:
Swaps:
Q3 2012		3.5		$	102.30	$	—	$	—	No	$	56
Q4 2012		3.4			102.20		—		—	No		50
2013		1.7			96.75		—		—	No		14
2014 – 2015		1.4			90.02		—		—	No		3
Call Options (sold)(b):
Q3 2012		2.0			—		100.00		—	No		(1	)
Q4 2012		2.1			—		100.00		—	No		(4	)
2013		19.4			—		94.74		—	No		(149	)
2014		16.9			—		96.92		—	No		(148	)
2015		24.7			—		100.45		—	No		(226	)
2016		18.9			—		104.71		—	No		(167	)
2017		5.3			—		83.50		—	No		(89	)
Call Options (bought)(c):
2012		(3.2	)		—		100.00		—	No		4
2013		(9.3	)		—		90.80		—	No		8
2014		(2.2	)		—		94.91		—	No		2
Swaptions:
Q4 2012		0.5			106.72		—		—	No		—
2013		5.5			104.39		—		—	No		(10	)
2014		2.9			106.69		—		—	No		(10	)
2015		2.4			106.61		—		—	No		(4	)
Total Oil											$	(671	)
Total Natural Gas and Oil											$	(939	)

(a) Included in the fair value are deferred premiums of $61 million and $28 million which we will realize in 2015 and 2016, respectively.

(b) Included in oil call options are NGL call options in the amount of 5,000 bbls per day at $38.01 per bbl for 2012.

(c) Included in the fair value are deferred premiums of $81 million and $19 million which we will realize in 2013 and 2014, respectively.

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In addition to the open derivative positions disclosed above, at June 30, 2012, we had $172 million of net hedging gains related to settled trades for future production periods that will be recorded within natural gas, oil and NGL sales as realized gains (losses) as they are transferred from either accumulated other comprehensive income or unrealized gains (losses) in the month of related production based on the terms specified in the original contract as noted below.

	June 30, 2012
	($ in millions)
Q3 2012	$	21
Q4 2012		(18	)
2013		103
2014		(165	)
2015		216
2016 – 2022		15
Total	$	172

The table below reconciles the changes in fair value of our natural gas, oil and NGL derivatives during the Current Period. Of the $939 million fair value liability as of June 30, 2012, $6 million related to contracts maturing in the next 12 months and ($945) million related to contracts maturing after 12 months. All open derivative instruments as of June 30, 2012 are expected to mature by December 31, 2022.

	2012
	($ in millions)
Fair value of contracts outstanding, as of January 1	$	(1,639	)
Change in fair value of contracts		731
Fair value of new contracts when entered into		35
Contracts realized or otherwise settled		(38	)
Fair value of contracts when closed		(28	)
Fair value of contracts outstanding, as of June 30	$	(939	)

The change in natural gas, oil and NGL prices during the Current Period decreased the liability of our derivative instruments by $731 million. This gain is recorded in natural gas, oil and NGL sales. We entered into new contracts which were in an asset position of $35 million. We settled contracts that were in an asset position for $38 million and we closed out contracts that were in an asset position for $28 million. The realized gain is recorded in natural gas, oil and NGL 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 recognized in natural gas, oil and NGL sales as unrealized gains (losses). Realized gains (losses) consist of settled contracts related to the production periods being reported. Unrealized gains (losses) consist of both temporary fluctuations in the mark-to-market values and settled values related to future production periods of derivatives not designated as cash flow hedges. As of June 30, 2012, we did not have any natural gas, oil and NGL derivatives that were designated as cash flow hedges.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	($ in millions)
Natural gas, oil and NGL sales	$	1,112	$	1,278	$	2,334	$	2,465
Realized gains (losses) on natural gas, oil and NGL derivatives		195		407		311		896
Unrealized gains (losses) on natural gas, oil and NGL derivatives		810		99		540		(1,093	)
Unrealized gains (losses) on ineffectiveness of cash flow hedges		—		8		—		18
Total natural gas, oil and NGL sales	$	2,117	$	1,792	$	3,185	$	2,286

Interest Rate Risk

The table below presents principal cash flows and related weighted average interest rates by expected maturity dates.

	Years of Maturity
	2012		2013			2014		2015			2016			Thereafter			Total
	($ in millions)
Liabilities:
Long-term debt – fixed rate(a)	$	—	$	464		$	—	$	1,661		$	—		$	8,503		$	10,628
Average interest rate		—		7.63	%		—		7.89	%		—			5.89	%		6.28	%
Long-term debt – variable rate	$	—	$	—		$	—	$	—		$	262		$	4,000		$	4,262
Average interest rate		—		—			—		—			2.98	%		11.16	%		10.66	%

(a) This amount does not include the discount included in long-term debt of ($584) million and interest rate derivatives of $23 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.

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Interest Rate Derivatives

To mitigate a portion of our exposure to volatility in interest rates related to our senior notes and credit facilities, we enter into interest rate derivatives. As of June 30, 2012, our interest rate derivative instruments consisted 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 June 30, 2012, the following interest rate derivatives were outstanding:

	Notional Amount		Weighted Average Rate		Fair Value Hedge	Net Premiums		Fair Value
			Fixed	Floating(a)
	($ in millions)					($ in millions)
Fixed to Floating:
Swaption
Q3 2012	$	250	6.5%	3 mL plus 484 bp	No	$	1	$	—
Floating to Fixed:
Swaps
Mature 2014 – 2015	$	1,050	2.132%	1 – 6 mL	No		—		(41	)
						$	1	$	(41	)

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

In addition to the open derivative positions disclosed above, at June 30, 2012 we had $79 million of net gains related to settled derivative contracts that will be recorded within interest expense as realized gains (losses) as they are transferred from either our senior note liability or unrealized interest expense gains (losses) over the next nine-year term of the related senior notes.

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, the Prior Quarter, the Current Period and the Prior Period are presented below.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	($ in millions)
Interest expense on senior notes	$	185		$	164		$	359		$	342
Interest expense on credit facilities		16			10			37			31
Interest expense on term loans		62			—			62			—
Realized (gains) losses on interest rate derivatives		(1	)		13			—			6
Unrealized (gains) losses on interest rate derivatives		(6	)		6			(2	)		12
Amortization of loan discount and other		42			8			42			23
Capitalized interest		(284	)		(176	)		(472	)		(381	)
Total interest expense	$	14		$	25		$	26		$	33

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Foreign Currency Derivatives

In December 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 cross currency swaps to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. In May 2011, we purchased and subsequently retired €256 million in aggregate principal amount of these senior notes following a tender offer, and we simultaneously unwound the cross currency swaps for the same principal amount. As a result, we reclassified a loss of $38 million from accumulated other comprehensive income to the condensed consolidated statement of operations, $20 million of which related to the unwound notional amount and was included in losses on purchases or exchanges of debt, and $18 million of which related to future interest associated with the unwound principal and was included in interest expense. Under the terms of the remaining cross currency swaps, on each semi-annual interest payment date, the counterparties pay Chesapeake €11 million and Chesapeake pays the counterparties $17 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay Chesapeake €344 million and Chesapeake will pay the counterparties $459 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Through the cross currency swaps, we have eliminated any potential variability in Chesapeake’s expected cash flows related to changes in foreign exchange rates and therefore the swaps qualify as cash flow hedges. The fair values of the cross currency swaps are recorded on the condensed consolidated balance sheet as a liability of $48 million at June 30, 2012. The euro-denominated debt in long-term debt has been adjusted to $435 million at June 30, 2012 using an exchange rate of $1.2668 to €1.00.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC 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 management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Chesapeake’s disclosure controls and procedures pursuant to 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 were effective as of June 30, 2012.

Changes in Internal Control Over Financial Reporting

On April 1, 2012, we implemented several modules of a new enterprise resource planning system (ERP), PeopleSoft Enterprise Financial and Supply Chain Management (PeopleSoft) version 9.1 for our midstream subsidiaries. PeopleSoft, coupled with streamlined business processes and other software solutions, allows us to implement integrated processes and systems linking accounting, finance, supply chain, project management, data and people. This implementation was part of a focus on upgrading and enhancing our financial systems and was not in response to any internal control deficiencies. We are in the process of testing the internal controls over financial reporting to accommodate these modifications to our business processes.

With the exception of the ERP implementation described above, there was no change in our internal control over financial reporting during the Current Period which materially affected, or was reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

The Company is involved in a number of litigation and regulatory proceedings. Many of these proceedings are in early stages, and many of them seek an indeterminate amount of damages or penalties. See Litigation and Regulatory Proceedings and Environmental Risk in Note 4 of the notes to the condensed consolidated financial statements in Part I, Item 1 of this report, which information is incorporated herein by reference, for a description of matters arising during the Current Quarter and new developments in previously reported proceedings.

Also, we refer you to information in Part II, Item 1. Legal Proceedings of our quarterly report on Form 10-Q for the quarter ended March 31, 2012 about settlements the Company entered into in April 2012 with the West Virginia Department of Environmental Protection (WVDEP) that terminated WVDEP proceedings regarding alleged violations of the West Virginia Dam Control and Safety Act at four structures constructed for Chesapeake in West Virginia.

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 2011 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 SEC.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table presents information about repurchases of our common stock during the Current Quarter:

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)
April 1, 2012 through April 30, 2012		25,275	$	19.54		—		—
May 1, 2012 through May 31, 2012		10,817	$	16.47		—		—
June 1, 2012 through June 30, 2012		28,278	$	18.21		—		—
Total		64,370	$	18.44		—		—

(a) Reflects 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.

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ITEM 3. Defaults Upon Senior Securities

Not applicable.

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.

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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
2.1*	Purchase Agreement, dated June 7, 2012, by and among Chesapeake Midstream Holdings, L.L.C. and GIP II Eagle 1 Holding, L.P., GIP II Eagle 2 Holding, L.P. and GIP II Eagle 3 Holding, L.P.	8-K		001-13726	2.1		06/13/2012
2.2*	Purchase Agreement, dated June 7, 2012, by and between Chesapeake Midstream Holdings, L.L.C. and GIP II Eagle 4 Holding, L.P.	8-K		001-13726	2.2		06/13/2012
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), as amended.	10-Q		001-13726	3.1.4		11/10/2008
3.1.3	Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock, as amended.	10-Q		001-13726	3.1.6		08/11/2008
3.1.4	Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A).	8-K		001-13726	3.2		05/20/2010
3.1.5	Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended.	10-Q		001-13726	3.1.5		08/09/2010
3.2	Chesapeake’s Amended and Restated Bylaws.	8-K		001-13726	3.2		06/08/2012
4.1	Credit Agreement, dated May 11, 2012, among Chesapeake Energy Corporation, as Borrower, Goldman Sachs Bank USA, as Administrative Agent, Jefferies Finance LLC, as Syndication Agent, and the several lenders from time to time parties thereto.	8-K		001-13726	4.1		05/14/2012
4.2	Amendment Agreement, dated May 15, 2012, among Chesapeake Energy Corporation, as Borrower, Goldman Sachs Bank USA, as Administrative Agent, and Jefferies Finance LLC, as Syndication Agent.	8-K		001-13726	4.1		05/17/2012
10.1	Letter Agreement, dated as of April 30, 2012, between the Board of Directors and Aubrey K. McClendon.	8-K		001-13726	1.1		05/02/2012

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
10.2	Restated Chesapeake Energy Corporation Founder Well Participation Program.	8-K	001-13726	1.2	05/02/2012
10.3	Chesapeake Energy Corporation Amended and Restated Long Term Incentive Plan.	8-K	001-13726	10.1.14	06/08/2012
10.4	Form of Indemnity Agreement for Officers and Directors.	8-K	001-13726	10.3	06/27/2012
12	Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.					X
31.1	Aubrey K. McClendon, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
31.2	Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
32.1	Aubrey K. McClendon, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.						X
32.2	Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.						X
101.INS	XBRL Instance Document.					X
101.SCH	XBRL Taxonomy Extension Schema Document.					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.					X
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document.					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.					X

* Schedules and exhibits omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally a copy of any omitted schedule or exhibit to the Securities and Exchange Commission upon request.

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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: August 9, 2012	By:	/s/ AUBREY K. MCCLENDON
		Aubrey K. McClendon President and Chief Executive Officer

Date: August 9, 2012	By:	/s/ DOMENIC J. DELL’OSSO, JR.
		Domenic J. Dell’Osso, Jr. Executive Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number		Exhibit	Filing Date		Filed Herewith	Furnished Herewith
2.1*	Purchase Agreement, dated June 7, 2012, by and among Chesapeake Midstream Holdings, L.L.C. and GIP II Eagle 1 Holding, L.P., GIP II Eagle 2 Holding, L.P. and GIP II Eagle 3 Holding, L.P.	8-K		001-13726	2.1		06/13/2012
2.2*	Purchase Agreement, dated June 7, 2012, by and between Chesapeake Midstream Holdings, L.L.C. and GIP II Eagle 4 Holding, L.P.	8-K		001-13726	2.2		06/13/2012
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), as amended.	10-Q		001-13726	3.1.4		11/10/2008
3.1.3	Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock, as amended.	10-Q		001-13726	3.1.6		08/11/2008
3.1.4	Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A).	8-K		001-13726	3.2		05/20/2010
3.1.5	Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended.	10-Q		001-13726	3.1.5		08/09/2010
3.2	Chesapeake’s Amended and Restated Bylaws.	8-K		001-13726	3.2		06/08/2012
4.1	Credit Agreement, dated May 11, 2012, among Chesapeake Energy Corporation, as Borrower, Goldman Sachs Bank USA, as Administrative Agent, Jefferies Finance LLC, as Syndication Agent, and the several lenders from time to time parties thereto.	8-K		001-13726	4.1		05/14/2012
4.2	Amendment Agreement, dated May 15, 2012, among Chesapeake Energy Corporation, as Borrower, Goldman Sachs Bank USA, as Administrative Agent, and Jefferies Finance LLC, as Syndication Agent.	8-K		001-13726	4.1		05/17/2012
10.1	Letter Agreement, dated as of April 30, 2012, between the Board of Directors and Aubrey K. McClendon.	8-K		001-13726	1.1		05/02/2012
10.2	Restated Chesapeake Energy Corporation Founder Well Participation Program.	8-K		001-13726	1.2		05/02/2012

108

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number		Exhibit	Filing Date		Filed Herewith		Furnished Herewith
10.3	Chesapeake Energy Corporation Amended and Restated Long Term Incentive Plan.	8-K		001-13726	10.1.14		06/08/2012
10.4	Form of Indemnity Agreement for Officers and Directors.	8-K		001-13726	10.3		06/27/2012
12	Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.								X
31.1	Aubrey K. McClendon, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.								X
31.2	Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.								X
32.1	Aubrey K. McClendon, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.										X
32.2	Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.										X
101.INS	XBRL Instance Document.								X
101.SCH	XBRL Taxonomy Extension Schema Document.								X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.								X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.								X
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document.								X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.								X

* Schedules and exhibits omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally a copy of any omitted schedule or exhibit to the Securities and Exchange Commission upon request.

109