CHK-2012.9.30-10Q
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X]    Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period Ended September 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 November 2, 2012, there were 664,655,404 shares of our common stock, $0.01 par value, outstanding.
 


Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2012


PART I.
Financial Information
 
 
Page
Item 1.
Condensed Consolidated Financial Statements (Unaudited):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
PART II.
 
 
Other Information
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
Item 5.
 
 
 
Item 6.



Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


 
September 30, 2012
 
December 31, 2011
 
($ in millions)
CURRENT ASSETS:
 
 
 
Cash and cash equivalents ($1 and $1 attributable to our VIEs)
$
142

 
$
351

Restricted cash
156

 
44

Accounts receivable
2,291

 
2,505

Short-term derivative assets
31

 
13

Deferred income tax asset
692

 
139

Other current assets
188

 
125

Current assets held for sale ($14 and $0 attributable to our VIEs)
111

 
—

Total Current Assets
3,611

 
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)
51,014

 
41,723

Unevaluated properties
15,254

 
16,685

Natural gas gathering systems and treating plants
—

 
1,455

Oilfield services equipment
1,972

 
1,611

Other property and equipment
3,629

 
3,555

Total Property and Equipment, at Cost
71,869

 
65,029

Less: accumulated depreciation, depletion and amortization (($43) and ($6) attributable to our VIEs)
(33,573
)
 
(28,290
)
Property and equipment held for sale, net ($121 and $0 attributable to our VIEs)
2,307

 
—

Total Property and Equipment, Net
40,603

 
36,739

LONG-TERM ASSETS:
 
 
 
Investments
647

 
1,531

Long-term derivative assets
6

 
—

Other long-term assets
681

 
388

Long-term assets held for sale
123

 
—

TOTAL ASSETS
$
45,671

 
$
41,835

CURRENT LIABILITIES:
 
 
 
Accounts payable
$
2,357

 
$
3,311

Short-term derivative liabilities ($5 and $9 attributable to our VIEs)
150

 
191

Accrued interest
213

 
183

Current maturities of long-term debt, net
463

 
—

Other current liabilities ($20 and $23 attributable to our VIEs)
3,097

 
3,397

Current liabilities held for sale ($31 and $0 attributable to our VIEs)
176

 
—

Total Current Liabilities
6,456

 
7,082

LONG-TERM LIABILITIES:
 
 
 
Long-term debt, net
15,755

 
10,626

Deferred income tax liabilities
3,418

 
3,484

Long-term derivative liabilities ($3 and $10 attributable to our VIEs)
999

 
1,541

Asset retirement obligations
353

 
323

Other long-term liabilities
997

 
818

Long-term liabilities held for sale
2

 
—

Total Long-Term Liabilities
21,524

 
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:
 
 
 
666,955,284 and 660,888,159 shares issued
7

 
7

Paid-in capital
12,246

 
12,146

Retained earnings
241

 
1,608

Accumulated other comprehensive income (loss)
(188
)
 
(166
)
Less: treasury stock, at cost; 1,860,507 and 1,552,533 common shares
(41
)
 
(33
)
Total Chesapeake Stockholders’ Equity
15,327

 
16,624

Noncontrolling interests
2,364

 
1,337

Total Equity
17,691

 
17,961

TOTAL LIABILITIES AND EQUITY
$
45,671

 
$
41,835


The accompanying notes are an integral part of these condensed consolidated financial statements.
1
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
 
($ in millions, except per share data)
REVENUES:
 
 
 
 
 
 
 
Natural gas, oil and NGL
$
1,437

 
$
2,402

 
$
4,622

 
$
4,688

Marketing, gathering and compression
1,381

 
1,422

 
3,710

 
3,844

Oilfield services
152

 
153

 
446

 
376

Total Revenues
2,970

 
3,977

 
8,778

 
8,908

OPERATING EXPENSES:
 
 
 
 
 
 
 
Natural gas, oil and NGL production
320

 
282

 
1,005

 
782

Production taxes
53

 
50

 
141

 
140

Marketing, gathering and compression
1,339

 
1,392

 
3,631

 
3,744

Oilfield services
116

 
118

 
321

 
287

General and administrative
148

 
151

 
440

 
410

Natural gas, oil and NGL depreciation, depletion and amortization
762

 
423

 
1,856

 
1,147

Depreciation and amortization of other assets
66

 
75

 
233

 
206

Impairment of natural gas and oil properties
3,315

 
—

 
3,315

 
—

Losses on sales and impairments of fixed assets and other
45

 
3

 
286

 
7

Total Operating Expenses
6,164

 
2,494

 
11,228

 
6,723

INCOME (LOSS) FROM OPERATIONS
(3,194
)
 
1,483

 
(2,450
)
 
2,185

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense
(36
)
 
(4
)
 
(63
)
 
(37
)
Earnings (losses) on investments
(23
)
 
28

 
(87
)
 
100

Gains on sales of investments
31

 
—

 
1,061

 
—

Losses on purchases or exchanges of debt
—

 
—

 
—

 
(176
)
Other income (expense)
(9
)
 
4

 
2

 
9

Total Other Income (Expense)
(37
)
 
28

 
913

 
(104
)
INCOME (LOSS) BEFORE INCOME TAXES
(3,231
)
 
1,511

 
(1,537
)
 
2,081

INCOME TAX EXPENSE (BENEFIT):
 
 
 
 
 
 
 
Current income taxes
22

 
(1
)
 
24

 
11

Deferred income taxes
(1,282
)
 
590

 
(623
)
 
801

Total Income Tax Expense (Benefit)
(1,260
)
 
589

 
(599
)
 
812

NET INCOME (LOSS)
(1,971
)
 
922

 
(938
)
 
1,269

Net income attributable to noncontrolling interests
(41
)
 
—

 
(131
)
 
—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
(2,012
)
 
922

 
(1,069
)
 
1,269

Preferred stock dividends
(43
)
 
(43
)
 
(128
)
 
(128
)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
$
(2,055
)
 
$
879

 
$
(1,197
)
 
$
1,141

EARNINGS (LOSS) PER COMMON SHARE:
 
 
 
 
 
 
 
Basic
$
(3.19
)
 
$
1.38

 
$
(1.86
)
 
$
1.79

Diluted
$
(3.19
)
 
$
1.23

 
$
(1.86
)
 
$
1.69

CASH DIVIDEND DECLARED PER COMMON SHARE
0.0875

 
0.0875

 
0.2625

 
0.25

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
 
 
 
 
 
 
 
Basic
644

 
638

 
643

 
636

Diluted
644

 
753

 
643

 
752


The accompanying notes are an integral part of these condensed consolidated financial statements.
2
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)


 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
 
($ in millions)
NET INCOME (LOSS)
$
(1,971
)
 
$
922

 
$
(938
)
 
$
1,269

Other comprehensive income (loss), net of income tax:
 
 
 
 
 
 
 
Unrealized gain (loss) on derivative instruments, net of income taxes
of $1 million, $44 million, $1 and $133 million
3

 
72

 
3

 
218

Reclassification of gain on settled derivative instruments,
net of income taxes of ($3) million, ($49) million,
($10) million and ($88) million
(6
)
 
(80
)
 
(18
)
 
(144
)
Ineffective portion of derivatives designated as cash flow hedges, net of income taxes of $0, $2 million,
       $0 and ($5) million
—

 
3

 
—

 
(8
)
Unrealized gain (loss) on investments, net of income taxes
of ($2) million, ($1) million, ($4) million and ($2) million
(3
)
 
(1
)
 
(7
)
 
(4
)
Other comprehensive income (loss)
(6
)
 
(6
)
 
(22
)
 
62

COMPREHENSIVE INCOME (LOSS)
(1,977
)
 
916

 
(960
)
 
1,331

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
(41
)
 
—

 
(131
)
 
—

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
$
(2,018
)
 
$
916

 
$
(1,091
)
 
$
1,331



The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


 
Nine Months Ended
September 30,
 
2012
 
2011
 
($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
NET INCOME (LOSS)
$
(938
)
 
$
1,269

ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
 
 
 
Depreciation, depletion and amortization
2,089

 
1,353

Deferred income tax expense (benefit)
(623
)
 
801

Unrealized (gains) losses on derivatives
(440
)
 
456

Stock-based compensation
93

 
119

Losses on sales and impairments of fixed assets
262

 
7

Impairment of natural gas and oil properties
3,315

 
—

(Gains) losses on investments
147

 
(19
)
Gains on sales of investments
(1,061
)
 
—

Other
80

 
12

Changes in assets and liabilities
(946
)
 
(274
)
Cash provided by operating activities
1,978

 
3,724

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Drilling and completion costs
(7,525
)
 
(5,345
)
Acquisitions of proved and unproved properties
(2,813
)
 
(3,773
)
Proceeds from divestitures of proved and unproved properties
2,445

 
6,357

Additions to other property and equipment
(1,916
)
 
(1,416
)
Proceeds from sales of other assets
219

 
682

Proceeds from (additions to) investments
(261
)
 
126

Proceeds from sale of midstream investment
2,000

 
—

Acquisition of drilling company
—

 
(339
)
Increase in restricted cash
(280
)
 
—

Other
(23
)
 
(7
)
Cash used in investing activities
(8,154
)
 
(3,715
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Proceeds from credit facilities borrowings
13,986

 
11,914

Payments on credit facilities borrowings
(13,614
)
 
(12,057
)
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
—

 
(2,015
)
Cash paid for common stock dividends
(170
)
 
(151
)
Cash paid for preferred stock dividends
(128
)
 
(128
)
Cash (paid) received on financing derivatives
(36
)
 
1,085

Proceeds from sales of noncontrolling interests
1,056

 
—

Proceeds from other financings
225

 
—

Distributions to noncontrolling interest owners
(163
)
 
—

Net increase (decrease) in outstanding payments in excess of cash balance
(159
)
 
489

Other
(68
)
 
(114
)
Cash provided by financing activities
5,981

 
—

Change in cash and cash equivalents classified as current assets held for sale
(14
)
 
—

Net increase (decrease) in cash and cash equivalents
(209
)
 
9

Cash and cash equivalents, beginning of period
351

 
102

Cash and cash equivalents, end of period
$
142

 
$
111

 

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 – (Continued)
(Unaudited)

 
Nine Months Ended
September 30,
 
2012
 
2011
 
($ in millions)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION OF NET CASH PAYMENTS (REFUNDS) FOR:
 
 
 
Interest, net of capitalized interest
$
—

 
$
18

Income taxes, net of refunds received
$
31

 
$
(25
)
SUPPLEMENTAL SCHEDULE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Dividends payable on our common and preferred stock were $99 million as of September 30, 2012 and 2011.
For the nine months ended September 30, 2012 and 2011, natural gas and oil properties decreased by $103 million and increased by $148 million, respectively, as a result of an increase or decrease in accrued acquisition, drilling and completion costs.
For the nine months ended September 30, 2012 and 2011, other property and equipment was adjusted by $57 million and $90 million, respectively, as a result of an increase in accrued costs.
As of September 30, 2012 and 2011, we recorded $60 million and $173 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.
5
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)


 
Nine Months Ended
September 30,
 
2012
 
2011
 
($ in millions)
PREFERRED STOCK:
 
 
 
Balance, beginning and end of period
$
3,062

 
$
3,065

Exchange of 0 and 3,000 shares of preferred stock for common stock
—

 
(3
)
Balance, end of period
3,062

 
3,062

COMMON STOCK:
 
 
 
Balance, beginning and end of period
7

 
7

PAID-IN CAPITAL:
 
 
 
Balance, beginning of period
12,146

 
12,194

Stock-based compensation
116

 
120

Exchange of 0 and 3,000 shares of preferred stock for common stock
—

 
3

Purchase of contingent convertible notes
—

 
(123
)
Reduction in tax benefit from stock-based compensation
(18
)
 
(5
)
Dividends on common stock
—

 
(48
)
Dividends on preferred stock
—

 
(15
)
Exercise of stock options
2

 
2

Balance, end of period
12,246

 
12,128

RETAINED EARNINGS:
 
 
 
Balance, beginning of period
1,608

 
190

Net income (loss) attributable to Chesapeake
(1,069
)
 
1,269

Dividends on common stock
(170
)
 
(112
)
Dividends on preferred stock
(128
)
 
(113
)
Balance, end of period
241

 
1,234

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
 
 
 
Balance, beginning of period
(166
)
 
(168
)
Hedging activity
(15
)
 
66

Investment activity
(7
)
 
(4
)
Balance, end of period
(188
)
 
(106
)
TREASURY STOCK – COMMON:
 
 
 
Balance, beginning of period
(33
)
 
(24
)
Purchase of 357,565 and 191,153 shares for company benefit plans
(9
)
 
(5
)
Release of 49,591 and 74,004 shares from company benefit plans
1

 
2

Balance, end of period
(41
)
 
(27
)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY
15,327

 
16,298

NONCONTROLLING INTERESTS:
 
 
 
Balance, beginning of period
1,337

 
—

Sales of noncontrolling interests
1,056

 
—

Net income attributable to noncontrolling interests
131

 
—

Distributions to noncontrolling interest owners
(160
)
 
—

Balance, end of period
2,364

 
—

TOTAL EQUITY
$
17,691

 
$
16,298




The accompanying notes are an integral part of these condensed consolidated financial statements.
6
Table of Contents
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). This Form 10-Q relates to the three and nine months ended September 30, 2012 (the “Current Quarter” and the “Current Period”, respectively) and three and nine months ended September 30, 2011 (the “Prior Quarter” and the “Prior Period”, respectively). 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 presentation 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 Current Quarter and the Current Period are not necessarily indicative of the results to be expected for the full year.
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
Our business strategy is to continue our reserves and production growth and transition our asset base from an exclusive focus on natural gas production to a focus that is, and in the future will remain, more balanced between natural gas and liquids production. This is a capital-intensive strategy, and we made capital expenditures in the Current Period that exceeded our cash flow from operations, filling this gap with borrowings and proceeds from sales of assets that we determined were non-core or did not fit our long-term plans. See Notes 8 and 16 for a description of our completed 2012 asset sales. We project that our capital expenditures will continue to exceed our operating cash flow through 2013; however, we expect to see a much smaller gap between our cash flow from operations and capital expenditures in 2013 than we have experienced in 2012.
As part of our asset 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 may adversely affect the amount of cash flow and earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) we generate and reduce the amount and value of collateral available to secure our obligations, both of which can be exacerbated by low prices received for our production. Thus, the assets we select and schedule for sales, our budgeted capital expenditures and our natural gas, oil and NGL price forecasts are carefully considered as we project our future ability to comply with the financial covenant maintenance requirements of our corporate revolving bank credit facility. In September 2012, the existing leverage ratio covenant was increased through an amendment to the credit facility agreement. See Note 3 for discussion of the terms of the amendment. We would have been unable to meet the required ratio as of September 30, 2012 without this amendment primarily because the closing of asset sales transactions occurred in the fourth quarter and not in September as we had anticipated. As a result, without the amendment, we would have been unable to reduce our indebtedness sufficiently as of September 30, 2012 to maintain our covenant compliance. The amendment relaxes our required indebtedness to EBITDA ratio for the quarter ended September 30, 2012 and the four subsequent quarters. Failure to maintain compliance with the covenants of our revolving bank credit facility would, absent a waiver or amendment, allow lenders to declare an event of default and cause any outstanding indebtedness under the facility to become immediately due and payable. Such action could also lead to cross defaults under our senior note and contingent convertible senior note indentures. See Note 3 for further discussion of our debt instruments.

7
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


Based on ongoing reductions in our capital expenditures, expected commodity prices as reflected in futures prices and prices for our currently hedged production, our forecasted drilling and production, projected levels of indebtedness and certain asset sales presently being negotiated, we believe we will be in compliance with the financial maintenance covenants, including the amended leverage ratios, of our corporate revolving bank credit facility through 2013. We believe the assumptions underlying our budget for this period are reasonable and that we have adequate flexibility, including the ability to adjust discretionary capital expenditures, to adapt to potential negative developments if needed to maintain covenant compliance. Our ability to generate operating cash flow and close asset sales in order to manage debt, however, are subject to all the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time. We do not have binding agreements for all of our planned asset sales and our ability to consummate each of these transactions is subject to changes in market conditions and other factors beyond our control. If one or more of the transactions is not completed in the anticipated time frame, or at all, or for less proceeds than anticipated, our ability to fund budgeted capital expenditures, reduce our indebtedness as planned and maintain our compliance with revolving bank credit facility covenants could be adversely affected.
We have a material exposure to natural gas prices, which reached 10-year lows in the Current Period. Approximately 70% and 83% of our estimated proved reserves volumes as of September 30, 2012 and December 31, 2011, respectively, were natural gas, and natural gas represented approximately 80% and 84% of our natural gas, oil and NGL sales volumes for the Current Period and the full year 2011, respectively. Although our natural gas derivative arrangements serve to mitigate a portion of the effect of price volatility on our cash flows, none of our 2013 natural gas production is currently protected by derivative instruments against downward price movement. 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. In addition, lower natural gas, oil and NGL prices could result in a further 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.
In the Current Period, we reduced our estimate of proved reserves by 5.5 tcfe primarily due to the impact of downward natural gas price revisions. Natural gas prices used in estimating proved reserves decreased by 31% from $4.12 per mcf for the 12 months ended December 31, 2011 to $2.83 per mcf for the 12 months ended September 30, 2012 using 12-month average prices required by the SEC. The reserve reductions primarily involved the loss of significant proved undeveloped reserves, largely 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 a result of lower estimated reserves, as of September 30, 2012, we were required to impair the carrying value of our natural gas and oil properties and, if the trailing 12-month average natural gas prices are lower in subsequent periods, we could have additional impairments in the future. See Natural Gas and Oil Properties below for further discussion of our impairment of the carrying value of our natural gas and oil properties as of September 30, 2012. An impairment of this type is a non-cash charge that does not impact our liquidity or our ability to comply with financial covenants. Future impairments of the carrying value of our natural gas and oil properties, if any, will be dependent on many factors, including natural gas, oil and NGL prices, production rates, levels of reserves, the evaluation of costs excluded from amortization, the timing and impact of asset sales, future development costs and service costs.
Natural Gas and Oil Properties
On a quarterly basis, we analyze our unevaluated leasehold and transfer to evaluated properties leasehold that can be associated with reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned. As our strategic focus is shifting from a natural gas asset base to a more balanced natural gas and liquids asset base, and as our budgeted capital expenditures are being reduced in the Current Quarter, we identified undeveloped leasehold having a cost of $1.684 billion that would not be a part of our development strategy going forward. The acreage was primarily located in the Williston and DJ Basins, as well as other non-core leasehold located throughout our operating areas.
We also review, on a quarterly basis, the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In the Current Quarter, capitalized costs of natural gas and oil properties exceeded the estimated present value calculation of future net revenues from our proved reserves, net of related income tax considerations, resulting in an impairment in the carrying value of natural gas and oil properties of $3.315 billion. For the ceiling test calculation, costs used are those

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


as of the end of the appropriate quarterly period. In calculating estimated future net revenues, current prices are calculated as the unweighted arithmetic average of natural gas and oil prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. Cash flow hedges locked in prior to September 30, 2012 which relate to future production periods increased the ceiling test impairment by $279 million. As of September 30, 2012, none of our open derivative instruments were designated as cash flow hedges. Our natural gas and oil hedging activities are discussed in Note 7 of these condensed consolidated financial statements. See Risks and Uncertainties above for a discussion of the reduction in our estimated proved reserves in the Current Period and factors that could impact a future ceiling test impairment.
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 we expect to complete the sale in the 2012 fourth quarter. Substantially all of the associated assets and liabilities qualified as held for sale as of September 30, 2012 are reported under our marketing, gathering and compression operating segment. In addition, we are pursuing the sale within the next 12 months of various other property and equipment, including certain drilling rigs and land and buildings primarily in the Fort Worth, Texas area. The drilling rigs are reported under our 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 pursuant to the rules governing oil and gas accounting. A summary of the assets and liabilities held for sale on our condensed consolidated balance sheet as of September 30, 2012 is detailed below. 
 
September 30, 2012
 
($ in millions)
Cash
$
14

Accounts receivable
90

Other assets
7

Current assets held for sale
$
111

Natural gas gathering systems and treating plants, net of accumulated depreciation
$
2,027

Oilfield services equipment, net of accumulated depreciation
24

Other property and equipment, net of accumulated depreciation and amortization
256

Property and equipment held for sale, net
$
2,307

Investments
$
123

Long-term assets held for sale
$
123

Accounts payable
$
33

Accrued liabilities
143

Current liabilities held for sale
$
176

Asset retirement obligations
$
2

Long-term liabilities held for sale
$
2


Cash and Cash Equivalents and Restricted Cash
For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents. Restricted cash consists of balances required to be maintained by the terms of agreements governing the activities of CHK Utica, L.L.C. (CHK Utica) and CHK Cleveland Tonkawa, L.L.C. (CHK C-T). For CHK Utica, we must retain a minimum cash balance equal to two quarterly dividend payments. In addition, cash proceeds received from CHK Utica asset sales must be used to pay for CHK Utica's capital expenditures or to redeem its preferred shares. For CHK C-T, we must retain an amount of cash (remeasured quarterly) equal to (i) the next two quarters of preferred dividend payments plus (ii) the projected capital and operating expenditures for the next six months (net of its projected net revenues during such six-month period). See Note 6 for further discussion of these transactions.


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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 Current Quarter and the Current Period, the following shares of unvested restricted stock and 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)
Three Months Ended September 30, 2012:
 
 
 
Common stock equivalent of our preferred stock outstanding:
 
 
 
5.75% cumulative convertible preferred stock
$
21

 
56

5.75% cumulative convertible preferred stock (series A)
$
16

 
39

5.00% cumulative convertible preferred stock (series 2005B)
$
3

 
5

4.50% cumulative convertible preferred stock
$
3

 
6

Unvested restricted stock
$
—

 
3

 
 
 
 
Nine Months Ended September 30, 2012:
 
 
 
Common stock equivalent of our preferred stock outstanding:
 
 
 
5.75% cumulative convertible preferred stock
$
64

 
56

5.75% cumulative convertible preferred stock (series A)
$
47

 
39

5.00% cumulative convertible preferred stock (series 2005B)
$
8

 
5

4.50% cumulative convertible preferred stock
$
9

 
6

Unvested restricted stock
$
—

 
4

As a result of the net loss to common stockholders in the Current Quarter and the Current Period, basic weighted average shares outstanding, which is used in computing basic EPS, and diluted weighted average shares outstanding, which is used in computing diluted EPS, were the same in both periods: 644 million shares in the Current Quarter and 643 million shares in the Current Period. The basic and diluted loss per common share was $3.19 and $1.86 in the Current Quarter and the Current Period, respectively.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


For the Prior Quarter and the Prior Period, all outstanding securities that were convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the Prior Quarter and the Prior Period is as follows: 
 
Income
(Numerator)
 
Weighted
Average
Shares
(Denominator)
 
Per
Share
Amount  
 
(in millions, except per share data)
Three Months Ended September 30, 2011:
 
 
 
 
 
Basic EPS
$
879

 
638

 
$
1.38

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
—

 
8

 
 
Outstanding stock options
—

 
1

 
 
Diluted EPS
$
922

 
753

 
$
1.23

Nine Months Ended September 30, 2011:
 
 
 
 
 
Basic EPS
$
1,141

 
636

 
$
1.79

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
64

 
56

 
 
Common shares assumed issued for 5.75% cumulative
    convertible preferred stock (series A)
47

 
39

 
 
Common shares assumed issued for 5.00% cumulative
    convertible preferred stock (series 2005B)
8

 
5

 
 
Common shares assumed issued for 4.50% cumulative
    convertible preferred stock
9

 
6

 
 
Unvested restricted stock
—

 
9

 
 
Outstanding stock options
—

 
1

 
 
Diluted EPS
$
1,269

 
752

 
$
1.69

 

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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 September 30, 2012 and December 31, 2011:
 
September 30, 2012
 
December 31, 2011
 
 
 
 
 
($ in millions)
Term loans due 2017(a)
$
4,000

 
$
—

7.625% senior notes due 2013(b)
464

 
464

9.5% senior notes due 2015
1,265

 
1,265

6.25% euro-denominated senior notes due 2017(c)
442

 
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(d)
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(e)
396

 
396

2.5% contingent convertible senior notes due 2037(e)
1,168

 
1,168

2.25% contingent convertible senior notes due 2038(e)
347

 
347

Corporate revolving bank credit facility
1,785

 
1,719

Midstream revolving bank credit facility
—

 
1

Oilfield services revolving bank credit facility
336

 
29

Discount on senior notes and term loans(f)
(559
)
 
(490
)
Interest rate derivatives(g)
21

 
28

Total debt, net
16,218

 
10,626

Less current maturities of long-term debt, net(b)
(463
)
 
—

Total long-term debt, net
$
15,755

 
$
10,626

_________________________________________
(a)
Subsequent to September 30, 2012, we used approximately $2.8 billion in proceeds from asset sales and $1.2 billion in partial proceeds from our new term loan (see Note 16) to fully repay the Term Loans due 2017.
(b)
These senior notes are due in July 2013. There is $1 million of discount associated with these notes.
(c)
The principal amount shown is based on the exchange rate of $1.2856 to €1.00 and $1.2973 to €1.00 as of September 30, 2012 and December 31, 2011, respectively. See Note 7 for information on our related foreign currency derivatives.
(d)
Issuers are Chesapeake Oilfield Operating, L.L.C. (COO), an indirect wholly owned subsidiary of the Company, 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.
(e)
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 quarterly. In the third 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

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


their notes into cash and common stock in the fourth 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 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

(f)
Discount as of September 30, 2012 and December 31, 2011 included $393 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. Also includes $114 million associated with our Term Loans due 2017 that were fully repaid subsequent to September 30, 2012.
(g)
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 provided 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. Subsequent to September 30, 2012, we used $4.0 billion in proceeds from asset sales and our new term loan (see Note 16) to fully repay the May 2012 term loans. We will record $155 million of associated losses with the repayment, including $86 million of deferred charges and $114 million of debt discount, offset by $45 million of interest accrued that will not be paid. Provisions that applied when the term loans were outstanding are described below.
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 applicable 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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


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 (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 September 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. Certain of our oilfield services subsidiaries, subsidiaries with noncontrolling interests, subsidiaries qualified as variable interest entities, and certain midstream and de minimis subsidiaries are not guarantors. See Note 14 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. The senior notes and contingent convertible senior notes indentures have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of $50 million or $75 million, depending on the indenture.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


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% and 8%, 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.
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. See Note 8 for further discussion of our Fayetteville Shale asset sale.
 
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.
In July 2013, the $464 million aggregate principal amount of our 7.625% senior notes will be due. No other scheduled principal payments are required on our senior notes until 2015.

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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. The COO senior notes have cross default provisions that apply to other indebtedness COO or any of its guarantor subsidiaries may have from time to time with an outstanding principal amount of $50 million or more.
Under a registration rights agreement, we agreed to file a registration statement within 365 days after the closing of the COO senior notes offering enabling holders of the COO senior notes to exchange the privately placed COO senior notes for publicly registered notes with substantially the same terms. We are required to use our commercially reasonable best efforts to cause the registration statement to become effective as soon as practicable after filing and to consummate the exchange offer on the earliest practicable date after such date, but in no event later than 60 days after the date the registration statement has become effective. We also agreed to make additional interest payments to holders, up to a maximum of 1% per annum, of the COO senior notes if we do not comply with our obligations under the registration rights agreement. We did not file a registration statement within 365 days after the closing of the COO senior notes and in the Current Quarter accrued approximately $1 million of additional expense we expect to incur related to this delay.
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 September 30, 2012
$
1,785

 
$
336

Letters of credit outstanding as of September 30, 2012
$
31

 
$
—

 ____________________________________________
(a)
Borrower is Chesapeake Exploration, L.L.C.
(b)
Borrower is COO.

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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 LIBOR, plus a margin that varies from 1.50% to 2.25% per annum according to our senior unsecured long-term debt ratings. These margins may be increased pursuant to the terms of the recent credit facility amendment discussed below. 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. In September 2012, we entered into an amendment to the credit facility agreement, effective September 30, 2012. See Risks and Uncertainties in Note 1 for further discussion. The amendment, among other things, adjusts our required indebtedness to EBITDA ratio as set forth below through the earlier of (a) December 31, 2013 and (b) the date on which we elect to reinstate the indebtedness to EBITDA ratio in effect prior to the amendment (in either case, the "Amendment Effective Period"). The amendment increased the maximum indebtedness to EBITDA ratio as of September 30, 2012 from 4.00 to 1.00 to 6.00 to 1.00 and revises the required ratio for the next four quarters as shown below. The ratio returns to 4.00 to 1.00 as of December 31, 2013 and thereafter.
Effective Date
 
Indebtedness to EBITDA Ratio
December 31, 2012
 
5.00 to 1.00
March 31, 2013
 
4.75 to 1.00
June 30, 2013
 
4.50 to 1.00
September 30, 2013
 
4.25 to 1.00
The credit facility amendment increases the applicable margin by 0.25% for borrowings under the corporate credit facility on each day during the Amendment Effective Period when borrowings exceed 50% of the borrowing capacity and requires us to pay a fee to each lender in an amount equal to 0.05% of its revolving commitment in the event that the Amendment Effective Period is in effect on June 30, 2013. Based on current commitment levels, this would result in an additional payment of $2 million. The amendment does not allow our collateral value securing the borrowings to be more than $75 million below the collateral value that was in effect as of September 30, 2012 during the Amendment Effective Period. We were in compliance with all covenants under the amended agreement as of September 30, 2012.
The facility is fully and unconditionally guaranteed, on a joint and several basis, by Chesapeake and certain of our wholly owned subsidiaries. If we should fail to perform our obligations under the agreement, 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 and contingent convertible 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.
Oilfield Services Credit Facility. Our $500 million syndicated oilfield services 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 an indirect 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

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restricted subsidiaries for this facility, but they are unrestricted subsidiaries under Chesapeake's senior notes, contingent convertible senior notes and corporate revolving bank credit facility), 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%, or 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 earnings before interest, taxes, depreciation, amortization and rent (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. COO was in compliance with all covenants under the agreement at September 30, 2012. If COO or its restricted subsidiaries should fail to perform their obligations under the agreement, 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 COO senior note indenture, which could in turn result in the acceleration of the COO senior note indebtedness. 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.
4.
Contingencies and Commitments
Contingencies
Litigation and Regulatory Proceedings
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 motion was fully briefed as of August 21, 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.

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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 is stayed pursuant to stipulation. On August 29, 2012, the plaintiff filed a motion to lift the stay, and on September 17, 2012, nominal defendant Chesapeake filed a cross-motion to stay the case pending resolution of the federal class action. 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. On November 30, 2011, the Company filed a motion to dismiss the action, which was denied on September 28, 2012. Pursuant to court order, nominal defendant Chesapeake filed an answer on October 12, 2012. By stipulated order, the individual defendants are not required to answer the complaint unless and until the plaintiff establishes standing to pursue claims derivatively.
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 variety of corporate governance measures. The court awarded attorney fees and expenses to plaintiffs’ counsel in the amount of $3.75 million 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. Appellants' opening brief was filed on September 14, 2012, and Chesapeake filed its response on October 24, 2012.
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 derivative 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. Plaintiffs in both the federal consolidated derivative action and the state court derivative action stipulated to stay their cases pending a ruling on the motion to dismiss to be filed in the federal securities class action described in the following paragraph.

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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 Mr. McClendon alleging violations of Sections 10(b) (and Rule 10b-5 promulgated thereunder) and 20(a) of the Securities Exchange Act of 1934. On July 20, 2012, a lead plaintiff was appointed, and on October 19, 2012, an amended complaint was filed against the Company, Mr. McClendon and certain other officers. The amended complaint asserts claims under Sections 10(b) (and Rule 10b-5) and 20(a) of the Securities Exchange Act of 1934 based on alleged misrepresentations regarding the Company's asset monetization strategy, including liabilities associated with its volumetric production payment (VPP) transactions, as well as Mr. McClendon's personal loans and the Company's internal controls. The action seeks class certification, damages of an unspecified amount 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 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. On August 16, 2012, defendants were given 60 days following the date on which a consolidated amended complaint is filed to answer. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with these cases.
 On May 2, 2012, Chesapeake and Mr. McClendon received notice from the U.S. Securities and Exchange Commission that its Fort Worth Regional Office had 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. Chesapeake was named a nominal defendant in the derivative action. On August 21, 2012, the District Court granted the Company's motion to dismiss the case. On October 11, 2012, the plaintiff appealed the dismissal to the Supreme Court of Oklahoma, and on October 15, 2012, the Supreme Court ordered the plaintiff to show cause why the appeal should not be dismissed as premature. On October 30, 2012, the plaintiff responded to the order to show cause.
Antitrust Investigations. 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 certain state governmental agencies in connection with other investigations relating to the Company’s purchase and lease of oil and gas rights. Chesapeake is providing 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

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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. 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. On August 10, 2012, Chesapeake filed a motion for new trial and/or to alter or amend the judgment. The motion has been fully briefed.
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
The nature of the natural gas and oil business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are set for potential environmental liabilities that are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and assessing the potential liability. Depending on the extent of an identified environmental concern, Chesapeake may, among other things, 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.
There are presently pending against our subsidiary, Chesapeake Appalachia, L.L.C. (CALLC), orders for compliance first 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, CALLC also received and responded to a subpoena issued by the grand jury of the U.S. District Court for the Northern District of West Virginia. On September 28, 2012, an information alleging misdemeanor violations of the CWA by CALLC was filed in this federal district court, and on October 5, 2012, CALLC pled guilty, pursuant to a binding plea agreement with the U.S. Attorney for the Northern District of West Virginia, to three misdemeanor counts of unauthorized discharge of dredge or fill materials into a water of the U.S. In the plea agreement, CALLC has agreed to pay a fine of $200,000 for each misdemeanor, for a total fine of $600,000, and accept a two-year probationary term. Additionally, the parties have agreed that potential violations by CALLC at the three other sites subject to the aforementioned subpoena would be addressed in the ongoing civil proceeding. All terms of the plea agreement, including the proposed sentence, are subject to court approval.
The CWA provides authority for significant civil 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. 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 orders for compliance will include monetary sanctions exceeding $100,000, and CALLC has agreed to pay a fine of $600,000 with respect to CWA criminal misdemeanor charges, 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 70 drilling rigs (net of 24 purchased rigs) and related equipment 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

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most cases we have the option to renew a 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 September 30, 2012, the minimum aggregate undiscounted future rig lease payments were approximately $332 million. During the Current Quarter, we repurchased 22 rigs from various lessors for an aggregate purchase price of $53 million, of which $25 million was deemed to be early lease termination costs and was recognized as Losses and Impairments of Fixed Assets and Other in the condensed consolidated statements of operations. See Note 11 for further discussion.
Chesapeake has contracts with various drilling contractors to utilize approximately 34 rigs with terms ranging from six months to three years. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2012, the aggregate undiscounted minimum future payments under these drilling rig commitments were approximately $316 million.
Compressor Leases
Through various transactions beginning in 2007, our compression subsidiary has sold 2,542 compressors (net of 11 purchased compressors), a significant portion of its compressor fleet, 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 a 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 September 30, 2012, the minimum aggregate undiscounted future compressor lease payments were approximately $443 million. Subsequent to September 30, 2012, we repurchased 220 compressor units for approximately $28 million from various lessors, lowering our minimum aggregate undiscounted future compressor lease payments by approximately $23 million.
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. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying condensed consolidated balance sheets; however, they are reflected as adjustments to future natural gas, oil and NGL sales prices used in our proved reserves estimates.
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, are presented below.
 
September 30, 2012
 
($ in millions)
2012
$
282

2013
1,194

2014
1,535

2015
1,626

2016
1,683

2017 - 2099
11,235

Total
$
17,555


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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 September 30, 2012, we had spud 87 cumulative Utica wells and are therefore ahead of the drilling pace required to meet the cumulative drilling commitment by December 31, 2012. 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 CHK Utica and CHK C-T financial transactions and in conjunction with the formation of the Chesapeake Granite Wash Trust. See Note 6 for discussion of these transactions and commitments.
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.
Property and Equipment Purchase Commitments
Much of the drilling equipment we purchase requires long production lead times.  As a result, we have outstanding orders and commitments for such equipment.  As of September 30, 2012, we had $197 million of purchase obligations related to future capital expenditures for drilling rigs and related equipment and hydraulic fracturing equipment in 2012 and 2013.
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.
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. We do not expect to meet the net acreage maintenance commitment with Total under the terms of our Barnett Shale joint venture agreement. We expect to have a net acreage shortfall of approximately 18,000 net acres, which, if not met by the December 31, 2012 measurement date, will result in a 2012 fourth quarter charge against earnings and a cash payment of approximately $36 million to Total in the first half of 2013.
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, providing at least a 10% gross margin to FTS, if utilization of FTS fleets falls below a certain level. 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 addition, in September 2012, we agreed to purchase our pro-rata share, equal to approximately $105 million, of preferred equity securities offered by FTS to existing stockholders. We expect to complete this transaction in November 2012. Each share of preferred stock is convertible into a specified number of shares of FTS common stock automatically upon a qualified initial public offering of FTS common stock and at our option at any time following the second anniversary of the issue date.
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

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(Unaudited)


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. As of September 30, 2012, Clean Energy's common stock was trading at $13.17 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 September 30, 2012, we had funded $115 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 $884 million. 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 September 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 $2 million of gain associated with the release of the liability related to the quarterly targets achieved in the Current Period. 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 September 30, 2012, CMD had committed to make capital contributions to these entities totaling approximately $1.1 billion through 2014. With the anticipated 2012 fourth 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.
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 wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.
In connection with divestitures, our purchase and sale agreements generally provide 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 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.
 

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5.
Other Long-Term Liabilities
Other long-term liabilities as of September 30, 2012 and December 31, 2011 are detailed below. 
 
September 30, 2012
 
December 31, 2011
 
($ in millions)
CHK Utica ORRI conveyance obligation(a)
$
279

 
$
290

CHK C-T ORRI conveyance obligation(b)
167

 
—

Financing lease obligations(c)
143

 
143

Revenues and royalties due others
128

 
109

Mortgages payable(d)
56

 
56

Other
224

 
220

Total other long-term liabilities
$
997

 
$
818

____________________________________________
(a)
$17 million and $10 million of the total $296 million and $300 million obligations are recorded in other current liabilities as of September 30, 2012 and December 31, 2011, respectively. See Note 6 for further discussion of the transaction.
(b)
$15 million of the total $182 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 the term loan in full without penalty. The payment obligation is guaranteed by Chesapeake. As of September 30, 2012, our Barnett Shale headquarters building was classified as property and equipment held for sale on our condensed consolidated balance sheet.
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 Current Period and Prior Period:
 
2012
 
2011
 
(in thousands)
Shares issued at January 1
660,888

 
655,251

Restricted stock issuances (net of forfeitures)
5,758

 
5,096

Stock option exercises
309

 
394

Preferred stock conversion
—

 
111

Shares issued at September 30
666,955

 
660,852


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Preferred Stock
The following reflects our preferred shares outstanding for the Current Period and Prior Period: 
 
5.75%
 
5.75% (A)  
 
4.5%
 
5.00%
(2005B)  
 
(in thousands)
Shares outstanding at January 1, 2012 and September 30, 2012
1,497

 
1,100

 
2,559

 
2,096

 
 
 
 
 
 
 
 
Shares outstanding at January 1, 2011
1,500


1,100


2,559


2,096

Conversion of preferred shares into common stock
(3
)
 
—

 
—

 
—

Shares outstanding at September 30, 2011
1,497

 
1,100

 
2,559

 
2,096

In the Prior Period, 3,000 shares of our outstanding 5.75% Cumulative Convertible Non-Voting Preferred Stock were converted into 111,111 shares of common stock pursuant to the holder's conversion rights.
Dividends
Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings will exist after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, such payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.
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.
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
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
 
($ in millions)
Natural gas and oil properties
$
18

 
$
30

 
$
55

 
$
90

General and administrative expenses
17

 
24

 
55

 
71

Natural gas, oil and NGL production expenses
6

 
8

 
18

 
26

Marketing, gathering and compression expenses
4

 
5

 
12

 
14

Oilfield services expenses
2

 
3

 
8

 
8

Total
$
47

 
$
70

 
$
148

 
$
209


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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
9,375

 
$
21.16

Vested
(7,225
)
 
$
28.87

Forfeited
(1,165
)
 
$
24.90

Unvested shares as of September 30, 2012
20,529

 
$
23.76

The aggregate intrinsic value of restricted stock vested during the Current Period was approximately $150 million based on the stock price at the time of vesting.
As of September 30, 2012, there was $356 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 2.6 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 Prior Quarter, the Current Period and the Prior Period, we recognized reductions in tax benefits related to restricted stock of $14 million, $7 million, $19 million and $8 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.
Stock Options. We granted stock options prior to 2006 under several stock compensation plans. Outstanding options expire ten years from the date of grant and vested over a four-year period. All 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
(322
)
 
$
6.53

 
 
 
 
Outstanding and exercisable at September 30, 2012
729

 
$
11.31

 
0.96
 
$
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 stock options.
During the Current Quarter and the Prior Quarter, we recognized excess tax benefits related to stock options of a nominal amount. During the Current Period and the Prior Period, we recognized excess tax benefits related to stock options of $1 million and $3 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.

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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 new net wells to be drilled on certain of our Cleveland and Tonkawa play leasehold. 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 (measured quarterly) equal to (i) the next two quarters of preferred dividend payments plus (ii) its projected capital and operating expenditures for the next six months (net of projected revenues during such six-month period). The amount so retained, approximately $112 million as of September 30, 2012, is reflected as restricted cash on our condensed consolidated balance sheet.
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 an optional distribution 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 September 30, 2012, the redemption price and the liquidation preference were each $1,320 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 up to 1,000 new net wells and the 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 existing wells and 1,000 new net wells. If at any time we hold fewer net acres than would enable us to drill all then-

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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 September 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, income of $19 million and $38 million, respectively, was attributable to the noncontrolling interests of CHK C-T. Under the development agreement, approximately 17 and 57 qualified net wells were added in the Current Quarter and Current Period, respectively.
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 sheets. Pursuant to the CHK Utica LLC Agreement, CHK Utica is required to retain a cash balance equal to 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 September 30, 2012. In addition, pursuant to the CHK Utica LLC Agreement, with respect to any sales proceeds as defined by the agreement, CHK Utica is required to separately account for, and dedicate all of such sales proceeds to either (i) capital expenditures made by CHK Utica in connection with its assets or (ii) the redemption of CHK Utica preferred shares. As a result of the sale of non-core Utica Shale assets in the Current Quarter, the amount reserved for paying capital expenditures, approximately $167 million, is reflected as restricted cash in other long-term assets on our condensed consolidated balance sheet as of September 30, 2012. See Note 8 for further discussion of the sale of non-core Utica Shale assets.
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 during a liquidated damages period, in which case an optional distribution 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 September 30, 2012, the redemption price and the liquidation preference were each approximately $1,340 per preferred share.

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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.
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 September 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 $66 million, respectively, was attributable to the noncontrolling interests of CHK Utica. Under the development agreement, approximately 12 and 48 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 September 30, 2012, we had drilled or caused to be drilled 48 development wells, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $156 million.
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

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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 August 10, 2012, the Trust declared a cash distribution of approximately $27 million, or $0.61 per common unit and $0.48 per subordinated unit, for the three-month period ended June 30, 2012 and covering production for the period from March 1, 2012 to May 31, 2012. The distribution was paid on August 30, 2012 to record unitholders as of August 20, 2012. The distribution was subordinated, with $13 million paid to Chesapeake and $14 million paid to third-party unitholders.
We have determined that the Trust constitutes a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our condensed consolidated financial statements. As of September 30, 2012 and December 31, 2011, $365 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 $28 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 September 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 $34 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.

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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 September 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 call swaptions to counterparties that allow them, on a specific date, to extend an existing fixed-price swap for a certain period of time. Chesapeake also buys put swaptions, that are exercisable on a specific date, which allows us to enter into a swap at a fixed price 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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


The estimated fair values of our natural gas, oil and NGL derivative instruments as of September 30, 2012 and December 31, 2011 are provided below. 
 
September 30, 2012
 
December 31, 2011
 
Volume    
 
Fair Value  
 
Volume    
 
Fair Value  
 
 
 
($ in millions)  
 
 
 
($ in millions)  
Natural gas (tbtu):
 
 
 
 
 
 
 
Fixed-price swaps
204

 
$
(58
)
 
—

 
$
—

Call options
492

 
(250
)
 
1,357

 
(284
)
Basis protection swaps
119

 
(17
)
 
106

 
(42
)
Put swaptions
11

 
(1
)
 
—

 
—

Total natural gas
826

 
(326
)
 
1,463

 
(326
)
Oil (mmbbl):
 
 
 
 
 
 
 
Fixed-price swaps
33.3

 
97

 
14.9

 
15

Call options
74.2

 
(785
)
 
94.7

 
(1,282
)
Call swaptions
8.0

 
(20
)
 
7.8

 
(53
)
Fixed-price knockout swaps
—

 
—

 
0.8

 
7

Total oil
115.5

 
(708
)
 
118.2

 
(1,313
)
Total estimated fair value
 
 
$
(1,034
)
 
 
 
$
(1,639
)
 
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 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
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
 
 
 
($ in millions)
 
 
Natural gas, oil and NGL sales
$
1,464

 
$
1,427

 
$
3,798

 
$
3,892

Gains (losses) on natural gas, oil and NGL derivatives
(27
)
 
980

 
824

 
783

Gains (losses) on ineffectiveness of cash flow hedges
—

 
(5
)
 
—

 
13

Total natural gas, oil and NGL sales
$
1,437

 
$
2,402

 
$
4,622

 
$
4,688



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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


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 September 30, 2012, we had hedged under the facility 1.4 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.
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 September 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 September 30, 2012 and December 31, 2011 are provided below. 
 
September 30, 2012
 
December 31, 2011
 
Notional
Amount    
 
Fair
Value      
 
Notional
Amount    
 
Fair
Value      
 
 
 
($ in millions)
 
 
Interest rate:
 
 
 
 
 
 
 
Swaps
$
1,050

 
$
(39
)
 
$
1,050

 
$
(42
)
Swaptions
500

 
(2
)
 
300

 
—

Totals
$
1,550

 
$
(41
)
 
$
1,350

 
$
(42
)

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


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
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
 
 
 
($ in millions)
 
 
Interest expense on senior notes
$
187

 
$
152

 
$
546

 
$
494

Interest expense on credit facilities
13

 
18

 
51

 
49

Interest expense on term loans
112

 
—

 
173

 
—

(Gains) losses on interest rate derivatives
(2
)
 
—

 
(4
)
 
19

Amortization of loan discount and other
24

 
8

 
67

 
30

Capitalized interest
(298
)
 
(174
)
 
(770
)
 
(555
)
Total interest expense
$
36

 
$
4

 
$
63

 
$
37

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 eight years, we will recognize $21 million in net 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 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 $37 million at September 30, 2012. The euro-denominated debt in long-term debt has been adjusted to $442 million at September 30, 2012 using an exchange rate of $1.2856 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 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.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


The following table presents the fair value and location of each classification of derivative instrument disclosed in the condensed consolidated balance sheets as of September 30, 2012 and December 31, 2011 on a gross basis without regard to same-counterparty netting: 
 
 
 
Fair Value
 
Balance Sheet Location
 
September 30, 2012
 
December 31, 2011
 
 
 
($ in millions)
Asset Derivatives:
 
 
 
 
 
Not designated as hedging instruments:
 
 
 
 
 
Commodity contracts
Short-term derivative instruments
 
$
108

 
$
54

Commodity contracts
Long-term derivative instruments
 
36

 
1

Total
 
144

 
55

Liability Derivatives:
 
 
 
 
 
Designated as hedging instruments:
 
 
 
 
 
Foreign currency contracts
Long-term derivative instruments
 
(37
)
 
(38
)
Total
 
(37
)
 
(38
)
Not designated as hedging instruments:
 
 
 
 
 
Commodity contracts
Short-term derivative instruments
 
(225
)
 
(232
)
Commodity contracts
Long-term derivative instruments
 
(953
)
 
(1,462
)
Interest rate contracts
Short-term derivative instruments
 
(2
)
 
—

Interest rate contracts
Long-term derivative instruments
 
(39
)
 
(42
)
Total
 
(1,219
)
 
(1,736
)
Total derivative instruments
 
$
(1,112
)
 
$
(1,719
)
 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 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
September 30,
 
Nine Months Ended
September 30,
Fair Value Derivatives 
 
Location of Gain (Loss)
 
2012
 
2011
 
2012
 
2011
 
 
 
 
 
 
($ in millions)
 
 
Interest rate contracts
 
Interest expense
&#