10-Q 1 d365885d10q.htm FORM 10-Q Form 10-Q
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 June 30, 2012

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

For the transition period from                      to                     

Commission File No. 1-13726

Chesapeake Energy Corporation

(Exact name of registrant as specified in its charter)

 

Oklahoma   73-1395733
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
6100 North Western Avenue  
Oklahoma City, Oklahoma   73118
(Address of principal executive offices)   (Zip Code)

(405) 848-8000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [X]      Accelerated filer [ ]      Non-accelerated filer [ ]      Smaller reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes [ ] No [X]

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

 

 

 


Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

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

PART I.

Financial Information

          Page  

Item 1.

   Condensed Consolidated Financial Statements (Unaudited):   
   Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011      1   
  

Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011

     3   
  

Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2012 and 2011

     4   
  

Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011

     5   
  

Condensed Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2012 and 2011

     7   
  

Notes to Condensed Consolidated Financial Statements

     8   

Item 2.

  

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

     63   

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

     95   

Item 4.

  

Controls and Procedures

     102   
PART II.   
Other Information   

Item 1.

  

Legal Proceedings

     103   

Item 1A.

  

Risk Factors

     103   

Item 2.

  

Unregistered Sales of Equity Securities and Use of Proceeds

     103   

Item 3.

  

Defaults Upon Senior Securities

     104   

Item 4.

  

Mine Safety Disclosures

     104   

Item 5.

  

Other Information

     104   

Item 6.

  

Exhibits

     105   


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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

                                             
     June 30,     December 31,  
         2012         2011  
     ($ in millions)  

CURRENT ASSETS:

    

Cash and cash equivalents ($1 and $1 attributable to our VIEs)

     $          1,024      $ 351   

Restricted cash

     224        44   

Accounts receivable

     2,123        2,505   

Short-term derivative assets

     112        13   

Deferred income tax asset

     785        139   

Other current assets

     149        125   

Current assets held for sale ($7 and $0 attributable to our VIEs)

     99          
  

 

 

   

 

 

 

Total Current Assets

     4,516        3,177   
  

 

 

   

 

 

 

PROPERTY AND EQUIPMENT:

    

Natural gas and oil properties, at cost based on full cost accounting:

    

Evaluated natural gas and oil properties ($488 and $498
attributable to our VIEs)

     46,773        41,723   

Unevaluated properties

     17,063        16,685   

Natural gas gathering systems and treating plants

            1,763   

Oilfield services equipment

     1,844        1,611   

Other property and equipment

     3,418        3,247   
  

 

 

   

 

 

 

Total Property and Equipment, at Cost

     69,098        65,029   
  

 

 

   

 

 

 

Less: accumulated depreciation, depletion and amortization
(($30) and ($6) attributable to our VIEs)

     (29,431     (28,290

Property and equipment held for sale, net ($85 and $0
attributable to our VIEs)

     2,207          
  

 

 

   

 

 

 

Total Property and Equipment, Net

     41,874        36,739   
  

 

 

   

 

 

 

LONG-TERM ASSETS:

    

Investments

     544        1,531   

Long-term derivative assets ($1 and $0 attributable to our VIEs)

     8          

Other long-term assets

     511        388   

Long-term assets held for sale

     73          
  

 

 

   

 

 

 

TOTAL ASSETS

     $        47,526      $ 41,835   
  

 

 

   

 

 

 

 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (Continued)

(Unaudited)

 

                                             
     June 30,     December 31,  
         2012         2011  
     ($ in millions)  

CURRENT LIABILITIES:

    

Accounts payable

     $           2,552      $ 3,311   

Short-term derivative liabilities ($0 and $9 attributable to our VIEs)

     106        191   

Accrued interest

     244        183   

Other current liabilities ($24 and $23 attributable to our VIEs)

     3,163        3,397   

Current liabilities held for sale ($27 and $0 attributable to our VIEs)

     194          
  

 

 

   

 

 

 

Total Current Liabilities

     6,259        7,082   
  

 

 

   

 

 

 

LONG-TERM LIABILITIES:

    

Long-term debt, net

     14,329        10,626   

Deferred income tax liabilities

     4,783        3,484   

Long-term derivative liabilities ($0 and $10 attributable to our VIEs)

     1,042        1,541   

Asset retirement obligations

     341        323   

Other long-term liabilities

     982        818   

Long-term liabilities held for sale

     2          
  

 

 

   

 

 

 

Total Long-Term Liabilities

     21,479        16,792   
  

 

 

   

 

 

 

CONTINGENCIES AND COMMITMENTS (Note 4)

    

EQUITY:

    

Chesapeake Stockholders’ Equity:

    

Preferred stock, $0.01 par value, 20,000,000 shares authorized:

    

  7,251,515 shares outstanding

     3,062        3,062   

Common stock, $0.01 par value, 1,000,000,000 shares authorized:

    

  664,194,954 and 660,888,159 shares issued

     7        7   

Paid-in capital

     12,226        12,146   

Retained earnings

     2,352        1,608   

Accumulated other comprehensive income (loss)

     (181     (166

Less: treasury stock, at cost;
1,811,919 and 1,552,533 common shares

     (39     (33
  

 

 

   

 

 

 

Total Chesapeake Stockholders’ Equity

     17,427        16,624   
  

 

 

   

 

 

 

Noncontrolling interests

     2,361        1,337   
  

 

 

   

 

 

 

Total Equity

     19,788        17,961   
  

 

 

   

 

 

 

TOTAL LIABILITIES AND EQUITY

   $           47,526      $ 41,835   
  

 

 

   

 

 

 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three Months Ended     Six Months Ended  
     June 30,     June 30,  
     2012     2011     2012     2011  
     ($ in millions, except per share data)  

REVENUES:

        

Natural gas, oil and NGL

   $ 2,117      $ 1,792      $ 3,185      $ 2,286   

Marketing, gathering and compression

     1,113        1,404        2,328        2,421   

Oilfield services

     159        122        294        223   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues

     3,389        3,318        5,807        4,930   
  

 

 

   

 

 

   

 

 

   

 

 

 

OPERATING EXPENSES:

        

Natural gas, oil and NGL production

     335        262        685        500   

Production taxes

     41        46        89        91   

Marketing, gathering and compression

     1,096        1,366        2,292        2,352   

Oilfield services

     109        92        205        169   

General and administrative

     156        130        292        259   

Natural gas, oil and NGL depreciation, depletion
and amortization

     588        366        1,094        724   

Depreciation and amortization of other assets

     83        63        166        131   

Losses on sales and impairments of fixed assets

     243        8        241        3   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

     2,651        2,333        5,064        4,229   
  

 

 

   

 

 

   

 

 

   

 

 

 

INCOME FROM OPERATIONS

     738        985        743        701   
  

 

 

   

 

 

   

 

 

   

 

 

 

OTHER INCOME (EXPENSE):

        

Interest expense

     (14     (25     (26     (33

Earnings (losses) on investments

     (59     47        (64     72   

Gain on sale of investment

     1,030               1,030          

Losses on purchases or exchanges of debt

            (174            (176

Other income

     5        2        11        5   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Other Income (Expense)

     962        (150     951        (132
  

 

 

   

 

 

   

 

 

   

 

 

 

INCOME BEFORE INCOME TAXES

     1,700        835        1,694        569   
  

 

 

   

 

 

   

 

 

   

 

 

 

INCOME TAX EXPENSE:

        

Current income taxes

     2        6        2        12   

Deferred income taxes

     661        319        659        210   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Income Tax Expense

     663        325        661        222   
  

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME

     1,037        510        1,033        347   

Net income attributable to noncontrolling interests

     (65            (89       
  

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO CHESAPEAKE

     972        510        944        347   

Preferred stock dividends

     (43     (43     (86     (85
  

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS

   $ 929      $ 467      $ 858      $ 262   
  

 

 

   

 

 

   

 

 

   

 

 

 

EARNINGS PER COMMON SHARE:

        

Basic

   $ 1.45      $ 0.74      $ 1.34      $ 0.41   

Diluted

   $ 1.29      $ 0.68      $ 1.25      $ 0.41   

CASH DIVIDEND DECLARED PER COMMON
SHARE

   $ 0.0875      $ 0.0875      $ 0.175      $ 0.1625   

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

        

Basic

     642        635        642        635   

Diluted

     751        751        752        645   

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

 

    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2012         2011         2012         2011      
    ($ in millions)  

NET INCOME

  $  1,037      $ 510      $ 1,033      $ 347   
 

 

 

   

 

 

   

 

 

   

 

 

 

Other comprehensive income, net of income tax:

       

Gain (loss) on derivative instruments, net of income taxes of ($2) million, $87 million, $0 and $89 million

    (3     141               146   

Reclassification of gain on settled derivative
instruments, net of income taxes of ($6) million,
($11) million, ($7) million and ($39) million

    (11     (18     (12     (64

Ineffective portion of derivatives designated as cash
flow hedges, net of income taxes of $0,
($3) million, $0 and ($7) million

           (5            (11

Unrealized gain (loss) on available-for-sale securities, net of income taxes of ($6) million, ($3) million, ($2) million and ($1) million

    (9     (5     (3     (2
 

 

 

   

 

 

   

 

 

   

 

 

 

  Other comprehensive income (loss)

    (23     113        (15     69   
 

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income

    1,014        623        1,018        416   
 

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income attributable to noncontrolling interests

    (65            (89       
 

 

 

   

 

 

   

 

 

   

 

 

 

COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE

  $ 949      $ 623      $ 929      $ 416   
 

 

 

   

 

 

   

 

 

   

 

 

 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Six Months Ended
June 30,
 
     2012     2011  
     ($ in millions)  

CASH FLOWS FROM OPERATING ACTIVITIES:

    

NET INCOME

   $ 1,033      $ 347   

ADJUSTMENTS TO RECONCILE NET INCOME TO CASH
PROVIDED BY OPERATING ACTIVITIES:

    

Depreciation, depletion and amortization

     1,260        855   

Deferred income tax expense

     659        210   

Unrealized (gains) losses on derivatives

     (542     1,087   

Stock-based compensation

     63        79   

Losses on sales and impairments of fixed assets

     241        3   

(Gains) losses on investments

     120        (23

Gain on sale of investment

     (1,030       

Losses on purchases or exchanges of debt

            33   

Other

     1        (3

Changes in assets and liabilities

     (776     (495
  

 

 

   

 

 

 

Cash provided by operating activities

     1,029        2,093   
  

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Drilling and completion costs

     (5,120     (3,395

Acquisitions of proved and unproved properties

     (1,795     (2,529

Proceeds from divestitures of proved and unproved properties

     1,555        6,173   

Additions to other property and equipment

     (1,311     (863

Proceeds from sales of other assets

     79        526   

Proceeds from (additions to) investments

     (128     212   

Proceeds from sale of midstream investment

     2,000          

Acquisition of drilling company

            (339

Increase in restricted cash

     (180       

Other

     (21     (25
  

 

 

   

 

 

 

Cash used in investing activities

     (4,921     (240
  

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from credit facilities borrowings

     10,104        8,343   

Payments on credit facilities borrowings

     (11,592     (10,235

Proceeds from issuance of term loans, net of discount and offering costs

     3,789          

Proceeds from issuance of senior notes, net of discount and offering costs

     1,263        977   

Cash paid to purchase debt

            (2,032

Cash paid for common stock dividends

     (112     (95

Cash paid for preferred stock dividends

     (86     (86

Cash (paid) received on financing derivatives

     (36     882   

Proceeds from sales of noncontrolling interests

     1,039          

Proceeds from other financings

     225          

Distributions to noncontrolling interest owners

     (104       

Net increase in outstanding payments in excess of cash balance

     121        448   

Other

     (39     (48
  

 

 

   

 

 

 

Cash provided by (used in) financing activities

     4,572        (1,846
  

 

 

   

 

 

 

Change in cash and cash equivalents classified as current assets held for sale

     (7       
  

 

 

   

 

 

 

Net increase in cash and cash equivalents

     673        7   

Cash and cash equivalents, beginning of period

     351        102   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 1,024      $ 109   
  

 

 

   

 

 

 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

(Unaudited)

 

     Six Months Ended
June 30,
 
         2012          2011  
     ($ in millions)  

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION OF
NET CASH PAYMENTS (REFUNDS) FOR:

     

Interest, net of capitalized interest

   $       $   

Income taxes, net of refunds received

   $ 6       $ (25

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

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

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

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

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

 

     Six Months Ended  
     June 30,  
         2012             2011      
     ($ in millions)  

PREFERRED STOCK:

    

Balance, beginning and end of period

   $ 3,062      $ 3,065   
  

 

 

   

 

 

 

COMMON STOCK:

    

Balance, beginning and end of period

     7        7   
  

 

 

   

 

 

 

PAID-IN CAPITAL:

    

Balance, beginning of period

     12,146        12,194   

Stock-based compensation

     84        114   

Purchase of contingent convertible notes

            (123

(Reduction in) tax benefit from stock-based compensation

     (4     2   

Dividends on common stock

            (48

Dividends on preferred stock

            (15

Exercise of stock options

            1   
  

 

 

   

 

 

 

Balance, end of period

     12,226        12,125   
  

 

 

   

 

 

 

RETAINED EARNINGS:

    

Balance, beginning of period

     1,608        190   

Net income attributable to Chesapeake

     944        347   

Dividends on common stock

     (114     (56

Dividends on preferred stock

     (86     (70
  

 

 

   

 

 

 

Balance, end of period

     2,352        411   
  

 

 

   

 

 

 

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):

    

Balance, beginning of period

     (166     (168

Hedging activity

     (12     71   

Investment activity

     (3     (2
  

 

 

   

 

 

 

Balance, end of period

     (181     (99
  

 

 

   

 

 

 

TREASURY STOCK – COMMON:

    

Balance, beginning of period

     (33     (24

Purchase of 272,640 and 134,300 shares for company benefit plans

     (6     (4

Release of 13,254 and 73,299 shares from company benefit plans

            2   
  

 

 

   

 

 

 

Balance, end of period

     (39     (26
  

 

 

   

 

 

 

TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY

     17,427        15,483   
  

 

 

   

 

 

 

NONCONTROLLING INTERESTS:

    

Balance, beginning of period

     1,337          

Sales of noncontrolling interests

     1,039          

Net income attributable to noncontrolling interests

     89          

Distributions to noncontrolling interest owners

     (104       
  

 

 

   

 

 

 

Balance, end of period

     2,361          
  

 

 

   

 

 

 

TOTAL EQUITY

   $ 19,788      $ 15,483   
  

 

 

   

 

 

 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1. Basis of Presentation and Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation (“Chesapeake” or the “Company”) and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission (SEC). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2011 (2011 Form 10-K) includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. The accompanying condensed consolidated financial statements of Chesapeake include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake holds a controlling interest. All significant intercompany accounts and transactions have been eliminated. The results for the three and six months ended June 30, 2012 are not necessarily indicative of the results to be expected for the full year. This Form 10-Q relates to the three and six months ended June 30, 2012 (the “Current Quarter” and the “Current Period”, respectively) and the three and six months ended June 30, 2011 (the “Prior Quarter” and the “Prior Period”, respectively).

Critical Accounting Policies

We consider accounting policies related to derivatives, variable interest entities, natural gas and oil properties and income taxes to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2011 Form 10-K.

Risks and Uncertainties

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

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

Held for Sale Assets and Liabilities

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

 

     June 30,  
     2012  
     ($ in millions)  

Cash

   $ 7   

Accounts receivable

     91   

Other assets

     1   
  

 

 

 

Current assets held for sale

   $ 99   
  

 

 

 

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

   $ 1,937   

Oilfield services equipment, net of accumulated depreciation

     27   

Other property and equipment, net of accumulated depreciation and amortization

     243   
  

 

 

 

Property and equipment held for sale, net

   $ 2,207   
  

 

 

 

Investments

   $ 73   
  

 

 

 

Long-term assets held for sale

   $ 73   
  

 

 

 

Accounts payable

   $ 41   

Accrued liabilities

     153   
  

 

 

 

Current liabilities held for sale

   $ 194   
  

 

 

 

Asset retirement obligations

   $ 2   
  

 

 

 

Long-term liabilities held for sale

   $ 2   
  

 

 

 

 

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

 

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

Six Months Ended June 30, 2011:

     

Common stock equivalent of our preferred stock outstanding:

     

5.75% cumulative convertible preferred stock

     $    43           56

5.75% cumulative convertible preferred stock (series A)

     $    32           39

5.00% cumulative convertible preferred stock (series 2005B)

     $      5           5

4.50% cumulative convertible preferred stock

     $      6           6

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

 

          Weighted        
          Average     Per  
    Income     Shares     Share  
    (Numerator)     (Denominator)         Amount      
    (in millions, except per share data)  

Three Months Ended June 30, 2012:

     

Basic EPS

  $ 929        642      $ 1.45   
 

 

 

   

 

 

   

 

 

 

Effect of Dilutive Securities:

     

Assumed conversion as of the beginning of the period
of preferred shares outstanding during the period:

     

Common shares assumed issued for 5.75% cumulative convertible preferred stock

    21        56     

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

    16        39     

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

    3        5     

Common shares assumed issued for 4.50% cumulative convertible preferred stock

    3        6     

Unvested restricted stock

           3     
 

 

 

   

 

 

   

Diluted EPS

  $ 972        751      $ 1.29   
 

 

 

   

 

 

   

 

 

 

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

          Weighted        
          Average     Per  
    Income     Shares     Share  
    (Numerator)     (Denominator)       Amount    
    (in millions, except per share data)  

Three Months Ended June 30, 2011:

     

Basic EPS

  $ 467        635      $ 0.74   
 

 

 

   

 

 

   

 

 

 

Effect of Dilutive Securities:

     

Assumed conversion as of the beginning of the period

    of preferred shares outstanding during the period:

     

Common shares assumed issued for 5.75% cumulative

    convertible preferred stock

    21        56     

Common shares assumed issued for 5.75% cumulative

    convertible preferred stock (series A)

    16        39     

Common shares assumed issued for 5.00% cumulative

    convertible preferred stock (series 2005B)

    3        5     

Common shares assumed issued for 4.50% cumulative

    convertible preferred stock

    3        6     

Unvested restricted stock

           9     

Outstanding stock options

           1     
 

 

 

   

 

 

   

Diluted EPS

  $ 510        751      $ 0.68   
 

 

 

   

 

 

   

 

 

 

Six Months Ended June 30, 2012:

     

Basic EPS

  $ 858        642      $ 1.34   
 

 

 

   

 

 

   

 

 

 

Effect of Dilutive Securities:

     

Assumed conversion as of the beginning of the period

    of preferred shares outstanding during the period:

     

Common shares assumed issued for 5.75% cumulative

    convertible preferred stock

    43        56     

Common shares assumed issued for 5.75% cumulative

    convertible preferred stock (series A)

    32        39     

Common shares assumed issued for 5.00% cumulative

    convertible preferred stock (series 2005B)

    5        5     

Common shares assumed issued for 4.50% cumulative

    convertible preferred stock

    6        6     

Unvested restricted stock

           4     
 

 

 

   

 

 

   

Diluted EPS

  $ 944        752      $ 1.25   
 

 

 

   

 

 

   

 

 

 

Six Months Ended June 30, 2011:

     

Basic EPS

  $ 262        635      $ 0.41   
 

 

 

   

 

 

   

 

 

 

Effect of Dilutive Securities:

     

Unvested restricted stock

           9     

Outstanding stock options

           1     
 

 

 

   

 

 

   

Diluted EPS

  $ 262        645      $ 0.41   
 

 

 

   

 

 

   

 

 

 

 

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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 June 30, 2012 and December 31, 2011:

 

                June 30,         December 31,  
                2012         2011  
            ($ in millions)  

Term loans due 2017

      $ 4,000      $   

7.625% senior notes due 2013

      464        464   

9.5% senior notes due 2015

      1,265        1,265   

6.25% euro-denominated senior notes due 2017(a)

      435        446   

6.5% senior notes due 2017

      660        660   

6.875% senior notes due 2018

      474        474   

7.25% senior notes due 2018

      669        669   

6.625% senior notes due 2019(b)

      650        650   

6.775% senior notes due 2019

      1,300          

6.625% senior notes due 2020

      1,300        1,300   

6.875% senior notes due 2020

      500        500   

6.125% senior notes due 2021

      1,000        1,000   

2.75% contingent convertible senior notes due 2035(c)

      396        396   

2.5% contingent convertible senior notes due 2037(c)

      1,168        1,168   

2.25% contingent convertible senior notes due 2038(c)

    347        347   

Corporate revolving bank credit facility

             1,719   

Midstream revolving bank credit facility

             1   

Oilfield services revolving bank credit facility

      262        29   

Discount on senior notes and term loans(d)

      (584     (490

Interest rate derivatives(e)

        23        28   
     

 

 

   

 

 

 

Total long-term debt, net

    $ 14,329      $ 10,626   
     

 

 

   

 

 

 

 

 

(a)

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

 

(b)

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

 

(c)

The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarter by quarter. In the second quarter of 2012, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes during the specified period and, as a result, the holders do not have the option to convert their notes into cash and common stock in the third quarter of 2012 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of such principal amount. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years, under certain conditions. We may redeem the convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

the notes, payable in cash. The optional repurchase dates, the common stock price conversion threshold amounts and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:

 

    Contingent  
    Convertible  
    Senior  Notes    

  

Repurchase Dates

   Common Stock
 Price Conversion 
Thresholds
  

 Contingent Interest 
First Payable
(if applicable)

 2.75% due 2035

  

  November 15, 2015, 2020, 2025, 2030

   $        48.51   

  May 14, 2016

 2.5% due 2037

  

  May 15, 2017, 2022, 2027, 2032

   $        63.93   

  November 14, 2017

 2.25% due 2038

  

  December 15, 2018, 2023, 2028, 2033

   $      107.27   

  June 14, 2019

 

(d)

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

 

(e)

See Note 7 for further discussion related to these instruments.

Term Loans

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

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

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

We were in compliance with all covenants under the term loan credit agreement at June 30, 2012. If we should fail to perform our obligations under the agreement, the term loans could be terminated and any outstanding borrowings under the term loan credit agreement could be declared immediately due and payable. The term loan credit agreement also has cross default provisions that apply to other indebtedness of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $125 million.

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

Chesapeake Senior Notes and Contingent Convertible Senior Notes

The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our wholly owned subsidiaries. COS Holdings, L.L.C. (COS) and its subsidiaries, CHK Utica, L.L.C., CHK Cleveland Tonkawa, L.L.C., Chesapeake Granite Wash Trust, MAC-LP L.L.C., Cardinal Gas Services, L.L.C. (Cardinal), Utica East Ohio Midstream LLC (UEOM) and certain de minimis subsidiaries are not guarantors. See Note 13 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries.

We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale/leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the contingent convertible senior notes do not have any financial or restricted payment covenants.

We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. These rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86%, 8.0% and 8.0%, respectively.

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

 

     Principal
Amount
    Purchased    
 
     ($ in millions)  

7.625% senior notes due 2013

   $ 36   

9.5% senior notes due 2015

     160   

6.25% euro-denominated senior notes due 2017(a)

     380   

6.5% senior notes due 2017

     440   

6.875% senior notes due 2018

     126   

7.25% senior notes due 2018

     131   

6.625% senior notes due 2020

     100   
  

 

 

 

Total senior notes

     1,373   
  

 

 

 

2.75% contingent convertible senior notes due 2035

     55   

2.5% contingent convertible senior notes due 2037

     210   

2.25% contingent convertible senior notes due 2038

     266   
  

 

 

 

Total contingent convertible senior notes

     531   
  

 

 

 

Total

   $ 1,904   
  

 

 

 

 

 

(a)

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

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

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

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

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

 

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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.

Bank Credit Facilities

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

 

     Corporate
Credit
     Facility(a)     
   Oilfield
Services
Credit
      Facility(b)     
     ($ in millions)

Facility structure

   Senior secured
revolving
   Senior secured
revolving

Maturity date

   December 2015    November 2016

Borrowing capacity

   $    4,000    $    500

Amount outstanding as of June 30, 2012

   $         —    $    262

Letters of credit outstanding as of June 30, 2012

   $         37    $      —

 

(a)

Borrower is Chesapeake Exploration, L.L.C.

 

(b)

Borrower is COO.

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

Corporate Credit Facility. Our $4.0 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the facility are secured by proved reserves and bear interest at our option at either (i) the greater of the reference rate of Union Bank, N.A. or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.50% to 1.25% per annum according to

 

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our senior unsecured long-term debt ratings, or (ii) the Eurodollar rate, which is based on LIBOR, plus a margin that varies from 1.50% to 2.25% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are determined periodically. The unused portion of the facility is subject to a commitment fee of 0.50% per annum. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens and require us to maintain an indebtedness to total capitalization ratio and an indebtedness to EBITDA ratio, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at June 30, 2012. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $50 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $125 million.

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

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

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

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

 

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4. Contingencies and Commitments

Contingencies

Litigation and Regulatory Inquiries

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

July 2008 Common Stock Offering. On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the Company and certain of its officers and directors along with certain underwriters of the Company’s July 2008 common stock offering. Following the appointment of a lead plaintiff and counsel, the plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. On September 2, 2010, the court denied the defendants’ motion to dismiss, and the court certified the class on March 30, 2012. Defendants moved for summary judgment on grounds of loss causation and materiality on December 16, 2011, and the plaintiff filed an Opposition on May 18, 2012. Discovery in the case is proceeding. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with the case. A derivative action was also filed in the District Court of Oklahoma County, Oklahoma on March 10, 2009 against certain current and former directors and officers of the Company asserting breaches of fiduciary duties relating to alleged material omissions in the registration statement for the July 2008 offering. The derivative action was stayed pursuant to stipulation. A second derivative action relating to the July 2008 offering was filed against certain current and former directors and officers of the Company in the U.S. District Court for the Western District of Oklahoma on September 6, 2011. This action also asserts breaches of fiduciary duties with respect to alleged material omissions in the offering registration statement. The Company filed a motion to dismiss the action on November 30, 2011, which is pending. Chesapeake is named as a nominal defendant in both derivative actions.

2008 CEO Compensation and Related Party Transaction. Three derivative actions were filed in the District Court of Oklahoma County, Oklahoma on April 28, May 7 and May 20, 2009 against the Company’s directors alleging, among other things, breaches of fiduciary duties relating to the 2008 compensation of the Company’s CEO, Aubrey K. McClendon, and seeking unspecified damages, equitable relief and disgorgement. These three derivative actions were consolidated and a Consolidated Derivative Shareholder Petition naming Chesapeake as a nominal defendant was filed on June 23, 2009. Chesapeake’s motion to dismiss was granted on February 26, 2010, and the Oklahoma Court of Civil Appeals affirmed the dismissal on August 26, 2011. The plaintiffs filed a petition for writ of certiorari with the Oklahoma Supreme Court on September 13, 2011.

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

 

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

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

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

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

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

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

 

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

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

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

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

Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute incidental to the Company’s business operations is likely to have a material adverse effect on its consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Environmental Risk

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

 

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

Commitments

Rig Leases

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

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

Compressor Leases

Through various transactions beginning in 2007, our compression subsidiary has sold 2,542 compressors (net of 11 repurchased units), a significant portion of its compressor fleet, for $634 million and entered into a master lease agreement. The term of the agreement varies by buyer ranging from four to ten years. The lease obligations are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks and any related net gains are amortized to marketing, gathering and compression expenses over the lease term. Under the leases, we can exercise an early purchase option or we can purchase the compressors at the expiration of the lease for the fair market value at the time. In addition, in most cases we have the option to renew the lease for negotiated new terms at the expiration of the lease. Commitments related to compressor lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of June 30, 2012, the minimum aggregate undiscounted future compressor lease payments were approximately $458 million.

 

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Gathering, Processing and Transportation Agreements

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

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

 

     June 30,
2012
 
     ($ in millions)  

2012

   $ 521   

2013

     1,216   

2014

     1,387   

2015

     1,466   

2016

     1,528   

2017 - 2099

     10,051   
  

 

 

 

Total

   $ 16,169   
  

 

 

 

Drilling Commitments

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

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

Natural Gas and Oil Purchase Commitments

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

 

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Net Acreage Maintenance Commitments

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

Other Commitments

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

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

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

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

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

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

 

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

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

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

 

5. Other Long-Term Liabilities

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

 

    

June 30,
2012

    

 December 31, 
2011

     ($ in millions)

CHK Utica ORRI conveyance obligation(a)

   $                 283      $                  290

CHK C-T ORRI conveyance obligation(b)

   175     

Financing lease obligations(c)

   143      143

Revenues and royalties due others

   114      109

Mortgages payable(d)

   56      56

Other

   211      220
  

 

    

 

Total other long-term liabilities

   $                 982      $                  818
  

 

    

 

 

 

(a)

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

 

(b)

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

 

(c)

In 2009, we financed 113 real estate surface assets in the Barnett Shale area for approximately $145 million and entered into a 40-year master lease agreement under which we agreed to lease the sites for approximately $15 million to $27 million annually. This lease transaction was recorded as a financing lease and the cash received was recorded with an offsetting long-term liability on the consolidated balance sheet. Chesapeake exercised its option to repurchase two of the assets in 2010 and one of the assets in 2011.

 

(d)

In 2009, we financed our regional Barnett Shale headquarters building in Fort Worth, Texas for net proceeds of approximately $54 million with a five-year term loan which has a floating rate of prime plus 275 basis points. At our option, we may prepay in full without penalty. The payment obligation is guaranteed by Chesapeake. As of June 30, 2012, our Barnett Shale headquarters building was classified as property and equipment held for sale on our condensed consolidated balance sheet.

 

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

Common Stock

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

 

         2012              2011      
     (in thousands)  

Shares issued at January 1

     660,888         655,251   

Restricted stock issuances (net of forfeitures)

     3,063         3,543   

Stock option exercises

     244         314   
  

 

 

    

 

 

 

Shares issued at June 30

     664,195         659,108   
  

 

 

    

 

 

 

Preferred Stock

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

 

      5.75%         5.75% (A)         4.50%       5.00%
  (2005B)  
 
    (in thousands)  

Shares outstanding at January 1, 2012
and June 30, 2012

    1,497        1,100        2,559        2,096   
 

 

 

   

 

 

   

 

 

   

 

 

 

Shares outstanding at January 1, 2011
and June 30, 2011

    1,500        1,100        2,559        2,096   
 

 

 

   

 

 

   

 

 

   

 

 

 

Dividends

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Stock-Based Compensation

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

 

    Three Months Ended
June 30,
    Six Months Ended
June 30,
 
    2012     2011     2012     2011  
    ($ in millions)  

Natural gas and oil properties

  $ 18      $ 29      $ 38      $ 60   

General and administrative expenses

    20        23        38        47   

Natural gas, oil and NGL production expenses

    5        9        12        18   

Marketing, gathering and compression expenses

    4        4        8        9   

Oilfield services expenses

    2        2        5        5   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 49      $ 67      $ 101      $ 139   
 

 

 

   

 

 

   

 

 

   

 

 

 

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

 

        Number of    
Unvested
Restricted
Shares
   

Weighted Average
Grant-Date

Fair Value

    (in thousands)      

Unvested shares as of January 1, 2012

    19,544      $  26.97

Granted

    4,955      $  23.32

Vested

    (3,732   $  27.17

Forfeited

    (610   $  26.10
 

 

 

   

Unvested shares as of June 30, 2012

    20,157      $  26.06
 

 

 

   

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

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

 

     Number of
Shares
  Underlying  
Options
   

Weighted
Average
Exercise
Price

Per Share

  

  Weighted  
Average
Contract
Life in
Years

  

  Aggregate  
Intrinsic
Value(a)

     (in
thousands)
              ($ in
millions)

Outstanding at January 1, 2012

     1,051      $    9.84    1.41    $    13

Exercised

     (248   $    6.41      
  

 

 

         

Outstanding and exercisable
at June 30, 2012

     803      $  10.91    1.13    $    6
  

 

 

         

 

 

(a)

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

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

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

Noncontrolling Interests

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

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

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

 

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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 June 30, 2012 and December 31, 2011, our natural gas, oil and NGL derivative instruments consisted of the following types of instruments:

 

   

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

 

   

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

 

   

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

 

   

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

 

   

Basis Protection Swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. Our basis protection swaps typically have negative differentials to NYMEX. Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

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

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

 

    June 30, 2012     December 31, 2011  
        Volume           Fair Value           Volume           Fair Value    
            ($ in millions)               ($ in millions)    

Natural gas (tbtu):

       

Fixed-price swaps

    187      $ 1             $   

Call options

    1,114        (237     1,357        (284

Basis protection swaps

    140        (32     106        (42
 

 

 

   

 

 

   

 

 

   

 

 

 

Total natural gas

    1,441        (268     1,463        (326
 

 

 

   

 

 

   

 

 

   

 

 

 

Oil (mmbbl):

       

Fixed-price swaps

    10.0        123        14.9        15   

Call options

    74.6        (770     94.7        (1,282

Swaptions

    11.3        (24     7.8        (53

Fixed-price knockout swaps

                  0.8        7   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total oil

    95.9        (671     118.2        (1,313
 

 

 

   

 

 

   

 

 

   

 

 

 

Total estimated fair value

    $ (939     $ (1,639
   

 

 

     

 

 

 

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Pursuant to accounting guidance for derivatives and hedging, certain derivatives qualify for designation as cash flow hedges. Following this guidance, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is recognized in natural gas, oil and NGL sales. Changes in the fair value of derivatives not designated as cash flow hedges that occur prior to their maturity (i.e., temporary fluctuations in value) are reported in the condensed consolidated statements of operations within natural gas, oil and NGL sales. We have currently elected not to designate any of our qualifying natural gas and oil derivatives as cash flow hedges. Therefore, changes in the fair value of these derivatives for the Current Period are reported in the condensed consolidated statement of operations.

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

 

    Three Months Ended
June 30,
    Six Months Ended
June 30,
 
    2012     2011     2012     2011  
          ($ in millions)        

Natural gas, oil and NGL sales

  $ 1,112      $ 1,278      $ 2,334      $ 2,465   

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

    1,005        506        851        (197

Gains (losses) on ineffectiveness of cash flow hedges

           8               18   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total natural gas, oil and NGL sales

  $ 2,117      $ 1,792      $ 3,185      $ 2,286   
 

 

 

   

 

 

   

 

 

   

 

 

 

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

Hedging Facility

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

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Interest Rate Derivatives

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

 

   

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

 

   

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

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

 

            June 30, 2012     December 31, 2011  
            Notional
    Amount    
    Fair
      Value      
    Notional
    Amount    
    Fair
      Value      
 
                  ($ in millions)        

Interest rate:

           

Swaps

      $ 1,050      $ (41   $ 1,050      $ (42

Swaptions

        250               300          
     

 

 

   

 

 

   

 

 

   

 

 

 

Totals

      $ 1,300      $ (41   $ 1,350      $ (42
     

 

 

   

 

 

   

 

 

   

 

 

 

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

 

        Three Months Ended
June 30,
    Six Months Ended
June 30,
 
        2012     2011     2012     2011  
              ($ in millions)        

Interest expense on senior notes

  $ 185      $ 164      $ 359      $ 342   

Interest expense on credit facilities

    16        10        37        31   

Interest expense on term loans

    62               62          

(Gains) losses on interest rate derivatives

    (7     19        (2     18   

Amortization of loan discount and other

    42        8        42        23   

Capitalized interest

      (284     (176     (472     (381
   

 

 

   

 

 

   

 

 

   

 

 

 

Total interest expense

    $ 14      $ 25      $ 26      $ 33   
   

 

 

   

 

 

   

 

 

   

 

 

 

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

Foreign Currency Derivatives

In December 2006, we issued 600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the euro-denominated senior notes, we entered into cross currency swaps to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. In May 2011, we purchased and subsequently retired 256 million in aggregate principal amount of these senior notes following a tender offer, and we simultaneously unwound the cross currency swaps for the same

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

Additional Disclosures Regarding Derivative Instruments and Hedging Activities

In accordance with accounting guidance for derivatives and hedging, to the extent that a legal right of set-off exists, Chesapeake nets the value of its derivative arrangements with the same counterparty in the accompanying condensed consolidated balance sheets. Derivative instruments reflected as current in the condensed consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. The derivative settlement amounts are not due until the month in which the related underlying hedged transaction occurs. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivative is deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying condensed consolidated statements of cash flows.

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

 

          Fair Value  
              June 30,         December 31,  
    

Balance Sheet Location

   2012     2011  
          ($ in millions)  

Asset Derivatives:

       

Derivatives not designated as hedging instruments:

       

Commodity contracts

   Short-term derivative instruments    $ 131      $ 54   

Commodity contracts

   Long-term derivative instruments      21        1   
     

 

 

   

 

 

 

Total

     152        55   
     

 

 

   

 

 

 

Liability Derivatives:

       

Derivatives designated as hedging instruments:

       

Foreign currency contracts

   Long-term derivative instruments      (48     (38
     

 

 

   

 

 

 

Total

     (48     (38
     

 

 

   

 

 

 

Derivatives not designated as hedging instruments:

       

Commodity contracts

   Short-term derivative instruments      (125     (232

Commodity contracts

   Long-term derivative instruments      (966     (1,462

Interest rate contracts

   Long-term derivative instruments      (41     (42
     

 

 

   

 

 

 

Total

     (1,132     (1,736
     

 

 

   

 

 

 

Total derivative instruments

   $ (1,028   $ (1,719
     

 

 

   

 

 

 

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

Fair Value Hedges

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

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

 

        Three Months Ended
June 30,
    Six Months Ended
June 30,
 

Fair Value Derivatives        

 

Location of Gain (Loss)

  2012     2011     2012     2011  
              ($ in millions)        

Interest rate contracts

 

Interest expense

  $ 2      $ 5      $ 4      $ 11   
   

 

 

   

 

 

   

 

 

   

 

 

 

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

Cash Flow Hedges

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

 

    Three Months Ended
June 30,
 
    2012     2011  
      Before Tax         After Tax         Before Tax         After Tax    
          ($ in millions)        

Balance, beginning of period

  $ (284   $ (176   $ (368   $ (228

Net change in fair value

    (5     (3     220        136   

Gains reclassified to income

    (17     (11     (29     (18
 

 

 

   

 

 

   

 

 

   

 

 

 

Balance, end of period

  $ (306   $ (190   $ (177   $ (110
 

 

 

   

 

 

   

 

 

   

 

 

 
    Six Months Ended
June 30,
 
    2012     2011  
      Before Tax         After Tax         Before Tax         After Tax    
          ($ in millions)        

Balance, beginning of period

  $ (287   $ (178   $ (291   $ (181

Net change in fair value

                  217        135   

Gains reclassified to income

    (19     (12     (103     (64
 

 

 

   

 

 

   

 

 

   

 

 

 

Balance, end of period

  $ (306   $ (190   $ (177   $ (110
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The following table presents the pre-tax gain (loss) recognized in, and reclassified from, accumulated other comprehensive income (AOCI) related to instruments designated as cash flow derivatives:

 

          Three Months Ended
June  30,
    Six Months Ended
June  30,
 
           

Cash Flow Derivatives

  

Location of Gain (Loss)

   2012     2011     2012      2011  
                ($ in millions)         

Gain (Loss) Recognized in

  AOCI (Effective Portion):

            

Commodity contracts

  

AOCI

   $      $ 234      $       $ 250   

Foreign currency contracts

  

AOCI

     (5     (14             (33
     

 

 

   

 

 

   

 

 

    

 

 

 
      $ (5   $ 220      $       $ 217   
     

 

 

   

 

 

   

 

 

    

 

 

 

Gain (Loss) Reclassified

  from AOCI

  (Effective Portion):

            

Commodity contracts

  

Natural gas, oil and

  NGL sales

   $ 17      $ 67      $ 19       $ 141   

Foreign currency contracts

   Interest expense             (18             (18

Foreign currency contracts

   Loss on purchase of debt             (20             (20
     

 

 

   

 

 

   

 

 

    

 

 

 
      $ 17      $ 29      $ 19       $ 103   
     

 

 

   

 

 

   

 

 

    

 

 

 

Gain (Loss) Recognized

  in Income

            

Commodity contracts:

            

 Ineffective portion

  

Natural gas, oil and

  NGL sales

   $      $ 8      $       $ 18   

 Amount initially excluded

  from effectiveness testing

  

Natural gas, oil and

  NGL sales

                           22   
     

 

 

   

 

 

   

 

 

    

 

 

 
      $      $ 8      $       $ 40   
     

 

 

   

 

 

   

 

 

    

 

 

 

Undesignated Derivatives

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

 

           Three Months Ended     Six Months Ended  
           June 30,     June 30,  

Derivative Contracts

  

Location of Gain (Loss)    

   2012      2011     2012     2011  
                 ($ in millions)        

Commodity contracts

  

Natural gas, oil and

  NGL sales

   $ 988       $ 439      $ 832      $ (360

Interest rate contracts

   Interest expense      5         (6     (2     (11

Equity contracts

   Other income      1                         
     

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ 994       $ 433      $ 830      $ (371
     

 

 

    

 

 

   

 

 

   

 

 

 

 

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(Unaudited)

 

Credit Risk

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

 

8. Acquisitions and Divestitures

Acquisition of Bronco Drilling

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

Texoma Woodford Asset Sale

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

Fayetteville Shale Asset Sale

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

 

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(Unaudited)

 

Joint Ventures

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

 

        Primary        
         Play    

   Joint
Venture
Partner
(a)
  

Joint
Venture

Date

   Interest
Sold
   Cash
Proceeds
Received
at Closing
     Total
Drilling
Carries
    Total Cash
and Drilling
Carry
Proceeds
     Drilling
Carries
Remaining
(b)
 
                           ($ in millions)         

Utica

   TOT    December 2011    25.0%    $ 610       $ 1,422      $ 2,032       $ 1,351   

Niobrara

   CNOOC    February 2011    33.3%      570         697        1,267         519   

Eagle Ford

   CNOOC    November 2010    33.3%      1,120         1,080        2,200           

Barnett

   TOT    January 2010    25.0%      800         1,404 (c)      2,204           

Marcellus

   STO    November 2008    32.5%      1,250         2,125        3,375           

Fayetteville

   BP    September 2008    25.0%      1,100         800        1,900           

Haynesville

    & Bossier

   PXP    July 2008    20.0%      1,650         1,508 (d)      3,158           
           

 

 

    

 

 

   

 

 

    

 

 

 
            $ 7,100       $ 9,036      $ 16,136       $ 1,870   
           

 

 

    

 

 

   

 

 

    

 

 

 

 

 

(a)

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

 

(b)

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

 

(c)

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

 

(d)

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

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

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

Volumetric Production Payments

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

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

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

We have completed the following VPP transactions since 2007:

 

        Date of VPP        

  

Division

  Proceeds     Proved Reserves
(at time of sale)
    $ / mcfe     Original
Term
         ($ in millions)     (bcfe)           (years)

March 2012

  

Anadarko Basin Granite Wash

  $ 744        160      $ 4.68      10

May 2011

  

Mid-Continent

    853        177      $ 4.82      10

September 2010

  

Barnett Shale

    1,150        390      $ 2.93        5

June 2010

  

Permian Basin

    335        38      $ 8.73      10

February 2010

  

East Texas and Texas Gulf Coast

    180        46      $ 3.95      10

August 2009

  

South Texas

    370        68      $ 5.46      7.5

December 2008

  

Anadarko and Arkoma Basins

    412        98      $ 4.19        8

August 2008

  

Anadarko Basin

    600        93      $ 6.38      11

May 2008

  

Texas, Oklahoma and Kansas

    622        94      $ 6.53      11

December 2007

  

Kentucky and West Virginia

    1,100        208      $ 5.29      15
    

 

 

   

 

 

     
     $ 6,366        1,372      $ 4.64     
    

 

 

   

 

 

     

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

 

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(Unaudited)

 

9. Investments

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

 

            Carrying Value  
    Approximate
Ownership %
 

Accounting
Method

      June 30,    
2012
    December 31,
2011
 
            ($ in millions)  

Chesapeake Midstream Partners, L.P.

  —     Equity   $      $ 987   

FTS International, Inc.

  30%   Equity     203        235   

Chaparral Energy, Inc.

  20%   Equity     137        143   

Sundrop Fuels, Inc.

  37%   Equity     63        34   

Clean Energy Fuels Corp.

  —     Cost     50        50   

Twin Eagle Resource Management, LLC

  30%   Equity     29        20   

Clean Energy Fuels Corp.

  1%   Fair Value     16        12   

Gastar Exploration Ltd.

  10%   Fair Value     13        22   

Other

  —         33        28   
     

 

 

   

 

 

 

Total investments

  $ 544      $ 1,531   
     

 

 

   

 

 

 

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

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

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

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

In the Current Period, we recorded a $4 million charge related to our share of Chaparral’s net loss and depreciation adjustments of $2 million related to the excess of our cost over our proportionate share of Chaparral’s book equity. The carrying value of our investment in Chaparral was in excess of our underlying equity in net assets by approximately $53 million as of June 30, 2012. This excess is attributed to the natural gas and oil reserves held by Chaparral and is being amortized over the estimated life of these reserves based on a unit of production rate.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

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

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

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

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

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

 

                Carrying Value  
        Approximate
Ownership %
  Accounting
Method
      June 30,    
    2012    
    December 31,
2011
 
                ($ in millions)  

Utica East Ohio Midstream, LLC

  59%   Equity   $ 51      $   

Ranch Westex JV, LLC

  33%   Equity     18          

Glass Mountain Pipeline, LLC

  50%   Equity     4          
       

 

 

   

 

 

 

Total investments held for sale

  $ 73      $   
       

 

 

   

 

 

 

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

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

 

10. Variable Interest Entities

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

Consolidated VIEs

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

Unconsolidated VIEs

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

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

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

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

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

 

11. Impairments

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

Land and Buildings

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Drilling Rigs and Equipment

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

 

12. Fair Value Measurements

Certain financial instruments are reported at fair value on the condensed consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the financial asset or liability and have the lowest priority. Chesapeake uses a market valuation approach based on available inputs and the following methods and assumptions to measure the fair values of its assets and liabilities, which may or may not be observable in the market.

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

Investments. The fair value of Chesapeake’s investment in Gastar Exploration Ltd. (NYSE Amex: GST) and Clean Energy Fuels Corporation (NASDAQ:CLNE) common stock is based on a quoted market price.

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

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

Debt. The fair value of certain of our long-term debt is based on the face amount of that debt along with the value of related designated fair value interest rate swaps. We currently do not have any debt recorded at fair value since we have no open fair value hedges.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

 

    Quoted
Prices in
Active
Markets
    (Level 1)    
    Significant
Other
Observable
Inputs
    (Level 2)    
    Significant
Unobservable
Inputs
    (Level 3)    
    Total
Fair Value
 
          ($ in millions)        

Financial Assets (Liabilities):

       

Cash and cash equivalents

  $ 1,024      $      $      $ 1,024   

Restricted cash

    224                      224   

Investments

    29                      29   

Other long-term assets

    70                      70   

Other long-term liabilities

    (69                   (69

Derivatives:

       

Commodity assets

           138        14        152   

Commodity liabilities

           (13     (1,078     (1,091

Interest rate liabilities

           (41            (41

Foreign currency liabilities

           (48            (48
 

 

 

   

 

 

   

 

 

   

 

 

 

Total derivatives

           36        (1,064     (1,028
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 1,278      $ 36      $ (1,064   $ 250   
 

 

 

   

 

 

   

 

 

   

 

 

 

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

 

    Quoted
Prices in
Active
Markets
    (Level 1)    
    Significant
Other
Observable
Inputs
    (Level 2)    
    Significant
Unobservable
Inputs

     (Level 3)    
    Total
Fair Value
 
          ($ in millions)        

Financial Assets (Liabilities):

       

Cash and cash equivalents

  $ 351      $      $      $ 351   

Restricted cash

    44                      44   

Investments

    34                      34   

Other long-term assets

    61                      61   

Other long-term liabilities

    (62                   (62

Derivatives:

       

Commodity assets

           46        9        55   

Commodity liabilities

           (31     (1,663     (1,694

Interest rate liabilities

           (42            (42

Foreign currency liabilities

           (38            (38
 

 

 

   

 

 

   

 

 

   

 

 

 

Total derivatives

           (65     (1,654     (1,719
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 428      $ (65   $ (1,654   $ (1,291
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

 

     Derivatives  
     Commodity     Interest
Rate
    Foreign
Currency
    Debt  
     ($ in millions)  

Beginning Balance as of January 1, 2012

   $ (1,654   $      $      $   

Total gains (losses) (realized/unrealized):

        

Included in earnings or change in net

  assets(a)

     548        2                 

Total purchases, issuances, sales and

 settlements:

        

Sales

            (2              

Settlements

     42                        
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending Balance as of June 30, 2012

   $ (1,064   $      $      $   
  

 

 

   

 

 

   

 

 

   

 

 

 

Beginning Balance as of January 1, 2011

   $ (1,954   $ (69   $ (43   $ (1,371

Total gains (losses) (realized/unrealized):

        

Included in earnings or change in net

  assets(a)

     (548     11                 

Total purchases, issuances, sales and

 settlements:

        

Sales

            (4              

Settlements

     106                        

Transfers in and out of Level 3(b)

            54        43        1,371   
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending Balance as of June 30, 2011

   $ (2,396   $ (8   $      $   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

   Natural Gas, Oil     Interest  
         and NGL Sales                 Expense          
     2012          2011             2012          2011  
     ($ in millions)  

Total gains (losses) included in earnings

  (or change in net assets) for the period

   $           548       $ (548   $ 2       $ 11   

Change in unrealized gains (losses) relating to

  assets still held at reporting date

   $           430       $ (592   $       $ (8

 

(b)

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

Qualitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

 

Instrument

Type

  

Unobservable

Input

   Range    Weighted
Average
  Fair Value
June 30,
2012
 
                   ($ in millions)  

Oil Trades(a)

  

Oil price volatility curve

   15.41% - 31.50%    23.10%     $      (794)     

Natural Gas Trades(a)

  

Natural gas price volatility curve

   22.09% - 60.47%    29.19%     $      (237)     

Natural Gas Basis Swaps(b)

  

Physical pricing point

  forward curves

   ($1.08) - $0.26    $    (0.19)           $        (32)     

 

 

(a)

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

 

(b)

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

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. The carrying values of financial instruments comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. We estimate the fair value of our long-term debt primarily using quoted market prices (Level 1). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.

 

     June 30, 2012      December 31, 2011  
         Carrying              Estimated              Carrying              Estimated      
     Amount      Fair Value      Amount      Fair Value  
            ($ in millions)         

Long-term debt

   $ 14,423       $ 14,381       $ 10,598       $ 11,399   

Nonrecurring Fair Value Measurements

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

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

13. Segment Information

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

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

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

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

 

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(Unaudited)

 

    Exploration
and
 Production 
    Marketing,
Gathering
and
 Compression 
    Oilfield
  Services  
    Other
  Operations  
    Intercompany
 Eliminations 
     Consolidated 
Total
 
    ($ in millions)  

For the Three Months Ended
June 30, 2012:

           

Revenues

  $ 2,117      $ 2,274      $ 506      $      $ (1,508   $ 3,389   

Intersegment revenues

           (1,161     (347            1,508          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 2,117      $ 1,113      $ 159      $      $      $ 3,389   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before
income taxes

  $ 1,090      $ 1,089      $ 57      $ (401   $ (135   $ 1,700   

For the Three Months Ended
June 30, 2011:

           

Revenues

  $ 1,792      $ 2,617      $ 275      $      $ (1,366   $ 3,318   

Intersegment revenues

           (1,213     (153            1,366          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 1,792      $ 1,404      $ 122      $      $      $ 3,318   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before
income taxes

  $ 780      $ 75      $ 21      $ 26      $ (67   $ 835   

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

    Exploration
and
 Production 
    Marketing,
Gathering
and
 Compression 
    Oilfield
  Services  
    Other
  Operations  
    Intercompany
 Eliminations 
     Consolidated 
Total
 
    ($ in millions)  

For the Six Months Ended

  June 30, 2012:

           

Revenues

  $ 3,185      $ 4,664      $ 953      $      $ (2,995   $ 5,807   

Intersegment revenues

           (2,336     (659            2,995          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 3,185      $ 2,328      $ 294      $      $      $ 5,807   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before

  income taxes

  $ 1,178      $ 1,156      $ 96      $ (502   $ (234   $ 1,694   

For the Six Months Ended

  June 30, 2011:

           

Revenues

  $ 2,286      $ 4,838      $ 523      $      $ (2,717   $ 4,930   

Intersegment revenues

           (2,417     (300            2,717          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 2,286      $ 2,421      $ 223      $      $      $ 4,930   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before

  income taxes

  $ 475      $ 160      $ 42      $ 35      $ (143   $ 569   

As of June 30, 2012:

           

Total Assets

  $ 41,947      $ 3,484      $ 1,971      $ 2,279      $ (2,155   $ 47,526   

As of December 31, 2011:

           

Total Assets

  $ 35,403      $ 4,047      $ 1,571      $ 2,718      $ (1,904   $ 41,835   

 

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(Unaudited)

 

14. Condensed Consolidating Financial Information

Chesapeake Energy Corporation is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly owned subsidiaries on a senior unsecured basis. Our oilfield services subsidiary, COS, and its subsidiaries are not guarantors of our senior notes, contingent convertible senior notes and corporate credit facility but are subject to the covenants and guarantees in their revolving bank credit facility agreement referred to in Note 3 that restrict them from paying dividends or distributions or making loans to Chesapeake. COS and its subsidiaries were released as guarantors of our senior notes and corporate credit facility in October 2011 when they were formally reorganized and capitalized. Our midstream subsidiary, CMD, and its subsidiaries were added as guarantors of our senior notes and corporate credit facility in June 2012 upon the termination of the midstream credit facility. All prior year information has been restated to reflect COS and its subsidiaries as non-guarantor subsidiaries and CMD and its subsidiaries as guarantor subsidiaries. In addition, CHK Utica, CHK C-T, Chesapeake Granite Wash Trust, MAC-LP, L.L.C., Cardinal, UEOM and certain de minimis subsidiaries are also non-guarantors.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Set forth below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2012 and December 31, 2011 and for the three and six months ended June 30, 2012 and 2011. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF JUNE 30, 2012

($ in millions)

 

          Non-              
          Guarantor     Guarantor              
      Parent       Subsidiaries     Subsidiaries     Eliminations     Consolidated  

CURRENT ASSETS:

         

Cash and cash equivalents

  $      $ 911      $ 113      $      $ 1,024   

Other

    1        3,138        746        (492     3,393   

Current assets held for sale

           92        7               99   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Current Assets

    1        4,141        866        (492     4,516   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

PROPERTY AND EQUIPMENT:

         

Natural gas and oil properties,

  at cost based on full cost

  accounting, net

           32,672        3,005        (134     35,543   

Other property and equipment

  at cost, net

           2,737        1,387               4,124   

Property and equipment

  held for sale, net

           2,095        112               2,207   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Property