
.	Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

Chesapeake Energy Corporation ("Chesapeake" or the "Company") is a natural gas and oil exploration and production company engaged in the exploration, development and acquisition of properties for the production of natural gas, oil and natural gas liquids (NGL) from underground reservoirs. We also provide substantial marketing, drilling and other oilfield services. Our operations are located onshore and in the continental United States.

Principles of Consolidation

The accompanying 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. Chesapeake consolidates subsidiaries in which it holds, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 12 for further discussion of investments. All significant intercompany accounts and transactions have been eliminated. Undivided interests in natural gas and oil exploration and production joint ventures are consolidated on a proportionate basis.

Variable Interest Entities

An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. We consolidate a VIE when we have both the power to direct the activities that most significantly impact the activities of the VIE and the right to receive benefits or the obligation to absorb losses of the entity that could be potentially significant to the VIE. Along with the VIEs that are consolidated in accordance with these guidelines, we also hold variable interests in other VIEs that are not consolidated because we are not the primary beneficiary. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 13 for further discussion of VIEs.

Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Estimates of natural gas and oil reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions may be material and could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A further decline in natural gas or NGL prices or a significant decline in oil prices could result in actual results differing significantly from our estimates.

Risks and Uncertainties

Our business strategy is to continue growing our reserves and production and transitioning from an asset base primarily focused on natural gas to an asset base more balanced between natural gas and liquids production. This is a capital-intensive strategy, and we made capital expenditures in 2012 that exceeded our cash flow from operations, filling the gap with borrowings and proceeds from sales of assets that we determined were non-core or did not fit our long-term plans. See Note 11 for a description of our 2012 asset sales. We project that our capital expenditures will continue to exceed our operating cash flow in 2013, although by a significantly smaller amount. Our 2013 capital expenditure budget is approximately 50% less than our 2012 capital expenditures, and as operator of a substantial portion of our natural gas and oil properties under development, we have significant control and flexibility over the development plan and the associated timing, enabling us to expeditiously reduce at least a portion of our capital spending if needed. To add certainty to future estimated cash flows by mitigating our downside exposure to lower commodity prices, we currently have downside hedge protection on approximately 50% of our 2013 estimated natural gas production at a price of $3.62 per mcf and 85% of our 2013 estimated oil production at a price of $95.45 per bbl, allowing us to reduce the effect of price volatility on our cash flows and earnings before interest, taxes, depreciation, depletion and amortization (EBITDA). Based on these and other factors, we believe we have adequate borrowing capacity through our current credit arrangements, together with anticipated proceeds from transactions subject to binding agreements to sell non-core assets, to make up the difference between our budgeted capital expenditures and cash flow from operations in 2013.

As part of our asset sales planning and capital expenditure budgeting process, we closely monitor the resulting effects on the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our corporate revolving bank credit facility. While asset sales enhance our ability to reduce debt, sales of producing natural gas and oil properties may adversely affect the amount of cash flow and EBITDA we generate and reduce the amount and value of collateral available to secure our obligations, both of which can be exacerbated by low prices received for our production. In September 2012, we obtained an amendment to our revolving bank credit facility agreement that relaxed the required indebtedness to EBITDA ratio for the quarter ended September 30, 2012 and the four subsequent quarters. We would have been unable to meet the required ratio as of September 30, 2012 without this amendment primarily because the closing of certain asset sales transactions occurred in the fourth quarter and not in September as we had anticipated. As a result, without the amendment, we would have been unable to reduce our indebtedness sufficiently as of September 30, 2012 to maintain our covenant compliance. Failure to maintain compliance with the covenants of our revolving bank credit facility could result in the acceleration of outstanding indebtedness under the facility and lead to cross defaults under our senior note and contingent convertible senior note indentures, hedge facility, equipment master lease arrangements and term loan. See Note 3 for further discussion of our debt instruments, including the terms of the credit facility amendment. Based on reductions in our budgeted capital expenditures, expected commodity prices (including the prices for our currently hedged production), our forecasted drilling and production, projected levels of indebtedness and binding purchase and sale agreements for certain future asset sales, we expect we will be in compliance with the financial maintenance covenants of our corporate revolving bank credit facility through 2013. We believe the assumptions underlying our budget for this period are reasonable and that we have adequate flexibility, including the ability to adjust discretionary capital expenditures, to adapt to potential negative developments if needed to maintain covenant compliance.

Natural gas prices reached 10-year lows in 2012, and although our strategic focus on increasing liquids production is progressing and we have hedges in place covering approximately 50% of our projected 2013 natural gas production, we continue to have significant exposure to natural gas prices. Approximately 70% and 83% of our estimated proved reserves volumes as of December 31, 2012 and December 31, 2011, respectively, were natural gas, and natural gas represented approximately 80% and 84% of our natural gas, oil and NGL sales volumes for 2012 and 2011, respectively. In 2012, we reduced our estimate of proved reserves by 3.1 tcfe, or 17%, primarily due to the impact of downward natural gas price revisions. Natural gas prices used in estimating proved reserves at December 31, 2012 and 2011 decreased by 33% from $4.12 per mcf to $2.76 per mcf, causing the loss of significant proved undeveloped reserves for which future development is uneconomic. As a result of lower estimated reserves, in the 2012 third quarter, we were required to impair the carrying value of our natural gas and oil properties, and we could have additional impairments in the future. See Natural Gas and Oil Properties below for further discussion of our impairment of the carrying value of our natural gas and oil properties in 2012.

We believe we have taken appropriate measures to mitigate the risks and uncertainties facing us in 2013. Nevertheless, our ability to generate operating cash flow and close asset sales in order to manage debt is subject to all the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time. We do not have binding agreements for all of our planned asset sales and our ability to consummate each of these transactions is subject to changes in market conditions and other factors beyond our control. If one or more of the transactions is not completed in the anticipated time frame, or at all, or for less proceeds than anticipated, our ability to fund budgeted capital expenditures and reduce our indebtedness could be adversely affected. Future impairments of the carrying value of our natural gas and oil properties, if any, will be dependent on many factors, including natural gas, oil and NGL prices, production rates, levels of reserves, the evaluation of costs excluded from amortization, the timing and impact of asset sales, future development costs and service costs.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents. Restricted cash consists of balances required to be maintained by the terms of the respective agreements governing the activities of CHK Utica, L.L.C. (CHK Utica) and CHK Cleveland Tonkawa, L.L.C. (CHK C-T). For CHK Utica, we must retain a minimum cash balance equal to two quarterly dividend payments. In addition, cash proceeds received from CHK Utica asset sales must be used to fund CHK Utica's capital expenditures or to redeem its preferred shares. For CHK C-T, we must retain an amount of cash (remeasured quarterly) equal to (i) the next two quarters of preferred dividend payments plus (ii) the projected operating funding shortfall for the next six months. See Note 8 for further discussion of these transactions.

Accounts Receivable

Our accounts receivable are primarily from purchasers of natural gas and oil and exploration and production companies which own interests in properties we operate. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables we believe will be uncollectible. During 2012, 2011 and 2010, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables. Accounts receivable as of December 31, 2012 and 2011 are detailed below.



	December 31,
	2012			2011
	($ in millions)
Natural gas, oil and NGL sales	$	1,457		$	1,089
Joint interest	592			1,171
Oilfield services	24			43
Related parties^(a)	23			45
Other	168			176
Allowance for doubtful accounts	(19		)	(19		)
Total accounts receivable	$	2,245		$	2,505

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(a)	See Note 6 for discussion of related party transactions.

Natural Gas and Oil Properties

Chesapeake follows the full cost method of accounting under which all costs associated with natural gas and oil property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities (see Note 10). Capitalized costs are amortized on a composite unit-of-production method based on proved natural gas and oil reserves. Estimates of our proved reserves as of December 31, 2012 were prepared by both third-party engineering firms and Chesapeake's internal staff. Approximately 89% of these proved reserves estimates (by volume) as of December 31, 2012 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis. The average composite rates used for depreciation, depletion and amortization of natural gas and oil properties were $1.76 per mcfe in 2012, $1.37 per mcfe in 2011 and $1.35 per mcfe in 2010.

Proceeds from the sale of natural gas and oil properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unevaluated properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unevaluated leasehold and transfer to evaluated properties leasehold that can be associated with reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned. As our strategic focus is shifting from a natural gas asset base to a more balanced natural gas and liquids asset base, and as our budgeted capital expenditures were being reduced in 2012, we identified undeveloped leasehold having a cost of $1.684 billion that would not be a part of our development strategy going forward. The acreage was primarily located in the Williston and DJ Basins, as well as other non-core leasehold located throughout our operating areas.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2012 and notes the year in which the associated costs were incurred.



	Year of Acquisition
	2012		2011		2010		Prior		Total
	($ in millions)
Leasehold acquisition cost	$	1,826	$	2,732	$	3,519	$	3,325	$	11,402
Exploration cost	1,213		176		42		—		1,431
Capitalized interest	810		424		312		376		1,922
Total	$	3,849	$	3,332	$	3,873	$	3,701	$	14,755

We also review, on a quarterly basis, the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for natural gas and oil cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In 2012, capitalized costs of natural gas and oil properties exceeded the estimated present value calculation of future net revenues from our proved reserves, net of related income tax considerations, resulting in an impairment in the carrying value of natural gas and oil properties in the 2012 third quarter of $3.315 billion. For the ceiling test calculation, costs used are those as of the end of the appropriate quarterly period. In calculating estimated future net revenues, current prices are calculated as the unweighted arithmetic average of natural gas and oil prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. Cash flow hedges locked in prior to September 30, 2012 relating to future production periods increased the 2012 third quarter ceiling test impairment by $279 million. As of December 31, 2012, none of our open derivative instruments were designated as cash flow hedges. Our natural gas and oil hedging activities are discussed in Note 9 of these consolidated financial statements. See Risks and Uncertainties above for a discussion of the reduction in our estimated proved reserves in 2012 and factors that could impact a future ceiling test impairment.

Two primary factors impacting the ceiling test are reserves levels and natural gas, oil and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an extended increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is written off as an expense.

We account for seismic costs in accordance with Rule 4-10 of Regulation S-X. Specifically, Rule 4-10 requires that all companies that use the full cost method capitalize exploration costs as part of their natural gas and oil properties (i.e., full cost pool). Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. Such costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly in order to ascertain whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unevaluated properties, they are included in the amortization base as incurred.

Other Property and Equipment

Other property and equipment consists primarily of oilfield services equipment, including drilling rigs, rental tools, hydraulic fracturing and mining equipment, natural gas compressors, land, buildings and improvements, vehicles, office equipment, natural gas gathering systems and treating plants. The majority of our natural gas gathering systems and treating plants were sold in 2012 as discussed in Note 11 to these consolidated financial statements. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 14 for further discussion of our gains and losses on the sales of other property and equipment. Other property and equipment costs, excluding land, are depreciated on a straight-line basis. A summary of our other property and equipment held for sale as of December 31, 2012 is summarized in Held for Sale Assets and Liabilities below. A summary of other property and equipment held for use and the useful lives is as follows:



	December 31,						Useful
	2012			2011			Life
	($ in millions)						(in years)
Oilfield services equipment	$	2,130		$	1,632		3 - 15
Natural gas gathering systems and treating plants	—			1,455			3 - 20
Buildings and improvements	1,580			1,202			10 - 39
Natural gas compressors	505			303			20
Land	515			926			—
Other	1,178			1,124			2 - 20
Total other property and equipment, at cost	5,908			6,642
Less: accumulated depreciation and amortization	(1,293		)	(1,082		)
Total other property and equipment, net	$	4,615		$	5,560

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. 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 impairments of $340 million, $46 million and $21 million in 2012, 2011 and 2010, respectively. See Note 14 for further discussion of these impairments.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries, VIEs or our investments and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

Capitalized Interest

During 2012, 2011 and 2010, interest of approximately $976 million, $727 million and $711 million, respectively, was capitalized on significant investments in unproved properties that were not being currently depreciated, depleted or amortized and on which exploration activities were in progress. The increase in 2012 compared to 2011 was primarily the result of capitalizing additional interest on senior notes and term loans issued in 2012. Additional interest of $4 million, $6 million and $5 million was capitalized in 2012, 2011 and 2010, respectively, on midstream and oilfield services assets which were under construction. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings.

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Chesapeake's $43 million of goodwill as of December 31, 2012 consists of the excess consideration over the fair value of assets acquired of $28 million in the Bronco Drilling Company acquisition and $15 million in the Horizon Drilling Services acquisition. Quoted market prices are not available for these reporting units and their fair values are based upon several valuation analyses, including discounted cash flows.

We performed annual impairment tests of goodwill in the fourth quarters of 2012 and 2011. Based on these assessments, no impairment of goodwill was required. Our goodwill is included in our oilfield services segment.

Accounts Payable and Other Current Liabilities

Included in accounts payable as of December 31, 2012 and 2011 are liabilities of approximately $432 million and $604 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Other current liabilities as of December 31, 2012 and 2011 are detailed below.



	December 31,
	2012		2011
	($ in millions)
Revenues and royalties due others	$	1,337	$	1,090
Accrued natural gas, oil and NGL drilling and production costs	525		590
Accrued acquisition costs	242		81
Joint interest prepayments received	749		865
Accrued payroll and benefits	224		199
Accrued dividends	101		99
Other	563		473
Total other current liabilities	$	3,741	$	3,397

Other Long-Term Liabilities

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



	December 31,
	2012		2011
	($ in millions)
CHK Utica ORRI conveyance obligation^(a)	$	275	$	290
CHK C-T ORRI conveyance obligation^(b)	164		—
Financing lease obligations^(c)	143		143
Mortgages payable^(d)	56		56
Other	538		329
Total other long-term liabilities	$	1,176	$	818

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(a)	$18 million and $10 million of the total $293 million and $300 million obligations are recorded in other current liabilities as of December 31, 2012 and December 31, 2011, respectively. See Note 8 for further discussion of the transaction.


(b)	$14 million of the total $178 million obligation is recorded in other current liabilities as of December 31, 2012. See Note 8 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. We anticipate making lease payments related to these assets of approximately $15 million in 2013, $16 million in 2014, $17 million in 2015, $17 million in 2016, $17 million in 2017 and $709 million in 2018 and beyond.

(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 promissory note which has a floating rate of prime plus 275 basis points. At our option, after June 2012 we could prepay the promissory note in full without penalty. As of December 31, 2012, our Barnett Shale headquarters building was classified as property and equipment held for sale on our consolidated balance sheet. Subsequent to December 31, 2012, we prepaid in full the promissory note.

Debt Issuance and Hedging Facility Costs

Included in other long-term assets are costs associated with the issuance of our senior notes and costs primarily associated with our term loans, revolving bank credit facilities and hedging facility. The remaining unamortized issuance costs at December 31, 2012 and 2011 totaled $182 million and $163 million, respectively, and are being amortized over the life of the senior notes, term loan, revolving bank credit facilities or hedging facility using the effective interest method.

Asset Retirement Obligations

We recognize liabilities for retirement obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which a natural gas or oil well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our natural gas and oil properties. See Note 16 for further discussion of asset retirement obligations.

Revenue Recognition

Natural Gas, Oil and NGL Sales. Revenue from the sale of natural gas, oil and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges.

Natural Gas Imbalances. We follow the "sales method" of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance liability net position as of December 31, 2012 and 2011 was $9 million and $8 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the natural gas it purchases from other working interest owners in operated wells at the terminus of gathering systems (where applicable) and delivers the natural gas to third parties, at which time revenues are recorded. Chesapeake's results of operations related to its natural gas and oil marketing activities are presented on a "gross" basis, because we act as a principal rather than an agent. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Oilfield Services Revenue. Our oilfield services operating segment is responsible for contract drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties.


•	Drilling. We earn revenues by drilling oil and natural gas wells for our customers under daywork contracts. We recognize revenue on daywork contracts for the days completed based on the dayrate specified in each contract. Payments received and costs incurred for mobilization services are recognized over the days of actual mobilization.

•

Hydraulic Fracturing. We recognize revenue upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day per active crew during the course of a job. A stage is considered complete when the customer requests or the job design dictates that pumping discontinue for that stage. Invoices typically include a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing our services.

•

Oilfield Rentals. We rent many types of oilfield equipment including drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and also provide air drilling services and services associated with the transfer of fresh water to the wellsite. We price our rentals and services by the day or hour based on the type of equipment being rented and the service job performed and recognize revenue ratably over the term of the rental.


•	Oilfield Trucking. Oilfield trucking provides rig relocation and logistics services as well as fluid handling services. Our trucks move drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transport produced water from the wellsites. We price these services by the hour and recognize revenue as services are performed.


•	Other Operations. We design, engineer and fabricate natural gas compressor packages that we primarily sell to Chesapeake. We price our compression units based on certain specifications such as horsepower, stages and additional options. We recognize revenue upon completion and transfer of ownership of the natural gas compression unit.

All significant intercompany accounts and transactions have been eliminated.

Derivatives

Chesapeake uses commodity price and financial risk management instruments to mitigate a portion of our exposure to price fluctuations in natural gas, oil and NGL prices and changes in interest rates and foreign exchange rates. Results of commodity derivative transactions are reflected in natural gas, oil and NGL sales, and results of interest rate and foreign exchange rate derivative transactions are reflected in interest expense.

We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as natural gas and oil cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings as natural gas and oil sales. Any change in the fair value resulting from ineffectiveness is recognized immediately in natural gas, oil and NGL sales. For interest rate derivative instruments designated as fair value hedges, changes in fair value are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are recognized currently in earnings. Cash settlements of our derivative arrangements 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 consolidated statement of cash flows.

Stock-Based Compensation

Chesapeake's stock-based compensation program during 2012, 2011 and 2010 consisted of restricted stock issued to employees and non-employee directors. Prior to 2006, we also issued stock options. 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. We utilized the Black-Scholes option pricing model to measure the fair value of stock options. 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.

For the years ended December 31, 2012, 2011 and 2010, we recorded the following stock-based compensation:



	Years Ended December 31,
	2012		2011		2010
	($ in millions)
Natural gas and oil properties	$	71	$	112	$	120
General and administrative expenses	71		92		84
Natural gas, oil and NGL production expenses	24		33		35
Marketing, gathering and compression expenses	15		17		18
Oilfield services expense	10		11		9
Total	$	191	$	265	$	266

Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in benefits are classified as operating cash outflows in our consolidated statements of cash flows. For the years ended December 31, 2012, 2011 and 2010, we recognized reductions in tax benefits related to stock-based compensation of $30 million, $26 million and $13 million, respectively.

Held for Sale Assets and Liabilities

We are currently pursuing the sale of our remaining midstream business, and we expect to complete these sales in the next 12 months. The midstream business qualified as held for sale as of December 31, 2012 and is reported under our marketing, gathering and compression operating segment. In addition, we are pursuing the sale within the next 12 months of various other property and equipment, including certain drilling rigs and land and buildings primarily in the Fort Worth, Texas area. The drilling rigs are reported under our oilfield services operating segment, and the land and buildings are reported under our other operating segment. Natural gas and oil properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. A summary of the assets and liabilities held for sale on our consolidated balance sheet as of December 31, 2012 is detailed below.



	December 31, 2012
	($ in millions)
Accounts receivable	$	4
Current assets held for sale	$	4

Natural gas gathering systems and treating plants, net of accumulated depreciation	$	352
Oilfield services equipment, net of accumulated depreciation^(a)	27
Other property and equipment, net of accumulated depreciation and amortization	255
Property and equipment held for sale, net	$	634

Accounts payable	$	4
Accrued liabilities	17
Current liabilities held for sale	$	21

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(a)	Subsequent to December 31, 2012, we sold eight rigs classified as held for sale assets as of December 31, 2012 for proceeds of approximately $27 million.

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2011 and 2010 to conform to the presentation used for the 2012 consolidated financial statements.