Chesapeake Energy (CHK)

Type of Production Payment Based on Risks of Ownership

Ownership Risk Analysis

In order for a production payment to be considered a volumetric production payment, as opposed to a production loan (dollar-denominated production payment) or a prepaid commodity sale, the purchaser must assume the risks typically associated with ownership. Below we discuss the principal owner risks: price risk and production/reserve risk.

Price Risk. The buyers assumed all, or substantially all, price risk associated with the VPP share of production, as the price is completely index based (i.e., variable). Even though Chesapeake transferred to the buyers derivatives that will serve to mitigate price risk, the buyers have sole control over the derivatives and bear the counterparty credit risk associated with the derivative positions. Chesapeake provided no guarantee or commitment as to pricing.

Production and Reserve Risk. The buyers assumed significant reserve risk. In the event the leasehold interests covering the VPP have insufficient reserves to satisfy the scheduled quantities of production to be delivered under the VPP, there is no recourse to Chesapeake. Chesapeake has no obligation to deliver hydrocarbons from any other property or lease or from Chesapeake’s retained interest in the subject leases.

The conveyance of the production payment contains a makeup mechanism to prevent either party from profiting on differences in the timing of actual delivery of the VPP share of hydrocarbons compared to the scheduled delivery of the VPP share of hydrocarbons. If there is a shortfall in scheduled deliveries, the quantity to be made up is adjusted to take into account any differences in the market price of the applicable hydrocarbons between the month in which the shortfall occurred and the month in which the shortfall is made up, and interest on the value of the deferred share of production is imposed. The shortfall quantity, as adjusted, is delivered in kind as soon as sufficient production is available from the properties. If market prices are higher in the month in which a makeup occurs compared to the month in which the production was scheduled to be delivered, the quantity of VPP hydrocarbons to be delivered will be reduced. If market prices are lower in the month in which the makeup occurs compared to the month in which the production was scheduled to be delivered, the quantity of VPP hydrocarbons will

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be increased. Accordingly, the buyers are in no better or worse position in terms of pricing risk than they would have been had the VPP share of production actually been delivered on the scheduled date.

While the makeup provision could cause the volumes ultimately delivered to the buyers to differ from the originally scheduled volumes, Chesapeake believes this does not substantively change the overall attributes of the VPP. The value and interest components of any short-term disruption in the scheduled deliveries of the VPP owners’ share of production would have a negligible effect on the overall VPP arrangement in relative terms. Conversely, a long-term disruption in the delivery of the scheduled volumes, although likely to have a more than negligible effect on the VPP arrangement through the value and interest components of the makeup provision, would indicate a cumulative inability of the reserves to keep pace with the scheduled volumes. The buyers have assumed the risk of inadequate reserves as the production payment is without recourse to other reserves or to Chesapeake.

Accounting Treatment Conclusion—Volumetric Production Payment

Based on the buyers’ assumption of significant production and reserve risks and substantially all price risk, Chesapeake concluded that the production payment should be accounted for as a volumetric production payment. Under Regulation S-X Rule 4-10(c)(6)(i), “sales of oil and gas properties . . . shall be accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves . . . attributable to the cost center.” Since the VPP constituted less than 2% of Chesapeake’s total proved reserves, a significant alteration of the relationship between capitalized costs and proved reserves did not take place (the impact of the sale on our 2007 fourth quarter DD&A rate was approximately 1.9%).

We also considered the provisions of Regulation S-X Rule 4-10(c)(6)(ii), which indicates that “purchases of oil and gas reserves in place ordinarily shall be accounted for as additional capitalized costs with the applicable cost center; however, significant purchases of production payments or properties with lives substantially shorter than the composite life of the cost center shall be accounted for separately.” While this provision is focused on the purchase of reserves, we believe it confirms that the full-cost rules consider production payments the transfer of a mineral interest as contemplated by Regulation S-X Rule 4-10(c)(6)(i) above.

Consideration of Alternative Accounting Treatment—Production Loan

A production loan, while similar to a volumetric production payment, requires the seller to deliver cash or quantities of oil and gas production having a value equal

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to the amount of cash received by the seller plus a stated rate of interest. An important distinction between a production loan and a volumetric production payment is that the volumes to be delivered under a volumetric production payment are specified in the agreement and there are no mechanisms that guarantee the value of the production and reserves attributable to the purchaser’s ownership interest. As described above, the buyers of Chesapeake’s VPP assumed all, or substantially all, price risks and reserve risk. Because the makeup mechanism does serve to mitigate some of the risk associated with the timing of production, Chesapeake carefully evaluated whether the VPP should be accounted for as debt.

In addition to utilizing the concept of risk transfer in the table above, the company evaluated the sale of the VPP using the attributes provided in EITF 88-18, Sales of Future Revenues. Of the six attributes listed in EITF 88-18, only one was potentially met. It states, “The enterprise has significant continuing involvement in the generation of the cash flows due the investor (for example, active involvement in the generation of the operating revenues of a product line, subsidiary, or business segment).” Although the presence of this attribute creates the rebuttable presumption that classification of the proceeds as debt is required, there are numerous mineral conveyances (including those discussed in SFAS 19 for entities utilizing successful efforts) that involve some element of continuing involvement by the seller, and for which sale accounting is provided. Chesapeake believes that EITF 88-18 was not intended to alter the accounting for mineral conveyances of oil and gas companies as contemplated by SFAS 19 and Regulation S-X Rule 4-10.

In summary, we rejected the alternative of accounting for the VPP as debt. The characteristics of the VPP, taken as a whole, are more indicative of a volumetric production payment as contemplated in Regulation S-X Rule 4-10.

Consideration of Alternative Accounting Treatment—Prepaid Commodity Sale

We rejected accounting for the VPP as a prepaid commodity sale because Chesapeake does not guarantee production and delivery of the scheduled volumes. These risks are assumed by the buyers.

Transfer of Derivatives

As part of the VPP transaction, Chesapeake entered into a Novation Agreement to transfer full ownership of certain derivative contracts to the buyers. These derivatives will mitigate commodity price risk of the buyers in connection with future deliveries of scheduled volumes of production. Although the buyers could have independently entered into similar derivatives to manage their price risk, the Novation Agreement simply facilitated this process, and the value of the novated hedges was a determinant in the calculation of the purchase price. The buyers

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have complete discretion over the derivatives. They could settle the contracts prior to maturity or hold them throughout the 15-year term of the VPP, and they have counterparty credit risk associated with the derivative positions. Chesapeake has provided no guarantee or commitment relating to the buyers’ VPP price risk.

The novated hedges were designated as cash flow hedges associated with Chesapeake production not part of the VPP transaction. Consequently, pursuant to SFAS 133, the associated fair value of the hedges (as of December 31, 2007) will be held in Other Comprehensive Income pending the respective months of related production pursuant to the original terms of the derivative contracts. The novated hedges had a net negative fair value of $52 million, which reduced the amount allocated to the properties sold.