This excerpt taken from the FST 10-Q filed May 7, 2009.
CRITICAL ACCOUNTING POLICIES, ESTIMATES, JUDGMENTS, AND ASSUMPTIONS
Reference should be made to Forest's 2008 Annual Report on Form 10-K under Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations"Critical Accounting Policies, Estimates, Judgments, and Assumptions" for a discussion of other critical accounting policies in addition to those discussed below.
This excerpt taken from the FST 10-K filed Feb 28, 2007.
Oil and Gas Reserve Estimates
Our estimates of proved reserves are based on the quantities of oil and gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production, and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a ceiling test limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures included in Note 15 to the Consolidated Financial Statements.
Reference should be made to Independent Audit of Reserves under Part I, Item 1Business, and Risk Factors Relating to ForestEstimates of oil and gas reserves are uncertain and inherently imprecise, under Part I, Item 1ARisk Factors, in this Form 10-K.
Accounting for Oil and Gas Derivatives Instruments
The Company follows the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Under the provisions of SFAS 133, the Company may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a fair value hedge) or against exposure to variability in expected future cash flows (a cash flow hedge). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge as noted above. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of operations due to the fact that changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings as other income or expense.
As a result of production deferrals experienced in the Gulf of Mexico related to hurricanes Katrina and Rita, Forest was required to discontinue cash flow hedge accounting on some of its natural gas and oil hedges during the third and fourth quarters of 2005. Additionally, as a result of the Spin-off on March 2, 2006, additional commodity swaps and collars formerly designated as cash flow hedges of offshore Gulf of Mexico production also no longer qualified for hedge accounting. Because a significant portion of the
Companys derivatives no longer qualified for hedge accounting and to increase clarity in its financial statements, the Company elected to discontinue hedge accounting prospectively for all of its remaining commodity derivatives beginning in March 2006. Accordingly, after March 2006, all changes in the fair values of our derivative instruments have been and will continue to be recognized as other income or expense.
The estimated fair values of our derivative instruments require substantial judgment. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions, or other factors, many of which are beyond our control.
Due to the volatility of oil and natural gas prices, the fair values of our derivative instruments are subject to large fluctuations in estimated fair value from period to period. For example, a hypothetical increase in the forward oil and natural gas prices used to calculate the fair value of the derivative instruments at December 31, 2006 of $1.00 per barrel and $.10 per MMbtu, respectively, would change the fair values of our derivative instruments at December 31, 2006 by approximately $11.0 million. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Actual gains or losses recognized in conjunction with our commodity derivative contracts will likely differ from those estimated at December 31, 2006 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
Valuation of Deferred Tax Assets
We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are generally determined based on differences between the financial statement carrying values of book assets and liabilities and their respective income tax bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on income tax assets and liabilities of a change in tax rates is included in operations in the period in which the change is enacted. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.
In assessing the value of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon future taxable income during the periods in which related temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets will reverse, management believes it is more likely than not that we will realize the benefits of these deferred tax assets, net of the existing valuation allowances at December 31, 2006. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during relevant periods are reduced.
Asset Retirement Obligations
Forest has obligations to remove tangible equipment and restore locations at the end of the oil and gas production operations. Forests largest concentration of removal and restoration obligations is associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms in the Cook Inlet of Alaska. Estimating the future restoration and removal costs, or asset retirement obligations, is difficult and requires management to make estimates and judgments, because most of the obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
Inherent in the calculation of the present value of our asset retirement obligations (ARO) under SFAS No. 143 are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory,
environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statement of Operations.
Full Cost Method of Accounting
The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the full cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported in our financial statements. We have elected to follow the full-cost method, which is described below.
Under the full cost method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement obligation liability is recorded. Capitalized costs applicable to each full cost center are depleted using the units of production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are accounted for prospectively in the depletion calculations. Assuming consistent production year over year, our depletion expense will be significantly higher or lower if we significantly decrease or increase our estimates of remaining proved reserves.
Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool, or reported as impairment expense in the Consolidated Statements of Operations, as applicable.
Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed each quarter on a country-by-country basis. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves, as adjusted for asset retirement obligations and the effect of cash flow hedges. This ceiling is compared to the net book value of the oil and gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash writedown is required. A ceiling test impairment could cause Forest to record a significant non-cash loss for a particular period; however, future DD&A expense would be reduced thereafter.
In countries or areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion, and amortization, and the application of the ceiling limitation. Unproved properties are assessed periodically to ascertain whether impairment has
occurred. An impairment of unproved property costs may be indicated through evaluation of drilling results, relinquishment of drilling rights or other information.
Under the alternative successful efforts method of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, exploratory dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis under the successful efforts method. Impairments are assessed on a property by property basis and are charged to expense when assessed.
In general, the application of the full cost method of accounting results in higher capitalized costs and higher depletion rates compared to the successful efforts method.
The full cost method is used to account for our oil and gas exploration and development activities, because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.