Oil and natural gas properties
The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $425.3 million and $470.0 million as of December 31, 2013 and 2012, respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. Our undeveloped properties are predominantly held-by-production, which reduces the risk of impairment as a result of lease expirations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. As a result of this evaluation, we impaired approximately $1.0 million and $60.8 million of undeveloped properties during 2013 and 2012, respectively, which were transferred to the depletable portion of the full cost pool during each year. The impairment was recorded to reflect the estimated market price which included certain properties that were no longer part of our drilling plans. There were no impairments of undeveloped properties during the year ended December 31, 2011.
We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20, Capitalization of Interest. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest related to these properties.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.
Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves.
Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record a ceiling test impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying the average price as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.
The ceiling test is computed using the simple average spot price for the trailing 12 month period using the first day of each month. For the 12 months ended December 31, 2013, the trailing 12 month reference prices were $3.67 per Mmbtu for natural gas at Henry Hub, and $96.78 per Bbl of oil for West Texas Intermediate at Cushing, Oklahoma. The price used for NGL's was $39.92 per Bbl and was based on the trailing 12 month average of realized prices. Each of the reference prices for oil, natural gas and NGLs are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedging instruments, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations.
As of December 31, 2013 pursuant to Rule 4-10(c)(4) of Regulation S-X, we were required to compute the ceiling test using the simple average spot price for the trailing 12 month period for oil and natural gas. The computation resulted in the carrying costs of our unamortized proved oil and natural gas properties, exceeding the December 31, 2013 ceiling test limitation by approximately $156.6 million, including the recently acquired Haynesville and Eagle Ford properties from Chesapeake ("Chesapeake Properties"). Our pricing for the acquisitions of the Chesapeake Properties was based on models which incorporate, among other things, market prices based on NYMEX futures as of the acquisition date. The ceiling test requires companies using the full cost accounting method to price period-ending proved reserves using the simple average spot price for the trailing 12 month period, which may not be indicative of actual market values. Given the short passage of time between closing of these acquisitions and the required ceiling test computation, the Company requested, and received, an exemption from the Securities and Exchange Commission ("SEC") to exclude the acquisition of the Chesapeake Properties from the ceiling test assessments for a period of 12 months following the corresponding acquisition dates.
If we cannot demonstrate the fair value of the Chesapeake Properties exceeds the unamortized carrying costs during the requested exemption periods prior to issuance of our financial statements, we are required to recognize an impairment. We evaluated the Chesapeake Properties for impairment using discounted cash flow models based on internally generated oil and natural gas reserves as of December 31, 2013. The Company's expectation of future prices is principally based on NYMEX futures contracts, adjusted for basis differentials. We believe the NYMEX futures contract reflects an independent pricing point for determining fair value.
The evaluation of impairment of our oil and natural gas properties includes estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.
For the years ended December 31, 2013, 2012 and 2011 we recognized impairments of $108.5 million, $1.3 billion and $233.2 million, respectively, to our proved oil and natural gas properties.
