1. Organization and Significant Accounting Policies
Nature of Operations
We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States and Canada. Our oil and gas assets are located in four operating regions in the United States, the Rocky Mountain, Mid-Continent, Permian Basin and onshore Gulf Coast, and in the province of Alberta, Canada.
The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling LLC (“Raven Drilling”) and its wholly-owned foreign subsidiary, Canadian Abraxas Petroleum, ULC (“Canadian Abraxas”). The term “Partnership” refers only to Abraxas Energy Partners, L.P.
The Company consolidates based on the guidance of Accounting Standards Codification (“ASC”) 810. ASC 810 establishes accounting and reporting standards for (1) ownership interests in subsidiaries held by others, (2) the amount of consolidated net income attributable to the controlling and non-controlling interests, (3) changes in the controlling ownership interest, (4) the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated and (5) disclosures that clearly identify and distinguish between the interests of the controlling and non-controlling owners. The adoption of ASC 810 resulted in changes to our presentation for non-controlling interests and did not have a material impact on the Company's results of operations and financial condition.
On June 30, 2009, Abraxas Petroleum and the Partnership signed an Agreement and Plan of Merger, which we refer to as the Original Merger Agreement, pursuant to which the Partnership agreed to merge with and into Abraxas Petroleum with Abraxas Petroleum surviving and on July 17, 2009, Abraxas Petroleum and the Partnership signed an Amended and Restated Agreement and Plan of Merger, which we refer to as the Merger Agreement, pursuant to which the Partnership agreed to merge with and into Abraxas Merger Sub, LLC, which we refer to as Merger Sub, with Merger Sub surviving the merger as a wholly-owned subsidiary of Abraxas Petroleum. We refer to this merger as the Merger. Under the terms of the Merger Agreement, at the effective time of the Merger on October 5, 2009, each common unit of the Partnership not owned by Abraxas Petroleum and its subsidiaries was converted into the right to receive 4.25 shares of Abraxas Petroleum common stock. We issued a total of 26,174,061 shares of our common stock in the Merger, including 420,552 shares of restricted common stock issued in exchange for restricted units and phantom units of the Partnership under the Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan.
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and the operations of the Partnership which was formed on May 25, 2007. The interest of the 51.8% owners of the Partnership was presented as non-controlling interest (through the date of its merger into Abraxas Petroleum). Abraxas owned the remaining 48.2% of Partnership interests. The Company determined that based on its control of the general partner of the Partnership, this 48.2% owned entity should be consolidated for financial reporting purposes.
Canadian Abraxas' assets and liabilities are translated to U.S. dollars at period-end exchange rates. Income and expense items are translated at average rates of exchange prevailing during the period. Translation adjustments are accumulated as a separate component of stockholders' equity.
Liquidity
The recent global recession had a significant impact on our operations. As a result of the recession, gas prices have been depressed due to the weak demand in the manufacturing industry and the oversupply of natural gas thereby causing a prolonged downturn, which reduced our cash flows from operations through 2011. In the future, if gas prices continue to be weak or if a significant decline in oil prices occurs, it could reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) 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 date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Concentration of Credit Risk
Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts. Accounts receivable are generally from companies with significant oil and gas marketing activities. The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions from which we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the current overall financial condition of the counterparties.
The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality.
Cash and Equivalents
Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.
Accounts Receivable
Accounts receivable are reported net of an allowance for doubtful accounts of approximately $54,000 and $84,000 at December 31, 2010 and 2011, respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.
Oil and Gas Properties
The Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties, except in unusual circumstances. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. As of December 31, 2009, our net capitalized costs of oil and gas properties in the United States did not exceed the present value of our estimated proved reserves. We did not own any properties outside of the United States in 2009. As of December 31, 2010, our net capitalized costs of oil and gas properties in the United States did not exceed the present value of our estimated proved reserves; however, the net capitalized costs of oil and gas properties in Canada exceeded the present value of our estimated proved reserves by $4.8 million resulting in a write down for the year ended December 31, 2010. As of December 31, 2011, our net capitalized costs of oil and gas properties in the United States and Canada did not exceed the present value of our estimated proved reserves.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost. Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method. Major renewals and improvements are recorded as additions to the property and equipment accounts. Repairs that do not improve or extend the useful lives of assets are expensed.
Assets Held for Sale
As discussed in Note 4, “Divestiture of Non-Core Properties,” during the fourth quarter of 2009 and throughout 2010, the Company sold certain properties, principally non-operated, non-core assets, to generate cash for debt repayment and to accelerate our drilling program. The Company's assets sold late in 2010 are presented separately as "Assets held for sale" in the consolidated balance sheet at December 31, 2010, in accordance with ASC 360. Assets held for sale were recorded at the amount of the sales proceeds with a corresponding reduction to the full cost pool in accordance with full cost accounting rules. Proceeds from this sale were received on February 1, 2011.
Estimates of Proved Oil and Gas Reserves
Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:
· the quality and quantity of available data;
· the interpretation of that data;
· the accuracy of various mandated economic assumptions; and
· the judgment of the persons preparing the estimate.
Our proved reserve information included in this report was predominately based on studies performed by the operations department of Abraxas and estimated by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may cause material revisions to the estimate.
In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas prices based on the average 12 month first-day-of-month pricing for the years ended December 31, 2010 and 2011, and costs as of December 31, 2010 and 2011. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.
The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields.
Derivative Instruments and Hedging Activities
The Company enters into agreements to hedge the risk of future oil and gas price fluctuations. Such agreements are in the form of fixed price swaps, which limit the impact of price fluctuations with respect to the Company's sale of oil and gas. The Company does not enter into speculative hedges.
The Company accounts for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for hedge accounting rules as prescribed by ASC 815. Accordingly, we do not account for our derivative instruments as cash flow hedges for financial reporting purposes and instead record their fair value on the balance sheet with adjustments to the carrying value of the instruments being recognized as a gain or loss in the current period.
Fair Value of Financial Instruments
The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value. The carrying value of those financial instruments that are classified as current approximates fair value because of the short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.
Share-Based Payments
The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. Options granted are valued at the date of grant and expense is recognized over the vesting period. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period. For the years ended December 31, 2009, 2010 and 2011, stock-based compensation was approximately $1.2 million, $1.6 million and $2.0 million, respectively. For additional information regarding share-based payments, refer to Note 7, “Stock-based Compensation, Option Plans and Warrants.”
Restoration, Removal and Environmental Liabilities
The Company is subject to extensive Federal, provincial, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.
The Company accounts for asset retirement obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements.
The following table summarizes the Company's asset retirement obligations during the three years ended December 31:
| | | 2009 | | | 2010 | | | 2011 | |
| | | (In thousands) | |
Beginning asset retirement obligation | | $ | 9,959 | | | $ | 10,326 | | | $ | 7,734 | |
New wells placed on production and other | | | 91 | | | | 64 | | | | 318 | |
Deletions related to property disposals and plugging costs | | | (282 | ) | | | (3,172 | ) | | | (92 | ) |
Accretion expense | | | 558 | | | | 516 | | | | 452 | |
Ending asset retirement obligation | | $ | 10,326 | | | $ | 7,734 | | | $ | 8,412 | |
Revenue Recognition and Major Purchasers
The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties. The Company utilizes the sales method to account for gas production imbalances. Under this method, income is recorded based on the Company's net revenue interest in production taken for delivery. The Company had no material gas imbalances at December 31, 2009, 2010 and 2011.
During 2009 and 2010, two purchasers accounted for 22% and 21% of oil and gas revenues, respectively. During 2011, three purchasers accounted for 28% of oil and gas revenues.
Deferred Financing Fees
Deferred financing fees are being amortized on the effective yield basis over the term of the related debt arrangements.
Income Taxes
The Company records deferred income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect to taxable income in the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10. Therefore, we have established a valuation allowance of $83.5 million for deferred tax assets at December 31, 2011.
Accounting for Uncertainty in Income Taxes
ASC 740 provides guidance on accounting for uncertainty in income taxes. ASC 740 is intended to clarify the accounting for uncertainty in income taxes recognized in a company's financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. ASC 740 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
Under ASC 740, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.
Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense.
Other Comprehensive Income (Loss)
ASC 220 requires disclosure of comprehensive income (loss), which includes reported net income (loss) as adjusted for other comprehensive income (loss). Comprehensive income (loss) for the Company is the change in the unrealized value of investments and foreign currency translation adjustments.
New Accounting Pronouncements
In 2010, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) to address diversity in practice in interpreting the pro forma revenue and earnings disclosure requirements for business combinations. The ASU specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the current year business combination(s) had occurred as of the beginning of the comparable prior annual reporting period. The adoption of this ASU will have no material impact on our consolidated financial statements.
In 2011, the FASB issued two ASUs which amend guidance for the presentation of comprehensive income. The amended guidance requires an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements. The current option to report other comprehensive income and its components in the statement of stockholders' equity will be eliminated. Although the new guidance changes the presentation of comprehensive income, there are no changes to the components that are recognized in net income or other comprehensive income under existing guidance. These ASUs are effective for us in the first quarter of 2012 and retrospective application will be required. These ASUs will change our financial statement presentation of comprehensive income but will not impact our net income, financial position, or cash flows.
In 2011, the FASB issued an ASU which intended to reduce complexity and costs by allowing an entity the option to make a qualitative evaluation about the likelihood of goodwill impairment to determine whether it should calculate the fair value of a reporting unit. The ASU also expands upon the examples of events and circumstances that an entity should consider between annual impairment tests in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The ASU is effective for us in the first quarter of 2012, with early adoption permitted. The adoption of this ASU will have no impact on our consolidated financial statements.
