UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

COMMISSION FILE NUMBER: 001-16071

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes[ X ]   No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). [ ]Yes[ X ]  No

 

 

The number of shares of the issuer’s common stock outstanding as of August 8, 2008 was:

 

 

 

Forward-Looking Information

We make forward-looking statements throughout this document. Whenever you read a statement that is not simply a statement of historical fact (such as statements including words like “believe”, “expect”, “anticipate”, “intend”, “plan”, “seek”, “estimate”, “could”, “potentially” or similar expressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they are reasonable. The forward-looking information contained in this document is generally located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations as well. These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends. The factors that may affect our expectations regarding our operations include, among others, the following:

In addition to these factors, important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the Cautionary Statements. 

 

 

ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX  

 

 

                 PART 1

FINANCIAL INFORMATION

 

 

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets

(in thousands)  

See accompanying notes to condensed consolidated financial statements (unaudited)

 

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets (continued)

(in thousands)

See accompanying notes to condensed consolidated financial statements (unaudited)

 

 

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Operations

(Unaudited)

(in thousands except per share data)  

See accompanying notes to condensed consolidated financial statements (unaudited)

 

 

                Abraxas Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands) 

 

See accompanying notes to condensed consolidated financial statements (unaudited)

 

 

Abraxas Petroleum Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(tabular amounts in thousands, except per share data) Note 1. Basis of Presentation  The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K filed for the year ended December 31, 2007. Such policies have been continued without change, except for the adoption of SFAS No. 157. Also, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations, and cash flows. All the material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. The accompanying interim consolidated financial statements have not been audited by independent registered public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. The results of operations for the three and six months ended June 30, 2008 are not necessarily indicative of results to be expected for the full year.

The terms “Abraxas” or “Abraxas Petroleum” refer to Abraxas Petroleum Corporation and its subsidiaries other than Abraxas Energy Partners, L.P., which we refer to as “Abraxas Energy Partners” or the “Partnership”, and its subsidiary, Abraxas Operating, LLC, which we refer to as “Abraxas Operating” and the terms “we”, “us”, “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its consolidated subsidiaries including Abraxas Energy Partners and Abraxas Operating effective May 25, 2007. The operations of Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes with the interest of the 52.8% minority owners of the Partnership presented as minority interest. Abraxas owns the remaining 47.2% of the partnership interests. The Company has determined that based on its control of the general partner of the Partnership, this 47.2% owned entity should be consolidated for financial reporting purposes.

 

The condensed consolidated financial statements included herein have been prepared by Abraxas and are unaudited, except for the balance sheet at December 31, 2007, which has been derived from the audited consolidated financial statements at that date. In the opinion of management, the unaudited condensed consolidated financial statements include all recurring adjustments necessary for a fair presentation of the financial position as of June 30, 2008 and 2007, and the cash flows for each of the six-month periods ended June 30, 2008 and 2007. Although management believes the unaudited interim related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations and the cash flows for the six-month period ended June 30, 2008 are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

 

Use of Estimates

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

Stock-based Compensation

 

 

The Company currently utilizes a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees. The Company uses the Black-Scholes model for option valuation as of the current time.

The following table summarizes the stock option activities for the six months ended June 30, 2008.

 

The following table shows the weighted average assumptions used in the Black-Scholes valuation of the fair value of option grants during 2008.

 

 

 Additional information related to options at June 30, 2008 and December 31, 2007 is as follows:

                 

 

As of June 30, 2008, there was approximately $1.3 million of unamortized compensation expense related to outstanding options that will be recognized through the period ended June 2012.

 

Recently Issued Accounting Pronouncements

Fair Value Measurements (SFAS No. 157) —In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The FASB agreed to defer the effective date of Statement 157 for one year for nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. There is no deferral for financial assets and financial liabilities. We adopted SFAS No. 157 effective January 1, 2008. We are evaluating the remaining impact of SFAS No. 157 on our consolidated financial statements and do not expect the impact of implementation to be material.

The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (SFAS No. 159) —In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and

 

 

certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement is effective for fiscal years beginning after November 15, 2007. We did not elect to measure any financial instruments or any other items at fair value as permitted by FAS 159 and consequently, the adoption of FAS 159 did not have a material effect on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Enhanced disclosures to improve financial reporting transparency are required and include disclosure about the location and amounts of derivative instruments in the financial statements, how derivative instruments are accounted for and how derivatives affect an entity’s financial position, financial performance and cash flows. A tabular format including the fair value of derivative instruments and their gains and losses, disclosure about credit risk-related derivative features and cross-referencing within the footnotes are also new requirements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application and comparative disclosures encouraged, but not required. We have not yet adopted SFAS No. 161. We do not believe that SFAS No. 161 will have a material impact on our financial position, results of operations or cash flows.

 

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” The statement is intended to improve financial reporting by identifying a consistent hierarchy for selecting accounting principles to be used in preparing financial statements that are prepared in conformance with generally accepted accounting principles. Unlike Statement on Auditing Standards (SAS) No. 69, “The Meaning of Present in Conformity With GAAP,” FAS No. 162 is directed to the entity rather than the auditor. The statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (PCAOB) amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with GAAP,” and is not expected to have any impact on the Company’s results of operations, financial condition or liquidity.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin (ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest (previously commonly referred to as a minority interest) in a subsidiary is an ownership interest in the consolidated entity and should be reported as equity in the consolidated financial statements. The presentation of the consolidated income statement has been changed by SFAS No. 160, and consolidated net income attributable to both the parent and the noncontrolling interest is now required to be reported separately. Previously, net income attributable to the noncontrolling interest was typically reported as an expense or other deduction in arriving at consolidated net income and was often combined with other financial statement amounts. In addition, the ownership interests in subsidiaries held by parties other than the parent must be clearly identified, labeled, and presented in the equity in the consolidated financial statements separately from the parent’s equity. Subsequent changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary should be accounted for consistently, and when a subsidiary is deconsolidated, any retained noncontrolling equity interest in the former subsidiary must be initially measured at fair value. Expanded disclosures, including a reconciliation of equity balances of the parent and noncontrolling interest, are also required. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Prospective application is required. Due to our investment in Abraxas Energy Partners, the adoption of SFAS No. 160 could have a material impact on our financial position and results of operations, however we do not believe that it will have a material impact on our cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the

 

 

acquisition. SFAS No. 141(R) also impacts the annual goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141(R). The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We cannot predict the impact that the adoption of SFAS No. 141(R) will have on our financial position, results of operations or cash flows with respect to any acquisitions completed after December 31, 2008.

 

Note 2. Income taxes The Company records income taxes using the asset and liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.

 

For the six-month period ended June 30, 2008, there is no current or deferred income tax expense or benefit due to losses and/or loss carryforwards and valuation allowance which has been recorded against such benefits.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is an interpretation of SFAS 109, “Accounting for Income Taxes”, and it seeks to reduce the diversity in practice associated with certain aspects of measurement and accounting for income taxes and requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. Accordingly, the Company adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have any effect on the Company’s financial position or results of operations for the quarter ended March 31, 2008. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2008, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 1999 through 2007 remain open to examination by the tax jurisdictions to which the Company is subject. Note 3. Long-Term Debt

Long-term debt consisted of the following:

 

Senior Secured Credit Facility. On June 27, 2007, Abraxas entered into a new senior secured revolving credit facility, which we refer to as the Credit Facility. The Credit Facility has a maximum commitment of $50 million. Availability under the Credit Facility is subject to a borrowing base. The borrowing base under the Credit Facility, which is $6.5 million as of June 30, 2008, is determined semi-annually by the lenders based upon our reserve reports, one of which must be materially prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we may also request one redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our current borrowing base. Our borrowing base at June 30, 2008 of $6.5 million was determined based upon our reserves at December 31, 2006 after giving effect to the contribution of properties to the Partnership in May 2007. There is no outstanding balance on this facility as of June 30, 2008. Our borrowing base can never exceed the $50.0 million

 

 

maximum commitment amount. Outstanding amounts under the Credit Facility will bear interest at (a) the greater of reference rate announced from time to time by Société Générale, and (b) the Federal Funds Rate plus ½ of 1%, plus in each case, (c) 0.5% - 1.5% depending on utilization of the borrowing base, or, if Abraxas elects, at the London Interbank Offered Rate plus 1.5% - 2.5%, depending on the utilization of the borrowing base. Subject to earlier termination rights and events of default, the Credit Facility’s stated maturity date will be June 27, 2011. Interest will be payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances.

Abraxas is permitted to terminate the Credit Facility, and may, from time to time, permanently reduce the lenders’ aggregate commitment under the Credit Facility in compliance with certain notice and dollar increment requirements.

Each of Abraxas’ subsidiaries other than the Partnership, Abraxas General Partner, LLC and Abraxas Energy Investments, LLC has guaranteed Abraxas’ obligations under the Credit Facility on a senior secured basis. Obligations under the Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of Abraxas’ and the subsidiary guarantors’ material property and assets.

Under the Credit Facility, Abraxas is subject to customary covenants, including certain financial covenants and reporting requirements. The Credit Facility requires Abraxas to maintain a minimum current ratio as of the last day of each quarter of not less than 1.00 to 1.00 (current assets to current liabilities) and an interest coverage ratio (generally defined as the ratio of consolidated EBITDA to consolidated interest expense as of the last day of such quarter) of not less than 2.50 to 1.00.

In addition to the foregoing and other customary covenants, the Credit Facility contains a number of covenants that, among other things, will restrict Abraxas’ ability to: 

The Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

Amended and Restated Partnership Credit Facility. On May 25, 2007, the Partnership entered into a senior secured revolving credit facility which was amended and restated on January 31, 2008, which we refer to as the Partnership Credit Facility. The Partnership Credit Facility has a maximum commitment of $300.0 million. Availability under the Partnership Credit Facility is subject to a borrowing base. The borrowing base under the Partnership Credit Facility, which is currently $140.0 million, is determined semi-annually by the lenders based upon the Partnership’s reserve reports, one of which must be materially prepared by the Partnership’s independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Partnership’s proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of the Partnership’s current borrowing base. The Partnership’s borrowing base at June 30, 2008 of $140.0 million was determined based upon its reserves at December 31, 2007 which included the reserves attributable to the oil and gas properties acquired from St. Mary Land & Exploration Company on January 31, 2008. The borrowing base can never exceed the $300 million maximum commitment amount. Outstanding amounts under the Partnership Credit Facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale and (2) the Federal Funds Rate plus 0.5%, plus in each case (b) .25% - 1.00%, depending on the utilization of the borrowing base or, if the Partnership elects, at the London Interbank Offered Rate plus 1.25% - 2.00%, depending on the utilization of the borrowing base. Subject to

 

 

earlier termination rights and events of default, the Partnership Credit Facility’s stated maturity date is January 31, 2013. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Partnership Credit Facility, and under certain circumstances, may be required, from time to time, to permanently reduce the lenders’ aggregate commitment under the Partnership Credit Facility. As of June 30, 2008, $115.6 million is outstanding under this facility, with $24.4 million available.

Each of the general partner of the Partnership, Abraxas General Partner, LLC, which is a wholly-owned subsidiary of Abraxas and which we refer to as the GP, and Abraxas Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which we refer to as the Operating Company, has guaranteed the Partnership’s obligations under the Credit Facility on a senior secured basis. Obligations under the Partnership Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the material property and assets of the GP, the Partnership and the Operating Company, other than the GP’s general partner units in the Partnership.

Under the Partnership Credit Facility, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Partnership Credit Facility requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.0 to 1.0 and an interest coverage ratio (defined as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of each quarter of not less than 2.50 to 1.00. The Partnership Credit Facility required it to enter into hedging arrangements for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the St. Mary properties). The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from our estimated net proved developed producing reserves (including the reserves attributable to the St. Mary properties) through December 31, 2011.

Under the terms of the Partnership Credit Facility, the Partnership may make cash distributions if, after giving effect to such distributions, the Partnership is not in default under the Partnership Credit Facility and there is no borrowing base deficiency and provided that no such distribution shall be made using the proceeds of any advance unless the amount of the unused portion of the amount then available under the Partnership Credit Facility is greater than or equal to 10% of the lesser of the Partnership’s borrowing base (which is currently $140.0 million) or the total commitment amount of the Partnership Credit Facility (which is currently $300.0 million) at such time.

In addition to the foregoing and other customary covenants, the Partnership Credit Facility contains a number of covenants that, among other things, will restrict the Partnership’s ability to:

The Partnership Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness including the Subordinated Credit Agreement described below, bankruptcy and material judgments and liabilities.

Subordinated Credit Agreement

On January 31, 2008, the Partnership entered into a subordinated credit agreement which we refer to as the Subordinated Credit Agreement. The Subordinated Credit Agreement has a maximum commitment of $50 million, all of which was borrowed at closing and remains outstanding as of June 30, 2008. Outstanding amounts under the Subordinated Credit Agreement bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, and (2) the Federal Funds Rate plus 0.5%, plus in each case, (b) 4.00% to 5.50% depending on the applicable date, or, if we elect, at the London

 

 

Interbank Offered Rate plus 5.00% to 6.50%, depending on the applicable date. The rates for the applicable dates are as follows:

At June 30, 2008, the interest rate on the facility was 8.2%. Subject to earlier termination rights and events of default, the Subordinated Credit Agreement’s stated maturity date is January 31, 2009. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Subordinated Credit Agreement, and under certain circumstances, may be required, from time to time, to make prepayments under the Subordinated Credit Agreement.

Each of the GP and Abraxas Operating has guaranteed the Partnership’s obligations under the Subordinated Credit Agreement on a subordinated secured basis. Obligations under the Subordinated Credit Agreement are secured by subordinated security interests, subject to certain permitted encumbrances, in all of the material property and assets of the Partnership, GP, and Abraxas, other than the GP’s general partner units in the Partnership.

Under the Subordinated Credit Agreement, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Subordinated Credit Agreement requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.0 to 1.0 and an interest coverage ratio (defined as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of each quarter of not less than 2.50 to 1.00. The Partnership Credit Facility required it to enter into hedging arrangements for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the St. Mary properties). The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from our estimated net proved developed producing reserves (including the reserves attributable to the St. Mary properties) through December 31, 2011.

In addition to the foregoing and other customary covenants, the Subordinated Credit Agreement contains a number of covenants that, among other things, will restrict the Partnership’s ability to:

The Subordinated Credit Agreement also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness including the Credit Facility, bankruptcy and material judgments and liabilities.

Real Estate Lien Note

On May 9, 2008 the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a new building to serve as its corporate headquarters. The note bears interest at a fixed rate of 6.65%. The note is interest only for six months. At the end of six months the note is payable in monthly principal and interest installments, based on a twenty year amortization, until maturity in June 2015 at which time the balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of June 30, 2008 $4.7 million is outstanding on the note.

 

 

Note 4. Earnings (Loss) Per Share The following table sets forth the computation of basic and diluted earnings (loss) per share:

 

 

    For the three and six months ended June 30, 2008 none of the shares issuable in connection with stock options or warrants are included in diluted shares. Inclusion of these shares would be antidilutive due to losses incurred in the periods. Had there not been losses in the periods, dilutive shares would have been 607,610 and 508,958 shares for the three and six months ended June 30, 2008, respectively.

 

Note 5. Hedging Program and Derivatives

 

The Partnership enters into derivative contracts, which we sometimes refer to as hedging agreements, to hedge the risk of future oil and gas price fluctuations. Such agreements are primarily in the form of NYMEX-based fixed price commodity swaps, which limit the impact of price fluctuations with respect to the Partnership’s sale of oil and gas. The Partnership does not enter into speculative hedges.

 

Statement of Financial Accounting Standards, (‘‘SFAS’’) No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended and interpreted, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The Partnership elected not to designate its derivative instruments for hedge accounting as prescribed by SFAS 133. Accordingly, all derivatives will be recorded on the balance sheet at fair value with changes in fair value being recognized in earnings.

 

Under the terms of the Partnership Credit Facility, Abraxas Energy Partners was required to enter into derivative contracts for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011 from its net proved developed producing reserves.

 

The following table sets forth the Partnership’s derivative contract position at June 30, 2008:

 

 

 

 

 

 Note 6. Financial Instruments

 

SFAS 157—Effective January 1, 2008, the Company adopted Financial Accounting Standards Board (“FASB”) Statement No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The implementation of SFAS 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate, which was not material. The primary impact from adoption was additional disclosures.

 

The Company elected to implement SFAS 157 with the one-year deferral permitted by FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”), issued February 2008, which defers the effective date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. As it relates to the Company, the deferral applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and gas property assessments; and the initial recognition of asset retirement obligations for which fair value is used.

 

Fair Value Hierarchy—SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

 

 

 

 

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

 

 

 

 

 

 

The Partnership’s derivative contracts consist of NYMEX-based fixed price commodity swaps which are not traded on a public exchange. These derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity, and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2.

 

Note 7. Minority interest in (income) loss of Partnership

 

          The minority interest in the (income) loss of the Partnership represents the third parties 52.8% interest in the Partnership’s net income/ loss. Additionally, in accordance with generally accepted accounting principles, when cumulative losses applicable to the minority interest exceed the minority interest equity capital in the entity, such excess and any further losses applicable to the minority interest are charged to the earnings of the majority interest. If future earnings are recognized by the minority interest, such earnings will then be credited to the majority interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. During the second quarter of 2008, primarily as a result of unrealized losses on derivative contracts, losses applicable to the minority interest exceeded the minority interest equity capital by $28.2 million and, thus $28.2 million of the minority interest loss in excess of equity was charged to earnings and is reflected as a reduction of the loss applicable to the minority interest.     

 

Note 8. Contingencies - Litigation

 

          From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At June 30, 2008, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its operations.

 

          The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K filed for the year ended December 31, 2007, as amended by our Annual Report on Form 10-K/A Number 1 filed with the Securities and Exchange Commission on August 11, 2008. The terms “Abraxas” or “Abraxas Petroleum” refer to Abraxas Petroleum Corporation and its subsidiaries other than Abraxas Energy Partners, L.P., which we refer to as “Abraxas Energy Partners” or the “Partnership”, and its subsidiary, Abraxas Operating, LLC, which we refer to as “Abraxas Operating” and the terms “we”, “us”, “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its consolidated subsidiaries including Abraxas Energy Partners and Abraxas Operating. The operations of Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes with the interest of the 52.8% minority owners presented as minority interest. Abraxas owns the remaining 47.2% of the partnership interests.  Critical Accounting Policies            There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2007. General

We are an independent energy company primarily engaged in the development and production of natural gas and crude oil. Our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary exploration projects in our core areas of operation. Success in our development and exploration activities is critical to the maintenance and growth of our current production levels and associated reserves.          

Factors Affecting Our Financial Results 

 

While we have attained positive net income for the five years ended December 31, 2007, we sustained a loss in the first half of 2008, primarily due to unrealized losses on derivative contracts, and we cannot assure you that we can achieve positive operating income and net income in the future. Our financial results depend upon many factors, which significantly affect our results of operations including the following: 

 

  Commodity Prices and Hedging Activities.

The results of our operations are highly dependent upon the prices received for our natural gas and crude oil production. The prices we receive for our production are dependent upon spot market prices, price differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of natural gas and crude oil are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our natural gas and crude oil production are dependent upon numerous factors beyond our control. Significant declines in prices for natural gas and crude oil could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis. Recently, the prices of natural gas and crude oil have been volatile. During the first six months of 2008, prices for natural gas and crude oil were sustained at record or near-

 

 

record levels. New York Mercantile Exchange (NYMEX) spot prices for West Texas Intermediate (WTI) crude oil averaged $111.10 per barrel for the six month period ended June 30, 2008. WTI crude oil ended the quarter at $140.00 per barrel. NYMEX Henry Hub spot prices for natural gas averaged $10.02 per million British thermal units (MMBtu) during first six months of 2008 and ended the quarter at $13.16.

The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:

During the first six months of 2008, differentials averaged $3.85 per BOE of crude oil and $1.38 per Mcf of natural gas. We expect to realize greater differentials during the remainder of 2008 because of the increased percentage of our production from the Rocky Mountain and Mid-Continent regions which experience higher differentials than our Texas properties. Under the terms of the Partnership Credit Facility, Abraxas Energy Partners was required to enter into derivative contracts for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011 from its net estimated proved developed producing reserves (including the reserves attributable to the properties acquired from St. Mary). The Partnership intends to enter into derivative contracts in the future to reduce the impact of price volatility on its cash flow. By removing a significant portion of price volatility on its future oil and gas production, the Partnership believes it will mitigate, but not eliminate, the potential effects of changing commodity gas prices on its cash flow from operations for those periods. However, because the prices at which we have hedged our oil and gas production are significantly less than current, historically high commodity prices, we will not realize increased cash flow on the portion of our production that we have hedged as a result of these high prices and we will sustain realized and unrealized losses on our derivative contracts. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules.

 

The following table sets forth the Partnership’s derivative contract position at June 30, 2008:

 

At June 30, 2008, the aggregate fair market value of our derivative contracts was approximately $(106.1) million.

Production Volumes. Because our proved reserves will decline as natural gas and crude oil are produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Approximately 90% of the estimated ultimate recovery of Abraxas’ and 91% of the Partnership’s, or 91% of our consolidated proved developed producing reserves as of December 31, 2007 had been produced. Based on the reserve information set forth in our reserve report of December 31, 2007, Abraxas’ average annual estimated decline rate for its net proved developed producing reserves is 9% during the first five years, 6% in the next five years, and approximately 5% thereafter. Based on the reserve information set forth in our reserve report of December 31, 2007, the Partnership’s average annual estimated decline rate for its net proved developed producing reserves is 12% during the first five years, 9% in the next five years and approximately 9% thereafter. These rates of decline are estimates and actual production declines could

 

 

be materially higher. While Abraxas has had some success in finding, acquiring and developing additional reserves, Abraxas has not always been able to fully replace the production volumes lost from natural field declines and prior property sales. For example, in 2006, Abraxas replaced only 7% of the reserves it produced. In 2007, however, we replaced 219% of the reserves we produced. Our ability to acquire or find additional reserves in the near future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.

We had capital expenditures of $155.5 million during the six months of 2008, including $133.2 million for the St. Mary property acquisition that closed in January, 2008, and have a capital budget for 2008 of approximately $55 million, above the St. Mary acquisition, of which $35 million is applicable to Abraxas and $20 million applicable to the Partnership. The final amount of our capital expenditures for 2008 will depend on our success rate, production levels, the availability of capital and commodity prices.

Availability of Capital. As described more fully under “Liquidity and Capital Resources” below, Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under the Credit Facility, cash on hand, distributions from the Partnership and if an appropriate opportunity presents itself, proceeds from the sale of properties. Abraxas Energy Partners’ principal sources of capital will be cash from operating activities, borrowings under the Partnership Credit Facility, and sales of debt or equity securities if available to it. At June 30, 2008, Abraxas had approximately $6.5 million of availability under the Credit Facility. Upon the closing of the acquisition of properties from St. Mary, the Partnership borrowed $115.6 million under the Partnership Credit Facility and $50 million under the Subordinate Credit Agreement. Upon the completion of this transaction in January 2008, the Partnership had $24.4 million available under the Partnership Credit Facility.

Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. Our properties are concentrated in locations that facilitate substantial economies of scale in drilling and production operations and more efficient reservoir management practices. At December 31, 2007 we operated 95% of the properties accounting for approximately 95% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenses.

Our future natural gas and crude oil production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our natural gas and crude oil properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. In 2006, for example, Abraxas replaced only 7% of the reserves it produced. In 2007, however, we replaced 219% of our reserves. If our proved reserves decline in the future, our production will also decline and, consequently, our cash flow from operations, distributions of available cash from the Partnership to Abraxas and the amount that Abraxas is able to borrow under its credit facility and that the Partnership will be able to borrow under its credit facility will also decline. In addition, approximately 69% of Abraxas’ and 56% of the Partnership’s estimated proved reserves at December 31, 2007 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected.

Borrowings and Interest. Abraxas Energy Partners has indebtedness of approximately $115.6 under the Amended Partnership Credit Facility and $50 million under the Subordinated Credit Agreement at June 30, 2008. The Partnership has $24.4 million available under the Partnership Credit Facility. Abraxas has availability of $6.5 million under its $50 million Credit Facility. There is currently no outstanding balance under this facility. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our numerous drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices. 

Results of Operations

 

 

The following table sets forth certain of our operating data for the periods presented. The operating data represents the consolidated data for Abraxas Petroleum and Abraxas Energy Partners L.P.

Comparison of Three Months Ended June 30, 2008 to Three Months Ended June 30, 2007

          Operating Revenue. During the three months ended June 30, 2008, operating revenue from natural gas and crude oil sales increased to $34.1 million compared to $12.7 million in the three months ended June 30, 2007. The increase in revenue was due to higher realized prices as well as an increase in production volumes. Increased commodity prices contributed $14.0 million to revenue while increased production volumes contributed $7.5 million for the quarter ended June 30, 2008.

 

Crude oil production volumes increased from 49.2 MBbls during the quarter ended June 30, 2007 to 147.6 MBbls for the same period of 2008. The increase in crude oil sales volumes was primarily due to production from properties acquired in the St. Mary acquisition that closed on January 31, 2008. Production for the quarter ended June 30, 2008 from these properties added 96.5 MBbls of crude oil. Natural gas production volumes increased from 1,474 MMcf for the three months ended June 30, 2007 to 1,698 MMcf for the same period of 2008. The properties acquired in the St. Mary acquisition contributed 440.6 MMcf of natural gas production during the quarter, which was partially offset by natural field declines.

 

Average sales prices, before realized losses on derivative contracts, for the quarter ended June 30, 2008 were:     Average sales prices, before realized losses on derivative contracts, for the quarter ended June 30, 2007 were:         Lease Operating Expenses (“LOE”). LOE for the three months ended June 30, 2008 increased to $7.2 million from $3.1 million for the same period in 2007. LOE related to the properties acquired in the St. Mary property acquisition added $4.0 million to LOE during the quarter. LOE on a per BOE basis for the three months ended June 30, 2008 was $16.65 per BOE compared to $10.39 for the same period of 2007. The increase in per BOE cost was attributable to the increase in the number of crude oil wells as a result of the St. Mary acquisition, which are generally more expensive to operate than natural gas wells, as well as the overall increase in costs.  

 

General and Administrative Expenses (“G&A”). G&A expenses excluding stock-based compensation increased to $1.2 million for the quarter ended June 30, 2008 from $895,000 for the same period of 2007. The increase in G&A was primarily due to higher personnel expenses associated with additional staff added to manage the properties acquired from St. Mary. G&A expense on a per BOE basis was $2.84 for the quarter ended June 30, 2008 compared to $3.04 for the same period of 2007. The decrease in G&A expense on a per BOE basis was primarily due to increased production volumes in the first quarter of 2008 compared to the same period in 2007.

 

        Stock-based Compensation. We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. For the quarters ended June 30, 2008 and 2007, stock based compensation was approximately $650,000 and $372,000, respectively. The increase in 2008 as compared to 2007 is due to the grant on options and restricted stock in the third quarter of 2007 as well as grants to new employees hired as a result of the St. Mary acquisition.

      Depreciation, Depletion and Amortization Expenses (“DD&A”). DD&A expense increased to $6.0 million for the three months ended June 30, 2008 as compared to $3.6 million for the three months ended June 30, 2007. The increase in DD&A is primarily the result of increased production as well as an increase in the depletion base as a result of the St. Mary acquisition. Our DD&A on a per BOE basis for the three months ended June 30, 2008 was $13.95 per BOE compared to $11.38 per BOE in 2007. The increase in the per BOE DD&A was due to the higher depletion base for the period.

       

     Interest Expense. Interest expense decreased to $2.7 million for the second quarter of 2008 compared to $2.8 million for the same period of 2007. The decrease in interest expense was primarily due to lower interest rates during the second quarter of 2008 as compared to 2007. The interest rate on our senior notes, which were redeemed in May 2007, was 12.5% for the three months ended June 30, 2007. The interest rates on the Partnerships Credit Agreement averaged approximately 4.8% and the interest rate on the Subordinated Credit Facility averaged approximately 8.0% for the quarter ended June 30, 2008.

    

      Loss on debt extinguishments. The loss on debt extinguishment in 2007 consists primarily of the call premium and interest that was paid in connection with the refinancing and redemption of our senior secured notes.

 

         Income taxes. Federal income tax and state of Texas margin tax have been recognized for the quarter ended June 30, 2007 as a result of the gain on the sale of assets during the period. No deferred income tax expense or benefit has been recognized due to losses or loss carryforwards and valuation allowance, which has been recorded against such benefits.       

 

    Gain on sale of assets. Abraxas Petroleum recognized a gain of $59.3 million on the sale of assets in 2007. This gain was calculated based on the requirements of Staff Accounting Bulletin 51, (Topic 5H) based on the fact that the Company elected gain treatment as a policy and the transaction met the following criteria: (1) there were no additional broad corporate reorganizations contemplated; (2) there was not a reason to believe that the gain would not be realized, since there is no additional capital raising transaction anticipated nor was there a significant concern about the new entity’s ability to continue in existence; (3) the share price of capital raised in the private placement was objectively determined; (4) no repurchases of the new subsidiary’s units are planned; and (5) the Company acknowledges that it will consistently apply the policy, and any future transactions that might result in a loss must be recorded as a loss in the income statement.

 

Income (loss) from derivative contracts. We account 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. Our derivative contract transactions are not designated for hedge

 

 

accounting as prescribed by SFAS 133; therefore, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. Abraxas Energy Partners has entered into a series of NYMEX–based fixed price commodity swaps, the estimated unearned value of these derivative contracts is approximately $(106.1) million as of June 30, 2008. For the quarter ended June 30, 2008, we realized a loss on these derivative contracts of $6.6 million. For the quarter ended June 30, 2008, we incurred unrealized losses on derivative contracts in place of $74.5 million. 

          Minority interest. Minority interest represents the share of the net income (loss) of Abraxas Energy Partners for the quarter owned by the partners other than Abraxas Petroleum. Additionally, in accordance with generally accepted accounting principles, when cumulative losses applicable to the minority interest exceed the minority interest equity capital in the entity, such excess and any further losses applicable to the minority interest are charged to the earnings of the majority interest. If future earnings are recognized by the minority interest, such earnings will then be credited to the majority interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. During the second quarter of 2008, primarily as a result of unrealized losses on derivative contracts, losses applicable to the minority interest exceeded the minority interest equity capital by $28.2 million and, thus $28.2 million of the minority interest loss in excess of equity was charged to earnings and is reflected as a reduction of the losses, realized and unrealized, applicable to the minority interest.             

 

Comparison of Six Months Ended June 30, 2008 to Six Months Ended June 30, 2007

 

          Operating Revenue. During the six months ended June 30, 2008, operating revenue from natural gas and crude oil sales increased to $55.9 million compared to $24.2 million in the six months ended June 30, 2007. The increase in revenue was due to higher commodity prices as well as increased production volumes. Higher commodity prices contributed $20.5 million to revenue for the six months ended June 31, 2008, while increased production volumes contributed $11.2 million to oil and gas revenue.

 

Crude oil production volumes increased from 99.3 MBbls during the six months ended June 30, 2007 to 263.6 MBbls for the same period of 2008. The increase in crude oil sales volumes was primarily due to production from properties acquired in the St. Mary acquisition that closed on January 31, 2008. Production for the months of February through June 2008 from these properties added 161.1MBbls of crude oil. Natural gas production increased to 3,203 MMcf for the six months ended June 30, 2008 from 2,925 MMcf for the same period of 2007. The properties acquired in the St. Mary acquisition contributed 793 MMcf of natural gas production during the period, which was partially offset by natural field declines.   Average sales prices, before the realized losses on derivative contracts, for the six months ended June 30, 2008 were:     Average sales prices, before realized losses on derivative contracts, for the six months ended June 30, 2007 were:  

 

    Lease Operating Expenses. LOE for the six months ended June 30, 2008 increased to $12.4 million from $6.0 million for the same period in 2007. LOE related to the properties acquired in the St. Mary property acquisition added $6.3 million to LOE during the period ended June 30, 2008. LOE on a per BOE basis for the six months ended June 30, 2008 was $15.51 per BOE compared to $10.27 for the same period of 2007. The increase in per BOE cost was attributable to the increase in the number of crude oil wells as a result of the St. Mary acquisition, which are generally more expensive to operate than natural gas wells, as well as an overall increase in costs.

   

 

          General and Administrative Expenses. G&A expenses, excluding stock-based compensation expense, increased from $2.0 million for the first six months of 2007 to $2.8 million for the same period of 2008. The increase in G&A was primarily due to higher personnel expenses associated with additional staff added to manage the properties acquired from St. Mary. G&A expense on a per BOE basis was $3.48 for the six months ended June 30, 2008 compared to $3.47 for the same period of 2007. The increase in G&A expense on a per BOE basis was primarily due higher G&A expense, offset by increased production volumes in 2008 compared to the same period in 2007.    

          Stock-based Compensation. We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. For the six months ended June 30, 2008 and 2007, stock based compensation was approximately $896,000 and $544,000, respectively. The increase in 2008 as compared to 2007 is due to the grant on options and restricted stock in the third quarter of 2007 as well as grants to new employees hired as a result of the St. Mary acquisition.

 

       Depreciation, Depletion and Amortization Expenses. DD&A expense increased to $11.1 million for the six months ended June 30, 2008 from $7.3 million for the same period of 2007. The increase in DD&A is primarily the result of increased production, as well as an increase in the depletion base as a result of the St. Mary acquisition. Our DD&A on a per BOE basis for the six months ended June 30, 2008 was $13.92 per BOE compared to $11.51 per BOE in 2007. The increase in the per BOE DD&A was due to the higher depletion base for the period.

    

      Interest Expense. Interest expense decreased to $5.1 million for the six months ended June 30, 2008 compared to $6.9 million for the same period of 2007. The decrease in interest expense was primarily due to lower interest rates during the six months ended June 30, 2008 as compared to 2007. The interest rate on our senior notes, which were redeemed in May 2007, was 12.5% for the six months ended June 30, 2007. The interest rates on the Partnerships Credit Ffacility averaged approximately 5.4% and the interest rate on the Subordinated Credit Agreement averaged approximately 8.5% for the six months ended June 30, 2008.

        

        Loss on debt extinguishments. The loss on extinguishment for the six months ended June 30, 2007 consists primarily of the call premium and interest that was paid in connection with the retirement of our senior secured notes.

 

        Income taxes. Federal income tax and Texas state margin tax have been recognized for the six months period ended June 30, 2007 as a result of the gain on the sale of assets during the period. No deferred income tax expense or benefit has been recognized due to losses or loss carryforwards and valuation allowance, which has been recorded against such benefits.

  

        Gain on sale of assets. Abraxas Petroleum recognized a gain of $59.3 million on the sale of assets in 2007. This gain was calculated based on the requirements of Staff Accounting Bulletin 51, in which a gain on sale of consolidated subsidiary stock can be recognized if certain criteria are met, (Topic 5H) based on the fact that the Company elected gain treatment as a policy and the transaction met the following criteria: (1) there were no additional broad corporate reorganizations contemplated; (2) there was not a reason to believe that the gain would not be realized, since there is no additional capital raising transaction anticipated nor was there a significant concern about the new entity’s ability to continue in existence; (3) the share price of capital raised in the private placement was objectively determined; (4) no repurchases of the new subsidiary’s units are planned; and (5) the Company acknowledges that it will consistently apply the policy, and any future transactions that might result in a loss must be recorded as a loss in the income statement.

 

Income (loss) from derivative contracts. We account 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. Our derivative contract transactions do not qualify for hedge accounting as prescribed by SFAS 133; therefore, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. Abraxas Energy Partners has entered into a series of NYMEX–based fixed price commodity swaps, the estimated unearned value of these derivative contracts is approximately $(106.1) million as of June 30, 2008. For the six months ended June 30, 2008, we realized a loss on these derivative contracts of $7.5 million. For the six months ended June 30, 2008 we incurred unrealized losses on derivative contracts in place of $100.6 million.  

          Minority interest. Minority interest represents the share of the net income (loss) of Abraxas Energy Partners for the quarter owned by the partners other than Abraxas Petroleum. Additionally, in accordance with generally accepted accounting principles, when cumulative losses applicable to the minority interest exceed the minority interest equity capital in the entity, such excess and any further losses applicable to the minority interest are charged to the earnings of the majority interest. If future earnings are recognized by the minority interest, such earnings will then be credited to the majority interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. During the second quarter of 2008, primarily as a result of unrealized losses on derivative contracts, losses applicable to the minority interest exceeded the minority interest equity capital by $28.2 million and, thus $28.2 million of the minority interest loss in excess of equity was charged to earnings and is reflected as a reduction of the loss applicable to the minority interest.               

 

Recently Issued Accounting Pronouncements

Fair Value Measurements (SFAS No. 157) —In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The FASB agreed to defer the effective date of Statement 157 for one year for nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. There is no deferral for financial assets and financial liabilities. . We adopted SFAS No. 157 effective January 1, 2008. We are evaluating the remaining impact of SFAS No. 157 on our consolidated financial statements and do not expect the impact of implementation to be material.

The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (SFAS No. 159) —In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement is effective for fiscal years beginning after November 15, 2007. We did not elect to measure any financial instruments or any other items at fair value as permitted by FAS 159 and consequently, the adoption of FAS 159 did not have a material effect on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Enhanced disclosures to improve financial reporting transparency are required and include disclosure about the location and amounts of derivative instruments in the financial statements, how derivative instruments are accounted for and how derivatives affect an entity’s financial position, financial performance and cash flows. A tabular format including the fair value of derivative instruments and their gains and losses, disclosure about credit risk-related derivative features and cross-referencing within the footnotes are also new requirements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application and comparative

 

 

disclosures encouraged, but not required. We have not yet adopted SFAS No. 161. We do not believe that SFAS No. 161 will have a material impact on our financial position, results of operations or cash flows.

 

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” The statement is intended to improve financial reporting by identifying a consistent hierarchy for selecting accounting principles to be used in preparing financial statements that are prepared in conformance with generally accepted accounting principles. Unlike Statement on Auditing Standards (SAS) No. 69, “The Meaning of Present in Conformity With GAAP,” FAS No. 162 is directed to the entity rather than the auditor. The statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (PCAOB) amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with GAAP,” and is not expected to have any impact on the Company’s results of operations, financial condition or liquidity.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin (ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest (previously commonly referred to as a minority interest) in a subsidiary is an ownership interest in the consolidated entity and should be reported as equity in the consolidated financial statements. The presentation of the consolidated income statement has been changed by SFAS No. 160, and consolidated net income attributable to both the parent and the noncontrolling interest is now required to be reported separately. Previously, net income attributable to the noncontrolling interest was typically reported as an expense or other deduction in arriving at consolidated net income and was often combined with other financial statement amounts. In addition, the ownership interests in subsidiaries held by parties other than the parent must be clearly identified, labeled, and presented in the equity in the consolidated financial statements separately from the parent’s equity. Subsequent changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary should be accounted for consistently, and when a subsidiary is deconsolidated, any retained noncontrolling equity interest in the former subsidiary must be initially measured at fair value. Expanded disclosures, including a reconciliation of equity balances of the parent and noncontrolling interest, are also required. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Prospective application is required. Due to our investment in Abraxas Energy Partners, the adoption of SFAS No. 160 could have a material impact on our financial position and results of operations, however we do not believe that it will have a material impact on our cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141(R). The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We cannot predict the impact that the adoption of SFAS No. 141(R) will have on our financial position, results of operations or cash flows with respect to any acquisitions completed after December 31, 2008.

 

Liquidity and Capital Resources  General. The natural gas and crude oil industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following costs:

 

 

 

The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our debt obligations and to continue to grow the business through the development of existing properties and the acquisition of new properties.

Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under its credit facility, cash on hand, and if an appropriate opportunity presents itself, proceeds from the sale of properties. We may also seek equity capital although we may not be able to complete any equity financings on terms acceptable to us, if at all. The Partnership’s principal sources of capital will be cash from operating activities, borrowings under the Partnership Credit Facility and sales of debt or equity securities if available to it.

Working Capital (Deficit). At June 30, 2008, our current liabilities of approximately $113.0 million exceeded our current assets of $33.2 million resulting in a working capital deficit of $79.8 million. This compares to a working capital of approximately $11.3 million at December 31, 2007. Current liabilities at June 30, 2008 consisted of current portion of long-term debt consisting of $50.0 million outstanding under the Partnership’s Subordinated Credit Agreement, the current portion of derivative liability of $42.0 million, trade payables of $8.7 million, revenues due third parties of $8.5 million, accrued interest of $1.0 million and other accrued liabilities of $2.9 million. The Partnership intends to repay its indebtedness under the Subordinated Credit Agreement with proceeds from its initial public offering (“IPO”) later this year. In the event that the IPO has not been completed in this time frame, or is not successful, the Partnership will enter into discussions with the lending institutions to either extend or refinance the $50.0 million in debt under its Subordinated Credit Agreement, due January 31, 2009. There can be no assurance that the Partnership will be successful in such negotiations.

 

Capital expenditures. Capital expenditures during the first six months of 2008 were $155.5 million compared to $8.8 million during the same period of 2007. The table below sets forth the components of these capital expenditures on a historical basis for the six months ended June 30, 2008 and 2007.

 

      

During the six months ended June 30, 2008, capital expenditures were primarily for the acquisition of properties from St. Mary, the development of our existing properties and the acquisition of an office building for our corporate headquarters. For the first six months of 2007, capital expenditures were primarily for the development of existing properties. We anticipate making capital expenditures of $55 million in 2008, excluding the cost of the St. Mary acquisition. The Partnership anticipates making capital expenditures for 2008 of $20 million which will be used primarily for the development of its current properties. These anticipated expenditures are subject to adequate cash flow from operations, availability under our Credit Facility and the Partnership’s Credit Facility and, in Abraxas’ case, distributions of available cash from the Partnership. If these sources of funding do not prove to be sufficient, we may also issue additional shares of equity securities although we may not be able to complete equity financings on terms acceptable to us, if at all. Our ability to make all of our budgeted capital expenditures will also be subject to availability of drilling rigs and other field equipment and services. Our capital expenditures could also include expenditures for the acquisition of producing properties if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. Should the prices of natural gas and crude oil decline and if our costs of operations continue to increase as a result of the scarcity of drilling rigs or if our production volumes decrease, our cash flows will decrease which may result in a reduction of the capital expenditures

 

 

budget. If we decrease our capital expenditures budget, we may not be able to offset natural gas and crude oil production volumes decreases caused by natural field declines and sales of producing properties, if any.

 

Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table:

 

 

          Operating activities during the six months ended June 30, 2008 provided us $30.5 million of cash compared to providing $325,000 in the same period in 2007. Net income plus non-cash expense items during 2008 and 2007 and net changes in operating assets and liabilities accounted for most of these funds. Financing activities provided $118.8 million for the first six months of 2008 compared to providing $19.9 million for the same period of 2007. Funds provided in 2008 were primarily proceeds from the Partnership’s credit facility and subordinated facility in connection with the St. Mary property acquisition. Most of the funds provided in 2007 were proceeds from the issuance of common stock, proceeds from the sale of units in Abraxas Energy Partners and proceeds from our revolving credit facilities. Investing activities used $155.5 million during the six months ended June 30, 2008 compared to using $8.8 million for the six months ended June 30, 2007. Expenditures of $155.5 million during the six months ended June 30, 2008 were primarily for the acquisition of properties from St. Mary Land and Exploration as well as the development of our existing properties. For the first half of 2007, capital expenditures were primarily for the development of existing properties.

 

Future Capital Resources. Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under the Credit Facility, cash on hand, distributions from the Partnership and if an appropriate opportunity presents itself, proceeds from the sale of properties. Abraxas Energy Partners’ principal sources of capital will be cash from operating activities, borrowings under the Partnership Credit Facility, and sales of debt or equity securities if available to it. Our cash flow from operations depends heavily on the prevailing prices of natural gas and crude oil and our production volumes of natural gas and crude oil. Although a significant portion of our consolidated natural gas and crude oil production is subject to derivative contracts, future natural gas and crude oil price declines would have a material adverse effect on our overall results, and therefore, our liquidity. Falling natural gas and crude oil prices could also negatively affect our ability to raise capital on terms favorable to us or at all.

Our cash flow from operations will also depend upon the volume of natural gas and crude oil that we produce. Unless we otherwise expand reserves, our production volumes may decline as reserves are produced. For example, in 2006, Abraxas replaced only 7% of the reserves it produced. In 2007 we replaced 219% of the reserves we produced. In the future, if an appropriate opportunity presents itself, we may sell producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful, exploration and development activities, acquire additional producing properties or identify additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including the risk that no commercially productive natural gas or crude oil reservoirs will be found. If our proved reserves decline in the future, our production will also decline and, consequently, our cash flow from operations, distributions from the Partnership and the amount that we are able to borrow under our credit facilities will also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 69% of Abraxas Petroleum’s and 50% of the Partnership’s total estimated proved reserves at December 31, 2007 were undeveloped. During the first six months of

 

 

2008, we expended approximately $16.3 million for wells in Texas and continued general well maintenance and work-overs utilizing our own work-over rigs.

Contractual Obligations

We are committed to making cash payments in the future on the following types of agreements:

•

Long-term debt

 

We have no off-balance sheet debt or unrecorded obligations and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of June 30, 2008:

 

____________

 

We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At June 30, 2008, our reserve for these obligations totaled $10.0 million for which no contractual commitment exists.

Off-Balance Sheet Arrangements. At June 30, 2008, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

 

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At June 30, 2008, we were not engaged in any legal proceedings that were expected, individually or in the aggregate, to have a material adverse effect on the Company.

 

Other obligations. We make and will continue to make substantial capital expenditures for the acquisition, development, exploration and production of crude oil and natural gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, sales of properties, sales of production payments and borrowings under our bank credit facilities and other sources. Given our high degree of operating control, the timing and incurrence of operating and capital expenditures is largely within our discretion.

 

Long-Term Indebtedness

 

Long-term debt consisted of the following:

 

 

 

 

Senior Secured Credit Facility. On June 27, 2007, Abraxas entered into a new senior secured revolving credit facility, which we refer to as the Credit Facility. The Credit Facility has a maximum commitment of $50 million. Availability under the Credit Facility is subject to a borrowing base. The borrowing base under the Credit Facility, which is currently $6.5 million, is determined semi-annually by the lenders based upon our reserve reports, one of which must be materially prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we may also request one redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our current borrowing base. Our borrowing base at June 30, 2008 of $6.5 million was determined based upon our reserves at December 31, 2006 after giving effect to the contribution of properties to the Partnership in May 2007. There is no outstanding balance on this facility as of June 30, 2008. Our borrowing base can never exceed the $50.0 million maximum commitment amount. Outstanding amounts under the Credit Facility will bear interest at (a) the greater of reference rate announced from time to time by Société Générale, and (b) the Federal Funds Rate plus ½ of 1%, plus in each case, (c) 0.5% - 1.5% depending on utilization of the borrowing base, or, if Abraxas elects, at the London Interbank Offered Rate plus 1.5% - 2.5%, depending on the utilization of the borrowing base. Subject to earlier termination rights and events of default, the Credit Facility’s stated maturity date will be June 27, 2011. Interest will be payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances.

Abraxas is permitted to terminate the Credit Facility, and may, from time to time, permanently reduce the lenders’ aggregate commitment under the Credit Facility in compliance with certain notice and dollar increment requirements.

Each of Abraxas’ subsidiaries other than the Partnership, Abraxas General Partner, LLC and Abraxas Energy Investments, LLC has guaranteed Abraxas’ obligations under the Credit Facility on a senior secured basis. Obligations under the Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of Abraxas’ and the subsidiary guarantors’ material property and assets.

Under the Credit Facility, Abraxas is subject to customary covenants, including certain financial covenants and reporting requirements. The Credit Facility requires Abraxas to maintain a minimum current ratio as of the last day of each quarter of not less than 1.00 to 1.00 (current assets to current liabilities) and an interest coverage ratio (generally defined as the ratio of consolidated EBITDA to consolidated interest expense as of the last day of such quarter) of not less than 2.50 to 1.00.

In addition to the foregoing and other customary covenants, the Credit Facility contains a number of covenants that, among other things, will restrict Abraxas’ ability to: 

 

 

The Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

Amended and Restated Partnership Credit Facility. On May 25, 2007, the Partnership entered into a senior secured revolving credit facility which was amended and restated on January 31, 2008, which we refer to as the Partnership Credit Facility. The Partnership Credit Facility has a maximum commitment of $300.0 million. Availability under the Partnership Credit Facility is subject to a borrowing base. The borrowing base under the Partnership Credit Facility, which is currently $140.0 million, is determined semi-annually by the lenders based upon the Partnership’s reserve reports, one of which must be materially prepared by the Partnership’s independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Partnership’s proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of the Partnership’s current borrowing base. The Partnership’s borrowing base at June 30, 2008 of $140.0 million was determined based upon its reserves at December 31, 2007 which inclued reserves attributable to the oil and gas properties acquired from St. Mary Land & Exploration Company on January 31, 2008. The borrowing base can never exceed the $300 million maximum commitment amount. Outstanding amounts under the Partnership Credit Facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale and (2) the Federal Funds Rate plus 0.5%, plus in each case (b) 25% - 1.00%, depending on the utilization of the borrowing base or, if the Partnership elects, at the London Interbank Offered Rate plus 1.25% - 2.00%, depending on the utilization of the borrowing base. Subject to earlier termination rights and events of default, the Partnership Credit Facility’s stated maturity date is January 31, 2013. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Partnership Credit Facility, and under certain circumstances, may be required, from time to time, to permanently reduce the lenders’ aggregate commitment under the Partnership Credit Facility.

Each of the general partner of the Partnership, Abraxas General Partner, LLC, which is a wholly-owned subsidiary of Abraxas and which we refer to as the GP, and Abraxas Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which we refer to as Abraxas Operating , has guaranteed the Partnership’s obligations under the Credit Facility on a senior secured basis. Obligations under the Partnership Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the material property and assets of the GP, the Partnership and Abraxas Operating, other than the GP’s general partner units in the Partnership.

Under the Partnership Credit Facility, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Partnership Credit Facility requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.0 to 1.0 (current assets to current liabilities) and an interest coverage ratio (defined as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of each quarter of not less than 2.50 to 1.00. The Partnership Credit Facility required it to enter into hedging arrangements for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the St. Mary properties). The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from our estimated net proved developed producing reserves (including the reserves attributable to the St. Mary properties) through December 31, 2011.

Under the terms of the Partnership Credit Facility, the Partnership may make cash distributions if, after giving effect to such distributions, the Partnership is not in default under the Partnership Credit Facility and there is no borrowing base deficiency and provided that no such distribution shall be made using the proceeds of any advance unless the amount of the unused portion of the amount then available

 

 

under the Partnership Credit Facility is greater than or equal to 10% of the lesser of the Partnership’s borrowing base (which is currently $140.0 million) or the total commitment amount of the Partnership Credit Facility (which is currently $300.0 million) at such time.

In addition to the foregoing and other customary covenants, the Partnership Credit Facility contains a number of covenants that, among other things, will restrict the Partnership’s ability to:

 

The Partnership Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness including the Subordinated Credit Agreement described below, bankruptcy and material judgments and liabilities.

Subordinated Credit Agreement

On January 31, 2008, the Partnership entered into a subordinated credit agreement which we refer to as the Subordinated Credit Agreement. The Subordinated Credit Agreement has a maximum commitment of $50 million, all of which was borrowed at closing. Outstanding amounts under the Subordinated Credit Agreement bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, and (2) the Federal Funds Rate plus 0.5%, plus in each case, (b) 4.00% to 5.50% depending on the applicable date, or, if we elect, at the London Interbank Offered Rate plus 5.00% to 6.50%, depending on the applicable date. The rates for the applicable dates are as follows:

At June 30, 2008, the interest rate on the facility was 8.2%. Subject to earlier termination rights and events of default, the Subordinated Credit Agreement’s stated maturity date is January 31, 2009. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Subordinated Credit Agreement, and under certain circumstances, may be required, from time to time, to make prepayments under the Subordinated Credit Agreement.

Each of the GP and Abraxas Operating has guaranteed the Partnership’s obligations under the Subordinated Credit Agreement on a subordinated secured basis. Obligations under the Subordinated Credit Agreement are secured by subordinated security interests, subject to certain permitted encumbrances, in property and assets of the Partnership, GP, and Abraxas Operating comprising at least 90% of the PV-10 of their proved reserves and the related oil and gas properties, other than the GP’s general partner units in the Partnership.

Under the Subordinated Credit Agreement, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Subordinated Credit Agreement requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.0 to 1.0 (current assets to current liabilities) and an interest coverage ratio (defined as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of each quarter of not less than 2.50 to 1.00. The Partnership Credit Facility required it to enter into hedging arrangements for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the St. Mary properties). The Partnership entered into NYMEX-based fixed price commodity swaps on approximately

 

 

85% of its estimated oil and gas production from our estimated net proved developed producing reserves (including the reserves attributable to the St. Mary properties) through December 31, 2011.

In addition to the foregoing and other customary covenants, the Subordinated Credit Agreement contains a number of covenants that, among other things, will restrict the Partnership’s ability to:

 

The Subordinated Credit Agreement also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness including the Credit Facility, bankruptcy and material judgments and liabilities.

Real Estate Lien Note

On May 9, 2008 the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a new building to serve as its corporate headquarters. The note bears interest at a fixed rate of 6.65%. The note is interest only for six months. At the end of six months the note is payable in monthly principle and interest installments, based on a twenty year amortization, until maturity in June 2015 at which time the balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of June 30, 2008, $4.7 million is outstanding on the note.

Hedging Activities.

 

Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. Under the terms of the Partnership Credit Facility, Abraxas Energy Partners was required to enter into derivative contracts, which we sometimes refer to as hedging arrangements for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011 from its net proved developed producing reserves.

 

Net Operating Loss Carryforwards.

At December 31, 2007, we had, subject to the limitation discussed below, $178.1 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire through 2027 if not utilized.

Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, we have established a valuation allowance of $47.2 million for deferred tax assets at December 31, 2007.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is an interpretation of SFAS 109, “Accounting for Income Taxes”, and it seeks to reduce the diversity in practice associated with certain aspects of measurement and accounting for income taxes and requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. Accordingly, the Company adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have any effect on the Company’s financial position or results of operations as of January 1, 2007 or for the quarter ended March 31, 2007. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2008, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 1999 through 2006 remain open to examination by the tax jurisdictions to which the Company is subject.

 

 

 

Commodity Price Risk

 

As an independent crude oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the quarter ended June 30, 2008, a 10% decline in crude oil and natural gas prices would have reduced our operating revenue, cash flow and net income by approximately $5.7 million for the quarter, however, due to the derivative contracts that the Partnership has in place, it is unlikely that a10% decline in commodity prices from their current levels would significantly impact our operating revenue, cash flow and net income.

 

Derivative Instrument Sensitivity

The Partnership accounts for its derivative instruments in accordance with SFAS 133 as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. In 2003 we elected not to designate derivative instruments as hedges. Accordingly the instruments are recorded on the balance sheet at fair value with changes in the market value of the derivatives being recorded in current derivative income (loss).

Under the terms of the Partnership Credit Facility, Abraxas Energy Partners was required to enter into derivative contracts for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011 from its net proved developed producing reserves. The Partnership intends to enter into hedging arrangements in the future to reduce the impact of price volatility on its cash flow. By removing a significant portion of price volatility on its future oil and gas production, the Partnership believes it will mitigate, but not eliminate, the potential effects of changing commodity gas prices on its cash flow from operations for those periods.

The following table sets forth the Partnership’s derivative contract position at June 30, 2008:

 

We expect to sustain realized and unrealized gains and losses as a result of our hedging arrangements. For the year ended December 31, 2007, we recognized a realized gain of $1.9 million and an unrealized loss of $(6.3) million, and for the three and six months ended June 30, 2008, we recognized a realized losses of $(6.6) million and $(7.5) million, respectively and unrealized losses of $(74.5) million and $(100.6) million, respectively, on our derivative contracts. The losses for the three and six months ended June 30, 2008 are a result of the contract prices being significantly less than current market prices. On June 30, 2008, NYMEX futures prices were $140.00 per barrel of oil and $13.35 per MMbtu of gas and we expect to continue to sustain realized and unrealized losses on our derivative contracts if market prices continue to be greater than our contract prices.

 

 Interest Rate Risk

 

 

 

Item 4.                       Controls and Procedures.          As of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of Abraxas’ “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) and concluded that the disclosure controls and procedures were effective and designed to ensure that material information relating to Abraxas and our consolidated subsidiaries which is required to be included in our periodic Securities and Exchange Commission filings would be made known to them by others within those entities. There were no changes in our internal controls over financial reporting during the period covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

 

 

ABRAXAS PETROLEUM CORPORATION  PART II

OTHER INFORMATION

 

 Item 1.     Legal Proceedings.              There have been no changes in legal proceedings from that described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, and in Note 6 in the Notes to Condensed Consolidated Financial Statements contained in Part I of this report on Form 10-Q. Item 1A.Risk Factors.              In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing Abraxas. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

 

An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations.

 

Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for all of our oil and gas are lower than the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. For example, production increases from competing Canadian and Rocky Mountain producers, combined with limited refining and pipeline capacity in the Rocky Mountain area, have gradually widened differentials in this area.

 

Our derivative contract activities could result in financial losses or could reduce our cash flow.

 

To achieve more predictable cash flow and reduce our exposure to adverse fluctuations in the prices of oil and gas and to comply with the requirements under our credit facility, we have and expect to continue to enter into derivative contracts, which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production that could result in both realized and unrealized derivative contract losses. The Partnership has entered into NYMEX-based fixed price commodity swap arrangements on approximately 85% of its estimated oil and gas production from its estimated net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the St. Mary properties). The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity price derivative contract activities. For example, the prices utilized in our derivative instruments are NYMEX-based, which may differ significantly from the actual prices we receive for oil and gas which are based on the local markets where oil and gas are produced. The prices that we receive for our oil and gas production are lower than the relevant benchmark prices that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. As a result, our cash flow could be affected if the basis differentials widen more than we anticipate. For more information see ‘‘—An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations’’. We currently do not have any basis differential hedging arrangements in place. Our cash flow could also be affected based upon the levels of our production. If production is higher than we estimate, we will have greater commodity price exposure than we intended. If production is lower than the nominal amount that is subject to our hedging arrangements, we may be forced to satisfy all or a portion of our hedging arrangements without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction in cash flows.

 

 

 

The prices at which the Partnership has hedged its oil and gas production are less than current market prices, which could adversely affect its ability to maintain or increase cash distributions.

 

The Partnership has entered into NYMEX-based fixed price commodity swap arrangements on approximately 85% of our estimated oil and gas production from its estimated net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the properties acquired from St. Mary). The volume weighted average prices at which the Partnership has hedged this production are $85.54 per barrel of oil and $8.32 per MMbtu of gas. These hedged prices are significantly less than NYMEX future prices on June 30, 2008 of $140.00 per barrel of oil and $13.35 per MMbtu of gas. As a result of this disparity, the Partnership will not be able to realize increased cash flow from these historically high commodity prices which could adversely affect its ability to increase cash distributions. Because prices in the Partnership’s derivative contracts are at less than current market prices, the Partnership has sustained realized and unrealized losses on its derivative contracts, and will continue to sustain such losses if market prices remain higher than the contract prices. For the six months ended June 30, 2008 the Partnership recognized a realized loss on derivative contracts of $7.5 million and an unrealized loss of $100.6 million. The realized loss has resulted in a decrease in cash flow from operations of the Partnership as well as negatively impacting cash available for distribution by the Partnership.

 

Item 2.          Unregistered Sales of Equity Securities and Use of Proceeds.

 

                      None

 

Item 3.           Defaults Upon Senior Securities.

                     None

Item 4.Submission of Matters to a Vote of Security Holders.

   At the Annual Meeting of Shareholders held on May 21, 2008, the following proposals were adopted by the margins indicated:  

 

 

In addition, the terms of office of Franklin A. Burke, Harold D. Carter, Barry J. Galt, Paul A. Powell Jr., and Robert L.G. Watson continued.

 

 

 

 

 

 

 

Item 5.         Other Information.

 

                None

 

Item 6.Exhibits.

 

 

 

ABRAXAS PETROLEUM CORPORATION  SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, as amended the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

President and Chief

Executive Officer

Executive Vice President and

Principal Accounting Officer