EXCO Resources 10-K 2011
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 3
For the Fiscal Year Ended December 31, 2009
For the Transition Period from to
Commission File Number 0-9204
EXCO RESOURCES, INC.
(Exact name of Registrant as specified in its charter)
Registrants telephone number, including area code: (214) 368-2084
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
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 such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files). YES ¨ 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 the definitions 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 ¨ No x
As of February 12, 2010, the registrant had 212,054,805 outstanding shares of common stock, par value $.001 per share, which is its only class of common stock. As of the last business day of the registrants most recently completed second fiscal quarter, the aggregate market value of the registrants common stock held by non-affiliates was $1,803,590,000.
For purposes of this calculation only, affiliates include all shares held by all officers, directors and 10% or greater shareholders.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants proxy statement to be furnished to shareholders in connection with its 2010 Annual Meeting of Shareholders are incorporated by reference in Part III, Items 10-14 of this Annual Report on Form 10-K.
EXCO Resources, Inc. is filing this Amendment No. 3 on Form 10-K/A (this Amendment) to its Annual Report on Form 10-K for the fiscal year ended December 31, 2009, originally filed with the Securities and Exchange Commission (the Commission) on February 24, 2010, and amended by Amendment No. 1 on Form 10-K/A filed with the Commission on March 3, 2010 (the 2009 Form 10-K), and further amended by Amendment No. 2 on Form 10-K/A on January 25, 2011, for the purpose of addressing comments received from the staff of the Commission relating to the 2009 Form 10-K.
This Amendment revises the 2009 Form 10-K as follows:
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.
In addition, in connection with filing this Amendment and pursuant to the rules of the Commission, the companys Chief Executive Officer and Chief Financial Officer have reissued their certifications pursuant to section 302 of the Sarbanes-Oxley Act of 2002, attached as Exhibits 31.1 and 31.2 to this Amendment. Because no financial statements are contained within this Amendment, we are not including certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under risk factors and elsewhere in this Annual Report on Form 10-K.
Overview and history
We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore North American oil and natural gas properties. Our principal operations are conducted in the East Texas/North Louisiana, Appalachia and Permian producing areas. In addition to our oil and natural gas producing operations, we hold a 50% equity interest in a joint venture which owns gathering systems and pipelines in East Texas/North Louisiana. Our assets in East Texas/North Louisiana, including our equity interest in midstream operations, are owned by our subsidiary, EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operatings debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources debt.
Historically, we used acquisitions and vertical drilling as our vehicle for growth. As a result of our acquisitions, we accumulated an inventory of drilling locations and acreage holdings with significant potential in the Haynesville/Bossier and Marcellus shale resource plays. This shale potential has allowed us to shift our focus to exploit these shales, primarily through horizontal drilling. Future acquisitions are likely to be focused on supplementing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. We will continue to develop certain vertical drilling opportunities in our East Texas/North Louisiana, Appalachia and Permian areas as industry economic conditions permit.
We currently have two credit agreements with a combined borrowing base of $1.3 billion, of which $747.6 million was drawn as of December 31, 2009. The EXCO Resources Credit Agreement has a borrowing base of $450.0 million and the EXCO Operating Credit Agreement has a borrowing base of $850.0 million. We expect to continue to grow by leveraging our management and technical teams experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations, accumulating undeveloped acreage in shale areas, exploitation projects and entering into joint venture transactions. We employ the use of debt along with a comprehensive derivative financial instrument program to mitigate commodity price volatility to support our strategy.
As of December 31, 2009, the PV-10 and the Standardized Measure of our Proved Reserves was approximately $747.7 million (see Item 1. Summary of geographic areas of operations for a reconciliation of PV-10 to Standardized Measure of Proved Reserves). For the year ended December 31, 2009, we produced 128.2 Bcfe of oil and natural gas. Based on our December 2009 average daily production of 224.0 Mmcfe, this translates to a reserve life of approximately 11.7 years. We used annualized December 2009 production, rather than actual 2009 production, to calculate our reserve life as of December 31, 2009 due to the significant reduction in production resulting from divestitures of proved producing reserves during 2009.
In 2009, we drilled 103 wells and completed 101 gross (53.0 net) wells with 98.1% drilling success rate. Our 2009 development, exploitation and other oil and natural gas property capital expenditures totaled $299.8 million. In addition, we leased $106.0 million of undeveloped acreage primarily in the Haynesville/Bossier shale resource play in East Texas/North Louisiana. Midstream capital expenditures, prior to the formation of TGGT, were $53.1 million and corporate capital expenditures totaled an additional $52.5 million. In addition, we
completed $233.6 million of acquisitions, which were mostly undeveloped acreage in the Haynesville shale resource play.
During 2009, we also completed sales of certain non-strategic assets pursuant to a previously announced divestiture program and entered into joint venture transactions with BG Group, resulting in net cash proceeds of approximately $2.1 billion after closing adjustments.
The following table summarizes our 2009 divestitures and joint venture transactions:
Our plans for 2010 are focused on the Haynesville/Bossier and Marcellus shales. Our budgeted capital expenditures total $471.4 million, of which $409.4 million is allocated to our East Texas/North Louisiana and Appalachia regions. In East Texas and North Louisiana, our capital expenditures in the BG AMI are expected to total $740.8 million, with EXCOs share being only $165.3 million, which reflects the favorable impact of the BG Carry. In Appalachia, our planned capital expenditures total $154.2 million.
The 2010 capital budget includes $39.1 million for midstream activities, including a $7.8 million equity contribution to TGGT. TGGT is the newly formed midstream joint venture owned equally by EXCO and BG Group. TGGT owns the midstream assets located within the BG AMI in East Texas and North Louisiana. The TGGT capital budget for 2010 is $101.0 million, $50.5 million net to EXCOs interest. This budget will be mostly funded by internal TGGT cash flow. The management of TGGT is also evaluating several expansion projects which, if approved, will require additional capital contributions.
Like all oil and natural gas production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to overcome this natural decline by drilling to identify and develop additional reserves and add additional reserves through acquisitions. As of December 31, 2009, 96.5% of our estimated Proved Reserves were natural gas. Consequently, our results of operations are particularly impacted by natural gas markets.
The impact of our 2009 divestitures and joint ventures with BG Group resulted in significant reductions to our Proved Reserves, production volumes, revenue and operating expenses. While the reductions will have a near-term impact on our results of operations, we believe the benefits from the liquidity provided by these
transactions and the BG Carry will allow us to accelerate development of our reserves and resources including our shale development and will more than compensate for these reductions.
Critical accounting policies
In response to the SECs Release No. 33-8040, Cautionary Advice Regarding Disclosure About Critical Accounting Policies, we have identified the most critical accounting policies used in the preparation of our consolidated financial statements. We determined the critical policies by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our Proved Reserves, accounting for business combinations, accounting for derivatives, share-based payments, our choice of accounting method for oil and natural gas properties, goodwill, asset retirement obligations and income taxes.
We prepared our consolidated financial statements for inclusion in this report in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.
Estimates of Proved Reserves
The Proved Reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:
Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. The assumptions used for our Haynesville well and reservoir characteristics and performance are subject to further refinement as more production history is accumulated.
You should not assume that the present value of future net cash flows represents the current market value of our estimated Proved Reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from Proved Reserves according to the requirements in the SECs Release No. 33-8995 Modernization of Oil and Gas Reporting, or Release No. 33-8995. Actual future prices and costs may be materially higher or lower than the prices and costs used in the preparation of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates.
Proved Reserves quantities directly and materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in the estimate of Proved Reserves may result from lower market prices, making it uneconomical to drill or produce from higher cost fields. In addition, a decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties and require an impairment of the carrying value of our oil and natural gas properties.
Proved Reserves are defined as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that
renewal is reasonably certain, regardless of whether the estimates is a deterministic estimate or probabilistic estimate. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
The area of the reservoir considered as proved includes both the area identified by drilling and limited by fluid contacts, if any, and adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.
Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and the project has been approved for development by all necessary parties and entities, including governmental entities.
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
For the periods covered by this Annual Report on Form 10-K, we use FASB ASC Subtopic 805-10 for Business Combinations to record our acquisitions of oil and natural gas properties or entities which we acquire beginning January 1, 2009. ASC 805-10 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value, with any excess purchase price being recognized as goodwill. Application of ASC 805-10 requires significant estimates to be made by management using information available at the time of acquisition. Since these estimates require the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available.
Accounting for derivatives
We use derivative financial instruments to protect against commodity price fluctuations and in connection with the incurrence of debt related to our acquisition activities. Our objective in entering into these derivative financial instruments is to manage price fluctuations and achieve a more predictable cash flow to fund our development, acquisition activities and support debt incurred with our acquisitions. These derivative financial instruments are not held for trading purposes. We do not designate our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivatives fair value as a component of current earnings.
We account for share-based payments to employees using the methodology prescribed in FASB ASC Topic 718 for CompensationStock Compensation Topic. At December 31, 2009, our employees and directors held options under EXCOs 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, to purchase 16,454,294 shares of EXCO common stock at prices ranging from $6.33 per share to $38.01 per share. The options expire ten years from the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of grant. We use the Black-Scholes model to calculate the fair value of issued options. The gross fair value of the granted options using the Black-Scholes model range from $2.28 per share to $14.27 per share. ASC Topic 718 requires share-based compensation be recorded with cost classifications consistent with cash compensation. EXCO uses the full cost method to account for its oil and natural gas properties. As a result, part of our share-based payments are capitalized. Total share-based compensation for 2009 was $24.1 million, of which $5.1 million was capitalized as part of our oil and natural gas properties. In 2008 and 2007, a total of $20.0 million and $15.0 million, respectively, of share-based compensation was incurred, of which $4.0 million and $2.4 million, respectively, was capitalized.
Accounting for oil and natural gas properties
The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives; the full cost method or the successful efforts method.
We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Unproved property costs are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess possible impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus costs of acquired proved and unproved leaseholds.
During April 2008 we initiated leasing projects to acquire shale drilling rights in both our Appalachia and East Texas/North Louisiana operating areas. In accordance with our policy and FASB ASC Subtopic 835-20 for Capitalization of Interest, we began capitalizing interest on unproved properties.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs are divided by the total quantity of Proved Reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.
Under the full cost method of accounting, sales, dispositions and other oil and natural gas property retirements are generally accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless the disposition would significantly alter the relationship between capitalized costs and Proved Reserves. During 2009, our BG Upstream Transaction, Mid-Continent Transaction, East Texas Transaction and Sheridan Transaction resulted in significant alterations to our full cost depletion pool and we determined that gain recognition was appropriate for these transactions. Gain or loss recognition on divestiture or abandonment of oil and natural gas properties where disposition would result in a significant alteration of the depletion rate requires allocation of a portion of the amortizable full cost pool based on the relative estimated fair value of the disposed oil and natural gas properties to the estimated fair value of total Proved Reserves. As discussed under Estimates of Proved Reserves, estimating oil and natural gas reserves involves numerous assumptions.
Prior to our December 31, 2009 adoption of Release No. 33-8995, at the end of each quarterly period the unamortized cost of oil and natural gas properties, net of related deferred income taxes, was limited to the full cost ceiling, computed as the sum of the estimated future net revenues from our Proved Reserves using period-end prices, discounted at 10%, and adjusted for related income tax effects (ceiling test). In the event our capitalized costs exceeded the ceiling limitation at the end of the reporting period, we subsequently evaluated the limitation for price changes occurring after the balance sheet date to assess impairment. Beginning December 31, 2009, Release No. 33-8995 requires that the full cost ceiling be computed as the sum of the estimated future net revenues from Proved Reserves using the average, first-day-of-the-month price during the previous 12-month period, discounted at 10% and adjusted for related income tax effects. The new rule no longer allows a company to subsequently evaluate the limitation for subsequent prices changes. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results.
For the year 2007, we sought and received exemptions from the Securities and Exchange Commission, or the SEC, in July 2007 to exclude three significant proved oil and natural gas property acquisitions which closed in late 2006 and during the first half of 2007 from our ceiling test computation for a period of 12 months from the closing date of each acquisition. There were no ceiling test exemptions in effect for any acquisitions for the years ended December 31, 2009 and 2008.
The quarterly calculation of the ceiling test is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
A change in control transaction involving an equity buyout on October 3, 2005, required the application of the purchase method of accounting pursuant to ASC 805-10 and goodwill of $220.0 million was recognized. Additional goodwill of $250.1 million was recognized from our 2006 acquisitions.
The BG Upstream Transaction, the East Texas Transaction, the Mid-Continent Transaction and the Sheridan Transaction each caused significant alterations to our depletion rate and we therefore evaluated the goodwill associated with these properties. As a result of our analysis, we eliminated $177.6 million of goodwill by reducing the gains associated with these transactions. In addition, the BG Midstream Transaction triggered the write off of $11.4 million of goodwill against the associated gain and the transfer of $11.4 million of goodwill to the TGGT investment.
As of December 31, 2009, our consolidated goodwill totals $269.7 million. Not all of our goodwill is currently deductible for income tax purposes. Furthermore, in accordance with FASB ASC Topic 350-Intangibles Goodwill and Other, goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are subject to various assumptions and judgments. We use a combination of valuation techniques, including discounted cash flow projections and market comparable analyses to evaluate our goodwill for possible impairment. Actual future results of these assumptions could differ as a result of economic changes which are not within our control. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations. As of December 31, 2009, we did not have any impairment of our goodwill.
Asset retirement obligations
We follow FASB ASC Subtopic 410-20 for Asset Retirement Obligations to account for legal obligations associated with the retirement of long-lived assets. ASC 410-20 requires these obligations be recognized at their estimated fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.
Accounting for income taxes
Income taxes are accounted for using the liability method of accounting in accordance FASB ASC Topic 740 for Income Taxes. We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. Deferred taxes are recorded to reflect the tax benefits and consequences of future years differences between the tax basis of assets and liabilities and their financial reporting basis. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Recent accounting pronouncements
On January 21, 2010, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update No. 2010-06Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed, Level 3 reconciliations for fair value measurements using significant unobservable inputs should be presented on a gross basis, the fair value measurement disclosure should be reported for each class of asset and liability, and disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring will be required for fair value measurements that fall in either Level 2 or 3. The update will be effective for interim and annual reporting periods beginning after December 15, 2009. This update will require us to update our disclosures on derivatives, but will have no impact to our financial position.
On April 1, 2009, the FASB issued FASB ASC Subtopic 805-20 for Business Combinations. ASC 805-20 amends and clarifies FASB SFAS No. 141 (revised 2007), Business Combinations, to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted ASC 805-20 on January 1, 2009.
In March 2008, the FASB issued FASB ASC Section 815-10-65 for Derivatives and Hedging. ASC 815-10-65 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the companys strategies and objectives for using derivative instruments. ASC 815-10-65 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See Note 9. Derivative financial instruments and fair value measurements for the impact to our disclosures.
On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. On January 16, 2010, the Financial Accounting Standards Board, or the FASB, issued Update No. 2010-03Extractive ActivitiesOil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, or Update No. 2010-03, to align the oil and gas reserve estimation and disclosure requirements of the Codification with Release No. 33-8995.
The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date.
Among other things, Release No. 33-8995 and the Update No. 2010-03:
The impact of the adoption of this statement can be seen in our disclosures in Item 1. Business. The change in the calculation of pricing resulted in prices of $3.87 per Mmbtu for Henry Hub and $61.18 per Bbl for Cushing, Oklahoma instead of the December 31, 2009 spot price of $5.79 per Mmbtu for Henry Hub and $79.36 per Bbl for Cushing, Oklahoma.
Our results of operations
A summary of key financial data for 2009, 2008 and 2007 related to our results of operations for the years then ended is presented below.
The following is a discussion of our financial condition and results of operations for the years ended December 31, 2009, 2008 and 2007.
The comparability of our results of operations for 2009, 2008 and 2007 is impacted by:
The availability of a ready market for oil and natural gas and the prices of oil and natural gas are dependent upon a number of factors that are beyond our control. These factors include, among other things:
Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of oil and natural gas from any producing well in which we have or may acquire an interest.
Marketing arrangements and backlog
We produce oil and natural gas. We do not refine or process the oil or natural gas we produce. We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.
We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend for a year or more. Our natural gas customers include utilities, natural gas marketing companies and a variety of commercial and industrial end users. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions.
For the year ended December 31, 2009, there were no sales to any individual customer which exceeded 10% of our consolidated revenues or were considered material to our operations. For the year ended December 31, 2008, sales to a natural gas marketing company, Crosstex Gulf Coast Marketing, and to a regulated natural gas utility company, Atmos Energy Marketing L.L.C. and its affiliates, accounted for approximately 12.0% and 11.2%, respectively, of total consolidated revenues. For the year ended December 31, 2007, sales to a regulated natural gas utility company, Atmos Energy Marketing L.L.C. and its affiliates, and an independent oil and natural gas company, Anadarko and its affiliates, accounted for approximately 18.9% and 11.4%, respectively, of total consolidated revenues. The loss of any significant customer may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas, but we believe that the loss of any one customer would not have a material adverse effect on our results of operations or financial condition.
We may be unable to market all of the oil and natural gas we produce. If our oil and natural gas can be marketed, we may be unable to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas reserves. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.
We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. In this situation, companies purchasing oil or natural gas in these areas reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our newly discovered oil or natural gas reserves, we may shut-in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated. Recent economic conditions related to the liquidity and creditworthiness of our purchasers may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.
For the years ended December 31, 2009, 2008 and 2007, we had net losses available to common shareholders of $496.8 million, $1.8 billion and $83.3 million, respectively.
During 2009, we closed divestiture and joint venture transactions totaling approximately $2.1 billion. Upon closing these transactions, we no longer operate in the Mid-Continent, Rockies and Ohio regions. Our current primary focus is the exploration and exploitation of the Haynesville/Bossier shales in East Texas/North Louisiana and the Marcellus shale in Appalachia.
Our results of operations for 2009 were impacted by the BG Upstream Transaction, the BG Midstream Transaction, the East Texas Transaction, the Mid-Continent Transaction, the Sheridan Transaction and the EnerVest Transaction. The impacts of these transactions include the following:
In addition, the impact of acquisitions, fluctuations in oil and natural gas prices, ceiling test write-downs and derivative financial instruments are significant to our results of operations. Acquisitions of producing oil and natural gas properties in 2008 and 2007 significantly increased our production, revenues and operating costs. There were large fluctuations in oil and natural gas prices during 2008 and 2009. In 2008, we received average oil prices of $96.93 per Bbl compared to $53.72 per Bbl in 2009 and in 2008 average natural gas prices of $9.06 per Mcfe compared to $3.93 per Mcfe in 2009. As a result of the decrease in natural gas prices from the end of 2008 and into 2009, we recognized write-downs to our full cost pool of $2.8 billion in 2008 and $1.3 billion in 2009. There were no write-downs required in 2007. In addition, we do not designate our derivative financial instruments as hedges. Therefore, we mark the non-cash changes in the fair value of our unsettled derivative financial instruments to market at the end of each reporting period. Due to significant fluctuations in the price of oil and natural gas during 2009, 2008 and 2007, the impacts of derivative financial instruments, including cash settlements or receipts with our counterparties and the non-cash mark-to-market impacts, totaled net gains of $232.0 million, $384.4 million and $26.8 million for 2009, 2008 and 2007, respectively.
Oil and natural gas revenues, production and prices
The following table presents our revenues, production and prices by major producing areas for the years ended December 31, 2009, 2008, 2007:
Total oil and natural gas revenues for 2009 were $550.5 million compared with $1.4 billion for 2008 and $875.8 million for 2007. For 2009, natural gas represented 84.7% of our oil and natural gas revenues and 92.6% of equivalent production. For 2008, natural gas represented 84.6% of our oil and natural gas revenues and 90.7% of equivalent production and for 2007, natural gas represented 86.6% of our oil and natural gas revenues and 91.9% of equivalent production.
Our equivalent production volumes for 2009 were 128.2 Bcfe compared with 144.6 Bcfe for 2008, a decrease of 11.4% due primarily to our 2009 divestitures, including the BG Upstream Transaction, which were partially offset by increased production volumes from Haynesville drilling results.
Production in our East Texas/North Louisiana region for 2009 was 82.1 Bcfe compared with 87.5 Bcfe in 2008. Divestures in 2009 impacting our East Texas/North Louisiana region included our East Texas Transaction and the BG Upstream Transaction. Our East Texas/North Louisiana production was also impacted as a result of production declines in our Vernon Field due to suspension of vertical drilling operations in the area. These decreases were almost offset, however, by increased production in our Haynesville area, which we began actively drilling in late 2008, and the addition of the Danville Field in East Texas, which we acquired in July 2008.
Our Mid-Continent region was sold in 2009. Our production in Appalachia in 2009 of 19.2 Bcfe compared with 20.9 Bcfe in 2008, was the result of normal declines impacted by suspension of drilling operations and the EnverVest Transaction. Our production declines in Permian were a result of normal declines, suspension of drilling operations and the divesture of our Vinegarone Field.
Our equivalent production volumes for 2008 were 144.6 Bcfe compared with 121.3 Bcfe for 2007, an increase of 19.2%, due to our 2008 Appalachian Acquisition and the Danville Acquisition, combined with full year 2008 production impacts from the 2007 Vernon Acquisition and the Southern Gas Acquisition. The Appalachian Acquisition and the Danville Acquisition contributed 7.7 Bcfe of production to our 2008 total volumes. Production increases of approximately 10.2 Bcfe in 2008 include the impact of a full year production from the Vernon Acquisition and the Southern Gas Acquisition compared with a partial year in 2007.
For 2009, our average price received for natural gas was $3.93 per Mcf compared with $9.06 per Mcf in 2008 and $6.81 per Mcf in 2007. The 2009 average price received for oil was $53.72 per Bbl compared to $96.93 per Bbl for 2008. The average price per Bbl for 2007 was $71.17. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, estimates of oil and natural gas in storage, weather and other seasonal conditions, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Changes in oil and natural gas prices have a significant impact on our oil and natural gas revenues, cash flows, quantities of estimated Proved Reserves and related liquidity. The decline from the 2008 prices to the 2009 prices was a result of a commodity price decline that started at end of the third quarter of 2008 and continued through 2009. Assuming our 2009 production levels, a change of $0.10 per Mcf of natural gas sold
would result in an annual increase or decrease in revenues and cash flow of approximately $11.9 million and a change of $1.00 per Bbl of oil sold would result in an annual increase or decrease in revenues and cash flow of approximately $1.6 million without considering the effects of derivative financial instruments.
In 2008, our revenues (before the impact of derivative financial instruments) increased to $1.4 billion from $875.8 million for 2007. The total increase of $529.0 million was attributable to an increase of $236.0 million from increased volumes primarily due to 2008 and 2007 acquisitions along with an increase in our realized price per Mcfe, which increased revenue by $293.0 million.
During 2008 we closed the Appalachian Acquisition, which included shallow natural gas properties located primarily in our central Pennsylvania operating area and the Danville Acquisition, which included producing oil and natural gas properties, acreage and other assets in Gregg, Rusk and Upshur counties of Texas. The Appalachian Acquisition and the Danville Acquisition increased our production in our Appalachia and East Texas/North Louisiana areas by 4.6 Bcfe and 3.1 Bcfe, respectively, during 2008. In addition, the impact of a full year of production in 2008 compared with a partial year in 2007 from the Vernon Acquisition increased volumes in East Texas/North Louisiana by 4.4 Bcfe. Volumes in the Mid-Continent area from the Southern Gas Acquisition increased by 5.7 Bcfe during 2008.
In January 2007, we completed the sale of our producing properties and undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado. This transaction included substantially all of our producing assets in Colorado. In May 2007, we sold a group of properties acquired in the Southern Gas Acquisition. While this sale, which provided proceeds of approximately $235.5 million, was substantial, it did not impact our results of operations as we did not hold the properties for a period of time sufficient to impact our operating results. In July 2007, we completed the sale of substantially all of our interest in the Cement Field located in our Mid-Continent area. In October 2007, we completed the purchase of an additional 45% ownership interest in approximately 28,000 acres of leasehold interests and 135 producing wells in our Canyon Sand Field in West Texas located in our Permian area. We also completed several small sales of producing properties and acreages throughout 2007. The Vernon Acquisition and the Southern Gas Acquisition significantly increased our production in the East Texas/North Louisiana and Mid-Continent areas during 2007.
Until our adoption of the equity method of accounting in connection with the BG Midstream Transaction in August 2009, our midstream revenues were principally derived from three of our wholly-owned subsidiaries: TGG, which owns an intrastate pipeline in East Texas and a gathering system in North Louisiana, Talco, which owns gathering systems in East Texas and North Louisiana and Vernon Gathering. Revenues in our midstream segment were derived from sales of natural gas purchased for resale and fees earned from gathering, transportation, treating and compression of natural gas. We do not own any natural gas processing facilities.
On August 14, 2009, we closed the BG Midstream Transaction. TGGT now holds our East Texas/North Louisiana midstream assets, exclusive of the Vernon Field midstream assets. TGGT is accounted for using the equity method of accounting. The net operations of Vernon Gathering are now reflected in Gathering and transportation on our Condensed Consolidated Statements of Operations.
Prior to the sale on August 14, 2009, we evaluated our midstream operations as if they were a stand alone operation. Accordingly, the results of operations discussed below are prior to intersegment eliminations.
For the year ended December 31, 2009, midstream revenues were $76.5 million compared with $147.6 million for year ended December 31, 2008. The decrease in sales for 2009 is due to the combination of lower prices received in 2009 from the sales of natural gas we purchased for resale, lower condensate prices and the adoption of the equity method of accounting for TGGTs operations on August 14, 2009.
For the year ended December 31, 2008, midstream revenues were $147.6 million, a 222.6% increase over the year ended December 31, 2007 midstream revenues of $45.8 million. Increases in the sales of natural gas account for 80.9% of the increase in the midstream revenues and are primarily attributable to the New Waskom Acquisition and gathering assets acquired in the Danville Acquisition. These assets, which were not owned in 2007, contained several contracts whereby we purchase and resell natural gas produced by third-parties. The remaining increase in revenues was attributable to increases in drip sales and gathering fees associated with the 2008 acquisitions, as well as increased throughput on our midstream assets.
Oil and natural gas operating costs
Our oil and natural gas operating costs for 2009, 2008, and 2007 were $138.7 million, $161.2 million and $115.7 million, respectively. Absolute increases or decreases in total dollar value from year to year are due primarily to operating expenses incurred from our acquisitions or divestitures. Management believes that analyses on a per Mcfe basis provide a more meaningful measure than the absolute dollar increases since the divestures in 2009 and the acquisitions in 2008 and 2007 significantly impacted the absolute dollar amounts. The following tables summarize direct operating expenses and unit rates per Mcfe for 2009, 2008, and 2007:
On a per Mcfe basis, oil and natural gas operating costs for the year ended December 31, 2009 decreased by $0.03 per Mcfe from year ended December 31, 2008. Direct lease operating expenses per unit decreased by $0.02 per Mcfe, or 2.0%, for the year ended December 31, 2009, from the year ended December 31, 2008. These decreases are principally the result of divestitures in 2009 and lower operating costs in our East Texas/North Louisiana area where increasing volumes from Haynesville wells benefit the unit rate. Benefits from the Haynesville results are partially offset by declining volumes from our base production that tend to increase the unit rate.
On a per Mcfe basis, oil and natural gas operating expenses for the year ended December 31, 2008 increased $0.16 per Mcfe from year ended December 31, 2007. Direct lease operating expenses increased by $0.14 per Mcfe, or 16.5%, for the year ended December 31, 2008 from the year ended December 31, 2007. These increases were primarily the result of our acquisitions in 2008 and the general increase in the costs of goods and services used in our oil and natural gas operations, most notably chemicals, labor, utilities, motor fuel and utility costs. Workover expenses for the year ended December 31, 2008, on a Mcfe basis, increased $0.02 per Mcfe from the year ended December 31, 2007 due primarily to higher costs for rigs and services.
Midstream operating expenses
Our midstream operating expenses before intersegment elimination, which includes the cost of natural gas purchased and then resold, for the year ended December 31, 2009 decreased $56.3 million from the year ended December 31, 2008. The decrease in midstream operating expenses was primarily attributable to a decline in the prices we paid for the natural gas we purchased for resale along with the August 14, 2009 BG Midstream Transaction and related adoption of the equity method of accounting for TGGTs operations. These decreases were offset by increases in both operating expenses and gas purchases resulting from the 2008 New Waskom and Danville acquisitions as well as the expansion of our gathering and transportation facilities in the East Texas/North Louisiana operating area in support of our Haynesville projects.
Our midstream operating expenses before intersegment eliminations for the year ended December 31, 2008 increased $90.4 million, or 406.0%, respectively, from the year ended December 31, 2007. The increase in midstream operating expenses for the year ended December 31, 2008 was primarily attributable to:
Gathering and transportation
We report gathering and transportation costs in accordance with FASB Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. We generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement, we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. Due to these two distinct selling arrangements, our computed realized prices, before the impact of derivative financial instruments, contain revenues which are reported under two separate bases. Gathering and transportation expenses totaled $19.0 million for year ended December 31, 2009, compared to $14.2 million for the year ended December 31, 2008 and $10.2 million for the year ended December 31, 2007.
As a result of the BG Midstream Transaction on August 14, 2009 our gathering system in Louisiana that supports our Vernon Field operations, which was previously reported within our midstream segment, is now reported net in Gathering and transportation on the Consolidated Statements of Operations.
We have entered into firm transportation agreements with pipeline companies to facilitate sales as we expand our Haynesville volumes. We expect our gathering and transportation expenses to increase significantly in 2010 and beyond.
Production and ad valorem taxes
Production and ad valorem taxes were $39.0 million, $76.9 million and $53.3 million for 2009, 2008, and 2007, respectively. However, on a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 7.1% of oil and natural gas sales, compared with 5.5% and 6.1% for 2007 and 2006, respectively. The increase in the percentage of revenue basis is primarily the result of the different taxing jurisdictions in which we operate. Production taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. In Louisiana, where a substantial percentage of our production is derived, severance taxes are levied on a per Mcf basis. Therefore, the resulting dollar value
of production is not sensitive to changes in prices for natural gas. The rate in Louisiana, whether stated on a per Mcfe basis or as a percentage of revenues, is also complicated by certain severance tax holidays on deep wells. Approval of these holidays is on a well by well basis, and credits are not recognized until approvals are received. Accordingly, a 50% decline in the average sales price per Mcf in Louisiana would double the effective production tax rate as a percentage of revenue. In our other operating areas, production taxes are predominantly price dependent. Ad valorem assessments also vary widely.
In addition to our existing production and ad valorem taxes on current properties, we may be subject to new taxes or changes to existing rates in the future. The state of Louisiana raised its severance tax rate to $0.33 per Mcf from $0.29 per Mcf effective July 1, 2009. In addition, the Commonwealth of Pennsylvania, which does not currently have ad valorem or severance taxes on oil and natural gas reserves or production, is currently studying different tax proposals impacting the oil and natural gas industry.
Overall, our production and ad valorem tax rates per Mcfe were $0.30 per Mcfe for 2009, $0.53 per Mcfe for 2008 and $0.44 per Mcfe for 2007. The following tables present our severance and ad valorem taxes on a per Mcfe basis and percentage of revenue basis for our significant producing regions.
Depreciation, depletion and amortization
The following table presents our depreciation, depletion and amortization expenses for the years ended December 31, 2009, 2008 and 2007. The depreciation, depletion and amortization rate per Mcfe produced varies significantly for each of the periods presented due to the various divestures, acquisitions and ceiling test write-downs incurred in 2008 and 2009. The 2007 Vernon Acquisition and the Southern Gas Acquisition, both of which included significant proved developed producing properties, increased the depreciation, depletion and amortization rate to $3.10 per Mcfe in 2007. The Appalachian Acquisition and the Danville Acquisition, along with a full year of activity related to the 2007 acquisitions, initially increased the depreciation, depletion and
amortization rate in 2008; however, these acquisitions were offset by the ceiling test write-downs in 2008. The annual 2008 depreciation, depletion and amortization rate was $3.18 per Mcfe, approximately 2.6% higher than 2007. The depletion rate was further reduced in 2009 by the first quarter 2009 ceiling test write-downs and the divestures during year, resulting in an annual depreciation, depletion and amortization rate of $1.72 per Mcfe in 2009, approximately 45.9% lower than 2008.
Accretion of discount on asset retirement obligations increased to $7.1 million in 2009 from $6.7 million in 2008 and $4.9 million in 2007. The increase in 2009 from 2008 and in 2008 from 2007 is due to the combination of significant well additions and related plugging liabilities in connection with our 2008 and 2007 acquisitions and increased estimates for the costs to plug and abandon properties. The increased estimates for plugging and abandoning properties reflect increased costs for labor, rig rates and materials used in those operations. The impact of our 2009 divestitures on accretion expenses in not significant as the divestitures occurred throughout 2009.
Write-down of oil and natural gas properties
For the year ended December 31, 2009, we recognized a ceiling test write-down of $1.3 billion. For the year ended December 31, 2008, we recognized ceiling test write-downs of $2.8 billion to our proved oil and natural gas properties. There were no ceiling test write-downs in 2007.
As discussed above, prior to our December 31, 2009 adoption of Release No. 33-8995, we were required by the SEC to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The prices used to compute our first quarter write-down were $3.63 per Mmbtu for natural gas and $49.64 per Bbl of oil as of March 31, 2009. Beginning December 31, 2009, Release No. 33-8995 states that we are required to compute the present value of our proved oil and natural gas properties using the simple average spot price for the trailing twelve month period using the first day of each month. The average prices used to compute the present value of our properties were $3.87 per Mmbtu for natural gas and $61.18 per Bbl of oil for 2009. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. We may face further ceiling test write-downs in future periods, depending on level of commodity prices, drilling results and well performance.
General and administrative expenses
The following table presents our general and administrative expenses for the years ended December 31, 2009, 2008 and 2007 and changes for each of the years then ended.
Net general and administrative expenses for the year ended December 31, 2009 were $99.2 million, or $0.77 per Mcfe, compared with $87.6 million, or $0.61 per Mcfe, in 2008, an increase of $11.6 million.
The primary components of the net increase of $11.6 million for the year ended December 31, 2009 were higher personnel costs of $16.4 million due to additional employees related to expansion of technical staff to exploit our shale resource asset base, $2.6 million in employee relocation and severance costs associated with our divestitures and office closures, $4.4 million in additional stock compensation expense related primarily to the acceleration of vesting of certain employees impacted by the divestitures and the impact the increase in our stock price had on the valuation of our December 2009 grants compared to the December 2008 grants and increased rent of $1.6 million resulting from our 2008 expansion.
These increases were offset by the following items:
Net general and administrative expenses for the year ended December 31, 2008 were $87.6 million, or $0.61 per Mcfe, compared with $64.7 million, or $0.53 per Mcfe, in 2007, an increase of $22.9 million. Significant components of the increase for the year ended December 31, 2008 include the following items:
Partially offsetting the increases in general and administrative expenses were operator overhead recoveries of $24.9 million and $18.4 million for the years ended December 31, 2008 and 2007, respectively. Additional offsets to general and administrative expenses were capitalized costs of $11.5 million and $5.7 million for the years ended December 31, 2008 and 2007, respectively.
Interest expense for the year ended December 31, 2009 was $147.2 million compared to $161.6 million for the same period in 2008. The decreased interest expense of $14.5 million is a result of $46.1 million decreased interest costs from our credit agreements due to the combination of significant reductions in outstanding debt beginning in the third quarter of 2009 and lower LIBO rates in 2009 compared to 2008, a $5.0 million decrease related to our interest rate swaps and a $2.0 million decrease related to a full year of capitalized interest. The decrease was offset by an increase of $9.0 million resulting primarily from the write-off of deferred financing fees related to the reduction of our debt on the credit agreements and $29.7 million of interest and deferred financing costs related to the Term Credit Agreement, which included a $15.0 million duration fee. We repaid the Term Credit Agreement in August 2009.
Interest expense for the year ended December 31, 2008 was $161.6 million compared to $181.3 million for the same period in 2007. The decrease of $19.7 million in 2008 when compared to 2007 reflects higher 2008 interest costs for the Term Credit Agreement of $26.9 million and settlements and non-cash changes in the fair value of interest swaps of $9.9 million which were more than offset by reductions of $50.2 million of prior year write-offs of deferred financing costs arising from early debt terminations, reduced interest on credit agreements of $1.7 million and $3.9 million of capitalized interest in 2008. There was no interest capitalized in 2007.
Derivative financial instruments
Our objective in entering into derivative financial instruments is to manage our exposure to commodity price and interest rate fluctuations, protect our returns on investments, service debt and achieve a more predictable cash flow in connection with our activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expenses due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.
The following table presents our realized and unrealized gains and losses from our oil and natural gas derivative financial instruments, which are reported as a component of other income or expenses in our Condensed Consolidated Statements of Operations. We expect that our revenues will continue to be significantly impacted in future periods by changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount of future production volumes subject to derivative financial instruments.
Our non-cash mark-to-market changes in the fair value of our oil and natural gas derivative financial instruments for the year ended December 31, 2009 resulted in a loss of $246.4 million compared to a gain of $493.7 million and a loss of $81.6 million for the years ended December 31, 2008 and 2007, respectively. The significant fluctuation was, again, attributable to high volatility in the prices for oil and natural gas between each of the years. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.
The use of derivative financial instruments allows us to limit the impacts of volatile price fluctuations associated with oil and natural gas. The following table presents our natural gas prices, before the impact of derivative financial instruments where average realized prices per Mcfe ranged from a high of $9.72 during the year end December 31, 2008 to a low of $4.30 during the year ended December 31, 2009 while the impact of cash settlements on derivatives decreased our price volatility from a high of $8.96 per Mcfe during the year ended December 31, 2008 to a low of $8.03 per Mcfe for the year ended December 31, 2009, respectively.
Our cash settlements for 2009 increased our other income by $478.5 million, or $3.73 per Mcfe compared to cash settlements decreasing our other income by $109.3 million, or $0.76 per Mcfe, in 2008. The significant fluctuations between settlements of receipts on our derivative financial instruments demonstrates the aforementioned volatility in prices.
We expect to continue our comprehensive derivative financial instrument program as part of our overall acquisition and financing strategy to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure. In connection with our acquisitions, we typically hedge a portion of future production acquired in order to lessen the variability of our returns on shareholders equity and to protect our shareholders equity by supporting our ability to meet our debt service obligations and stabilize cash flows.
In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal through February 14, 2010 at LIBO rates ranging from 2.45% to 2.8%. For the year ended December 31, 2009, we had realized losses from settlements of $12.2 million and $2.0 million of cumulative non-cash unrealized losses attributable to our interest rate swaps. For the year ended December 31, 2008, we had realized gains from settlements of $0.6 million and $9.9 million of non-cash unrealized losses attributable to our interest rate swaps. Our interest rate derivative financial instruments terminated as of February 14, 2010.
The following table presents a reconciliation of our income tax provision (benefit) for the years ended December 31, 2009, 2008 and 2007.
During 2009, our income tax rate was impacted by the recognition of valuation allowances against deferred tax assets, which were primarily due to ceiling test write-downs that caused previous book basis and tax basis differences to change from deferred tax liabilities to deferred tax assets and divestitures of properties.
During 2008, our income tax rate was impacted by the establishment of valuation allowances against deferred tax assets, which were primarily due to ceiling test write-downs that caused previous book basis and tax basis differences to change from deferred tax liabilities to deferred tax assets. Our deferred tax assets were offset by valuation allowances after testing to determine if the asset would meet a more likely than not criteria for realization pursuant to FASB ASC Topic 740- Income Taxes.
During 2007, our income tax rate was impacted by the substitution of a current federal net operating loss carryback for previously claimed foreign tax credits resulting from the 2005 sale of our Canadian subsidiary. The impact, net of a federal refund of $6.1 million, was an $11.0 million non-cash expense, principally related to foreign tax credits which are required since we no longer have any foreign operations.
Also, as a result of our 2007 acquisitions, our state effective rate increased which required us to change the rate in which we record our deferred tax assets and liabilities. This amount was recognized in our 2007 income tax expense as a current period expense and is presented as part of the Other line item presented above.
EXCO files income tax returns in the U.S. federal jurisdictions and various state jurisdictions. With few exceptions, EXCO is no longer subject to U.S. federal and state and local examinations by tax authorities for years before 2004. The Internal Revenue Service, or IRS, completed its examination of EXCOs 2004 U.S. federal income tax return in January 2008. The result of the audit was an adjustment between U.S. and our Canadian subsidiary for a hedge recorded to the wrong entity. There was no material change to EXCOs financial position.
The Company adopted the provisions of FASB ASC Subtopic 740-10 for Income Taxes on January 1, 2007. As a result of ASC Subtopic 740-10, the Company recognized zero liabilities for unrecognized tax benefits. As of December 31, 2009, 2008 and 2007, the Companys policy is to recognize interest related to unrecognized tax benefits of interest expense and penalties in operating expenses. The Company has not accrued any interest or penalties relating to unrecognized tax benefits in the current financials.
Liquidity, capital resources and capital commitments
Our financial strategy is to use a combination of cash flow from operations, bank financing, cash received from joint ventures, proceeds from sales of oil and natural gas properties and the issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. Prior to 2009, we used acquisitions of producing properties and vertical drilling of development wells in established basins as our primary vehicle for growth. These acquisitions provided us with substantial acreage with deep rights in shale resource plays, and our recent success using horizontal drilling in the Haynesville shale in East Texas/North Louisiana has created significant growth opportunities in the area, as well as in the Bossier shale play in East Texas/North Louisiana and the Marcellus shale play in Appalachia. These additional opportunities have resulted in a shift in our focus from an acquisition-oriented strategy to horizontal drilling, development and exploitation activities. As a result of the BG Upstream Transaction in August 2009, we increased our drilling and leasing activities within the BG AMI. Pursuant to the Joint Development Agreement, or JDA, with BG Group, BG Group also agreed to fund 75% of our 50% interest in deep drilling projects up to a total of $400.0 million. As a result of this carried amount, our required capital expenditures will be substantially reduced during the carried period, which we project will extend through 2011. As of December 31, 2009, approximately $367.7 million remains unfunded by BG Group under the carry provisions of the JDA.
Cash flows from operations and unused borrowing capacity under our revolving credit agreements represent the primary source of liquidity to fund our operations and our capital expenditure programs. The primary factors impacting our cash flow from operations include (i) levels of production from our oil and natural gas properties, (ii) prices we receive for sales of oil and natural gas production, including settlement proceeds or payments related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs for our general and administrative activities and (v) interest expense and other financing related costs. The following table presents our liquidity and financial position as of December 31, 2009 and February 12, 2010:
Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility and the use of derivative financial instruments to mitigate price fluctuations Prices for natural gas experienced significant declines beginning in the third quarter of 2008 and remained at low levels throughout 2009. As a result of these low prices, we suspended many of our vertical drilling projects as economics did not meet our internal rate of return objectives. The following table presents a comparison of our existing 2010 capital budget to our 2009 activities.
In the fourth quarter of 2008, we commenced a program to divest various oil and natural gas assets across our entire portfolio and engaged several different brokers to assist with these divestitures. This divestiture program, combined with the BG Upstream Transaction and the BG Midstream Transaction, resulted in cash proceeds of approximately $2.1 billion, after customary closing and post-closing adjustments and provided us with substantial liquidity. We used these proceeds to pay down debt on both of our revolving credit facilities and pay off our Term Credit Agreement. As of December 31, 2009, we had reduced our consolidated outstanding debt to $1.2 billion, a reduction of $1.8 billion from the December 31, 2008 debt levels. However, our oil and natural gas production, results of operations and future liquidity from operations will be reduced in the near term as a result of asset sales and the reduced interest in properties sold to the BG Group.
We generally do not establish a budget for acquisitions, as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit agreements is subject to restrictions imposed by our lenders and the indenture governing our 7 1/4% Senior Notes due January 15, 2011, or Senior Notes, contains restrictions on incurring indebtedness and pledging our assets. In addition, disruptions in the credit and capital markets have limited the availability of financing to fund acquisitions. Any future acquisitions will more than likely be focused on supplementing our shale resource holdings in our East Texas/North Louisiana and Appalachia areas as economic conditions permit.
As of December 31, 2009, the aggregate borrowing bases under our credit agreements, after the October 2009 borrowing base redeterminations, totaled $1.3 billion, of which $747.6 million was drawn. In addition, we have $444.7 million outstanding under our Senior Notes due on January 11, 2011.
The U.S. House of Representatives has adopted legislation to control and reduce GHGs. The U.S. Senate is working on similar legislation. Although it is not possible at this time to predict whether or when any such legislation will emerge from Congress, any laws or regulations that may be adopted to restrict or reduce GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce. The EPA has also taken recent action related to GHGs that would require large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions. Although this rule does not limit the amount of GHGs that can be emitted, it could require us to incur costs to monitor, recordkeep and report emissions of GHGs associated with our operations.
Recent events affecting liquidity
The capital and credit markets remained constrained and unpredictable throughout 2009. Actions taken by the United States government and Federal Reserve in 2008 and 2009 through enacted legislation and
implementation of various programs have had only limited impact in stabilizing the credit markets and promoting liquidity in financial institutions. The impacts of these actions, some of which have not yet been fully implemented, on our industry and on us, are not determinable at this time, nor can we determine the length of time that credit markets will remain constrained, and the ultimate impact on our ability to access capital is expected to be equally uncertain.
In addition to the turmoil in the credit markets and related uncertainties, prices for natural gas suffered a precipitous decline beginning in the third quarter of 2008 and has continued throughout 2009. As of February 12, 2010, the spot prices for oil and natural gas were $74.13 per Bbl and $5.53 per Mmbtu compared with $79.36 per Bbl and $5.79 per Mmbtu as of December 31, 2009. NYMEX future prices for oil and natural gas have also remained depressed throughout 2009, reflecting anticipated decreased domestic and worldwide demand for oil and natural gas as a result of the global recession and uncertainties about the depth and length of the recession and the timing of a recovery. Each of the aforementioned events could impact our near-term, and perhaps long-term, liquidity and operating revenues resulting in changes to business plans or operations. As discussed in greater detail under Item 3. Quantitative and Qualitative Disclosures About Market Risk, we use derivative financial instruments to mitigate commodity price fluctuations and interest rate fluctuations to manage our debt service requirements.
Our proposed capital budget for 2010 reflects targeted capital expenditures. As in 2009, our 2010 capital program will focus on Haynesville/Bossier shale plays in East Texas/North Louisiana and we will begin to exploit the Marcellus shale play in Appalachia. Our 2009 asset sales and reduced ownership interest in East Texas/North Louisiana properties arising from the BG Upstream Transaction, will impact our production volumes in future periods. However, the provision in the JDA for the BG Group to fund 75% of our share of drilling and development costs on new Haynesville and other deep rights wells spud after closing, up to a total of $400.0 million, will allow us to accelerate our development of the Haynesville shale play while continuing to reduce our development cost per Mcf. While our recent debt reduction combined with the value created by the carried portion of capital expenditures are favorable as they relate to our reliance on available credit, the credit markets remain an area of concern.
Our 7 1/4% senior notes with a principal balance of $444.7 million mature on January 15, 2011. We believe that our cash flows from operations and amounts available to us under our credit facilities will provide us with sufficient liquidity to pay-off the 7 1/4% senior notes at maturity. Alternatively, we believe current market conditions may provide an opportunity to refinance the Senior Notes if necessary.
Despite the ongoing problems and uncertainties existing in the capital and credit markets and commodity prices, we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities, reduced capital expenditures and remaining borrowing capacity under our credit agreements will be adequate to meet the cash requirements to fund our operations, debt service obligations and our 2010 capital expenditure programs As discussed above, our 2009 divestiture program and BG Group joint venture transactions, generated approximately $2.1 billion is cash proceeds, which enabled us to reduce our bank debt by $1.8 billion during 2009 and will substantially reduce our debt service requirements in 2010. Our future cash flows are subject to a number of variables including production volumes, oil and natural gas prices and drilling and service costs.
Significant acreage acquisitions may also have an impact on our near term liquidity as these types of acquisitions may cause an increase in our outstanding debt without any immediate cash flows or increases in our borrowing base in our credit agreements.
Divestitures and related transactions
During 2009, we implemented our previously announced asset divestiture program to sell certain non-strategic oil and natural gas assets and pursue a potential joint venture to accelerate development of our considerable acreage holdings in East Texas/North Louisiana in the Haynesville and Bossier shale plays. The following table summarizes the results of our 2009 divestitures and joint venture transactions:
On August 11, 2009, we closed on sales of assets contained within the East Texas Transaction and the Mid-Continent Transaction with Encore for aggregate cash proceeds of approximately $352.0 million, after final closing adjustments. The oil and natural gas properties sold included (i) all of EXCOs interests in its Gladewater area and Overton field in Gregg, Upshur and Smith counties in East Texas, or the East Texas Properties, and (ii) certain oil and natural gas properties in the Mid-Continent region of Oklahoma, Kansas and the Texas Panhandle, or the Mid-Continent Sale, collectively the Encore Transactions.
BG Group transactions
On August 14, 2009, we closed on the BG Upstream Transaction and the BG Midstream Transaction representing the sale of an undivided 50% interest in certain oil and natural gas properties in East Texas/North Louisiana and a 50% interest in certain midstream operations, respectively, in East Texas/North Louisiana for aggregate proceeds of approximately $983.0 million, after final closing adjustments.
In addition, BG Group will fund 75% of our capital expenditures on certain drilling and completion activities within the AMI until the aggregate of such expenditures equals $400.0 million, or the BG Group Carry. The BG Group Carry is expected to be fully funded in 2011 or 2012. If BG Group defaults in the payment of the BG Group Carry, then EXCO has the right to require BG Group to reassign to EXCO a proportionate percentage of BG Groups interest in the deep rights within the AMI. Upon the reassignment, the BG Group Carry will terminate.
Other than the BG Group Carry, each party will be responsible for its share of the costs and expenses associated with exploring, developing and producing the oil and natural gas assets in the AMI. To facilitate
funding these costs and expenses and to provide security to each party, BG Group and EXCO have agreed to fund periodically an escrow account created by the parties with an amount equal to estimates of certain future expenses for the following three month period. In addition to this three month deposit, EXCO has agreed to fund one additional month of development costs into the escrow account and three additional months of operating expenses into the escrow account.
On November 10, 2009 we closed on the sale of most of our remaining oil and natural gas assets located in the Mid-Continent region to Sheridan Holding Company I, LLC for cash proceeds of $531.4 million, subject to final closing adjustments. Proceeds from the sale were primarily used to reduce balance outstanding under the EXCO Resources Credit Agreement.
On November 24, 2009, we consummated the sale of certain Ohio and Northwestern Pennsylvania shallow producing oil and natural gas properties to EV Energy Partners, L.P. and related entities. Total cash proceeds from the sale were $129.7 million, subject to final closing adjustments and receipt of $13.1 million of properties sold subject to receipt of required consents. Proceeds from the sale were primarily used to reduce the balances outstanding under the EXCO Resources Credit Agreement.
Historical sources and uses of funds
Cash flows from operations
Our operating cash flows are driven by the quantities of our production of oil and natural gas and the prices received from the sale of this production and revenue generated from our midstream operating activities. Prices of oil and natural gas have historically been very volatile and can significantly impact the cash from the sale our oil and natural gas production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of oil and natural gas property operating costs, severance and ad valorem taxes, interest on our indebtedness, general and administrative expenses and taxes on income.
Net cash provided by operating activities was $433.6 million for the year ended December 31, 2009 compared with $975.0 million for the year ended December 31, 2008. The 55.5% decrease is attributable primarily to net cash from decreased production resulting from oil and natural gas property divestitures in 2009 and from lower average oil and natural gas prices in 2009 compared with average prices for the 2008 year. At December 31, 2009, our cash and cash equivalents balance was $68.4 million and our evergreen escrow account, which is principally used for Haynesville development operations, was $58.9 million. On February 12, 2010, our cash, cash equivalent and restricted cash balance was $142.8 million.
We began paying quarterly dividends of $0.025 per share on our common stock in the fourth quarter of 2009. During the fourth quarter we paid two dividends to our common shareholders which totaled $10.6 million.
Investing activities and transactions
In recent years, a significant amount of our growth has been through acquisitions of existing producing and non-producing oil and natural gas properties and related assets. These acquisitions have been funded to a great extent by borrowings under credit agreements and term loan agreements, as well as issuance of equity. As discussed above, the deterioration in the U.S. and worldwide credit and equity markets has significantly diminished our ability to fund additional growth in the near term through these capital sources.
Acquisitions and capital expenditures
The following table presents our capital expenditures and acquisitions for the years ended December 31, 2009, 2008 and 2007.
Our 2009 acquisitions emphasized undeveloped acreage. Our 2008 and 2007 acquisitions were principally producing and undeveloped oil and natural gas properties.
During 2008, we completed the acquisitions of oil and natural gas properties, undeveloped acreage and other oil and natural gas assets totaling $766.3 million. These acquisitions included the Appalachian Acquisition, the New Waskom Acquisition and the Danville Acquisition.
In addition to these acquisitions of producing oil and natural gas properties and midstream assets, during the second and third quarters of 2008, we conducted two leasing programs of undeveloped acreage in East Texas/North Louisiana and Appalachia to exploit the Haynesville, Marcellus and Huron shales. In Appalachia, our existing shallow production areas and newly acquired leasehold interests hold deep rights in the Marcellus and Huron shale formations. Similarly, in East Texas/ North Louisiana, our existing production areas and newly acquired leasehold interests hold deep rights in the Haynesville/Bossier shale play. We spent approximately $64.9 million in the Haynesville/Bossier shale plays in East Texas/North Louisiana and approximately $92.1 million in the Marcellus and Huron shale plays in the Appalachia region of the United States during 2008.
During 2007, we consummated acquisitions of oil and natural gas properties and undeveloped acreage totaling $2.47 billion, including the Vernon Acquisition and the Southern Gas Acquisition.
2010 Capital budget
Our capital expenditures budget for 2010 will continue to emphasize development of our significant shale resources in the Haynesville Shale play in East Texas/North Louisiana in conjunction with our joint venture with BG Group and increased emphasis of our significant acreage holdings covering the Marcellus Shale play in Appalachia.
The 2010 capital expenditures emphasize horizontal shale development in East Texas/North Louisiana and in Appalachia. Presently, we have budgeted approximately $471.4 million for capital expenditures in 2010, of which we are contractually obligated to spend $70.7 million as of December 31, 2009. We expect to utilize our current cash balances, including funds which we have already placed in our restricted accounts to fund Haynesville development, cash flow generated from operations and available funds under our credit agreements in 2010 to fund capital expenditures and acquisitions, if any. The capital budget for 2010 reflects a 7.8% decrease
from 2009 actual capital expenditures, excluding acquisitions of approximately $233.6 million. The 2010 capital budget of $471.4 million is net of approximately $205.1 million of BG Carry covering our interests in certain drilling and completion costs in East Texas/North Louisiana.
Future cash flows are subject to a number of variables including production volumes, fluctuations in oil and natural gas prices and our ability to service the debt incurred in connection with our acquisitions. If cash flows decline we may be required to further reduce our capital expenditure budget, which in turn may affect our production in future periods. Our cash flow from operations and other capital resources may not provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures.
Credit agreements and long-term debt
As of February 12, 2010, we have total debt outstanding aggregating $1.2 billion consisting of two credit agreements and Senior Notes of $444.7 million due in January 2011. Terms and considerations of each of the debt obligations are discussed below. We are presently in discussions with our banking group to consolidate our two credit agreements into one facility.
EXCO Resources Credit Agreement
The EXCO Resources Credit Agreement, pursuant to the fifth amendment effective on October 2, 2009, has a borrowing base of $450.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. The borrowing base is redetermined semi-annually, with EXCO and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. Borrowings under the EXCO Resources Credit Agreement are collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO may have in place derivative financial instruments covering no more than 80% of its forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Resources Credit Agreement matures on March 30, 2012.
The fifth amendment to the EXCO Resources Credit Agreement, among other things, modified the terms and conditions under which EXCO is permitted to pay a cash dividend on its common stock. Pursuant to the fifth amendment, EXCO may declare and pay cash dividends on its common stock in an amount not to exceed $50.0 million in any four consecutive fiscal quarters, provided that as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) EXCO has at least 10% of its borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under EXCOs 7 1/4% Senior Notes Indenture.
The EXCO Resources Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for agreements of this type. The interest rate ranges from LIBOR plus 175 basis points, or bps, to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage.
On February 12, 2010, we had $81.5 million of outstanding indebtedness and $353.3 million of available borrowing capacity under the EXCO Resources Credit Agreement. On February 12, 2010, the one month LIBOR was 0.23%, which would result in an interest rate of approximately 1.98% on any new indebtedness we may incur under the EXCO Resources Credit Agreement.
As of December 31, 2009, EXCO was in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:
The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement.
EXCO Operating Credit Agreement
The EXCO Operating Credit Agreement, as amended, currently has a borrowing base of $850.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. The borrowing base is redetermined semi-annually, with EXCO Operating and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. The EXCO Operating Credit Agreement is secured by a first priority lien on the assets of EXCO Operating, including 100% of the equity of EXCO Operatings subsidiaries, and is guaranteed by all existing and future subsidiaries of EXCO Operating. EXCO Operating may have in place derivative financial instruments covering no more than 80% of the forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO Operating is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Operating Credit Agreement matures on March 30, 2012.
On October 16, 2009, the lenders agreed to consents which (i) confirmed the borrowing base under the EXCO Operating Credit Agreement at $850.0 million until the next borrowing base redetermination date, (ii) provided for EXCO Operating to grant to lenders a first priority lien and security interest in all of its equity interest in TGGT, representing EXCO Operatings retained 50% interest in the midstream assets contributed in connection with the BG Midstream Transaction, and (iii) by November 30, 2009, consummate transactions to unwind oil and natural gas derivatives with respect to notional volumes of oil and natural gas with respect to sold production volumes which had been waived by a July 29, 2009 consent.
The EXCO Operating Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for agreements of this type. The interest rate ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an ABR pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage.
On February 12, 2010, we had $666.1 million of outstanding indebtedness and $183.9 million available borrowing capacity under the EXCO Operating Credit Agreement. On February 12, 2010, the one month LIBO rate was 0.23%, which would result in an interest rate of approximately 2.48% on any new indebtedness we may incur under the EXCO Operating Credit Agreement.
As of December 31, 2009, EXCO Operating was in compliance with the financial covenants contained in the EXCO Operating Credit Agreement, which require that EXCO Operating:
The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Operating Credit Agreement.
Term Credit Agreement
On December 8, 2008, EXCO Operating entered into a $300.0 million senior unsecured term credit agreement with an aggregate balance of $300.0 million. Net proceeds from the loan of $274.4 million, after bank fees and expenses, were used to repay and terminate an original $300.0 million senior unsecured term credit agreement that was scheduled to mature on December 15, 2008. In addition to the fees incurred upon the closing of the Term Credit Agreement, EXCO Operating provided for additional fees on unpaid principal amounts, or duration fees, as defined in the agreement. These included a 5% fee on the unpaid principal on June 15, 2009 and an additional 3% fee on any unpaid outstanding balance as of September 15, 2009. On June 15, 2009 we remitted the first duration fee payment of $15.0 million
In connection with the closings of the BG Upstream Transaction and the BG Midstream Transaction on August 14, 2009 and the East Texas Transaction on August 11, 2009, EXCO Operating repaid the Term Credit Agreement. As a consequence of the early payment of the unsecured term loan, EXCO Operating avoided payment of a $9.0 million duration fee that would have been due on September 15, 2009.
The unamortized balance of deferred financing costs attributable to the Term Credit Agreement of approximately $9.9 million was written off and is included in interest expense in the year ended December 31, 2009.
7 1/4% senior notes due January 15, 2011
As of December 31, 2009, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at December 31, 2009 was $4.0 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $445.8 million on December 31, 2009.
Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year. Effective January 15, 2007, we may redeem some or all of the Senior Notes for the redemption price set forth in the Senior Notes. On January 15, 2010, we paid $16.1 million of interest on the Senior Notes. Another interest payment of $16.1 million will be due on July 15, 2010. We presently have sufficient borrowing capacity under the EXCO Resources Credit Agreement and the EXCO Operating Credit Agreement to pay the Senior Notes.
The indenture governing the Senior Notes contains covenants, which limit our ability and the ability of our guarantor subsidiaries to:
We paid cash dividends totaling $82.8 million to the holders of our Preferred Stock between January 1, 2008 and July 18, 2008, the date upon which the Preferred Stock was converted into our common stock. On July 18, 2008, we converted all outstanding shares of our Preferred Stock into a total of approximately 105.2 million shares of our common stock. The conversion of the Preferred Stock has the effect of increasing the book value of shareholders equity by approximately $2.0 billion. We also paid all accrued but unpaid dividends in cash totaling approximately $12.8 million to the holders of the converted shares of Preferred Stock as of July 18, 2008. After July 18, 2008, dividends ceased to accrue on the Preferred Stock and all rights of the holders with respect to the Preferred Stock terminated, except for the right to receive the whole shares of common stock issuable upon conversion, accrued dividends through July 18, 2008 and cash in lieu of any fractional shares. The conversion of all outstanding shares of Preferred Stock into common stock eliminated our obligation to pay quarterly cash dividends of $35.0 million, resulting in annual dividend savings of $140.0 million.
Derivative financial instruments
We use oil and natural gas derivatives and financial risk management instruments to manage our exposure to commodity price and interest rate fluctuations. We do not designate these instruments as hedging instruments for financial accounting purposes, and, as a result, we recognize the change in the respective instruments fair value currently in earnings, as a gain or loss on oil and natural gas derivatives and interest expense on financial risk management instruments.
Oil and natural gas derivatives
Our production is generally sold at prevailing market prices. However, we periodically enter into oil and natural gas contracts for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets.
Our objective in entering into oil and natural gas derivative contracts is to mitigate the impact of price fluctuations and achieve a more predictable cash flow associated with our acquisition activities and borrowings under our credit agreements. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. As of December 31, 2009, we had contracts in place for the volumes and prices shown below:
Interest rate swaps
In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal through February 14, 2010 at LIBO rates ranging from 2.45% to 2.8%. For the year ended December 31, 2009, we had realized losses from settlements of $12.2 million. The fair value of our interest rate swaps was a liability of $2.0 million as of December 31, 2009.
Off-balance sheet arrangements
Contractual obligations and commercial commitments
The following table presents a summary of our contractual obligations at December 31, 2009:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 3 to its annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
INDEX TO EXHIBITS