EXCO Resources, Inc. Reports Second Quarter 2009 Results

EXCO Resources, Inc. (NYSE:XCO) today announced its second quarter 2009 results of operations. Highlights during the quarter include:

• Oil and natural gas production was 36.5 Bcfe, or 401 Mmcfe per day for the second quarter 2009 compared with 35.9 Bcfe, or 394 Mmcfe per day during the second quarter 2008. Results from our Haynesville shale operations contributed 43 Mmcf per day of net production, which more than offsets the impacts of our reduced conventional drilling and the effects of asset sales closed during the second quarter of 2009.
• Oil and natural gas revenues, as adjusted for the cash settlements of our derivative financial instruments (derivatives), were $288 million for the second quarter 2009 compared with $338 million for the second quarter 2008. The lower revenues reflect realized price declines of 68% for natural gas and 54% for oil from the prior year’s second quarter, which were largely offset by the cash settlements of our derivatives. Oil and natural gas revenues for the second quarter 2009 were $146 million, exclusive of the impacts of derivatives, compared with the second quarter 2008 oil and natural gas revenues of $429 million.
• Adjusted net income available to common shareholders, a non-GAAP measure adjusting for unrealized derivative gains and losses and other non-cash items typically not included by securities analysts in published estimates, was $0.29 per diluted share for the second quarter 2009. While down from the $0.34 per diluted share for the second quarter 2008, adjusted net income increased from $0.19 per diluted share for the first quarter 2009.
• Adjusted EBITDA, defined as earnings before interest, taxes, depreciation, depletion and amortization, and other non-cash income and expense items (a non-GAAP measure) for the second quarter 2009 was $210 million compared with $263 million in the second quarter 2008.
• Midstream operating profit, before the effect of intercompany eliminations, was $9 million for the second quarter 2009, compared with $12 million in the prior year’s second quarter. Almost all of the decreased operating profit in the midstream operations was due to lower revenue from natural gas and condensate sales resulting from lower commodity prices.
• We announced a joint venture with BG Group in a large area of mutual interest which contains most of our oil and natural gas assets in our East Texas/North Louisiana area, excluding the Vernon Field, and 50% of our related midstream assets. Cash proceeds are expected to be approximately $900 million, plus estimated closing cost adjustments, and closing is expected in the third quarter 2009. BG Group will also fund $400 million of future capital attributable to our 50% interest, with BG Group paying 75% of our share of drilling and completion costs related to the Haynesville and Bossier shales until the $400 million commitment is satisfied. Production from the 50% interest in the assets to be sold to BG Group was 69 Mmcfe per day for the second quarter of 2009.
• Our asset divestiture program activities gained significant traction during the second quarter 2009. During the quarter, we closed $51 million of asset sales representing 9 Mmcfe per day of net production. We expect to close over $390 million of additional asset sales in the third quarter 2009, including the previously announced sales of assets in East Texas and our Mid-Continent regions to an affiliate of Encore Acquisition Company for $375 million. Production from these assets was 36 Mmcfe per day for the second quarter of 2009. We also have certain of our non-strategic Appalachian assets located in Ohio and Northwest Pennsylvania for sale which produced 16 Mmcfe per day for the second quarter of 2009.
• In light of the continuing success of our Haynesville shale development and the expected closing of the joint venture with BG Group, we expect to increase our development drilling and leasing activities in East Texas/North Louisiana. We now plan on drilling 37 operated Haynesville wells as compared to our original budget of 27 operated wells in 2009. Although our level of activity will increase, our actual capital expenditures for 2009 will remain at approximately $500 million as a result of BG Group funding 75% of our costs on deep drilling. If the estimated purchase price adjustment for capital expenditures since the effective date of the transactions with BG Group is considered, our 2009 captial expenditures would be approximately $360 million.

Douglas H. Miller, EXCO’s Chairman and CEO, commented, "The second quarter of 2009 was one of outstanding accomplishments for EXCO. On June 30, 2009 we announced East Texas/North Louisiana upstream and midstream joint ventures with BG Group which will result in approximately $900 million in cash plus closing adjustments, with an additional $400 million invested over the next 2-3 years in the form of drilling and completion funding equal to 75% of our capital expenditures for deep wells. We are very pleased to have BG Group as a partner. This partnership with BG Group, given their strong technical, business and financial capabilities, will allow us to ramp up our exploration and development and midstream activities in East Texas/North Louisiana, particularly in the Haynesville and Bossier shales, and will also enhance our gas marketing activities.

In addition to our joint venture announcement and our asset divestitures, we continued to realize outstanding drilling results in the Haynesville shale. We have completed 11 Haynesville horizontal wells this year, of which seven were in the second quarter. Our average operated completions in DeSoto Parish, Louisiana this year have resulted in initial production rates of 24 million cubic feet of natural gas per day. We also completed a successful horizontal Haynesville well in Caddo Parish.

For the remainder of 2009, we will continue increasing our drilling and completion activity in the Haynesville shale as we plan to drill an additional 26 operated wells. We will also continue to evaluate our strong Marcellus shale position in Appalachia by drilling test wells, building our operating staff and developing our plans for 2010 and beyond. Activities in other areas will be dependent upon a strengthening of commodity prices.”

For the six months ended June 30, 2009, adjusted net income available to common shareholders was $0.48 per diluted share compared with adjusted net income of $0.45 per dilutive share for the six months ended June 30, 2008. Adjusted EBITDA for the six months ended June 30, 2009 was $405 million compared with $517 million for the six months ended June 30, 2008, a decrease of approximately 22% due primarily to lower commodity prices in 2009.

Equivalent production for the six months ended June 30, 2009 was 72.9 Bcfe, an increase of 3% from the prior year’s six month period equivalent production of 71.0 Bcfe. The increase in production reflects the impacts from our Haynesville drilling program which more than offset decreases attributable to suspension of our vertical drilling activities, normal decline in our other operating areas and sales of assets during the six months ended June 30, 2009.

The average price per barrel of oil, excluding derivatives, was $46.34 per Bbl for the six months ended June 30, 2009 compared with $109.21 for the prior year’s six month period. The average natural gas price, excluding derivatives for the six months ended June 30, 2009 and 2008 was $4.07 and $9.87 per Mcf, respectively, a decrease of approximately 59%.

Net Income

Our reported net loss and net loss available to common shareholders shown below, both GAAP measures, include certain items not typically included by securities analysts in their published estimates of financial results. Management is disclosing the non-GAAP measures of adjusted net income and adjusted net income available to common shareholders because it quantifies the financial impact of non-cash gains or losses resulting from derivatives, non-cash ceiling test write-downs and other items management believes affect the comparability of our results of operations which are included in GAAP net income measures. The following table provides a reconciliation of our net loss and net loss available to common shareholders to non-GAAP measures of adjusted net income and adjusted net income available to common shareholders:

(1) The assumed income tax rate is 40% for all periods.

(2) Deferred tax valuation allowance has been adjusted to reflect impacts of adjustments.

(3) Per share amounts are based on weighted average number of common shares outstanding.

(4) Represents dilution per share attributable to common stock equivalents from in-the-money stock options for periods with adjusted net income available to common shareholders, along with any impact of dilutive preferred stock. Preferred stock was dilutive to adjusted net income for the three months ended June 30, 2008. Therefore, the assumed conversion of preferred stock and related $35 million dividend savings are included in the diluted earnings per share computation. Diluted income per share for the six months ended June 30, 2008 is computed using the weighted average common stock and dilutive stock options. The assumed conversion of preferred stock for the six months ended June 30, 2008 is not included in the diluted per share computation as those shares are antidilutive. The preferred stock was converted into common stock in the third quarter of 2008, therefore there is no impact in 2009.

Operations activity and outlook

We spent $85 million on development and exploitation activities, drilling and completing 22 gross (13.7 net) wells in the second quarter 2009, compared with 34 gross (27.9 net) wells during the first quarter 2009. We had an overall drilling success rate of 100% for the second quarter 2009. Our total capital expenditures, including leasing, midstream and corporate activities, were $124 million in the second quarter 2009. As commodity prices declined beginning in the third quarter 2008, we reduced our drilling activities. We currently have 8 drilling rigs operating across our portfolio, which we have reduced from 32 drilling rigs late in the third quarter 2008 in response to lower commodity prices. Although we expect our third and fourth quarter 2009 leasing, drilling and completion activities in East Texas and North Louisiana area to increase, our actual corporate expenditures for 2009 will remain at approximately $500 million as a result of the effects of the sale of 50% of our interest to BG Group combined with the impact of BG Group’s funding of 75% of our interest in deep projects. We will continue to focus our capital expenditures in areas that will provide strong returns in the current commodity price environment.

We are continuing with plans to sell certain non-strategic assets during 2009. We completed asset sales of approximately $56 million through June 2009 and expect cash proceeds from asset sales and joint ventures in excess of $1.3 billion in the third quarter 2009. Proceeds of all sales or joint ventures will be used to reduce debt and allow more capital to be focused on our shale development and other activities.

East Texas/North Louisiana

East Texas/North Louisiana is our largest division in terms of production and reserves, and our primary targets across this region include the Haynesville shale, the upper and lower Cotton Valley, Travis Peak, Pettet and Hosston formations. Currently, our emphasis is exploitation of our Haynesville shale play position. In East Texas/North Louisiana, we drilled and completed 19 gross (11.7 net) wells in the second quarter 2009.

Haynesville Shale

During the second quarter 2009, our horizontal Haynesville Shale development program yielded exceptional results with some of the highest production rates in the play. We also achieved significant improvements in operational efficiencies. We completed 7 gross (4.1 net) operated horizontal Haynesville wells during the second quarter 2009, and have 2 gross (0.9 net) currently in the completion phase and 6 gross (4.5 net) drilling. Our average initial production rates in DeSoto Parish were 24 Mmcf per day for wells completed during the second quarter, with a range of 21.2 – 26.4 Mmcf per day. We utilized four operated drilling rigs and one operated spudder rig in the quarter and expect to add three additional drilling rigs during the third quarter 2009.

We also participated in 3 gross (0.7 net) non-operated wells in DeSoto Parish, Louisiana with initial production rates ranging from 14.4 to 24.5 Mmcf per day and 1 gross (0.3 net) well in Caddo Parish, Louisiana with an initial production rate of 10.2 Mmcf per day. At the end of the second quarter, we had interests in 2 gross (0.1 net) non-operated horizontal Haynesville shale wells, 1 in the drilling phase and 1 in the completion phase.

We currently have 12 gross (8.4 net) operated horizontal wells and 6 gross (1.2 net) non-operated horizontal wells flowing to sales. Production from our Haynesville wells recently reached a combined gross rate of 174 Mmcf per day (72 Mmcf per day net).

Our DeSoto Parish area has yielded some of the highest production rates in the entire play. The EXCO operated average initial production in DeSoto Parish is 24 Mmcf per day, with all of our wells having initial production rates in excess of 21 Mmcf per day. This high level of performance over a broad area underscores the consistency and high quality of the shale reservoir on our acreage and also demonstrates the effectiveness of our target selection and completion design. Our initial wells were completed with 9-10 frac stages and our most recent wells have been completed with 12-14 frac stages to maximize reserves and production by providing more contact with the fractured shale reservoir.

Our drilling times are improving and considerable operational efficiencies have been made. Our initial wells took 70 - 75 days from spud to rig release and our last five wells have taken an average of 48 days from spud to rig release. Our lateral lengths are now typically 4,500 feet and are designed to maximize the length in the target interval. Our completion operations are initiated immediately following rig release, and our pipeline construction runs parallel to our drilling operations. All of our operated wells have flowed to sales immediately following completion operations due to close coordination with our midstream business. Our midstream activity is progressing as planned with construction of a 36-inch pipeline header system and associated treating facilities. The 36-inch header system is designed to flow both EXCO and third party gas. We have firm transportation of 370 Mmcf per day in the immediate area, including our new commitments on a recently announced third party pipeline project scheduled to be completed in late 2009. We are well positioned in the play and have considerable growth potential with over 4.5 Tcf of potential Haynesville shale reserves.

Cotton Valley

In the second quarter 2009, we drilled 7 gross (5.2 net) Cotton Valley wells. Of the 7 gross wells, 1 gross (1.0 net) was in our Vernon area and 6 gross (4.2 net) were in the Holly field area. With current natural gas prices at the lowest levels in several years, we have elected to suspend most of the operated Cotton Valley drilling.

Appalachia

In Appalachia, we hold in excess of 1.0 million net leasehold acres. Our major operating areas include Pennsylvania, Ohio, and West Virginia, where we historically drilled for the Clinton/Medina sandstone, stacked Devonian sandstone, Devonian shale, Berea shale and other productive horizons. Included as a subset of our extensive acreage position, we now control approximately 361,000 acres in the Marcellus shale fairway, with more than 215,000 acres located in the core area of the over pressured Marcellus. A significant percentage of this fairway acreage is held by production (HBP) by our shallow producing assets. Also as a subset of our acreage position, 130,000 acres (70% HBP) exist within the Huron Shale play of West Virginia. We believe our present leasehold position in the Marcellus and Huron Shale fairways contains between 7 to 12 TCF of potential reserves. Throughout 2009, our technical Marcellus activity is focused on integrating our 2008 Marcellus well results and seismic data, delineating our acreage blocks using our updated geological model and drilling and completing test wells to high grade for a 2010 development program.

Other

We drilled and completed 2 gross (1.5 net) wells in our Permian area Canyon Sand field during the second quarter 2009 resulting in a 100% success rate. One of these wells helped earn approximately 11,000 net contiguous acres under a joint venture. We continue to evaluate 3-D seismic over approximately 35,000 net acres adjacent to our Canyon Sand field and hold approximately 77,000 net acres in the area.

Our Mid-Continent division production averaged approximately 63 Mmcfe per day during the second quarter 2009. In the Mid-Continent, we drilled and completed 1 gross (0.5 net) wells during the second quarter 2009. Based on current commodity prices, we have suspended most operated drilling in these regions.

Midstream

Throughput on our transportation and gathering systems in East Texas/North Louisiana averaged 598 Mmcf per day for the second quarter 2009, up from 554 Mmcf per day in the fourth quarter 2008. In 2009, we are focused on the installation of our Haynesville Header system, which will be strategically located near our Haynesville shale development in northwest Louisiana. Some phases of the project are expected to be operational in the third quarter 2009. When complete, the system will have throughput capacity of 500 Mmcf per day at 500 psi, expandable to approximately 1.2 Bcf per day with operational changes in line pressure and compression. This pipeline installation program will ensure that EXCO and other third party producers have access to multiple gas markets.

Financial Data

Our consolidated balance sheets as of December 31, 2008 and June 30, 2009, consolidated statements of operations for the three and six months ended June 30, 2009 and 2008 and consolidated statements of cash flows for the six months ended June 30, 2009 and 2008 are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release which have not been previously reconciled.

EXCO will host a conference call on Wednesday, August 5, 2009 at 9:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call 800-309-5788 if you wish to participate and ask for the EXCO conference call ID# 19096480. The conference call will also be webcast on EXCO’s website at www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted on EXCO’s website on Tuesday, August 4, 2009, after market close.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., August 19, 2009. Please call 800-642-1687 and enter conference ID#19096480 to hear the recording. A digital recording of the conference call will also be available on EXCO’s website.

Additional information about EXCO Resources, Inc. may be obtained by contacting EXCO’s Chairman, Douglas H. Miller, or its President, Stephen F. Smith, at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number 214-368-2084, or by visiting EXCO’s website at www.excoresources.com. EXCO’s SEC filings and press releases can be found under the Investor Relations tab.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this presentation, and the risk factors included in the Annual Report on Form 10-K for the year ended December 31, 2008 and our other periodic filings with the SEC.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

The SEC has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms "probable,” "possible,” "potential,” "unproved,” or "unbooked potential,” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2008 available on our website at www.excoresources.com under the Investor Relations tab.

(1) Earnings before interest, taxes, depreciation, depletion and amortization, or "EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. "Adjusted EBITDA” represents EBITDA adjusted to exclude non-cash write-downs of oil and natural gas properties, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivative financial instruments and stock-based compensation expense. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, these measures are used in covenant calculations required under our revolving and term credit agreements and the indenture governing our 7 1/4 % senior notes. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to us. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures.

(2) Excludes non-cash changes in fair value of $1.8 million and $4.0 million for the three and six months ended June 30, 2009, respectively, and $11.0 million and $7.4 million for the three and six months ended June 30, 2008, respectively, for interest rate swaps included in GAAP interest expense.

Cash Flow

Second quarter 2009 cash flow from operations before changes in working capital and settlements of derivative financial instruments with a financing element (adjusted cash flow) was $176 million, a 24% decrease from the prior year’s second quarter due primarily to lower product prices. The following table reconciles cash flow from operations pursuant to GAAP to cash flow without working capital adjustments and derivative settlements with a financing element.

(1) Cash flow from operations before working capital changes and adjustments for settlements of derivative financial instruments with a financing element is presented because management believes it is a useful financial indicator for companies in our industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company’s ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. Operating cash flow is not a measure of financial performance pursuant to GAAP and should not be used as an alternative to cash flows from operating, investing, or financing activities. We have also elected to exclude the adjustment for derivative financial instruments with a financing element as this adjustment simply reclassifies settlements from operating cash flows to financing activities. Management believes these settlements should be included in this non-GAAP measure to conform to the intended measure of our ability to generate cash to fund operations and development activities.