DALLAS--(BUSINESS WIRE)--EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced first quarter results for 2011.
Our first quarter 2011 operating and financial results reflect our increased refinement and innovation in our Haynesville/Bossier shale area and expansion of our Marcellus shale operations. During the quarter, we completed two strategic acreage-intensive acquisitions in Pennsylvania and have expanded our development activities and midstream infrastructure in our Haynesville/Bossier focus areas. Our production and cash flows are increasing and our capital expenditure program is supported by significant available borrowing capacity from our credit agreement, which will result in our achieving significant asset growth. Our financial results follow.
- Adjusted net earnings, a non-GAAP measure adjusting for non-cash gains and losses from derivative financial instruments (derivatives), gains from early termination of derivatives, gains on divestitures, costs we have incurred in connection with a buyout proposal received from our Chairman and Chief Executive Officer and items typically not included by securities analysts in published estimates, were $0.13 per share for the first quarter 2011 compared to $0.15 per share for the first quarter 2010.
- GAAP results were net income of $0.10 per diluted share for the first quarter 2011 compared with net income of $0.54 per diluted share for the first quarter 2010.
- Oil and natural gas production was 37 Bcfe, or 408 Mmcfe per day, for the first quarter 2011 compared with 350 Mmcfe per day in the fourth quarter 2010 and 264 Mmcfe per day in the first quarter 2010.
- Oil and natural gas revenues for the first quarter 2011 were $161 million compared with the first quarter 2010 oil and natural gas revenues of $131 million. Our average sales price per Mcfe decreased by 20% from the prior year period, but was more than offset by a 55% increase in production. When the impacts of cash settlements from our oil and natural gas derivatives are considered, excluding gains from early termination of $38 million in the first quarter 2010, oil and natural gas revenues were $188 million for the first quarter 2011 compared with $170 million for the first quarter 2010.
- Adjusted earnings before interest, taxes, depreciation, depletion and amortization and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the first quarter 2011 were $126 million.
Douglas H. Miller, EXCO’s Chief Executive Officer commented, “We are very pleased with our first quarter results, both financially and operationally. We continue to increase our daily production, averaging 408 Mmcfe per day in the first quarter of 2011, a 17% increase over the fourth quarter of 2010. We have added nearly 200 Mmcfe per day of net production through the drill bit since the beginning of 2010, effectively replacing the production sold in our 2009/2010 divestiture program. Our Haynesville results continue to be very strong and we are beginning to gain real traction in the Marcellus. We completed a significant acquisition of acreage and some production in the prolific northeastern Pennsylvania area in the first quarter and initial drilling and completion results have been very encouraging. We also made an acquisition in our central Pennsylvania development area. In April, we completed an acquisition of approximately 3,500 acres of surface, mineral interests and royalties in the heart of our DeSoto Parish core area of the Haynesville, all within or adjacent to existing producing units which we operate.
“Effective April 1, 2011, we finalized the redetermination of the borrowing base under our Credit Agreement. The borrowing base was increased from $1.0 billion to $1.5 billion, the interest rate was reduced and the Credit Agreement was extended by two years.
“We continue to be very optimistic about our growth potential in our focus areas. We have an outstanding group of managers and employees in all areas and are at the leading edge of technology and operational expertise. We have a significant inventory of high quality drilling locations and a strong balance sheet which enable us to exploit our resources in an aggressive way. We expect 2011 to be a record-setting year in terms of production and reserves.”
Net income
Our reported net income shown below, a GAAP measure, includes certain items not typically included by securities analysts in their published estimates of financial results. The following table provides a reconciliation of our net income to non-GAAP measures of adjusted net income:
| Three months ended | Three months ended | ||||||||||||||||||
| March 31, 2011 | March 31, 2010 | ||||||||||||||||||
| (in thousands, except per share amounts) | Amount | Per share | Amount | Per share | |||||||||||||||
| Net income, GAAP | $ | 21,941 | $ | 115,568 | |||||||||||||||
| Adjustments: | |||||||||||||||||||
| Non-cash mark-to-market (gains) losses on derivative financial instruments | 23,514 | (24,120 | ) | ||||||||||||||||
| Gains from early termination of derivative financial instruments | - | (37,936 | ) | ||||||||||||||||
| Non-recurring other operating items | 2,975 | - | |||||||||||||||||
| Income taxes on above adjustments (1) | (10,596 | ) | 24,822 | ||||||||||||||||
| Adjustment to deferred tax asset valuation allowance (2) | (8,776 | ) | (46,227 | ) | |||||||||||||||
| Total adjustments, net of taxes | 7,117 | (83,461 | ) | ||||||||||||||||
| Adjusted net income | $ | 29,058 | $ | 32,107 | |||||||||||||||
| Net income, GAAP (3) | $ | 21,941 | $ | 0.10 | $ | 115,568 | $ | 0.54 | |||||||||||
| Adjustments shown above (3) | 7,117 | 0.03 | (83,461 | ) | (0.39 | ) | |||||||||||||
| Dilution attributable to stock options (4) | - | - | - | - | |||||||||||||||
| Adjusted net income | $ | 29,058 | $ | 0.13 | $ | 32,107 | $ | 0.15 | |||||||||||
| Common stock and equivalents used for earnings per share (EPS): | |||||||||||||||||||
| Weighted average common shares outstanding | 213,531 | 212,086 | |||||||||||||||||
| Dilutive stock options | 3,579 | 3,580 | |||||||||||||||||
| Shares used to compute diluted EPS for adjusted net income | 217,110 | 215,666 | |||||||||||||||||
(1) The assumed income tax rate is 40% for all periods.
(2) Deferred tax valuation allowance has been adjusted to reflect the assumed income tax rate of 40% for all periods.
(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.
Cash flow and financing transactions
Our cash flow from operations before working capital changes was $113 million for the first quarter 2011. We use our cash flow, credit agreement and proceeds from selected divestitures to fund drilling and development programs.
| Three months ended | ||||||||||||
| March 31, | % | |||||||||||
| (in thousands) | 2011 | 2010 | Change | |||||||||
| Cash flow from operations, GAAP | $ | 79,073 | $ | 91,303 | ||||||||
| Net change in working capital | 31,239 | 45,389 | ||||||||||
| Gains from early termination of derivative financial instruments | - | (37,936 | ) | |||||||||
| Non-recurring other operating items | 2,975 | - | ||||||||||
| Settlements of derivative financial instruments with a | ||||||||||||
| financing element | - | (907 | ) | |||||||||
| Cash flow from operations before changes in working capital | ||||||||||||
| and non-recurring other operating items, non-GAAP measure (1) | $ | 113,287 | $ | 97,849 | 16 | % | ||||||
(1) Cash flow from operations before working capital changes, non-recurring other operating items, early termination of derivatives and adjustments for settlements of derivative financial instruments with a financing element are 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. Non-recurring other operating items and early termination of derivatives have been excluded as they do not reflect our on-going operating activities.
Redetermination of borrowing base
On April 1, 2011, the lenders under our revolving credit agreement completed their regular semi-annual redetermination of the borrowing base, resulting in an increase of the borrowing base from $1.0 billion to $1.5 billion. In addition, the interest rate under the credit agreement was reduced by 50 basis points (bps) and the maturity date was extended from April 30, 2014 to April 1, 2016. The next redetermination of the borrowing base is scheduled to occur on October 1, 2011.
As of April 28, 2011, $929 million was drawn under our credit agreement and we had $275 million of cash, which includes $170 million of restricted cash. We anticipate receiving $113 million from BG Group during the second quarter 2011 for their participation in our April 2011 DeSoto Parish acquisition.
Operations activity and outlook
We spent $198 million on development and exploitation activities, drilling and completing 65 gross (36.1 net) operated wells in the first quarter 2011, compared with 51 gross (31.0 net) operated wells during the fourth quarter 2010. In addition, we participated in 17 gross (0.7 net) wells operated by others (OBO) during the first quarter 2011. We had an overall drilling success rate of 99% for the first quarter 2011. Our total capital expenditures, including leasing and net of acreage reimbursements from BG Group, were approximately $246 million in the first quarter 2011. We are continuing efforts to opportunistically acquire additional leasehold in our core shale areas.
Our projected capital spending for 2011 is presented in the following table:
| Three months ended | April - December | Full Year | |||||||
| March 31, | Forecast | Forecast | |||||||
| (in thousands) | 2011 | 2011 | 2011 | ||||||
| Capital expenditures: | |||||||||
| Development capital expenditures | 198,288 | 632,416 | 830,704 | ||||||
| Lease purchases(1) | 24,546 | 33,954 | 58,500 | ||||||
| Seismic | 4,447 | 6,953 | 11,400 | ||||||
| Gas gathering and water pipelines | 812 | 16,588 | 17,400 | ||||||
| Corporate and other | 17,518 | 40,682 | 58,200 | ||||||
| Total capital expenditures | $ | 245,611 | $ | 730,593 | $ | 976,204 | |||
|
(1) Net of acreage reimbursements from BG Group totaling $22.9 million ($5.5 million received in Q1 2011 and expected future reimbursements of $17.4 million). |
|||||||||
In addition to our capital program, we closed on $276 million, net to EXCO, of acquisitions during the first quarter 2011.
Haynesville/Bossier Shale
Our horizontal Haynesville shale development program continues to yield outstanding results. As of May 1, 2011, our Haynesville/Bossier operated production was 1,041 Mmcf per day gross (333 Mmcf per day net) and with the addition of our OBO wells, we had 356 Mmcf per day of net production. Our development program in DeSoto Parish, Louisiana is focused on manufacturing on 80-acre spacing. Our program in San Augustine and Nacogdoches, Counties, Texas (the Shelby Trough) is focused on delineation and testing of our acreage. During 2011, we plan to drill 233 gross (65.2 net) wells in the Haynesville/Bossier shale play in East Texas/North Louisiana. Of these 233 wells, 163 gross wells are operated by us.
We drilled and completed 42 gross (17.2 net) operated horizontal Haynesville and Bossier wells and participated in 17 gross (0.7 net) OBO Haynesville horizontal wells during the first quarter of 2011. We utilized 22 operated rigs and spud 45 operated horizontal wells. In addition to our operated rig count, we have four OBO rigs drilling in the play and spud 10 OBO wells during the quarter. We currently have 182 operated horizontal wells and 107 OBO horizontal wells flowing to sales.
The average initial production rate during the quarter from all of our operated Haynesville horizontal wells in DeSoto Parish was 18.1 Mmcf per day on a managed drawdown/restricted choke program. This high level of performance in our 80-acre development program underscores the quality and consistency of our shale assets. We are continuing to focus on the capital efficiencies of our drilling and completion program. Methods to improve our gas recoveries and to reduce our well costs include more efficient drilling pad design, less directional drilling in the intermediate hole section, more efficient fracture stimulation design, cluster spacing changes and different combinations of proppant, among others.
We are also encouraged by the results from our testing and delineation program in the Shelby Trough. We drilled and completed our first horizontal Middle Bossier test in San Augustine County during the first quarter 2011 with an initial production rate of 25.5 Mmcf per day from a 16 stage fracture stimulation treatment. We have recently tested two Haynesville horizontal wells in Nacogdoches County with initial production rates of 31.5 and 31.7 Mmcf per day and flowing pressures of 9,280 and 10,000 psi, respectively.
Marcellus Shale
During the first quarter 2011 in the Marcellus shale, we spud 8 new operated wells and drilled and completed 5 gross (2.0 net) operated wells. The initial production rates of these wells ranged from 2.1 Mmcf per day to 10.6 Mmcf per day from lateral lengths between 2,250 feet and 4,500 feet. The average initial production rates from these wells were above our expected production type curve, which forecasts that we will have initial production rates of 1.0 Mmcf per day for every 1,000 feet of completed lateral. We are implementing a development program within our recently acquired acreage in northeast Pennsylvania and certain of our acreage in west central Pennsylvania. We are also implementing an appraisal program across much of our other acreage, primarily in central Pennsylvania.
We plan to drill 64 gross (23.6 net) operated wells in the Marcellus shale play in our Appalachia region during 2011. Of the 64 wells, 57 gross (20.5 net) will be development wells and 7 gross (3.1 net) will be appraisal wells. This drilling will be within the EXCO/BG Group Appalachian JV area, so our net drilling dollars are reduced by the effect of the carry we receive from BG Group. Approximately $111 million of the carry remains available to us from BG Group as of March 31, 2011. We expect that the remaining carry amount will be used by the end of 2011. We are currently drilling with two operated rigs and we plan to exit 2011 with five operated drilling rigs in Appalachia.
Permian
We drilled and completed 18 gross (16.9 net) wells in our Permian area Canyon Sand field during the first quarter 2011 with 95% drilling success as one of our wells was a dry hole. We continue to run two operated rigs in the Canyon Sand field and plan to spend $48 million to drill 72 gross (69.8 net) wells in 2011. Oil production at Sugg Ranch has increased by 40% in the first quarter of 2011 as compared to the first quarter of 2010, and economics for this drilling activity typically have rates-of-return in excess of 60%.
Midstream
Through our jointly held midstream company, TGGT, we continue our major infrastructure expansion efforts in our Shelby Trough area of East Texas in order to meet the expected throughput volume increase. We are also continuing to develop our gathering and treating capacity in the DeSoto Parish area of northwest Louisiana. Total throughput for TGGT averaged approximately 1.2 Bcf per day for the first quarter of 2011 compared with total average throughput of 1.0 Bcf per day in the fourth quarter 2010. Our throughput as of May 1, 2011 was approximately 1.4 Bcf per day.
TGGT closed a $500 million credit agreement during the first quarter 2011, which combined with internally generated cash flow, will fund its capital program. At the closing of the credit agreement, TGGT funded a distribution to its owners, of which $125 million was distributed to us.
Financial Data
Our consolidated balance sheets as of March 31, 2011 and December 31, 2010 and consolidated statements of operations for the three months ended March 31, 2011 and 2010, and consolidated statements of cash flows for the three months ended March 31, 2011 and 2010, 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, May 4, 2011 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# 60662663. 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, after market close, on EXCO’s website on Tuesday, May 3, 2011.
A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., May 18, 2011. Please call (800) 642-1687 and enter conference ID# 60662663 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, as amended, for the year ended December 31, 2010, 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 permits oil and natural gas companies in filings made with the SEC to disclose 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. Beginning with reserves reported for the year ended December 31, 2009, the SEC permits optional disclosure of “probable” and “possible” reserves in its filings with the SEC. EXCO may use broader terms to describe additional reserve opportunities such as “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, probable or possible 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, as amended, for the year ended December 31, 2010, which is available on our website at www.excoresources.com under the Investor Relations tab.
|
EXCO Resources, Inc. Consolidated balance sheet |
||||||||
| March 31, | December 31, | |||||||
| (in thousands) | 2011 | 2010 | ||||||
| (Unaudited) | ||||||||
| Assets | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 8,528 | $ | 44,229 | ||||
| Restricted cash | 150,592 | 161,717 | ||||||
| Accounts receivable, net: | ||||||||
| Oil and natural gas | 100,999 | 80,740 | ||||||
| Joint interest | 102,113 | 104,358 | ||||||
| Interest and other | 27,631 | 35,594 | ||||||
| Inventory | 7,075 | 7,876 | ||||||
| Derivative financial instruments | 58,253 | 73,176 | ||||||
| Other | 20,643 | 12,770 | ||||||
| Total current assets | 475,834 | 520,460 | ||||||
| Equity investments | 264,978 | 379,001 | ||||||
| Oil and natural gas properties (full cost accounting method): | ||||||||
|
Unproved oil and natural gas properties and development costs not being amortized |
824,686 | 599,409 | ||||||
| Proved developed and undeveloped oil and natural gas properties | 2,649,345 | 2,370,962 | ||||||
| Accumulated depletion | (1,375,536 | ) | (1,312,216 | ) | ||||
| Oil and natural gas properties, net | 2,098,495 | 1,658,155 | ||||||
| Gas gathering assets | 158,741 | 157,929 | ||||||
| Accumulated depreciation and amortization | (26,909 | ) | (24,772 | ) | ||||
| Gas gathering assets, net | 131,832 | 133,157 | ||||||
| Office, field, and other equipment, net | 41,569 | 43,149 | ||||||
| Deferred financing costs, net | 29,014 | 30,704 | ||||||
| Derivative financial instruments | 19,818 | 23,722 | ||||||
| Goodwill | 218,256 | 218,256 | ||||||
| Deposits on acquisitions | - | 464,151 | ||||||
| Other assets | 6,664 | 6,665 | ||||||
| Total assets | $ | 3,286,460 | $ | 3,477,420 | ||||
|
EXCO Resources, Inc. Consolidated balance sheet |
||||||||||
| March 31, | December 31, | |||||||||
| (in thousands, except per share and share data) | 2011 | 2010 | ||||||||
| (Unaudited) | ||||||||||
| Liabilities and shareholders' equity | ||||||||||
| Current liabilities: | ||||||||||
| Accounts payable and accrued liabilities | $ | 175,687 | $ | 152,999 | ||||||
| Revenues and royalties payable | 140,811 | 108,830 | ||||||||
| Accrued interest payable | 3,311 | 18,983 | ||||||||
| Current portion of asset retirement obligations | 1,279 | 900 | ||||||||
| Income taxes payable | 211 | 211 | ||||||||
| Derivative financial instruments | 6,508 | 3,775 | ||||||||
| Total current liabilities | 327,807 | 285,698 | ||||||||
| Long-term debt | 1,328,526 | 1,588,269 | ||||||||
| Deferred income taxes | - | - | ||||||||
| Derivative financial instruments | 6,153 | 4,200 | ||||||||
| Asset retirement obligations and other long-term liabilities | 58,653 | 58,701 | ||||||||
| Commitments and contingencies | - | - | ||||||||
| Shareholders' equity: | ||||||||||
|
Preferred stock, $0.001 par value; authorized shares - 10,000,000; none issued and outstanding |
- | - | ||||||||
| Common stock, $0.001 par value; 350,000,000 authorized shares; | ||||||||||
| 214,286,651 shares issued and 213,747,430 shares outstanding at March 31, 2011; | ||||||||||
| 213,736,266 shares issued and 213,197,045 shares outstanding at December 31, 2010 | 214 | 214 | ||||||||
| Additional paid-in capital | 3,162,888 | 3,151,513 | ||||||||
| Accumulated deficit | (1,590,302 | ) | (1,603,696 | ) | ||||||
| Treasury stock, at cost; 539,221 at March 31, 2011 and December 31, 2010 | (7,479 | ) | (7,479 | ) | ||||||
| Total shareholders' equity | 1,565,321 | 1,540,552 | ||||||||
| Total liabilities and shareholders' equity | $ | 3,286,460 | $ | 3,477,420 | ||||||
|
EXCO Resources, Inc. Consolidated statement of operations |
||||||||
| Three months ended | ||||||||
| March 31, | ||||||||
| (in thousands, except per share data) | 2011 | 2010 | ||||||
| Revenues: | ||||||||
| Oil and natural gas | $ | 161,228 | $ | 130,994 | ||||
| Costs and expenses: | ||||||||
| Oil and natural gas production | 24,934 | 27,058 | ||||||
| Gathering and transportation | 17,286 | 11,113 | ||||||
| Depreciation, depletion and amortization | 67,930 | 38,818 | ||||||
| Accretion of discount on asset retirement obligations | 857 | 1,089 | ||||||
| General and administrative | 23,423 | 26,419 | ||||||
| Other operating items | 2,167 | (407 | ) | |||||
| Total costs and expenses | 136,597 | 104,090 | ||||||
| Operating income | 24,631 | 26,904 | ||||||
| Other income (expense): | ||||||||
| Interest expense | (14,816 | ) | (10,634 | ) | ||||
| Gain on derivative financial instruments | 3,421 | 99,149 | ||||||
| Other income | 160 | 60 | ||||||
| Equity income | 8,545 | 89 | ||||||
| Total other income (expense) | (2,690 | ) | 88,664 | |||||
| Income before income taxes | 21,941 | 115,568 | ||||||
| Income tax expense | - | - | ||||||
| Net income | $ | 21,941 | $ | 115,568 | ||||
| Earnings per common share: | ||||||||
| Basic | ||||||||
| Net income | $ | 0.10 | $ | 0.54 | ||||
| Weighted average common shares outstanding | 213,531 | 212,086 | ||||||
| Diluted | ||||||||
| Net income | $ | 0.10 | $ | 0.54 | ||||
|
Weighted average common and common equivalent shares outstanding |
217,110 | 215,666 | ||||||
|
EXCO Resources, Inc. Consolidated statement of cash flows |
|||||||||
| Three months ended | |||||||||
| March 31, | |||||||||
| (in thousands) | 2011 | 2010 | |||||||
| Operating Activities: | |||||||||
| Net income | $ | 21,941 | $ | 115,568 | |||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||
| Depreciation, depletion and amortization | 67,930 | 38,818 | |||||||
| Stock option compensation expense | 2,668 | 4,609 | |||||||
| Accretion of discount on asset retirement obligations | 857 | 1,089 | |||||||
| Income from equity investments | (8,545 | ) | (89 | ) | |||||
| Non-cash change in fair value of derivatives | 23,514 | (24,120 | ) | ||||||
| Cash settlements of assumed derivatives | - | 907 | |||||||
| Deferred income taxes | - | - | |||||||
|
Amortization of deferred financing costs; discount on the 2018 Notes and premium on the 2011 Notes |
1,947 | (90 | ) | ||||||
| Effect of changes in: | |||||||||
| Accounts receivable | (15,296 | ) | (40,548 | ) | |||||
| Other current assets | (2,813 | ) | (1,680 | ) | |||||
| Accounts payable and other current liabilities | (13,130 | ) | (3,161 | ) | |||||
| Net cash provided by operating activities | 79,073 | 91,303 | |||||||
| Investing Activities: | |||||||||
| Additions to oil and natural gas properties, gathering systems and equipment | (199,610 | ) | (124,223 | ) | |||||
| Property acquisitions | (506,833 | ) | (10,943 | ) | |||||
| Restricted cash | 11,125 | (11,079 | ) | ||||||
| Deposit on pending acquisitions | 464,151 | - | |||||||
| Investment in equity investments | (162 | ) | (44,500 | ) | |||||
| Return of investment in equity investments | 125,000 | - | |||||||
| Proceeds from disposition of property and equipment | 259,103 | 66,925 | |||||||
| Advances to Appalachia JV | (5,063 | ) | - | ||||||
| Other | (1,250 | ) | - | ||||||
| Net cash provided by (used in) investing activities | 146,461 | (123,820 | ) | ||||||
| Financing Activities: | |||||||||
| Borrowings under credit agreements | 40,000 | 39,960 | |||||||
| Repayments under credit agreements | (300,000 | ) | (24,981 | ) | |||||
| Proceeds from issuance of common stock | 7,312 | 4,206 | |||||||
| Payment of common stock dividends | (8,547 | ) | (6,364 | ) | |||||
| Settlements of derivative financial instruments with a financing element | - | (907 | ) | ||||||
| Net cash provided by (used in) financing activities | (261,235 | ) | 11,914 | ||||||
| Net decrease in cash | (35,701 | ) | (20,603 | ) | |||||
| Cash at beginning of period | 44,229 | 68,407 | |||||||
| Cash at end of period | $ | 8,528 | $ | 47,804 | |||||
| Supplemental Cash Flow Information: | |||||||||
| Cash interest payments | $ | 32,809 | $ | 21,041 | |||||
| Income tax payments | $ | - | $ | - | |||||
| Supplemental non-cash investing and financing activities: | |||||||||
| Capitalized stock option compensation | $ | 1,380 | $ | 1,105 | |||||
| Capitalized interest | $ | 7,740 | $ | 2,915 | |||||
| Issuance of common stock for director services | $ | 15 | $ | 9 | |||||
|
EXCO Resources, Inc. Consolidated EBITDA And adjusted EBITDA reconciliations and statement of cash flow data (Unaudited) |
|||||||||
| Three months ended | |||||||||
| March 31, | |||||||||
| (in thousands) | 2011 | 2010 | |||||||
| Net income | $ | 21,941 | $ | 115,568 | |||||
| Interest expense | 14,816 | 10,634 | |||||||
| Income tax expense | - | - | |||||||
| Depreciation, depletion and amortization | 67,930 | 38,818 | |||||||
| EBITDA(1) | 104,687 |
|
165,020 | ||||||
| Accretion of discount on asset retirement obligations | 857 | 1,089 | |||||||
| Non-recurring other operating items | 2,975 | - | |||||||
| Equity method income | (8,545 | ) | (89 | ) | |||||
| Non-cash change in fair value of derivative financial | |||||||||
| instruments | 23,514 | (22,102 | ) | ||||||
| Gains from early termination of derivative financial instruments | - | (37,936 | ) | ||||||
| Stock based compensation expense | 2,668 | 4,609 | |||||||
| Adjusted EBITDA (1) | $ | 126,156 |
|
$ | 110,591 | ||||
| Interest expense (2) | (14,816 | ) | (12,652 | ) | |||||
| Income tax expense | - | - | |||||||
| Amortization of deferred financing costs, premium on | |||||||||
| the 2011 Notes and discount on the 2018 Notes | 1,947 | (90 | ) | ||||||
| Deferred income taxes | - | - | |||||||
| Gains from early termination of derivative financial instruments | - | 37,936 | |||||||
| Non-recurring other operating items | (2,975 | ) | - | ||||||
| Changes in operating assets and liabilities | (31,239 | ) | (45,389 | ) | |||||
| Settlements of derivative financial instruments with a | |||||||||
| financing element | - | 907 | |||||||
| Net cash provided by operating activities | $ | 79,073 |
|
$ | 91,303 | ||||
| Three months ended | ||||||||
| March 31, | ||||||||
|
(in thousands) |
2011 | 2010 | ||||||
| Statement of cash flow data (unaudited): | ||||||||
| Cash flow provided by (used in): | ||||||||
| Operating activities | $ | 79,073 | $ | 91,303 | ||||
| Investing activities | 146,461 | (123,820 | ) | |||||
| Financing activities | (261,235 | ) | 11,914 | |||||
| Other financial and operating data: | ||||||||
| EBITDA(1) | 104,687 | 165,020 | ||||||
| Adjusted EBITDA(1) | 126,156 |
110,591 |
||||||
(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-recurring other operating items, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, gains from early termination of derivatives, stock-based compensation and income or losses from equity method investments. 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 credit agreement and the indenture governing our 7.5% senior notes due September 15, 2018. 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 $0 and $2 million for the three months ended March 31, 2011 and 2010, respectively, for interest rate swaps included in GAAP interest expense.
|
EXCO Resources, Inc. Summary of operating data |
||||||||||
| Three months ended | ||||||||||
| March 31, | % | |||||||||
| 2011 | 2010 | Change | ||||||||
| Production: | ||||||||||
| Oil (Mbbls) | 193 | 159 | 21 | % | ||||||
| Gas (Mmcf) | 35,525 | 22,837 | 56 | % | ||||||
| Oil and natural gas (Mmcfe) | 36,683 | 23,791 | 54 | % | ||||||
| Average daily production (Mmcfe) | 408 | 264 | 55 | % | ||||||
|
Average sales prices (before derivative financial instrument activities): |
||||||||||
| Oil (per Bbl) | $ | 90.01 | $ | 75.24 | 20 | % | ||||
| Gas (per Mcf) | 4.05 | 5.21 | -22 | % | ||||||
| Total production (per Mcfe) | 4.40 | 5.51 | -20 | % | ||||||
| Average costs (per Mcfe): | ||||||||||
| Oil and natural gas operating costs | $ | 0.53 | $ | 0.81 | -35 | % | ||||
| Production and ad valorem taxes | 0.15 | 0.33 | -55 | % | ||||||
| Gathering and transportation costs | 0.47 | 0.47 |
0 |
% | ||||||
| Depletion | 1.73 | 1.43 | 21 | % | ||||||
| Depreciation and amortization | 0.13 | 0.20 | -35 | % | ||||||
| General and administrative | 0.64 | 1.11 | -42 | % | ||||||