EXCO Resources, Inc.12377 Merit Drive, Suite 1700, LB 82, Dallas, Texas 75251
(214) 368-2084 FAX (972) 367-3559
EXCO RESOURCES, INC. REPORTS FOURTH QUARTER AND FULL YEAR
2013 RESULTS
DALLAS, TEXAS, February 25, 2014…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced fourth quarter and full year operating and financial results for 2013.
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| • | Adjusted EBITDA was $124 million for the fourth quarter 2013 and $418 million for the full year 2013, which exceeded our mid-point guidance. |
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| • | Reduced leverage and improved liquidity since the third quarter 2013 through a $273 million rights offering of our common stock and $305 million of closed and announced divestitures. |
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| • | Capital expenditures were $101 million for the fourth quarter 2013 and $340 million for the full year 2013. Actual capital expenditures were below our mid-point guidance reflecting continued fiscal discipline. |
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• | Drilled and completed 26 gross (11.8 net) operated wells for the fourth quarter 2013 and 99 gross (49.0 net) operated wells for the full year 2013. |
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| • | Production was 41 Bcfe, or 446 Mmcfe per day, for the fourth quarter 2013 and 162 Bcfe, or 444 Mmcfe per day, for the full year 2013, which exceeded our mid-point guidance. |
Jeff Benjamin, EXCO’s chairman, commented, “The company completed numerous transactions and operational initiatives in 2013 to improve its balance sheet and position itself for future growth. Most recently, we closed a successful rights offering of our common stock and raised $273 million which the company used to reduce indebtedness. This rights offering demonstrated the support we have from both our broad shareholder base and our principal investors. We will continue to demonstrate capital discipline in 2014 as we develop our asset base in the Haynesville, Marcellus and Eagle Ford shales.”
Financial results
Adjusted EBITDA for the fourth quarter 2013 was $124 million compared with $108 million for the third quarter 2013. Adjusted EBITDA for the year ended 2013 was $418 million compared with $468 million for the year ended 2012. Adjusted EBITDA is a non-GAAP measure and is computed using earnings before interest, taxes, depletion, depreciation and amortization, and is further adjusted for gains from asset sales, impairments of our oil and natural gas properties, other non-cash income and expenses, and other items impacting comparability.
Adjusted net income, a non-GAAP measure, was $0.04 per diluted share for the fourth quarter 2013 compared with $0.04 per diluted share for the third quarter 2013. Adjusted net income was $0.30 per
diluted share for the year ended 2013 compared with $0.38 per diluted share for the year ended 2012. The non-GAAP adjustments include gains from asset sales, unrealized gains or losses from derivative financial instruments, non-cash asset impairments and other items typically not included by securities analysts in published estimates.
GAAP results were a net loss of $123 million, or $0.57 per diluted share, for the fourth quarter 2013 compared with a net loss of $99 million, or $0.46 per diluted share, for the third quarter 2013. The net loss for the fourth quarter 2013 was primarily due to the non-cash impairment of $98 million to our oil and natural gas properties. The impairment was primarily due to downward revisions of our reserves in the Haynesville shale as a result of operational matters, and the narrowing of basis differentials between oil price indices and higher costs associated with the gathering and transportation of our natural gas production from the Eagle Ford shale. In the Haynesville shale, we have modified our spacing program in our core area from eight wells per section to six wells per section in order to optimize our rate of return and value for each section. We also have plans to reduce line pressure in the field, alleviate loading and expand our artificial lift program. In the Eagle Ford shale, we are developing a long term solution to increase capacity of the gathering system for our core area in order to reduce our costs and improve market access. However, these planned improvements will not be incorporated into our proved reserves until we have the results to support and objectively quantify these amounts. GAAP results were net income of $22 million, or $0.10 per diluted share, for the year ended 2013 compared with a net loss of $1.4 billion, or $6.50 per diluted share, for the year ended 2012. The net income for the year ended 2013 was primarily the result of income from operations benefiting from higher commodity prices and the gain on the divestiture of certain oil and natural gas properties and related assets in connection with the formation of the EXCO/HGI Partnership, which was partially offset by asset impairments. The pro forma operating and financial information for the years ended December 31, 2013 and 2012 is presented in a supplemental schedule to this press release as if the acquisitions of the Haynesville and Eagle Ford assets from subsidiaries of Chesapeake Energy Corporation ("Chesapeake") and the formation of the EXCO/HGI Partnership had occurred on January 1, 2012.
Oil, natural gas and natural gas liquids ("NGL") production was 41 Bcfe, or 446 Mmcfe per day, for the fourth quarter 2013 compared with 42 Bcfe, or 455 Mmcfe per day, in the third quarter 2013. Fourth quarter 2013 production from the East Texas/North Louisiana region was 311 Mmcfe per day compared with 340 Mmcfe per day in the third quarter 2013. The decrease in production was primarily the result of higher downtime for completion activities, timing of wells turned-to-sales and normal production declines. Fourth quarter production from the South Texas region was 656 Mbbls, or 7 Mboe per day, compared with 377 Mbbls, or 6 Mboe per day, subsequent to the acquisition in the third quarter 2013. The increase in production was the result of our continued development within the Eagle Ford shale including 13 gross wells turned-to-sales and the installation of artificial lift on certain wells during the quarter. The fourth quarter 2013 production in the Appalachia region averaged 66 Mmcfe per day compared with 64 Mmcfe per day in the third quarter 2013. Our proportionate share of production from the EXCO/HGI Partnership was 26 Mmcfe per day in the fourth quarter 2013 compared to 27 Mmcfe per day in the third quarter 2013. Oil, natural gas and NGL production was 162 Bcfe, or 444 Mmcfe per day, for the year ended 2013 compared with 190 Bcfe, or 519 Mmcfe per day, for the year ended 2012. The decrease in year over year production was primarily the result of our contribution of properties to the EXCO/HGI Partnership and natural production declines, partially offset by our acquisition of Haynesville and Eagle Ford assets during 2013.
Oil, natural gas and NGL revenues for the fourth quarter 2013 were $180 million compared with $165 million for the third quarter 2013. Our average sales price per Mcfe increased to $4.39 per Mcfe for the fourth quarter 2013 from $3.95 per Mcfe for the third quarter 2013. Our sales price per Mcfe was positively impacted by higher oil production for the fourth quarter 2013 compared to the third quarter 2013. When
the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $194 million, or $4.73 per Mcfe for the fourth quarter 2013, compared with $176 million, or $4.21 per Mcfe for the third quarter 2013. Oil, natural gas and NGL revenues for the year ended 2013 were $634 million compared with $547 million for the year ended 2012. Our average sales price per Mcfe increased to $3.92 per Mcfe for the full year 2013 from $2.88 per Mcfe for the full year 2012. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $676 million, or $4.18 per Mcfe for the full year 2013, compared with $749 million, or $3.94 per Mcfe for the full year 2012.
Our direct operating costs were $0.45 per Mcfe for the fourth quarter 2013 compared with $0.41 per Mcfe for the third quarter 2013. The increase was primarily the result of higher direct operating costs per Mcfe associated with increased oil production in the Eagle Ford shale. Our direct operating costs were $0.38 per Mcfe for the year ended 2013 compared with $0.41 per Mcfe for the year ended 2012. The decrease was primarily attributable to the contribution of properties to the EXCO/HGI Partnership, which typically have higher operating costs per Mcfe, and was partially offset by higher direct operating costs per Mcfe associated with our oil production in the Eagle Ford shale.
Cash flow from operations before changes in working capital and other operating items impacting comparability, a non-GAAP measure, was $100 million for the fourth quarter 2013 compared with $87 million for the third quarter 2013. Cash flow from operations before changes in working capital and other operating items impacting comparability was $345 million for the year ended 2013 compared to $404 million for the year ended 2012. During 2013, we primarily used our cash flow from operations and available borrowing capacity in our credit agreement to fund our drilling and development programs and acquire oil and natural gas properties.
Recent developments
TGGT sale
On November 15, 2013, we closed the sale of 100% of our equity interests in midstream assets in East Texas and North Louisiana ("TGGT") to Azure Midstream Holdings LLC ("Azure") for net cash proceeds of $240 million and approximately 4% of the total outstanding equity interests of Azure. The proceeds from the sale were used to reduce indebtedness under the asset sale requirement of the EXCO Resources Credit Agreement.
Rights offering
We closed a rights offering of our common stock on January 17, 2014 which resulted in the issuance of 54,574,734 shares for net proceeds of $273 million. We used the net proceeds to pay indebtedness under the EXCO Resources Credit Agreement, including payment in full of the remaining indebtedness related to the asset sale requirement as well as a portion of the indebtedness outstanding under the revolving commitment under the EXCO Resources Credit Agreement. The elimination of the asset sale requirement resulted in a decrease in our interest rate of 100 basis points on the revolving commitment. After giving effect to the repayment of indebtedness using proceeds from the rights offering, the available borrowing base on the revolving commitment under the EXCO Resources Credit Agreement was $900 million with approximately $491 million of outstanding indebtedness and approximately $402 million of unused borrowing base, net of letters of credit. This improved our leverage ratio, as defined in the EXCO Resources Credit Agreement, from 3.6 to 1.0 prior to the rights offering, to 3.0 to 1.0 after the rights offering. We have presented information in a supplemental schedule to this press release relating to our liquidity as of December 31, 2013 as well as on a pro forma basis as if the closing of the Rights Offering had occurred on December 31, 2013.
Permian JV sale agreement
On February 13, 2014, we entered into a purchase and sale agreement to sell our non-operated interest in a joint venture in the Permian Basin for approximately $65 million, subject to customary purchase price adjustments and the receipt of certain third-party consents. This sale includes our interest in producing wells and undeveloped acreage with horizontal drilling opportunities. The effective date of the transaction will be January 1, 2014 and is expected to close in the first half of 2014. We plan to use the proceeds to reduce indebtedness under the EXCO Resources Credit Agreement, which will improve our liquidity and reduce our leverage.
Operations activity and outlook
We spent $66 million on development and exploration activities, drilling 24 gross (5.8 net) operated wells and completing 26 gross (11.8 net) operated wells in the fourth quarter 2013. In addition, we participated in the drilling of 11 gross (1.9 net) wells operated by others ("OBO") during the fourth quarter 2013. We spent $265 million on development and exploration activities, drilling 64 gross (26.7 net) operated wells and completing 99 gross (49.0 net) operated wells for the full year 2013. In addition, we participated in the drilling of 22 gross (3.6 net) OBO wells for the full year 2013. Our development and exploration activities were focused on our Haynesville shale and Eagle Ford shale properties during 2013.
Our actual capital expenditures for the fourth quarter 2013, full year 2013, and 2014 capital budget are presented in the following table.
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| | | | | | | | | | | | |
| (in thousands) | | Fourth Quarter | | Full Year | | 2014 Budget |
| Capital expenditures (1): | | | | | | |
| Development capital expenditures | | $ | 66,055 |
| | $ | 265,120 |
| | $ | 294,000 |
|
| Lease purchases | | 10,605 |
| | 14,835 |
| | 19,000 |
|
| Seismic | | 3,912 |
| | 10,217 |
| | 2,000 |
|
| Field operations, gathering and water pipelines | | 12,238 |
| | 12,379 |
| | 24,000 |
|
| Corporate and other | | 8,496 |
| | 37,287 |
| | 29,000 |
|
| Total capital expenditures | | $ | 101,306 |
| | $ | 339,838 |
| | $ | 368,000 |
|
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| (1) | Excludes capital expenditures related to our partnership with HGI. |
Our board of directors approved a capital budget of $368 million for 2014 of which $294 million is allocated to development and completion activities. Our developmental activities in the East Texas/ North Louisiana region are primarily focused on our core area in DeSoto Parish, Louisiana as well as a limited drilling program in the Shelby area of East Texas. Our developmental activities in the South Texas region will primarily be focused on our core area in the Eagle Ford shale. We believe the capital budget is appropriate for current commodity prices and our capital structure, and was designed to manage our capital expenditures in relation to our operating cash flow. These capital expenditures exclude the EXCO/HGI Partnership, which funds its capital expenditures through internally generated cash flow and its credit agreement.
Proved Reserves
Our estimated proved reserves as of December 31, 2013, were 1.1 Tcfe with a PV-10 of $1.3 billion calculated pursuant to SEC pricing rules. For 2013, the SEC reference price was $3.67 per Mmbtu for natural gas, $96.78 per Bbl for oil, and $39.92 per barrel for NGLs, in each case adjusted for geographical and historical differentials. Our estimated proved reserves would have been 1.3 Tcfe with a PV-10 of $1.6 billion using NYMEX futures strip prices at December 31, 2013, as adjusted for energy content, quality
and basis differentials, of $4.24 per Mcf for natural gas, $80.83 per Bbl for oil, and $38.88 per Bbl for NGLs. The discussion of reserves within this press release relates to our estimated proved reserves calculated pursuant to SEC pricing rules.
During 2013, we added 400 Bcfe of proved reserves through acquisitions including 260 Bcfe in the Haynesville shale, 116 Bcfe in the Eagle Ford shale, and 25 Bcfe for our proportionate share of the EXCO/HGI Partnership's acquisition of Cotton Valley properties. We also added 86 Bcfe through discoveries and extensions primarily as a result of our development programs in the Haynesville and Eagle Ford shales, as well as completion activities in the Marcellus shale.
Our revisions of previous estimates during 2013 included upward revisions to our proved reserve quantities of 280 Bcfe as a result of an increase in price, which extended the economic life of certain producing properties and resulted in the reclassification of unproved locations to proved undeveloped properties that became economical when using the prices prescribed by the SEC. The upward revisions due to changes in price were partially offset by downward revisions of 127 Bcfe in proved reserves due to other factors. These downward revisions were primarily related to operational matters for our Haynesville shale properties such as scaling, liquid loading due to high-line pressure and the impact of drainage on new wells drilled directly offset to the unit wells. We have modified our spacing program from eight wells per section to six wells per section in order to maximize our rate of return for each section. We also have plans to reduce line pressure in the field, alleviate loading and implement an artificial lift program. However, these planned improvements will not be incorporated into our proved reserves until we have the results to support and objectively quantify these amounts.
We sold 358 Bcfe of proved reserves during the year, including 328 Bcfe as part of our contribution of properties to the EXCO/HGI Partnership and 30 Bcfe as part of the participation agreement in the Eagle Ford shale. Additionally, we produced 162 Bcfe during the year. The following table presents the details of our changes in proved reserves:
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| | | | | | | | | | | | | |
| | | Oil (Mbbls) | | Natural gas (Mmcf) | | Natural gas liquids (Mbbls) | | Equivalent natural gas (Mmcfe) |
| Proved Developed Reserves | | 11,274 |
| | 657,116 |
| | 2,088 |
| | 737,291 |
|
| Proved Undeveloped Reserves | | 4,104 |
| | 359,363 |
| | 495 |
| | 386,954 |
|
| Total Proved Reserves | | 15,378 |
| | 1,016,479 |
| | 2,583 |
| | 1,124,245 |
|
| The changes in reserves for the year are as follows: | | | | | | | | |
| January 1, 2013 | | 5,570 |
| | 936,132 |
| | 6,639 |
| | 1,009,386 |
|
| Purchases of reserves in place | | 16,022 |
| | 290,933 |
| | 2,201 |
| | 400,271 |
|
| Discoveries and extensions | | 5,960 |
| | 46,834 |
| | 513 |
| | 85,672 |
|
| Revisions of previous estimates (1): | | | | | | | | |
| Reclassification to unproved reserves (2) | | (190 | ) | | (1,509 | ) | | (196 | ) | | (3,825 | ) |
| Changes in price | | 457 |
| | 272,614 |
| | 686 |
| | 279,472 |
|
| Other factors | | (3,029 | ) | | (105,186 | ) | | (545 | ) | 621 |
| (126,630 | ) |
| Sales of reserves in place | | (8,224 | ) | | (270,018 | ) | | (6,472 | ) | | (358,194 | ) |
| Production | | (1,188 | ) | | (153,321 | ) | | (243 | ) | | (161,907 | ) |
| December 31, 2013 | | 15,378 |
| | 1,016,479 |
| | 2,583 |
| | 1,124,245 |
|
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| (1) | Revisions of previous estimates include both reserves in place at the beginning of the year and acquisitions during the year. |
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| (2) | Represents proved undeveloped reserves reclassified to unproved pursuant to the five year development rule established by the SEC. This reclassification was a result of decisions not to commit development capital to certain conventional properties held by the EXCO/HGI Partnership in the Permian Basin. While these locations qualify as proved undeveloped reserves as they directly offset a proved location, our planned capital programs do not support development at this time, resulting in the reclassification. |
Our drilling program during 2013 was primarily focused on the Haynesville shale and our recently acquired properties in the Eagle Ford shale. Additionally, our activities in the Marcellus shale focused on completing our inventory of drilled locations and a limited appraisal and development program. During 2013, our capital expenditures in the Haynesville shale were focused on the development of our core area in DeSoto Parish. Due to our extensive history of development in the core DeSoto Parish area, most of the locations were reflected as discoveries and extensions in prior years. In the Eagle Ford shale, our development included both converting proved undeveloped reserves to developed as well as extensions and discoveries of locations within our core area and adjacent acreage as part of a farmout agreement. Additionally, our completion activities in the Marcellus shale resulted in additional discoveries and extensions of proved undeveloped locations offsetting the proved developed producing properties. Our finding and development costs to convert reserves to the proved developed reserves were $1.69 per Mcfe during 2013 compared to $1.60 per Mcfe during 2012. The increase from prior year was primarily attributable to higher finding and development costs per Mcfe associated with our oil properties in the Eagle Ford shale. The following table details the components of our 2013 proved developed additions:
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| | | | | | | | |
| | | Year Ended |
| (dollars in thousands) | | December 31, 2013 | | December 31, 2012 |
| Development costs | | $ | 218,353 |
| | $ | 329,013 |
|
| Exploration costs | | 38,579 |
| | 3,450 |
|
| Total development and exploration (1) | | $ | 256,932 |
| | $ | 332,463 |
|
| | | | | |
| Additions to proved developed reserves (Mmcfe) (2) | | 152,007 |
| | 207,320 |
|
| | | | | |
| Finding and development costs per Mcfe | | $ | 1.69 |
| | $ | 1.60 |
|
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| (1) | Excludes $13 million and $71 million for the years ended December 31, 2013 and 2012, respectively, of rig termination fees, field operations capital and other leasehold development costs which are not directly associated with future proved developed reserve additions. |
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| (2) | Our additions to proved developed reserves include both proved undeveloped reserves converted to proved developed reserves, and unproved reserves converted to proved developed reserves. |
Financial Data
Our consolidated balance sheets as of December 31, 2013 and December 31, 2012, consolidated statements of operations for the three months ended December 31, 2013 and September 30, 2013 and for the year ended December 31, 2013 and 2012 and consolidated statements of cash flows for the year ended December 31, 2013 and 2012, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release.
EXCO will host a conference call on Wednesday, February 26, 2014 at 9:00 a.m. (Central 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#43723853. 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, February 25, 2014. A digital recording will be available starting two hours after the completion of the conference call until March 12, 2014. Please call (800) 585-8367 and enter conference ID#43723853 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 Chris Peracchi, EXCO’s Director of Finance and Investor Relations and Treasurer 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.
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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. We caution users of the financial statements not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the cautionary statements and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the Securities and Exchange Commission, or the SEC, on February 21, 2013 and as amended by Amendment No. 1 to Annual Report on Form 10-K/A on August 30, 2013 and after February 26, 2014 our annual Report on Form 10-K for the year ended December 31, 2013, and our other periodic filings with the SEC.
Our revenues, operating results and financial condition substantially depend on prevailing prices for oil and natural gas and the availability of capital from our credit agreement, or the EXCO Resources Credit Agreement. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. 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. The SEC permits optional disclosure of “probable” and “possible” reserves in filings with the commission. 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 actually being 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, 2012, filed with the SEC on February 21, 2013 and as amended by Amendment No. 1 to Annual Report on Form 10-K/A on August 30, 2013, and after February 26, 2014 our Annual Report on Form 10-K for the year ended December 31, 2013 which is available on our website at www.excoresources.com under the Investor Relations tab.
EXCO Resources, Inc.
Consolidated Balance Sheets
|
| | | | | | | | |
| (in thousands) | | December 31,
2013 | | December 31,
2012 |
| | | | | |
| Assets | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 50,483 |
| | $ | 45,644 |
|
| Restricted cash | | 20,570 |
| | 70,085 |
|
| Accounts receivable, net: | | | | |
| Oil and natural gas | | 128,352 |
| | 84,348 |
|
| Joint interest | | 70,759 |
| | 69,446 |
|
| Other | | 18,022 |
| | 15,053 |
|
| Inventory | | 3,087 |
| | 5,705 |
|
| Derivative financial instruments | | 8,226 |
| | 49,500 |
|
| Other | | 6,355 |
| | 22,085 |
|
| Total current assets | | 305,854 |
| | 361,866 |
|
| Equity investments | | 57,562 |
| | 347,008 |
|
| Oil and natural gas properties (full cost accounting method): | | | | |
| Unproved oil and natural gas properties and development costs not being amortized | | 425,307 |
| | 470,043 |
|
| Proved developed and undeveloped oil and natural gas properties | | 3,554,210 |
| | 2,715,767 |
|
| Accumulated depletion | | (2,183,464 | ) | | (1,945,565 | ) |
| Oil and natural gas properties, net | | 1,796,053 |
| | 1,240,245 |
|
| Gathering assets | | 33,473 |
| | 130,830 |
|
| Accumulated depreciation and amortization | | (10,338 | ) | | (34,364 | ) |
| Gathering assets, net | | 23,135 |
| | 96,466 |
|
| Office, field and other equipment, net | | 27,204 |
| | 20,725 |
|
| Deferred financing costs, net | | 28,807 |
| | 22,584 |
|
| Derivative financial instruments | | 6,829 |
| | 16,554 |
|
| Goodwill | | 163,155 |
| | 218,256 |
|
| Other assets | | 29 |
| | 28 |
|
| Total assets | | $ | 2,408,628 |
| | $ | 2,323,732 |
|
EXCO Resources, Inc.
Consolidated Balance Sheets
|
| | | | | | | | |
| (in thousands, except per share and share data) | | December 31,
2013 | | December 31,
2012 |
| | | | | |
| Liabilities and shareholders’ equity | | | | |
| Current liabilities: | | | | |
| Accounts payable and accrued liabilities | | $ | 132,188 |
| | $ | 83,240 |
|
| Revenues and royalties payable | | 154,862 |
| | 134,066 |
|
| Accrued interest payable | | 18,144 |
| | 17,029 |
|
| Current portion of asset retirement obligations | | 191 |
| | 1,200 |
|
| Income taxes payable | | — |
| | — |
|
| Derivative financial instruments | | 11,919 |
| | 2,396 |
|
| Current maturities of long-term debt | | 31,866 |
| | — |
|
| Total current liabilities | | 349,170 |
| | 237,931 |
|
| Long-term debt | | 1,858,912 |
| | 1,848,972 |
|
| Deferred income taxes | | — |
| | — |
|
| Derivative financial instruments | | 9,671 |
| | 26,369 |
|
| Asset retirement obligations and other long-term liabilities | | 42,970 |
| | 61,067 |
|
| Commitments and contingencies | | — |
| | — |
|
| Shareholders’ equity: | |
|
| | |
| Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding | | — |
| | — |
|
| Common stock, $0.001 par value; 350,000,000 authorized shares; 218,783,540 shares issued and 218,244,319 shares outstanding at December 31, 2013; 218,126,071 shares issued and 217,586,850 shares outstanding at December 31, 2012 | | 215 |
| | 215 |
|
| Subscription rights, $0.001 par value, 54,574,734 issued and outstanding at December 31, 2013 | | 55 |
| | — |
|
| Additional paid-in capital | | 3,219,748 |
| | 3,200,067 |
|
| Accumulated deficit | | (3,064,634 | ) | | (3,043,410 | ) |
| Treasury stock, at cost; 539,221 shares at December 31, 2013 and December 31, 2012 | | (7,479 | ) | | (7,479 | ) |
| Total shareholders’ equity | | 147,905 |
| | 149,393 |
|
| Total liabilities and shareholders’ equity | | $ | 2,408,628 |
| | $ | 2,323,732 |
|
EXCO Resources, Inc.
Consolidated Statements of Operations
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Year Ended December 31, |
| (in thousands, except per share data) | | December 31, 2013 | | September 30, 2013 | | 2013 | | 2012 |
| Revenues: | | (Unaudited) | | (Unaudited) | | | | |
| Total revenues | | $ | 180,440 |
| | $ | 165,314 |
| | $ | 634,309 |
| | $ | 546,609 |
|
| Costs and expenses: | | | | | | | | |
| Oil and natural gas operating costs | | 18,571 |
| | 17,187 |
| | 61,277 |
| | 77,127 |
|
| Production and ad valorem taxes | | 6,668 |
| | 6,074 |
| | 21,971 |
| | 27,483 |
|
| Gathering and transportation | | 26,096 |
| | 26,665 |
| | 100,645 |
| | 102,875 |
|
| Depletion, depreciation and amortization | | 82,580 |
| | 74,499 |
| | 245,775 |
| | 303,156 |
|
| Impairment of oil and natural gas properties | | 97,839 |
| | — |
| | 108,546 |
| | 1,346,749 |
|
| Accretion of discount on asset retirement obligations | | 649 |
| | 619 |
| | 2,514 |
| | 3,887 |
|
| General and administrative | | 25,383 |
| | 21,937 |
| | 91,878 |
| | 83,818 |
|
| (Gain) loss on divestitures and other operating items | | 1,985 |
| | 2,739 |
| | (177,518 | ) | | 17,029 |
|
| Total costs and expenses | | 259,771 |
| | 149,720 |
| | 455,088 |
| | 1,962,124 |
|
| Operating income (loss) | | (79,331 | ) | | 15,594 |
| | 179,221 |
| | (1,415,515 | ) |
| Other income (expense): | | | | | | | | |
| Interest expense, net | | (30,818 | ) | | (36,474 | ) | | (102,589 | ) | | (73,492 | ) |
| Gain (loss) on derivative financial instruments | | (19,495 | ) | | 7,443 |
| | (320 | ) | | 66,133 |
|
| Other income (expense) | | (1,168 | ) | | 94 |
| | (828 | ) | | 969 |
|
| Equity income (loss) | | 7,949 |
| | (85,308 | ) | | (53,280 | ) | | 28,620 |
|
| Total other income (expense) | | (43,532 | ) | | (114,245 | ) | | (157,017 | ) | | 22,230 |
|
| Income (loss) before income taxes | | (122,863 | ) | | (98,651 | ) | | 22,204 |
| | (1,393,285 | ) |
| Income tax expense | | — |
| | — |
| | — |
| | — |
|
| Net income (loss) | | $ | (122,863 | ) | | $ | (98,651 | ) | | $ | 22,204 |
| | $ | (1,393,285 | ) |
| Earnings (loss) per common share: | | | | | | | | |
| Basic: | | | | | | | | |
| Net income (loss) | | $ | (0.57 | ) | | $ | (0.46 | ) | | $ | 0.10 |
| | $ | (6.50 | ) |
| Weighted average common shares outstanding | | 215,410 |
| | 215,056 |
| | 215,011 |
| | 214,321 |
|
| Diluted: | | | | | | | | |
| Net income (loss) | | $ | (0.57 | ) | | $ | (0.46 | ) | | $ | 0.10 |
| | $ | (6.50 | ) |
| Weighted average common shares and common share equivalents outstanding | | 215,410 |
| | 215,056 |
| | 230,912 |
| | 214,321 |
|
EXCO Resources, Inc.
Consolidated Statements of Cash Flows
|
| | | | | | | | |
| | | Year Ended December 31, |
| (in thousands) | | 2013 | | 2012 |
| Operating Activities: | | | | |
| Net income (loss) | | $ | 22,204 |
| | $ | (1,393,285 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | |
| Depletion, depreciation and amortization | | 245,775 |
| | 303,156 |
|
| Share-based compensation expense | | 10,748 |
| | 8,926 |
|
| Accretion of discount on asset retirement obligations | | 2,514 |
| | 3,887 |
|
| Impairment of oil and natural gas properties | | 108,546 |
| | 1,346,749 |
|
| (Income) loss from equity investments | | 53,280 |
| | (28,620 | ) |
| (Gain) loss on derivative financial instruments | | 320 |
| | (66,133 | ) |
| Cash settlements of derivative financial instruments | | 42,119 |
| | 202,078 |
|
| Deferred income taxes | | — |
| | — |
|
| Amortization of deferred financing costs and discount on debt issuance | | 29,624 |
| | 9,788 |
|
| (Gain) loss on divestitures and other non-operating items | | (185,163 | ) | | 1,303 |
|
| Effect of changes in: | | | | |
| Accounts receivable | | (46,176 | ) | | 112,919 |
|
| Other current assets | | 9,627 |
| | 7,090 |
|
| Accounts payable and other current liabilities | | 57,216 |
| | 6,928 |
|
| Net cash provided by operating activities | | 350,634 |
| | 514,786 |
|
| Investing Activities: | | | | |
| Additions to oil and natural gas properties, gathering assets and equipment | | (320,538 | ) | | (534,175 | ) |
| Property acquisitions | | (976,714 | ) | | (2,748 | ) |
| Proceeds from disposition of property and equipment | | 749,628 |
| | 38,045 |
|
| Equity method investments | | 236,289 |
| | (14,907 | ) |
| Restricted cash | | 49,515 |
| | 85,840 |
|
| Net changes in advances to joint ventures | | 10,645 |
| | 851 |
|
| Other | | (1,303 | ) | | — |
|
| Net cash used in investing activities | | (252,478 | ) | | (427,094 | ) |
| Financing Activities: | | | | |
| Borrowings under credit agreements | | 1,004,523 |
| | 53,000 |
|
| Repayments under credit agreements | | (1,022,785 | ) | | (93,000 | ) |
| Proceeds from issuance of common stock | | 1,712 |
| | 1,968 |
|
| Payment of common stock dividends | | (43,214 | ) | | (34,358 | ) |
| Deferred financing costs and other | | (33,553 | ) | | (1,655 | ) |
| Net cash used in financing activities | | (93,317 | ) | | (74,045 | ) |
| Net increase (decrease) in cash | | 4,839 |
| | 13,647 |
|
| Cash at beginning of period | | 45,644 |
| | 31,997 |
|
| Cash at end of period | | $ | 50,483 |
| | $ | 45,644 |
|
| Supplemental Cash Flow Information: | | | | |
| Cash interest payments | | $ | 88,936 |
| | $ | 86,298 |
|
| Income tax payments | | — |
| | — |
|
| Supplemental non-cash investing and financing activities: | | | | |
| Capitalized share-based compensation | | $ | 7,288 |
| | $ | 7,513 |
|
| Capitalized interest | | 18,729 |
| | 23,809 |
|
| Issuance of common stock for director services | | 93 |
| | 597 |
|
| Accrued restricted stock dividends | | 214 |
| | 300 |
|
| EXCO/HGI Partnership debt upon formation, net | | 58,613 |
| | — |
|
| Issuance of subscription rights | | 55 |
| | — |
|
EXCO Resources, Inc.
Consolidated EBITDA
And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Year Ended December 31, |
| (in thousands) | | December 31, 2013 | | September 30, 2013 | | 2013 | | 2012 |
| Net income (loss) | | $ | (122,863 | ) | | $ | (98,651 | ) | | $ | 22,204 |
| | $ | (1,393,285 | ) |
| Interest expense | | 30,818 |
| | 36,474 |
| | 102,589 |
| | 73,492 |
|
| Income tax expense | | — |
| | — |
| | — |
| | — |
|
| Depletion, depreciation and amortization | | 82,580 |
| | 74,499 |
| | 245,775 |
| | 303,156 |
|
| EBITDA(1) | | $ | (9,465 | ) | | $ | 12,322 |
| | $ | 370,568 |
| | $ | (1,016,637 | ) |
| Accretion of discount on asset retirement obligations | | 649 |
| | 619 |
| | 2,514 |
| | 3,887 |
|
| Impairment of oil and natural gas properties | | 97,839 |
| | — |
| | 108,546 |
| | 1,346,749 |
|
| (Gain) loss on divestitures and other items impacting comparability | | 8,143 |
| | 2,653 |
| | (170,550 | ) | | 17,928 |
|
| Equity (income) loss | | (7,949 | ) | | 85,308 |
| | 53,280 |
| | (28,620 | ) |
| Net (gains) losses on derivative financial instruments | | 19,495 |
| | (7,443 | ) | | 320 |
| | (66,133 | ) |
| Cash settlements on derivative financial instruments | | 13,703 |
| | 10,904 |
| | 42,119 |
| | 202,078 |
|
| Share based compensation expense | | 1,255 |
| | 3,170 |
| | 10,748 |
| | 8,926 |
|
| Adjusted EBITDA (1) | | $ | 123,670 |
| | $ | 107,533 |
| | $ | 417,545 |
| | $ | 468,178 |
|
| Interest expense | | (30,818 | ) | | (36,474 | ) | | (102,589 | ) | | (73,492 | ) |
| Income tax expense | | — |
| | — |
| | — |
| | — |
|
| Amortization of deferred financing costs and discount | | 7,184 |
| | 15,843 |
| | 29,624 |
| | 9,788 |
|
| Deferred income taxes | | — |
| | — |
| | — |
| | — |
|
| Other operating items impacting comparability | | (6,840 | ) | | (2,769 | ) | | (14,613 | ) | | (16,625 | ) |
| Changes in working capital | | 34,067 |
| | (31,994 | ) | | 20,667 |
| | 126,937 |
|
| Net cash provided by operating activities | | $ | 127,263 |
| | $ | 52,139 |
| | $ | 350,634 |
| | $ | 514,786 |
|
EXCO Resources, Inc.
Consolidated EBITDA
And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Year Ended December 31, |
| (in thousands) | | December 31, 2013 | | September 30, 2013 | | 2013 | | 2012 |
| Statement of cash flow data: | | | | | | | | |
| Cash flow provided by (used in): | | | | | | | | |
| Operating activities | | $ | 127,263 |
| | $ | 52,139 |
| | $ | 350,634 |
| | $ | 514,786 |
|
| Investing activities | | 146,114 |
| | (881,644 | ) | | (252,478 | ) | | (427,094 | ) |
| Financing activities | | (256,387 | ) | | 815,749 |
| | (93,317 | ) | | (74,045 | ) |
| Other financial and operating data: | | | | | | | | |
| EBITDA(1) | | $ | (9,465 | ) | | $ | 12,322 |
| | $ | 370,568 |
| | $ | (1,016,637 | ) |
| Adjusted EBITDA(1) | | 123,670 |
| | 107,533 |
| | 417,545 |
| | 468,178 |
|
| |
| (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 other operating items impacting comparability, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash write-downs of assets, 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. |
EXCO Resources, Inc.
Consolidated Adjusted Net Income and Adjusted Net Income Reconciliations
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Year Ended |
| | | December 31, 2013 | | September 30, 2013 | | December 31, 2013 | | December 31, 2012 |
| (in thousands, except per share amounts) | | Amount | | Per share | | Amount | | Per share | | Amount | | Per share | | Amount | | Per share |
| Net income (loss), GAAP | | $ | (122,863 | ) | | | | $ | (98,651 | ) | | | | $ | 22,204 |
| | | | $ | (1,393,285 | ) | | |
| Adjustments: | | | | | | | | | | | | | | | | |
| Total net (gain) loss on derivatives | | 19,495 |
| | | | (7,443 | ) | | | | 320 |
| | | | (66,133 | ) | | |
| Cash receipts on derivative financial instruments | | 13,703 |
| | | | 10,904 |
| | | | 42,119 |
| | | | 202,078 |
| | |
| Impairment of oil and natural gas properties | | 97,839 |
| | | | — |
| | | | 108,546 |
| | | | 1,346,749 |
| | |
| Adjustments included in equity (income) loss | | (4,736 | ) | | | | 94,580 |
| | | | 90,214 |
| | | | 27,088 |
| | |
| (Gain) loss on divestitures and other items impacting comparability | | 8,143 |
| | | | 2,653 |
| | | | (170,550 | ) | | | | 17,928 |
| | |
| Deferred finance cost amortization acceleration | | 4,256 |
| | | | 13,183 |
| | | | 20,974 |
| | | | 3,000 |
| | |
| Income taxes on above adjustments (1) | | (55,480 | ) | | | | (45,551 | ) | | | | (36,649 | ) | | | | (612,284 | ) | | |
| Adjustment to deferred tax asset valuation allowance (2) | | 49,145 |
| | | | 39,460 |
| | | | (8,882 | ) | | | | 557,314 |
| | |
| Total adjustments, net of taxes | | 132,365 |
| | | | 107,786 |
| | | | 46,092 |
| | | | 1,475,740 |
| | |
| Adjusted net income | | $ | 9,502 |
| | | | $ | 9,135 |
| | | | $ | 68,296 |
| | | | $ | 82,455 |
| | |
| | | | | | | | | | | | | | | | | |
| Net income (loss), GAAP (3) | | $ | (122,863 | ) | | $ | (0.57 | ) | | $ | (98,651 | ) | | $ | (0.46 | ) | | $ | 22,204 |
| | $ | 0.10 |
| | $ | (1,393,285 | ) | | $ | (6.50 | ) |
| Adjustments shown above (3) | | 132,365 |
| | 0.61 |
| | 107,786 |
| | 0.50 |
| | 46,092 |
| | 0.20 |
| | 1,475,740 |
| | 6.88 |
|
| Dilution attributable to share-based payments and rights outstanding (4) | | — | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Adjusted net income | | $ | 9,502 |
| | $ | 0.04 |
| | $ | 9,135 |
| | $ | 0.04 |
| | $ | 68,296 |
| | $ | 0.30 |
| | $ | 82,455 |
| | $ | 0.38 |
|
| | | | | | | | | | | | | | | | | |
| Common stock and equivalents used for earnings per share (EPS): | | | | | | | | | | | | | | | | |
| Weighted average common shares outstanding | | 215,410 |
| | | | 215,056 |
| | | | 215,011 |
| | | | 214,321 |
| 215,011 |
| |
| Dilutive stock options | | — |
| | | | 274 |
| | | | — |
| | | | — |
| — |
| |
| Dilutive restricted shares | | 327 |
| | | | 902 |
| | | | 420 |
| | | | — |
| 420 |
| |
| Dilutive subscription rights | | 7,118 |
| | | | — |
| | | | 15,481 |
| | | | — |
| | |
| Shares used to compute diluted EPS for adjusted net income | | 222,855 |
| | | | 216,232 |
| | | | 230,912 |
| | | | 214,321 |
| 230,912 |
| |
| |
| (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 share equivalents from in-the-money stock options, dilutive restricted shares and subscription rights calculated in accordance with the treasury stock method. |
EXCO Resources, Inc.
Consolidated Cash Flow from Operations before Working Capital Changes and Other Operating Items Impacting Comparability and Reconciliations
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Year Ended December 31, |
| (in thousands) | | December 31, 2013 | | September 30, 2013 | | 2013 | | 2012 |
| Cash flow from operations, GAAP | | $ | 127,263 |
| | $ | 52,139 |
| | $ | 350,634 |
| | $ | 514,786 |
|
| Net change in working capital | | (34,067 | ) | | 31,994 |
| | (20,667 | ) | | (126,937 | ) |
| Other operating items impacting comparability | | 6,840 |
| | 2,769 |
| | 14,613 |
| | 16,625 |
|
| Cash flow from operations before changes in working capital and other operating items impacting comparability, non-GAAP measure (1) | | $ | 100,036 |
| | $ | 86,902 |
| | $ | 344,580 |
| | $ | 404,474 |
|
| |
(1) | Cash flow from operations before working capital changes and other operating items impacting comparability 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. Cash flow from operations before changes in working capital 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. Other operating items impacting comparability have been excluded as they do not reflect our on-going operating activities. |
EXCO Resources, Inc.
Summary of Operating Data
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | % | | Year Ended December 31, | | % |
| | | December 31, 2013 | | September 30, 2013 | | Change | | 2013 | | 2012 | | Change |
| Production: | | | | | | | | | | | | |
| Oil (Mbbls) | | 653 |
| | 383 |
| | 70 | % | | 1,188 |
| | 704 |
| | 69 | % |
| Natural gas liquids (Mbbls) | | 65 |
| | 53 |
| | 23 | % | | 243 |
| | 510 |
| | (52 | )% |
| Natural gas (Mmcf) | | 36,765 |
| | 39,268 |
| | (6 | )% | | 153,321 |
| | 182,644 |
| | (16 | )% |
| Total production (Mmcfe) (1) | | 41,073 |
| | 41,884 |
| | (2 | )% | | 161,907 |
| | 189,928 |
| | (15 | )% |
| Average daily production (Mmcfe) | | 446 |
| | 455 |
| | (2 | )% | | 444 |
| | 519 |
| | (14 | )% |
| Average sales price (before cash settlements of derivative financial instruments): | | | | | | | | | | | | |
| Oil (per Bbl) | | $ | 90.79 |
| | $ | 102.60 |
| | (12 | )% | | $ | 93.80 |
| | $ | 88.24 |
| | 6 | % |
| Natural gas liquids (per Bbl) | | 35.51 |
| | 32.04 |
| | 11 | % | | 35.23 |
| | 43.27 |
| | (19 | )% |
| Natural gas (per Mcf) | | 3.23 |
| | 3.17 |
| | 2 | % | | 3.35 |
| | 2.53 |
| | 32 | % |
| Natural gas equivalent (per Mcfe) | | 4.39 |
| | 3.95 |
| | 11 | % | | 3.92 |
| | 2.88 |
| | 36 | % |
| Costs and expenses (per Mcfe): | | | | | | | | | | | | |
| Oil and natural gas operating costs | | $ | 0.45 |
| | $ | 0.41 |
| | 10 | % | | $ | 0.38 |
| | $ | 0.41 |
| | (7 | )% |
| Production and ad valorem taxes | | 0.16 |
| | 0.15 |
| | 7 | % | | 0.14 |
| | 0.14 |
| | — | % |
| Gathering and transportation | | 0.64 |
| | 0.64 |
| | — | % | | 0.62 |
| | 0.54 |
| | 15 | % |
| Depletion | | 1.97 |
| | 1.74 |
| | 13 | % | | 1.47 |
| | 1.52 |
| | (3 | )% |
| Depreciation and amortization | | 0.04 |
| | 0.04 |
| | — | % | | 0.05 |
| | 0.08 |
| | (38 | )% |
| General and administrative | | 0.62 |
| | 0.52 |
| | 19 | % | | 0.57 |
| | 0.44 |
| | 30 | % |
Selected Pro Forma Financial Information
(Unaudited)
The EXCO/HGI Partnership was formed on February 14, 2013, which resulted in the reduction of our economic interest in certain oil and natural gas properties contributed to the partnership. On March 5, 2013, the EXCO/HGI Partnership purchased the remaining shallow Cotton Valley assets from an affiliate of BG Group, plc. During the third quarter of 2013, we closed the acquisitions of oil and natural gas properties in the Haynesville and Eagle Ford shale formations from Chesapeake. The following table presents selected pro forma operating and financial information for the years ended December 31, 2013 and 2012 as if these transactions had occurred on January 1, 2012. The pro forma information is not necessarily indicative of what actually would have occurred if the transactions had been completed as of January 1, 2012, nor is it necessarily indicative of future consolidated results of operations.
|
| | | | | | | | | | | | | | | | |
| | | Year ended December 31, 2013 |
| (dollars in thousands, except per unit rate) | | Historical EXCO | | EXCO/HGI Partnership pro forma adjustments | | Chesapeake Properties pro forma adjustments | | Pro forma EXCO |
| Production: | | | | | | | | |
| Total production (Mmcfe) | | 161,907 |
| | (2,705 | ) | | 27,279 |
| | 186,481 |
|
| Average production (Mmcfe/d) | | 444 |
| | (7 | ) | | 75 |
| | 512 |
|
| Revenues: | | | | | | | | |
| Oil and natural gas revenues | | $ | 634,309 |
| | $ | (12,657 | ) | | $ | 150,319 |
| | $ | 771,971 |
|
| Average realized price ($/Mcfe) | | 3.92 |
| | 4.68 |
| | 5.51 |
| | 4.14 |
|
| Expenses: | | | | | | | | |
| Direct operating costs | | 61,277 |
| | (3,489 | ) | | 22,564 |
| | 80,352 |
|
| Per Mcfe | | 0.38 |
| | 1.29 |
| | 0.83 |
| | 0.43 |
|
| Production and ad valorem taxes | | 21,971 |
| | (1,545 | ) | | 5,965 |
| | 26,391 |
|
| Per Mcfe | | 0.14 |
| | 0.57 |
| | 0.22 |
| | 0.14 |
|
| Gathering and transportation (1) | | 100,645 |
| | (782 | ) | | — |
| | 99,863 |
|
| Per Mcfe | | 0.62 |
| | 0.29 |
| | — |
| | 0.54 |
|
| Excess of revenues over operating expenses | | $ | 450,416 |
| | $ | (6,841 | ) | | $ | 121,790 |
| | $ | 565,365 |
|
| | | | | | | | | |
| | | Year ended December 31, 2012 |
| (dollars in thousands, except per unit rate) | | Historical EXCO | | EXCO/HGI Partnership pro forma adjustments | | Chesapeake Properties pro forma adjustments | | Pro forma EXCO |
| Production: | | | | | | | | |
| Total production (Mmcfe) | | 189,928 |
| | (25,077 | ) | | 46,414 |
| | 211,265 |
|
| Average production (Mmcfe/d) | | 519 |
| | (69 | ) | | 127 |
| | 577 |
|
| Revenues: | | | | | | | | |
| Oil and natural gas revenues | | $ | 546,609 |
| | $ | (111,276 | ) | | $ | 168,677 |
| | $ | 604,010 |
|
| Average realized price ($/Mcfe) | | 2.88 |
| | 4.44 |
| | 3.63 |
| | 2.86 |
|
| Expenses: | | | | | | | | |
| Direct operating costs | | 77,127 |
| | (29,081 | ) | | 28,173 |
| | 76,219 |
|
| Per Mcfe | | 0.41 |
| | 1.16 |
| | 0.61 |
| | 0.36 |
|
| Production and ad valorem taxes | | 27,483 |
| | (13,379 | ) | | 9,217 |
| | 23,321 |
|
| Per Mcfe | | 0.14 |
| | 0.53 |
| | 0.20 |
| | 0.11 |
|
| Gathering and transportation (1) | | 102,875 |
| | (7,892 | ) | | — |
| | 94,983 |
|
| Per Mcfe | | 0.54 |
| | 0.31 |
| | — |
| | 0.45 |
|
| Excess of revenues over operating expenses | | $ | 339,124 |
| | $ | (60,924 | ) | | $ | 131,287 |
| | $ | 409,487 |
|
(1) The oil and natural gas revenues for the Chesapeake Properties are presented net of gathering and treating expenses.
Selected Pro Forma Financial Information
(Unaudited)
The following table presents information relating to our liquidity as of December 31, 2013 as well as on a pro forma basis as if the closing of the Rights Offering had occurred on December 31, 2013. The pro forma information is not considered to be complete and excludes the impact of all other transactions subsequent to December 31, 2013.
|
| | | | | | | | |
| (in thousands) | | December 31, 2013 | | Pro forma |
| Cash (1) (2) | | $ | 66,518 |
| | $ | 66,518 |
|
| Revolving credit facility under the EXCO Resources Credit Agreement | | 735,000 |
| | 490,992 |
|
| Asset sale requirement under the EXCO Resources Credit Agreement | | 28,866 |
| | — |
|
| Term loan under the EXCO Resources Credit Agreement (3) | | 298,500 |
| | 298,500 |
|
| 2018 Notes (4) | | 750,000 |
| | 750,000 |
|
| Total debt (5) | | $ | 1,812,366 |
| | $ | 1,539,492 |
|
| Net debt | | $ | 1,745,848 |
| | $ | 1,472,974 |
|
| Borrowing base (6) | | $ | 1,228,866 |
| | $ | 1,200,000 |
|
| Unused borrowing base (7) | | $ | 158,112 |
| | $ | 402,120 |
|
| Unused borrowing base plus cash (1) (7) | | $ | 224,630 |
| | $ | 468,638 |
|
| |
| (1) | Includes restricted cash of $20.6 million at December 31, 2013. |
| |
| (2) | Excludes our proportionate share of cash related to the EXCO/HGI Partnership of $4.5 million at December 31, 2013. |
| |
| (3) | Excludes unamortized discount of $2.8 million at December 31, 2013. |
| |
| (4) | Excludes unamortized discount of $7.3 million at December 31, 2013. |
| |
| (5) | Excludes our proportionate share of the debt related to the EXCO/HGI Partnership of $88.5 million as of December 31, 2013. |
| |
| (6) | Includes the borrowing base for the revolving commitment and term loan under the EXCO Resources Credit Agreement. |
| |
| (7) | Net of $6.9 million in letters of credit and $1.5 million in repayments under the term loan as of December 31, 2013. |
