EXCO Resources, Inc. Reports Third Quarter 2014 Results
EXCO Resources Inc. (NYSE: XCO) (“EXCO”) today announced operating and financial results for the third quarter 2014.
- Adjusted EBITDA was $94 million for the third quarter 2014, which exceeded the mid-point of guidance.
- Production was 33 Bcfe, or 358 Mmcfe per day, for the third quarter 2014, which was within our guidance.
- Drilled 26 gross (11.6 net) and completed 21 gross (6.8 net) operated horizontal shale wells in the third quarter 2014.
- Implemented cost reduction initiatives which resulted in oil and natural gas operating costs and general and administrative costs below the low-end of guidance for the third quarter 2014.
- Enhanced our liquidity as a result of an increase to the borrowing base under our credit agreement.
- Expect to reduce indebtedness and further enhance liquidity as a result of the pending sale of our interests in Compass Production Partners.
Jeff Benjamin, EXCO’s chairman, commented, "We continue to demonstrate strong financial performance and execute on our key business objectives. The energy sector has recently experienced a decline in market valuation driven by lower commodity prices; however, we believe that our execution of several key transactions and fiscal discipline over the past year has positioned EXCO for future success. Our improved balance sheet, enhanced liquidity and hedging strategy will allow us to accomplish our business strategies through various commodity price cycles. Our financial position gives us the ability to actively pursue acquisitions as opportunities arise. We have also been impressed with the recent success of several operational initiatives that are expected to unlock additional value from our current asset base, including our enhanced completion methods and programs to optimize our base production."
Financial results
GAAP results were net income of $42 million, or $0.15 per diluted share, for the third quarter 2014 compared with net income of $2 million, or $0.01 per diluted share, for the second quarter 2014. The increase in net income was primarily due to volatility in commodity prices which resulted in higher unrealized gains on derivative contracts in the current quarter. This was partially offset by lower revenues in the current quarter due to a decrease in production and realized commodity prices.
Adjusted EBITDA for the third quarter 2014 was $94 million compared with $105 million for the second quarter 2014. 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, unrealized gains or losses from derivative financial instruments, 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 $0.01 per diluted share for the third quarter 2014 compared with $0.03 per diluted share for the second quarter 2014. 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.
Oil, natural gas and natural gas liquids ("NGLs") production was 33 Bcfe, or 358 Mmcfe per day, for the third quarter 2014 compared with 35 Bcfe, or 383 Mmcfe per day, for the second quarter 2014. Third quarter 2014 production from the East Texas/North Louisiana region was 242 Mmcfe per day compared with 257 Mmcfe per day in the second quarter 2014. The decrease in production was primarily the result of normal production declines and the timing of completions based on our drilling program. The decrease was partially offset by the additional production from the 7 gross (4.0 net) operated wells turned-to-sales during the third quarter 2014 (including 2 gross (1.0 net) operated wells that were turned-to-sales on the last day of the quarter). Third quarter 2014 production from the South Texas region was 540 Mboe, or 5,870 Boe per day, compared with 596 Mboe, or 6,550 Boe per day, in the second quarter 2014. The decrease in production was primarily due to reduced completion activity which resulted in an increased inventory of wells that were drilled and waiting on completion at the end of the third quarter 2014. The reduced completion activity and inventory of wells was primarily due to wells waiting on the construction of our first centralized production facility in the region which became operational in the fourth quarter of 2014. The third quarter 2014 production in the Appalachia region was 56 Mmcfe per day compared with 62 Mmcfe per day in the second quarter 2014. The decrease in production was due to normal production declines and additional downtime due to planned pipeline maintenance. Our proportionate share of production from Compass Production Partners was 25 Mmcfe per day for both the third quarter 2014 and the second quarter 2014.
Oil, natural gas and NGL revenues for the third quarter 2014 were $151 million compared with $183 million for the second quarter 2014. Our average sales price per Mcfe decreased to $4.58 per Mcfe for the third quarter 2014 from $5.25 per Mcfe for the second quarter 2014. Our average sales price per Mcfe for the third quarter 2014 decreased primarily due to lower market prices for oil and natural gas compared to the second quarter 2014. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $153 million, or $4.65 per Mcfe, for the third quarter 2014, compared with $168 million, or $4.83 per Mcfe, for the second quarter 2014.
Our direct operating costs were $14 million, or $0.43 per Mcfe, for the third quarter 2014 compared with $16 million, or $0.45 per Mcfe, for the second quarter 2014. The lower direct operating costs were primarily due to the continued execution of cost reduction initiatives in the South Texas region including decreased salt water disposal costs and reduced reliance on third-party contractors.
Our general and administrative costs were $14 million for the third quarter 2014 compared with $20 million for the second quarter 2014. The decrease was primarily due to lower headcount from the reduction in force during the second quarter 2014. Also, we incurred severance costs and lease termination fees for unused office space in the second quarter of 2014 that we did not incur in the third quarter 2014.
Cash flows from operations before changes in working capital and other operating items impacting comparability, a non-GAAP measure, were $72 million for the third quarter 2014 compared with $84 million for the second quarter 2014. During the third quarter 2014, we primarily used our cash flows from operations to fund our drilling and development program.
Recent developments
Compass Production Partners sale
On October 6, 2014, we entered into an agreement to sell our 25.5% economic interest in Compass Production Partners, LP ("Compass") to an affiliate of Harbinger Group, Inc. for $119 million in cash. We intend to use the proceeds to reduce indebtedness under the revolving commitment of our credit agreement ("EXCO Resources Credit Agreement"). Our borrowing base under the EXCO Resources Credit Agreement will not be affected by this sale since Compass is not a guarantor subsidiary. In addition, our consolidated indebtedness will be reduced by our proportionate share of Compass's indebtedness upon closing of the sale. As of September 30, 2014, we proportionally consolidated $83 million of indebtedness related to Compass's credit agreement. The transaction is expected to close during the fourth quarter of 2014.
Borrowing base redetermination and liquidity update
On October 22, 2014, our borrowing base under the EXCO Resources Credit Agreement was increased from $875 million to $900 million. The increase in our borrowing base improves our liquidity and demonstrates the quality of our assets. EXCO had liquidity of $711 million as of September 30, 2014. On a pro forma basis as if the sale of our interest in Compass and the borrowing base redetermination had occurred on September 30, 2014, our liquidity would have been $855 million. The anticipated reduction in indebtedness as a result of the Compass sale will also improve the metrics utilized in the financial covenants under the EXCO Resources Credit Agreement.
Operations activity and outlook
We spent $91 million on development activities, drilling 26 gross (11.6 net) operated wells and completing 21 gross (6.8 net) operated wells in the third quarter 2014. Our development program during 2014 is focused on our properties in the Haynesville and Eagle Ford shales. Our diverse portfolio of oil and natural gas properties gives us optionality to make capital decisions to maximize our returns based on our evaluation of industry trends and commodity prices. We remain focused on efficiently managing our capital expenditures as part of our development program.
Our capital expenditure program for the fourth quarter 2014 will primarily focus on our properties in the Haynesville and Eagle Ford shales. Our development activities in the East Texas/North Louisiana region will focus on drilling and completion activities in the Haynesville and Bossier shales within DeSoto Parish, Louisiana. In addition, we will be completing wells that have been drilled in the Shelby area of East Texas. Our development activities in the South Texas region will primarily focus on drilling and completion activities in the Eagle Ford shale within our core area and limited drilling outside of our core area as part of a farmout agreement. Our first centralized production facility in the region became operational in the fourth quarter 2014 which allows us to begin production from our inventory of wells that were waiting on completion at the end of the third quarter 2014.
Our actual capital expenditures during the first, second and third quarter 2014 as well as our fourth quarter and full year 2014 forecast are presented in the following table.
| (in thousands) | First Quarter 2014 | Second Quarter 2014 | Third Quarter 2014 | Fourth Quarter Forecast | Full Year 2014 Forecast | ||||||||||||||||
| Capital expenditures (1): | |||||||||||||||||||||
| Development capital expenditures | $ | 80,198 | $ | 78,245 | $ | 91,204 | $ | 91,353 | $ | 341,000 | |||||||||||
| Field operations, gathering and water pipelines | 8,518 | 9,447 | (1,039 | ) | 5,074 | 22,000 | |||||||||||||||
| Lease purchases | 1,996 | 1,215 | 3,696 | 7,093 | 14,000 | ||||||||||||||||
| Seismic | 8 | 150 | 179 | 1,663 | 2,000 | ||||||||||||||||
| Corporate and other | 9,317 | 10,069 | 9,465 | 13,149 | 42,000 | ||||||||||||||||
| Total | $ | 100,037 | $ | 99,126 | $ | 103,505 | $ | 118,332 | $ | 421,000 | |||||||||||
(1) Excludes capital expenditures related to Compass, which funded its capital expenditures through internally generated cash flows and its credit agreement.
East Texas/North Louisiana
In the East Texas/North Louisiana region during the third quarter 2014, we operated an average of six drilling rigs primarily focused on manufacturing in our core area in DeSoto Parish, Louisiana. In DeSoto Parish, we drilled 15 gross (8.9 net) operated wells and completed 5 gross (3.0 net) wells during the quarter. We had an inventory of 12 gross (6.7 net) wells that were drilled and waiting on completion in DeSoto Parish at the end of the quarter, most of which will be turned-to-sales in the fourth quarter 2014. We have continued to optimize our well design by increasing the amount of proppant used in the hydraulic fracturing process on completions during the quarter. These changes in our well design are expected to improve our well performance and estimated ultimate recoveries. We are also in the process of completing our first cross-unit development in DeSoto Parish that includes drilling 5,000 to 7,000 foot laterals into a section bisected by a fault. The laterals on the cross-unit development are longer than our typical laterals of approximately 4,200 feet for Haynesville shale wells in DeSoto Parish. We plan to turn these wells to sales during the fourth quarter 2014.
In the Shelby area, we completed 2 gross (1.0 net) wells on the last day of the quarter. In addition, we have plans to complete and turn-to-sales 4 gross (1.9 net wells) in the fourth quarter 2014. Prior to 2014, our activity in this area has historically consisted of delineating the acreage, establishing infrastructure, and performing technical evaluations. Our drilling program during 2014 was designed to include enhanced completion methods, longer laterals and a more restricted flowback program. As part of our restricted flowback program, we have been managing the choke size to limit the production of the wells to 10 Mmcf per day. The restricted flowback limits the initial production of the wells; however, we anticipate it will increase the estimated ultimate recoveries. We have been encouraged by the results of the wells turned-to-sales in this area during 2014. The more conservative flowback, along with the other design changes, are yielding strong well performance as evidenced by a minimal reduction in flowing pressures over time. We drilled 8 gross (3.9 net) wells in the area during 2014 which includes 5 gross (2.4 net) in the Haynesville shale and 3 gross (1.5 net) in the Bossier shale. We are experiencing similar strong results from both the Haynesville and Bossier shale wells. We have approximately 250 operated undeveloped locations in this area which provide a platform for future growth.
We have spud a test well in the Bossier shale in DeSoto Parish in the fourth quarter 2014 to further assess the potential of the formation. The Bossier shale lies just above certain portions of the Haynesville shale and contains rich deposits of natural gas. We will utilize our technical expertise and recently enhanced completion methods that have proven to be successful in our Haynesville shale development. We will evaluate the results of the test in DeSoto Parish which could result in the addition of a significant number of drilling locations.
We completed our first refrac stimulation test on a mature Haynesville shale well in a fully developed unit within DeSoto Parish during the third quarter 2014. This test consisted of a second fracture stimulation treatment in an existing well to re-stimulate the shale reservoir. The refrac stimulation resulted in an increase in production for this well of 1.4 Mmcf per day on a more restricted choke as well as an increase in flowing casing pressure of 3,000 psi. The well continues to perform well as evidenced by the minimal reduction in production and pressure in the three months since the refrac stimulation. We expect to perform a similar treatment on other wells in the region and have plans for three additional refrac stimulation tests during the fourth quarter 2014. We have identified more than 270 operated Haynesville shale wells that are potential candidates for this treatment.
We have implemented several initiatives during the year to enhance and manage our base production in the region. This includes the initiation of a compression program, foamer injection program and the installation of artificial lift. Our compression program included the installation of two interim lateral compressor units during the quarter. We are currently studying additional interim lateral compression options and full field compression options in this region. We have seen sustained performance improvement from these initiatives as evidenced by a flattening of our base decline.
Additionally, BG Group’s right to participate in our acquisition of oil and natural gas properties within an area of mutual interest in the East Texas/North Louisiana region expired in August 2014. We have significant experience and technical expertise in this region and this allows us to realize the full economic benefits of future acquisitions without the participation of a significant joint venture partner.
South Texas
In the South Texas region during the third quarter 2014, we operated an average of two drilling rigs focused on development of the Eagle Ford shale. We drilled 11 gross (2.7 net) operated wells and completed 14 gross (2.9 net) wells in the Eagle Ford shale during the quarter. Our drilling program during the quarter consisted of manufacturing and testing in the core area and adjacent areas under a farmout agreement. We have continued to expand our position in the area by earning additional acreage through drilling under the farmout agreement and leasing properties adjacent to our core area. We are preparing to test the Buda formation on a portion of our acreage later this year.
Our first centralized production facility within our core area became operational in the fourth quarter 2014 which allows us to begin production from wells connected to this system. At the end of the quarter, we had 31 gross (6.1 net) operated wells in the Eagle Ford shale that were drilled and waiting on completion, most of which will be turned-to-sales during the fourth quarter 2014. There are two additional centralized facilities within our core area that are currently in the construction phase.
We have realized significant improvements in our drilling performance since we acquired the assets in the South Texas region during 2013. This includes improved drilling times per well which are currently averaging 13 days from spud to rig release. We continue to evaluate updates to our well design including longer laterals and more proppant used in the hydraulic fracturing process. During the third quarter 2014, our shut-in volumes averaged 1,300 net Bbls of oil per day due to wells waiting on the centralized facilities as well as offset drilling, completion and maintenance activities. This is an increase from the shut-in volumes during the second quarter 2014 which averaged 1,100 net Bbls of oil per day. We are implementing initiatives to optimize and increase the efficiency of our production including the installation of artificial lift. The artificial lift units installed to-date have been successful in flattening our base decline.
Appalachia
In the Appalachia region, we remain focused on base production efficiency from our Marcellus shale and conventional assets. We have been able to effectively manage our base production declines as a result of increased automation and surveillance equipment to reduce downtime as well as artificial lift installations. We have also recently restructured our field organization to better align the operations personnel with the asset base and reduce our operating costs.
We are currently constructing a pad site for limited appraisal drilling in early 2015 targeting the Marcellus shale in Northeast Pennsylvania near recent successful well results. A significant portion of our acreage in the Marcellus shale is held-by-production, which allows us to control the timing of the development in this region.
Financial Data
Our consolidated balance sheets as of September 30, 2014 and December 31, 2013, consolidated statements of operations for the three months ended September 30, 2014, June 30, 2014, and September 30, 2013 and nine months ended September 30, 2014 and 2013 and consolidated statements of cash flows for the nine months ended September 30, 2014 and 2013, 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, October 29, 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#24918635. 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 prior to the conference call. A digital recording will be available starting two hours after the completion of the conference call until November 12, 2014. Please call (800) 585-8367 and enter conference ID#24918635 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 Vice President 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.
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, 2013, filed with the Securities and Exchange Commission ("SEC") on February 26, 2014, 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. 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.
| EXCO Resources, Inc. | ||||||||||
| Condensed Consolidated Balance Sheets | ||||||||||
| (in thousands) | September 30, 2014 | December 31, 2013 | ||||||||
| (Unaudited) | ||||||||||
| Assets | ||||||||||
| Current assets: | ||||||||||
| Cash and cash equivalents | $ | 47,950 | $ | 50,483 | ||||||
| Restricted cash | 21,959 | 20,570 | ||||||||
| Accounts receivable, net: | ||||||||||
| Oil and natural gas | 88,958 | 128,352 | ||||||||
| Joint interest | 58,167 | 70,759 | ||||||||
| Other | 6,027 | 18,022 | ||||||||
| Derivative financial instruments | 19,230 | 8,226 | ||||||||
| Inventory and other | 6,586 | 9,442 | ||||||||
| Total current assets | 248,877 | 305,854 | ||||||||
| Equity investments | 56,361 | 57,562 | ||||||||
| Oil and natural gas properties (full cost accounting method): | ||||||||||
| Unproved oil and natural gas properties and development costs not being amortized | 354,225 | 425,307 | ||||||||
| Proved developed and undeveloped oil and natural gas properties | 3,870,486 | 3,554,210 | ||||||||
| Accumulated depletion | (2,380,540 | ) | (2,183,464 | ) | ||||||
| Oil and natural gas properties, net | 1,844,171 | 1,796,053 | ||||||||
| Gathering assets | 33,884 | 33,473 | ||||||||
| Accumulated depreciation and amortization | (11,617 | ) | (10,338 | ) | ||||||
| Gathering assets, net | 22,267 | 23,135 | ||||||||
| Office, field and other equipment, net | 25,535 | 27,204 | ||||||||
| Deferred financing costs, net | 33,166 | 28,807 | ||||||||
| Derivative financial instruments | 8,813 | 6,829 | ||||||||
| Goodwill | 163,155 | 163,155 | ||||||||
| Other assets | 27 | 29 | ||||||||
| Total assets | $ | 2,402,372 | $ | 2,408,628 | ||||||
| EXCO Resources, Inc. | ||||||||||
| Condensed Consolidated Balance Sheets | ||||||||||
| (in thousands, except per share and share data) | September 30, 2014 | December 31, 2013 | ||||||||
| (Unaudited) | ||||||||||
| Liabilities and shareholders’ equity | ||||||||||
| Current liabilities: | ||||||||||
| Accounts payable and accrued liabilities | $ | 120,358 | $ | 109,217 | ||||||
| Revenues and royalties payable | 168,331 | 154,862 | ||||||||
| Drilling advances | 51,547 | 22,971 | ||||||||
| Accrued interest payable | 22,836 | 18,144 | ||||||||
| Current portion of asset retirement obligations | 216 | 191 | ||||||||
| Income taxes payable | — | — | ||||||||
| Derivative financial instruments | 9,297 | 11,919 | ||||||||
| Current maturities of long-term debt | — | 31,866 | ||||||||
| Total current liabilities | 372,585 | 349,170 | ||||||||
| Long-term debt | 1,549,439 | 1,858,912 | ||||||||
| Deferred income taxes | — | — | ||||||||
| Derivative financial instruments | 7,987 | 9,671 | ||||||||
| Asset retirement obligations and other long-term liabilities | 45,319 | 42,970 | ||||||||
| Commitments and contingencies | — | — | ||||||||
| Shareholders’ equity: | ||||||||||
| Common stock, $0.001 par value; 350,000,000 authorized shares; 274,324,023 shares issued and 273,784,802 shares outstanding at September 30, 2014; 218,783,540 shares issued and 218,244,319 shares outstanding at December 31, 2013 | 270 | 215 | ||||||||
| Subscription rights, $0.001 par value; none issued and outstanding at September 30, 2014; 54,574,734 issued and outstanding at December 31, 2013 | — | 55 | ||||||||
| Additional paid-in capital | 3,500,488 | 3,219,748 | ||||||||
| Accumulated deficit | (3,066,237 | ) | (3,064,634 | ) | ||||||
| Treasury stock, at cost; 539,221 shares at September 30, 2014 and December 31, 2013 | (7,479 | ) | (7,479 | ) | ||||||
| Total shareholders’ equity | 427,042 | 147,905 | ||||||||
| Total liabilities and shareholders’ equity | $ | 2,402,372 | $ | 2,408,628 | ||||||
| EXCO Resources, Inc. | |||||||||||||||||||||||||
| Condensed Consolidated Statements of Operations | |||||||||||||||||||||||||
| (Unaudited) | |||||||||||||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||
| (in thousands, except per share data) | September 30, 2014 | June 30, 2014 | September 30, 2013 | September 30, 2014 | September 30, 2013 | ||||||||||||||||||||
| Revenues: | |||||||||||||||||||||||||
| Total revenues | $ | 151,042 | $ | 182,966 | $ | 165,314 | $ | 532,480 | $ | 453,869 | |||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||
| Oil and natural gas operating costs | 14,099 | 15,827 | 17,187 | 48,713 | 42,706 | ||||||||||||||||||||
| Production and ad valorem taxes | 7,978 | 7,364 | 6,074 | 22,951 | 15,303 | ||||||||||||||||||||
| Gathering and transportation | 25,822 | 26,038 | 26,665 | 76,473 | 74,549 | ||||||||||||||||||||
| Depletion, depreciation and amortization | 64,913 | 67,253 | 74,499 | 201,441 | 163,195 | ||||||||||||||||||||
| Impairment of oil and natural gas properties | — | — | — | — | 10,707 | ||||||||||||||||||||
| Accretion of discount on asset retirement obligations | 709 | 695 | 619 | 2,085 | 1,865 | ||||||||||||||||||||
| General and administrative | 14,059 | 19,504 | 21,937 | 50,901 | 66,495 | ||||||||||||||||||||
| (Gain) loss on divestitures and other operating items | 663 | 2,973 | 2,739 | 6,382 | (179,503 | ) | |||||||||||||||||||
| Total costs and expenses | 128,243 | 139,654 | 149,720 | 408,946 | 195,317 | ||||||||||||||||||||
| Operating income | 22,799 | 43,312 | 15,594 | 123,534 | 258,552 | ||||||||||||||||||||
| Other income (expense): | |||||||||||||||||||||||||
| Interest expense, net | (23,974 | ) | (25,968 | ) | (36,474 | ) | (70,106 | ) | (71,771 | ) | |||||||||||||||
| Gain (loss) on derivative financial instruments | 42,844 | (14,718 | ) | 7,443 | (14,896 | ) | 19,175 | ||||||||||||||||||
| Other income | 53 | 77 | 94 | 176 | 340 | ||||||||||||||||||||
| Equity income (loss) | (153 | ) | (410 | ) | (85,308 | ) | 548 | (61,229 | ) | ||||||||||||||||
| Total other income (expense) | 18,770 | (41,019 | ) | (114,245 | ) | (84,278 | ) | (113,485 | ) | ||||||||||||||||
| Income (loss) before income taxes | 41,569 | 2,293 | (98,651 | ) | 39,256 | 145,067 | |||||||||||||||||||
| Income tax expense | — | — | — | — | — | ||||||||||||||||||||
| Net income (loss) | $ | 41,569 | $ | 2,293 | $ | (98,651 | ) | $ | 39,256 | $ | 145,067 | ||||||||||||||
| Earnings (loss) per common share: | |||||||||||||||||||||||||
| Basic: | |||||||||||||||||||||||||
| Net income (loss) | $ | 0.15 | $ | 0.01 | $ | (0.46 | ) | $ | 0.15 | $ | 0.68 | ||||||||||||||
| Weighted average common shares outstanding | 270,631 | 270,492 | 215,056 | 267,316 | 214,877 | ||||||||||||||||||||
| Diluted: | |||||||||||||||||||||||||
| Net income (loss) | $ | 0.15 | $ | 0.01 | $ | (0.46 | ) | $ | 0.15 | $ | 0.67 | ||||||||||||||
| Weighted average common shares and common share equivalents outstanding | 272,066 | 271,226 | 215,056 | 267,690 | 215,195 | ||||||||||||||||||||
| EXCO Resources, Inc. | ||||||||||
| Condensed Consolidated Statements of Cash Flows | ||||||||||
| (Unaudited) | ||||||||||
| Nine Months Ended September 30, | ||||||||||
| (in thousands) | 2014 | 2013 | ||||||||
| Operating Activities: | ||||||||||
| Net income | $ | 39,256 | $ | 145,067 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||
| Depletion, depreciation and amortization | 201,441 | 163,195 | ||||||||
| Share-based compensation expense | 4,370 | 9,493 | ||||||||
| Accretion of discount on asset retirement obligations | 2,085 | 1,865 | ||||||||
| Impairment of oil and natural gas properties | — | 10,707 | ||||||||
| (Income) loss from equity method investments | (548 | ) | 61,229 | |||||||
| (Gain) loss on derivative financial instruments | 14,896 | (19,175 | ) | |||||||
| Cash settlements (payments) of derivative financial instruments | (32,187 | ) | 28,416 | |||||||
| Amortization of deferred financing costs and discount on debt issuance | 9,891 | 22,440 | ||||||||
| Gain on divestitures and other non-operating items | (8 | ) | (186,466 | ) | ||||||
| Effect of changes in: | ||||||||||
| Accounts receivable | 60,201 | (32,121 | ) | |||||||
| Other current assets | (1,135 | ) | 4,879 | |||||||
| Accounts payable and other current liabilities | 60,103 | 13,842 | ||||||||
| Net cash provided by operating activities | 358,365 | 223,371 | ||||||||
| Investing Activities: | ||||||||||
| Additions to oil and natural gas properties, gathering assets and equipment | (297,736 | ) | (180,603 | ) | ||||||
| Property acquisitions | (12,987 | ) | (1,007,362 | ) | ||||||
| Proceeds from disposition of property and equipment | 76,536 | 745,733 | ||||||||
| Restricted cash | (1,389 | ) | 33,948 | |||||||
| Net changes in advances to joint ventures | (3,181 | ) | 10,055 | |||||||
| Equity method investments | 1,749 | (363 | ) | |||||||
| Net cash used in investing activities | (237,008 | ) | (398,592 | ) | ||||||
| Financing Activities: | ||||||||||
| Borrowings under credit agreements | 40,000 | 1,004,523 | ||||||||
| Repayments under credit agreements | (884,970 | ) | (777,470 | ) | ||||||
| Proceeds received from issuance of 2022 Notes | 500,000 | — | ||||||||
| Proceeds from issuance of common stock, net | 271,760 | 1,712 | ||||||||
| Payment of common stock dividends | (40,604 | ) | (32,237 | ) | ||||||
| Deferred financing costs and other | (10,076 | ) | (33,458 | ) | ||||||
| Net cash provided by (used in) financing activities | (123,890 | ) | 163,070 | |||||||
| Net decrease in cash | (2,533 | ) | (12,151 | ) | ||||||
| Cash at beginning of period | 50,483 | 45,644 | ||||||||
| Cash at end of period | $ | 47,950 | $ | 33,493 | ||||||
| Supplemental Cash Flow Information: | ||||||||||
| Cash interest payments | $ | 69,257 | $ | 74,949 | ||||||
| Income tax payments | — | — | ||||||||
| Supplemental non-cash investing and financing activities: | ||||||||||
| Capitalized share-based compensation | $ | 4,432 | $ | 5,533 | ||||||
| Capitalized interest | 15,410 | 15,264 | ||||||||
| Issuance of common stock for director services | 185 | 65 | ||||||||
| Accrued restricted stock dividends | 255 | 349 | ||||||||
| Debt assumed upon formation of Compass, net | — | 58,613 | ||||||||
| EXCO Resources, Inc. | |||||||||||||||||||||||||
| Consolidated EBITDA | |||||||||||||||||||||||||
| And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data | |||||||||||||||||||||||||
| (Unaudited) | |||||||||||||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||
| (in thousands) | September 30, 2014 | June 30, 2014 | September 30, 2013 | September 30, 2014 | September 30, 2013 | ||||||||||||||||||||
| Net income (loss) | $ | 41,569 | $ | 2,293 | $ | (98,651 | ) | $ | 39,256 | $ | 145,067 | ||||||||||||||
| Interest expense | 23,974 | 25,968 | 36,474 | 70,106 | 71,771 | ||||||||||||||||||||
| Income tax expense | — | — | — | — | — | ||||||||||||||||||||
| Depletion, depreciation and amortization | 64,913 | 67,253 | 74,499 | 201,441 | 163,195 | ||||||||||||||||||||
| EBITDA(1) | $ | 130,456 | $ | 95,514 | $ | 12,322 | $ | 310,803 | $ | 380,033 | |||||||||||||||
| Accretion of discount on asset retirement obligations | 709 | 695 | 619 | 2,085 | 1,865 | ||||||||||||||||||||
| Impairment of oil and natural gas properties | — | — | — | — | 10,707 | ||||||||||||||||||||
| (Gain) loss on divestitures and other items impacting comparability | 1,747 | 6,775 | 2,653 | 11,122 | (178,693 | ) | |||||||||||||||||||
| Equity (income) loss | 153 | 410 | 85,308 | (548 | ) | 61,229 | |||||||||||||||||||
| Net (gains) losses on derivative financial instruments | (42,844 | ) | 14,718 | (7,443 | ) | 14,896 | (19,175 | ) | |||||||||||||||||
| Cash settlements (payments) on derivative financial instruments | 2,282 | (14,659 | ) | 10,904 | (32,187 | ) | 28,416 | ||||||||||||||||||
| Share based compensation expense | 1,118 | 1,745 | 3,170 | 4,370 | 9,493 | ||||||||||||||||||||
| Adjusted EBITDA (1) | $ | 93,621 | $ | 105,198 | $ | 107,533 | $ | 310,541 | $ | 293,875 | |||||||||||||||
| Interest expense | (23,974 | ) | (25,968 | ) | (36,474 | ) | (70,106 | ) | (71,771 | ) | |||||||||||||||
| Income tax expense | — | — | — | — | — | ||||||||||||||||||||
| Amortization of deferred financing costs and discount | 2,194 | 5,253 | 15,843 | 9,891 | 22,440 | ||||||||||||||||||||
| Other operating items impacting comparability | (1,755 | ) | (6,775 | ) | (2,769 | ) | (11,130 | ) | (7,773 | ) | |||||||||||||||
| Changes in working capital | 20,157 | (9,920 | ) | (31,994 | ) | 119,169 | (13,400 | ) | |||||||||||||||||
| Net cash provided by operating activities | $ | 90,243 | $ | 67,788 | $ | 52,139 | $ | 358,365 | $ | 223,371 | |||||||||||||||
| EXCO Resources, Inc. | |||||||||||||||||||||||||
| Consolidated EBITDA | |||||||||||||||||||||||||
| And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data | |||||||||||||||||||||||||
| (Unaudited) | |||||||||||||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||
| (in thousands) | September 30, | June 30, | September 30, | September 30, | September 30, | ||||||||||||||||||||
| Statement of cash flow data: | |||||||||||||||||||||||||
| Cash flow provided by (used in): | |||||||||||||||||||||||||
| Operating activities | $ | 90,243 | $ | 67,788 | $ | 52,139 | $ | 358,365 | $ | 223,371 | |||||||||||||||
| Investing activities | (112,065 | ) | (101,199 | ) | (881,644 | ) | (237,008 | ) | (398,592 | ) | |||||||||||||||
| Financing activities | 23,894 | (15,223 | ) | 782,556 | (123,890 | ) | 163,070 | ||||||||||||||||||
| Other financial and operating data: | |||||||||||||||||||||||||
| EBITDA(1) | $ | 130,456 | $ | 95,514 | $ | 12,322 | $ | 310,803 | $ | 380,033 | |||||||||||||||
| Adjusted EBITDA(1) | 93,621 | 105,198 | 107,533 | 310,541 | 293,875 | ||||||||||||||||||||
| (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 impairments 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, similar measures are used in covenant calculations required under our credit agreement, the indenture governing our 7.5% senior notes due September 15, 2018 ("2018 Notes"), and the indenture governing our 8.5% senior notes due April 15, 2022 ("2022 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 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. The calculation of EBITDA and Adjusted EBITDA as presented herein differ in certain respects from the calculation of comparable measures in the EXCO Resources Credit Agreement, the indenture governing our 2018 Notes and the indenture governing our 2022 Notes. |
| EXCO Resources, Inc. | ||||||||||||||||||||||||||||||||||||||||||||
| Consolidated Adjusted Net Income and Adjusted Net Income Reconciliations | ||||||||||||||||||||||||||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||||||||||||||||||||||||||
| Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||||||||
| September 30, | June 30, | September 30, | September 30, | September 30, | ||||||||||||||||||||||||||||||||||||||||
| (in thousands, except per share amounts) | Amount | Per | Amount | Per | Amount | Per | Amount | Per | Amount | Per | ||||||||||||||||||||||||||||||||||
| Net income (loss), GAAP | $ | 41,569 | $ | 2,293 | $ | (98,651 | ) | $ | 39,256 | $ | 145,067 | |||||||||||||||||||||||||||||||||
| Adjustments: | ||||||||||||||||||||||||||||||||||||||||||||
| Total net (gains) losses on derivatives | (42,844 | ) | 14,718 | (7,443 | ) | 14,896 | (19,175 | ) | ||||||||||||||||||||||||||||||||||||
| Cash receipts (payments) on derivative financial instruments | 2,282 | (14,659 | ) | 10,904 | (32,187 | ) | 28,416 | |||||||||||||||||||||||||||||||||||||
| Impairment of oil and natural gas properties | — | — | — | — | 10,707 | |||||||||||||||||||||||||||||||||||||||
| Adjustments included in equity (income) loss | — | — | 94,580 | (1,749 | ) | 94,950 | ||||||||||||||||||||||||||||||||||||||
| (Gain) loss on divestitures and other items impacting comparability | 1,747 | 6,775 | 2,653 | 11,122 | (178,693 | ) | ||||||||||||||||||||||||||||||||||||||
| Deferred finance cost and discount on debt issuance amortization acceleration | — | 3,099 | 13,183 | 3,471 | 16,718 | |||||||||||||||||||||||||||||||||||||||
| Income taxes on above adjustments (1) | 15,526 | (3,973 | ) | (45,551 | ) | 1,779 | 18,831 | |||||||||||||||||||||||||||||||||||||
| Adjustment to deferred tax asset valuation allowance (2) | (16,628 | ) | (917 | ) | 39,460 | (15,702 | ) | (58,027 | ) | |||||||||||||||||||||||||||||||||||
| Total adjustments, net of taxes | (39,917 | ) | 5,043 | 107,786 | (18,370 | ) | (86,273 | ) | ||||||||||||||||||||||||||||||||||||
| Adjusted net income | $ | 1,652 | $ | 7,336 | $ | 9,135 | $ | 20,886 | $ | 58,794 | ||||||||||||||||||||||||||||||||||
| Net income (loss), GAAP (3) | $ | 41,569 | $ | 0.15 | $ | 2,293 | $ | 0.01 | $ | (98,651 | ) | $ | (0.46 | ) | $ | 39,256 | $ | 0.15 | $ | 145,067 | $ | 0.68 | ||||||||||||||||||||||
| Adjustments shown above (3) | (39,917 | ) | (0.14 | ) | 5,043 | 0.02 | 107,786 | 0.50 | (18,370 | ) | (0.07 | ) | (86,273 | ) | (0.40 | ) | ||||||||||||||||||||||||||||
| Dilution attributable to share-based payments (4) | — | — | — | — | — | — | — | — | — | (0.01 | ) | |||||||||||||||||||||||||||||||||
| Adjusted net income | $ | 1,652 | $ | 0.01 | $ | 7,336 | $ | 0.03 | $ | 9,135 | $ | 0.04 | $ | 20,886 | $ | 0.08 | $ | 58,794 | $ | 0.27 | ||||||||||||||||||||||||
| Common stock and equivalents used for earnings per share (EPS): | ||||||||||||||||||||||||||||||||||||||||||||
| Weighted average common shares outstanding | 270,631 | 270,492 | 215,056 | 267,316 | 214,877 | |||||||||||||||||||||||||||||||||||||||
| Dilutive stock options | — | — | 274 | — | 8 | |||||||||||||||||||||||||||||||||||||||
| Dilutive restricted shares | 1,435 | 734 | 902 | 374 | 310 | |||||||||||||||||||||||||||||||||||||||
| Shares used to compute diluted EPS for adjusted net income | 272,066 | 271,226 | 216,232 | 267,690 | 215,195 | |||||||||||||||||||||||||||||||||||||||
| (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 and dilutive restricted shares 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 | Nine Months Ended | ||||||||||||||||||
| (in thousands) | September 30, 2014 | June 30, 2014 | September 30, 2013 | September 30, 2014 | September 30, 2013 | ||||||||||||||
| Cash flow from operations, GAAP | $ | 90,243 | $ | 67,788 | $ | 52,139 | $ | 358,365 | $ | 223,371 | |||||||||
| Net change in working capital | (20,157 | ) | 9,920 | 31,994 | (119,169 | ) | 13,400 | ||||||||||||
| Non-recurring other operating items | 1,747 | 6,775 | 2,769 | 11,122 | 7,773 | ||||||||||||||
| Cash flow from operations before changes in working capital and other operating items impacting comparability, non-GAAP measure (1) | $ | 71,833 | $ | 84,483 | $ | 86,902 | $ | 250,318 | $ | 244,544 | |||||||||
| (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 | % | Three Months Ended | % | Nine Months Ended | % | |||||||||||||||||||||||||
| September 30, 2014 | June 30, 2014 | Change | September 30, 2014 | September 30, 2013 | Change | September 30, 2014 | September 30, 2013 | Change | ||||||||||||||||||||||
| Production: | ||||||||||||||||||||||||||||||
| Oil (Mbbls) | 537 | 579 | (7 | )% | 537 | 383 | 40 | % | 1,709 | 535 | 219 | % | ||||||||||||||||||
| Natural gas (Mmcf) | 29,359 | 31,006 | (5 | )% | 29,359 | 39,268 | (25 | )% | 93,087 | 116,556 | (20 | )% | ||||||||||||||||||
| Natural gas liquids (Mbbls) | 62 | 65 | (5 | )% | 62 | 53 | 17 | % | 186 | 178 | 4 | % | ||||||||||||||||||
| Total production (Mmcfe) (1) | 32,953 | 34,870 | (5 | )% | 32,953 | 41,884 | (21 | )% | 104,457 | 120,834 | (14 | )% | ||||||||||||||||||
| Average daily production (Mmcfe) | 358 | 383 | (7 | )% | 358 | 455 | (21 | )% | 383 | 443 | (14 | )% | ||||||||||||||||||
| Average sales price (before cash settlements of derivative financial instruments): | ||||||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 94.50 | $ | 96.81 | (2 | )% | $ | 94.50 | $ | 102.60 | (8 | )% | $ | 93.11 | $ | 97.49 | (4 | )% | ||||||||||||
| Natural gas (per Mcf) | 3.36 | 4.04 | (17 | )% | 3.36 | 3.17 | 6 | % | 3.95 | 3.39 | 17 | % | ||||||||||||||||||
| Natural gas liquids (per Bbl) | 27.44 | 27.42 | — | % | 27.44 | 32.04 | (14 | )% | 30.12 | 35.12 | (14 | )% | ||||||||||||||||||
| Natural gas equivalent (per Mcfe) | 4.58 | 5.25 | (13 | )% | 4.58 | 3.95 | 16 | % | 5.10 | 3.76 | 36 | % | ||||||||||||||||||
| Costs and expenses (per Mcfe): | ||||||||||||||||||||||||||||||
| Oil and natural gas operating costs | $ | 0.43 | $ | 0.45 | (4 | )% | $ | 0.43 | $ | 0.41 | 5 | % | $ | 0.47 | $ | 0.35 | 34 | % | ||||||||||||
| Production and ad valorem taxes | 0.24 | 0.21 | 14 | % | 0.24 | 0.15 | 60 | % | 0.22 | 0.13 | 69 | % | ||||||||||||||||||
| Gathering and transportation | 0.78 | 0.75 | 4 | % | 0.78 | 0.64 | 22 | % | 0.73 | 0.62 | 18 | % | ||||||||||||||||||
| Depletion | 1.93 | 1.89 | 2 | % | 1.93 | 1.74 | 11 | % | 1.89 | 1.30 | 45 | % | ||||||||||||||||||
| Depreciation and amortization | 0.04 | 0.04 | — | % | 0.04 | 0.04 | — | % | 0.04 | 0.05 | (20 | )% | ||||||||||||||||||
| (1) | Mmcfe is calculated by converting one barrel of oil or natural gas liquids into six Mcf of natural gas. |
Contact
EXCO Resources Inc.
Chris Peracchi, 214-368-2084
Vice President of Finance and Investor Relations, and Treasurer
www.excoresources.com
