EXCO Resources, Inc. Reports Second Quarter 2014 Results

EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced second quarter operating and financial results for 2014.

• Adjusted EBITDA was $105 million for the second quarter 2014, which exceeded the high-end of guidance.
• Production was 35 Bcfe, or 383 Mmcfe per day, for the second quarter 2014, which exceeded the high-end of guidance.
• Oil and natural gas operating costs for the second quarter 2014 were below the low-end of guidance, reflecting continued fiscal discipline.
• Our capital structure was enhanced through the $500 million offering of senior unsecured notes issued in April 2014.
• Drilled 32 gross (9.9 net) and completed 25 gross (7.9 net) operated horizontal shale wells in the second quarter 2014.

Jeff Benjamin, EXCO’s chairman, commented, "We had a positive quarter and are ahead of the guidance for our key financial and operational measures. Oil is making a significant contribution to the operating results of the organization as it makes up approximately 30% of total revenue for the past six months. We are excited about the potential for growth through the acquisition program for Eagle Ford shale properties beginning next year. EXCO remains committed to the continued development of our natural gas assets and we believe this will create long-term value for shareholders.

"The recent $500 million senior unsecured notes offering further enhanced our liquidity and added an eight year term to our capital structure. We are evaluating potential acquisitions and leases of undeveloped acreage that would be complementary to our current portfolio and accretive to the Company. There are several operational initiatives to improve the performance and ultimate recoveries from our current asset base that will be implemented during 2014. The board of directors has authorized an increase to our capital budget of up to $80 million to provide flexibility for the operating team to pursue growth initiatives. Our enhanced liquidity allows us flexibility to make optimal decisions based on current market conditions."

Financial results

GAAP results were net income of $2 million, or $0.01 per diluted share, for the second quarter 2014 compared with a net loss of $5 million, or $0.02 per diluted share, for the first quarter 2014. The increase in net income was primarily due to volatility in commodity prices which resulted in higher unrealized losses on derivative contracts in the prior quarter. This was partially offset by lower revenues in the current quarter due to a decrease in production and realized natural gas prices.

Adjusted EBITDA for the second quarter 2014 was $105 million compared with $112 million for the first quarter 2014. Our adjusted EBITDA exceeded our capital expenditures for each of the periods during 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 $0.03 per diluted share for the second quarter 2014 compared with $0.05 per diluted share for the first 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 ("NGL") production was 35 Bcfe, or 383 Mmcfe per day, for the second quarter 2014 compared with 37 Bcfe, or 407 Mmcfe per day, in the first quarter 2014. Second quarter 2014 production from the East Texas/North Louisiana region was 257 Mmcfe per day compared with 280 Mmcfe per day in the first quarter 2014. The decrease in production was primarily the result of natural production declines and was partially offset by the additional production from the 12 gross (5.1 net) operated wells turned-to-sales during the second quarter 2014. Second quarter 2014 production from the South Texas region was 596 Mboe, or 6,550 Boe per day, compared with 584 Mboe, or 6,500 Boe per day, in the first quarter 2014. The increase in production was primarily due to our focus on completion activities which resulted in 13 gross (2.9 net) operated wells turned-to-sales during the second quarter 2014. The second quarter 2014 production in the Appalachia region was 62 Mmcfe per day compared with 61 Mmcfe per day in the first quarter 2014. The increase in production was due to lower downtime resulting from freezing issues in the prior quarter. Our proportionate share of production from Compass Production Partners (formerly "EXCO/HGI Partnership") was 25 Mmcfe per day in the second quarter 2014 compared to 24 Mmcfe per day in the first quarter 2014.

Oil, natural gas and NGL revenues for the second quarter 2014 were $183 million compared with $198 million for the first quarter 2014. Our average sales price per Mcfe decreased to $5.25 per Mcfe for the second quarter 2014 from $5.42 per Mcfe for the first quarter 2014. Our average sales price per Mcfe for the second quarter 2014 was positively impacted by a higher percentage of oil revenues and offset by lower market prices for natural gas compared to the first quarter 2014. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $168 million, or $4.83 per Mcfe for the second quarter 2014, compared with $179 million, or $4.88 per Mcfe for the first quarter 2014.

Our direct operating costs were $16 million, or $0.45 per Mcfe, for the second quarter 2014 compared with $19 million, or $0.51 per Mcfe, for the first quarter 2014. The lower direct operating costs were primarily due to the cost reduction initiatives in the Eagle Ford shale including decreased salt water disposal costs, shorter flowback periods and reduced reliance on third-party contractors. Additionally, we had a reduction in force of field personnel in Appalachia which decreased our operating costs in the region.

Our general and administrative costs were $20 million for the second quarter 2014 compared with $17 million for the first quarter 2014. The increase was primarily due to $2 million of severance costs associated with a reduction in force as a result of our continued focus on fiscal discipline and managing our general and administrative costs and lease termination fees of $1 million for certain unused office space.

Cash flows from operations before changes in working capital and other operating items impacting comparability, a non-GAAP measure, were $84 million for the second quarter 2014 compared with $94 million for the first quarter 2014. During the second quarter 2014, we primarily used our cash flows from operations to fund our drilling and development program.

Recent developments

2022 Notes

On April 16, 2014, we completed a public offering of $500 million in aggregate principal amount of senior notes due April 15, 2022 ("2022 Notes"). We received net proceeds of $490 million after offering fees and expenses. These notes bear interest at a rate of 8.5% per year, payable on April 15 and October 15 of each year, with payments commencing on October 15, 2014. We used the net proceeds to reduce indebtedness under the EXCO Resources Credit Agreement including the $298 million outstanding principal balance on the term loan and the remaining proceeds were used to reduce a portion of the indebtedness outstanding under the revolving commitment. As a result of this transaction, our unused availability under the EXCO Resources Credit Agreement was $686 million as of June 30, 2014. The improvement in our liquidity as a result of this offering enhances our financial flexibility and positions us for future growth.

Operations activity and outlook

We spent $78 million on development activities, drilling 32 gross (9.9 net) operated wells and completing 25 gross (7.9 net) operated wells in the second quarter 2014. Our development program during 2014 is focused on our properties in the Haynesville and Eagle Ford shales. In June 2014, our board of directors approved an increase to our capital budget of up to $80 million for the remainder of the year. This allows us the flexibility to modify our drilling program in the Haynesville and Eagle Ford shales if opportunities arise to maximize our returns or further evaluate other formations. We continue to evaluate industry trends, commodity prices, and internal operational and financial analyses to assess potential modifications to our drilling program. We remain focused on efficiently managing our capital expenditures as part of our development program. We will incorporate any additional development into our hedging strategy and may enter into additional derivative contracts to protect our return on investment. The additional development as a result of our ability to increase our capital expenditures will not result in significant production volumes until 2015 based on the timing of wells turned-to-sales. Our actual capital expenditures during the first and second quarter 2014 are presented in the following table.

(1) Excludes capital expenditures related to Compass Production Partners, LP, which funded its capital expenditures through internally generated cash flows and its credit agreement.

East Texas / North Louisiana

In the Haynesville shale during the second quarter 2014, we operated three drilling rigs focused on manufacturing in our core area in DeSoto Parish, Louisiana and two drilling rigs focused on appraisal, testing and delineation in the Shelby area of East Texas. In DeSoto Parish, we drilled 7 gross (3.9 net) operated wells during the quarter and completed 10 gross (4.1 net) wells during the quarter. The average initial production rate from these wells was 12.9 Mmcf per day with an average 7,219 psi flowing casing pressure on an average 19/64ths choke. Our development program during the second half of 2014 will focus on sections which have a high working interest and were acquired in 2013. During the second quarter 2014, we drilled 3 gross (1.5 net) operated wells as part of our first cross-unit development in DeSoto Parish that includes drilling 5,000 to 8,000 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.

In the Shelby area, we drilled 4 gross (1.9 net) operated wells during the quarter and completed 2 gross (1.0 net) wells during the quarter. We are currently in the process of completing our 2014 drilling program in this region which includes 8 gross (3.8 net) wells consisting of longer laterals, a modified completion design and a more restricted flowback procedure. The restricted flowback will limit 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 two wells completed in this area during the quarter. The restricted initial production rates for these wells averaged 9.9 Mmcf per day on a maximum 17/64ths choke with an average 8,335 psi flowing casing pressure. 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 are planning to drill a test well in the Bossier shale in DeSoto Parish during 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 and this could result in a significant number of additional drilling locations if we are able to establish attractive economics to drill in the formation.

We have initiated a compression program in the Haynesville shale to enhance our base production. We are currently studying additional interim lateral compression options and full field compression options in this region. In addition, we recently completed our first refrac stimulation test in DeSoto Parish. This test consisted of a second fracture stimulation treatment in an existing well to re-stimulate the shale reservoir near the wellbore. The refrac stimulation resulted in an increase in production for this well of 1.2 Mmcf per day on a more restricted choke. We expect to perform a similar treatment on other wells in the region and have plans for a second refrac stimulation during the third quarter 2014.

South Texas

In the Eagle Ford shale, our drilling activities ranged from three to five drilling rigs during the second quarter 2014 focused in our core area in Zavala County, Texas. We drilled 21 gross (4.1 net) operated wells and completed 13 gross (2.9 net) wells in the Eagle Ford shale during the quarter. Our 2014 drilling program consists of manufacturing and testing in the core area and appraisal drilling in the adjacent farmout areas. In July 2014, we reduced our rig count to two operated drilling rigs as a result of our ability to achieve shorter drilling times which will allow us to focus on completing our inventory of wells that are waiting-on-completion. The high demand for personnel and materials utilized in completion activities and the installation of centralized facilities for properties in the Eagle Ford shale have caused delays and resulted in an inventory of wells that have been drilled and are waiting-on-completion. We plan to focus on completing our inventory of wells prior to increasing our rig count to three operated drilling rigs towards the end of the third quarter 2014.

We have realized significant improvements to our drilling performance since we acquired the Eagle Ford assets in 2013. We continue to achieve improved drilling times per well and are currently averaging 13 days from spud to rig release and recently drilled a well in 10.9 days with a total measured depth of 14,500 feet. During the second quarter 2014, our shut-in volumes ranged from 600 to 1,400 net Bbls of oil per day due to offset drilling, completion and maintenance activities. This is a reduction from the shut-in volumes during the first quarter 2014 which ranged from 1,650 to 2,500 net Bbl of oil per day as we are working to optimize our drilling and completion schedules. We are implementing initiatives to optimize and increase the efficiency of our production including the installation of artificial lift.

We are implementing a number of technological initiatives in the area. We recently acquired 3-D seismic data over a large portion of our acreage to help assess the subsurface potential of the assets and recently completed a microseismic survey that monitored a multi-well completion. We are currently preparing to test the Buda formation on a portion of our acreage later this year.

Appalachia

In the Appalachia region, we remain focused on base production efficiency from our Marcellus shale and conventional assets. Our production has remained relatively flat during the first and second quarters of 2014 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.

Our plans include limited appraisal drilling in late 2014 targeting the Marcellus shale in Northwest 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 June 30, 2014 and December 31, 2013, consolidated statements of operations for the three months ended June 30, 2014, March 31, 2014, and June 30, 2013 and six months ended June 30, 2014 and 2013 and consolidated statements of cash flows for the six months ended June 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, July 30, 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#24918634. 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 August 14, 2014. Please call (800) 585-8367 and enter conference ID#24918634 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.

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.

(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, these 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 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.

(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.