DALLAS--(BUSINESS WIRE)--EXCO Resources, Inc. (NYSE: XCO) (“EXCO”, the “Company” or “we”) today announced that it has amended the Amended and Restated Credit Agreement (the “Credit Agreement”) to provide EXCO the financial flexibility to selectively develop its asset base while deferring a significant amount of the Company’s drilling inventory until commodity prices improve. The Credit Agreement was amended to:
- remove the total consolidated leverage ratio through September 2016 and then be reinstated in the fourth quarter of 2016 at 6.00x stepping down to 4.50x for the first quarter of 2018;
- add a senior secured leverage ratio of 2.50x and an interest coverage ratio of 2.00x; and
- set the borrowing base at $725 million.
EXCO has worked aggressively to reduce debt since closing on approximately $1 billion of acquisitions in July 2013 through non-core asset sales and a rights offering of our common stock. Our total debt was reduced from approximately $2.1 billion at July 31, 2013 to $1.5 billion at December 31, 2014. As of December 31, 2014, we had pro forma liquidity of $586 million, based on our borrowing base of $725 million, which will allow us to execute on our capital program and opportunistically pursue strategic acquisitions. We are highly confident in the quality of the Credit Agreement’s underlying collateral asset base and thank our bank group for their continued support of EXCO.
As of December 31, 2014, our proved reserves were approximately 1.3 Tcfe, prepared in accordance with SEC standards, of which 91% were natural gas and 47% were proved developed reserves. Approximately 96% of our proved reserves were related to our shale properties, with approximately 69% located in the Haynesville and Bossier shales in East Texas and North Louisiana, 18% in the Marcellus shale in Appalachia and 9% in the Eagle Ford shale in South Texas. Our non-shale proved reserves represented approximately 4% of total proved reserves as of December 31, 2014, which consisted primarily of conventional assets in the Appalachia region. As of December 31, 2014, the PV-10 and standardized measure of our proved reserves was approximately $1.5 billion. There is no difference in the standardized measure and PV-10 as the impact of net operating loss carry-forwards eliminated future income taxes. The prices used for the SEC year end 2014 reserves were $4.35 per Mmbtu for natural gas, $94.99 per Bbl for oil and $33.03 per Bbl for natural gas liquids.
Proved reserves increased by 140 Bcfe from January 1, 2014, as production of 136 Bcfe and the sale of our remaining interest in Compass of 127 Bcfe were predominantly offset by 168 Bcfe of price revisions, 131 Bcfe of upward performance and other revisions and 96 Bcfe of discoveries and extensions.
Our reserves were positively impacted by the results of our successful 2014 drilling and completion program in the Shelby area of East Texas. The continued performance of the first two initial test wells in Shelby under our new completion and flowback methodology resulted in increasing their proved reserve estimates from 1.0 Bcf per 1,000 feet of lateral to 1.75 Bcf per 1,000 feet, or in excess of 11 Bcf per well. Additionally, our year-end proved undeveloped reserve estimates have increased from 1.0 Bcf per 1,000 feet of lateral to 1.3 Bcfe per 1,000 feet of lateral, which is our minimum target for Shelby wells drilled in 2015. The 131 Bcfe of upward performance and other revisions included 67 Bcfe of upward revisions in the Shelby area of East Texas based on improved well performance as a result of our enhanced completion methods, including more proppant per foot of lateral length, longer laterals and a more restricted flowback. The upward revisions also included 46 Bcfe from our Appalachia region based on a shallower decline than previously forecasted. The 96 Bcfe of discoveries and extensions were primarily due to 52 Bcfe from our drilling in the Shelby area in East Texas and 26 Bcfe from our Eagle Ford shale development.
Our Board of Directors has approved a 2015 capital budget of up to $275 million. The capital budget includes approximately $215 million allocated to development and completion activities. Our budget was designed to allocate capital to projects that:
- produce attractive returns in the current commodity price environment;
- add proved reserves to our portfolio; and
- maintain high value acreage positions.
Our capital budget will allow us to preserve our liquidity and capital resources in preparation for future growth as we expect 2105 Adjusted EBITDA to be approximately equivalent to our capital budget. We have reduced our drilling activity in South Texas and plan to focus our development on natural gas production in the Haynesville and Bossier shales located in East Texas and North Louisiana where we expect to spend 69% of our drilling and completion capital with our drilling efforts focused in the Shelby area. We believe our Shelby area in East Texas will provide significant growth opportunities for EXCO as we convert undrilled locations to proved developed producing wells and add proved undeveloped locations to our drilling inventory. We will continue to monitor the commodity price environment throughout 2015 and will adjust our capital program as necessary to maximize our returns and manage our cash flow.
The 2015 capital budget is currently allocated among the different budget categories as follows:
|(Dollars in millions)||2015 Capital Budget|
|Drilling and completion||$215|
|Field operations, gathering and water projects||16|
|Land and capitalized costs||44|
We expect to fund our 2015 capital budget with cash flow from operations and borrowings under our Credit Agreement. Our financial position and diverse portfolio of high quality oil and natural gas assets allow us flexibility in the current commodity price environment. The 2015 capital budget excludes our offer program with a joint venture partner in the Eagle Ford shale, which is expected to be funded with borrowings under our Credit Agreement.
Capital Budget Detail
Our 2015 operated rig count is expected to average four rigs, of which three will drill in the Haynesville and Bossier shales in East Texas and North Louisiana and one will drill in the Eagle Ford shale and the Buda formation in South Texas. We will also utilize a rig in Appalachia intermittently to drill two appraisal wells.
Details of our plans within the various areas follow:
|Gross Wells||Net Wells||Net Wells||Drilling &||Other|
(Dollars in millions)
|East TX/North LA||25||11.9||17.6||$150||$8||$158|
(1) EXCO operated
(2) Includes $21 million of capitalized interest and $16 million of capitalized general and administrative expenses
East Texas and North Louisiana:
As a result of our successful drilling and completion program in the Shelby area of East Texas during 2014, we will be focusing our efforts in this area in 2015 to capture additional value. Our development in North Louisiana will focus on completing and turning to sales wells drilled in 2014, base production initiatives and a limited drilling program. We plan to spend a total of $158 million developing wells in the Haynesville and Bossier shales, of which $150 million will be spent on drilling and completion, including $18 million to fund our working interest in wells operated by others. We plan to spud 25 gross (11.9 net) horizontal wells and turn to sales 32 gross (17.6 net) horizontal wells in these areas.
We plan to spud 22 gross (9.4 net) horizontal wells and turn to sales 14 gross (5.9 net) horizontal wells in the Shelby area of East Texas. We have approximately 250 operated undeveloped locations in this area which provide a platform for future growth. We will continue to utilize the enhanced completion methods, longer laterals and restricted flowback program that proved to be successful on the wells drilled in 2014. Under our more restrictive flowback methodology, both our recently completed East Texas and North Louisiana wells are exhibiting lower decline rates which we believe will result in reduced capital to maintain production and area operating cash flow in future years. Based on our year end estimates of proved reserves, we estimate the ultimate recoveries ("EUR") to be 1.3 Bcfe per 1,000 feet of lateral from the wells drilled in the Shelby area during 2015. The wells that are planned to be drilled during 2015 are expected to include laterals ranging from 6,300 to 7,500 feet and average $10.8 million for drilling and completion. Our drilling activity in the Shelby area will add proved undeveloped locations and reserves to our asset base as we continue to develop this area. We believe there is the potential for additional upside in the EURs once we have more historical data to incorporate into the type curves from the wells drilled in this area.
Our development capital in our Holly area in DeSoto Parish, Louisiana will focus on completing and turning to sales 15 wells drilled in 2014, base production initiatives and a limited drilling program. We plan to drill three gross (2.5 net) Haynesville wells in the first half of 2015 and turn-to sales 18 gross (11.7 net) wells in the first half of 2015. In addition, we will continue our refrac program on a limited basis as we analyze the data from the six refracs performed to date and develop a long term plan during 2015.
We have reduced our drilling activity in South Texas in response to lower crude oil prices and plan to average one rig in 2015. Our 2015 capital program is designed to preserve leasehold commitments, fulfill continuous drilling obligations and drill a key test well in the Buda formation. We plan to spend a total of $66 million in this region during 2015, of which $59 million will be spent to spud 23 gross (7.1 net) horizontal wells, at an average of $6.6 million for drilling and completion with 7,400 foot average lateral lengths, and turn to sales 44 gross (10.7 net) horizontal wells. We plan to turn-to-sales 37 gross (7.0 net) Eagle Ford shale horizontal wells in our core area acreage, and six gross (3.2 net) horizontal wells outside of our core area. The most recent wells turned-to-sales feature enhanced completion methods and have provided our best results to date in the region. Our 2015 capital budget includes one gross (0.5 net) operated Buda well which we spud in January (gross cost of $2.9 million) and our participation in three non-operated Buda wells. The Buda formation has the potential to add drilling locations to our inventory characterized by low capital intensity with high rates of return. Our capital program also includes $7 million to fund pumping units to optimize our production and infrastructure development to reduce future operating costs.
The 2015 capital budget program for our Marcellus shale program totals $14 million, of which $6 million will be spent to drill and complete two gross (0.7 net) appraisal wells. 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. This allows us the optionality for future development activities with minimal cost to hold our position. The appraisal wells to be drilled during 2015 are strategically located nearby areas in which we have observed strong well performance from recent results.
Oil, natural gas and natural gas liquids production was 31 Bcfe, or 340 Mmcfe per day, for the fourth quarter 2014. Production was at the low end of our guidance range as we further rate restricted the North Louisiana wells we turned to sales in November and December to maximize the wells EURs based on the successful rate restriction production and pressure results we have experienced in East Texas.
In North Louisiana, we completed six refracs in mature Haynesville shale wells and are encouraged by the results. We performed our first refrac in July and the production rate increased from 550 Mcf per day to 1,900 Mcf per day and it is currently producing 1,500 Mcf per day. While our other refracs do not have as much history, we have seen similar production increases. We will continue to monitor the performance of these refracs and gather data as we further refine the techniques and evaluate the application of refracs across our Haynesville shale wells.
We also recently completed the Bossier shale test well that was drilled in DeSoto Parish, Louisiana and it is performing in-line with our expectations. This was the first well we have drilled in the Bossier shale in North Louisiana using the enhanced completion methods we have utilized in both our East Texas Haynesville and Bossier and North Louisiana Haynesville activities. Based on the enhanced completion methods, existing in-place infrastructure and our ability to reduce drilling and completion costs, we believe that we can develop over 300 Bossier shale drilling locations (based on standard lateral lengths and units) in North Louisiana in the future.
In South Texas, we realized improved production rates utilizing enhanced completion methods on wells recently turned to sales with 13 wells averaging 24 hour initial production rates of 839 Bbl per day. The three central facilities in the area are operational and we have recently drilled Eagle Ford wells in 9.5 days with some of the longest laterals in the area. We participated in our first non-operated Buda well which had initial production of 690 Bbl per day. We have drilled our first operated Buda well with a 9,800 foot lateral in January and expect it to start producing in February.
We continue to work with our vendors to achieve cost reductions given the current commodity price environment. We have realized fracture stimulation, cementing, production chemical, rentals and fuel cost savings and are reviewing additional operating and general and administrative cost reduction initiatives. Three of our four remaining rig contracts expire in 2015 (April, August and December, respectively), which could provide opportunities for lowering our costs.
South Texas Offer Process
We made our first offer for wells drilled under the participation agreement with a joint venture partner (“Participation Agreement”) in January. This included seven wells for a total offer price of $14.8 million. One of the wells met the required return hurdle and the specific well criteria for a committed well as defined in the Participation Agreement (“Committed Well”). The remaining six wells did not meet the Committed Well criteria due to the timing of artificial lift installation, off-set fracturing activity and other factors set forth in the Participation Agreement. These wells are defined as uncertainty wells in the Participation Agreement (“Uncertainty Wells”). Our joint venture partner is only required to accept the offer for the Committed Well of $2.4 million. Our joint venture partner may accept the offers for the Uncertainty Wells. However, they have the right to elect to decline our offer for Uncertainty Wells for up to two quarters. We expect the offer and acceptance process to be completed and the acquisition to close during the first quarter.
There are 34 additional wells that are expected to be included in the offer process during the remainder of 2015; however, the extent and timing of these acquisitions in future periods will be dependent on the terms and conditions of the offer process. We currently do not anticipate that all 34 wells will meet the Committed Well criteria when the initial offer is made. Any offer well that remains an Uncertainty Well for two consecutive quarters converts to a Committed Well and is included in the offer for Committed Wells for the quarter immediately following such period. As such, the number of wells acquired in 2015 could be lower than the 41 wells offered on.
EXCO has derivative contracts in place protecting approximately 65% of our expected 2015 natural gas production. The Company’s 2015 natural gas derivative contracts consist of 117,500 Mmbtus per day of fixed price swaps at an average NYMEX Henry Hub price of $4.20 per Mmbtu, and 75,000 Mmbtus per day of three-way collar contracts. The three-way collar contracts have an average NYMEX Henry Hub call price of $4.47 per Mmbtu, a put price of $3.83 per Mmbtu and a short put price of $3.33 per Mmbtu. In addition, the Company has derivative contracts in place hedging approximately 50% of our expected 2015 oil production at an average fixed swap price of $91.09 per barrel (including the impact of basis swaps). The mark-to-market value of the Company’s derivative contracts as of December 31, 2014 was approximately $100 million.
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 you 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.