DALLAS--(BUSINESS WIRE)--EXCO Resources, Inc. (NYSE:XCO) is providing certain operational information regarding its fourth quarter and full year ended December 31, 2010.
- Oil and natural gas production was 32.2 Bcfe for the fourth quarter 2010, or 350 Mmcfe per day, which represents a 70% increase from pro forma fourth quarter 2009 production of 19.0 Bcfe, or 206 Mmcfe per day. We currently estimate our net production to average between 520-580 Mmcfe per day for the full year 2011, and expect to exit 2011 with net production in excess of 600 Mmcfe per day. The following table presents the 2010 actual fourth quarter and full year pro forma production compared with the pro forma 2009 fourth quarter and full year production.
| Three months ended December 31, | ||||||||||||||
| 2010 | 2009 | Period to period change | ||||||||||||
| (in Mmcfe) |
Actual production |
Per day |
Pro forma production (1) |
Per day |
Pro forma production |
Per day |
||||||||
| Producing region: | ||||||||||||||
| East Texas/North Louisiana | 28,528 | 310 | 15,607 | 170 | 12,921 | 140 | ||||||||
| Appalachia | 1,809 | 20 | 1,678 | 18 | 131 |
2 |
||||||||
| Permian and other | 1,855 | 20 | 1,668 | 18 | 187 | 2 | ||||||||
| Total | 32,192 | 350 | 18,953 | 206 | 13,239 | 144 | ||||||||
| Twelve months ended December 31, | ||||||||||||||
| 2010 | 2009 | Period to period change | ||||||||||||
| (in Mmcfe) |
Pro forma production (2) |
Per day |
Pro forma production (1) |
Per day | Pro forma production | Per day | ||||||||
| Producing region: | ||||||||||||||
| East Texas/North Louisiana | 95,423 | 261 | 63,272 | 173 | 32,151 | 88 | ||||||||
| Appalachia | 6,720 | 18 | 6,928 | 19 | (208 | ) | (1 | ) | ||||||
| Permian and other | 7,156 | 20 | 7,853 | 22 | (697 | ) | (2 | ) | ||||||
| Total | 109,299 | 299 | 78,053 | 214 | 31,246 | 85 | ||||||||
(1) The pro forma adjustments reduce production volumes attributable to properties sold in 2009 and properties affected by both the East Texas/North Louisiana JV and the Appalachia JV as if these sales had occurred on January 1, 2009.
(2) The pro forma adjustments reduce production volumes attributable to the properties affected by the Appalachia JV as if the sale had occurred on January 1, 2010.
- The increased production highlights the success of our Haynesville shale drilling program where we produced 19.0 Bcf (206 Mmcf per day), representing 59% of our total production during the fourth quarter 2010 compared with 4.3 Bcf (47 Mmcf per day), or 23% of our total production, in the pro forma fourth quarter 2009. During the fourth quarter 2010, our production was impacted by 1.9 Bcf (21 Mmcf per day) of net shut-in production primarily due to shut-in producing wells as we drilled and completed offset wells. We anticipate that as we implement our manufacturing mode of development, certain planned shut-ins will continue. Our gross operated Haynesville production increased from an average of 7 Mmcf per day in the fourth quarter of 2008 to 723 Mmcf per day as of December 31, 2010. We achieved this significant production growth primarily by drilling and completing 115 operated wells from the fourth quarter 2008 to December 31, 2010. Including non-operated volumes, we exited 2010 with a net Haynesville production rate of 234 Mmcf per day and approximately 11 Mmcf per day net shut-in.
- In Appalachia, we closed the acquisition of acreage and producing assets from Chief Oil & Gas, LLC (Chief) for $459 million on January 11, 2011. We recently completed the best Marcellus shale well in our portfolio on this acreage and this well is currently producing approximately 10 Mmcf per day with flowing casing pressure in excess of 3,900 psi. We have 10 additional wells awaiting completion and plan to begin a two rig drilling program on this acreage early in 2011. Pursuant to our joint development agreement, BG Group has the right to participate for 50% of this acquisition.
- As previously announced, our year end 2010 estimated proved reserves increased by 56% to 1.5 Tcfe. We replaced 576% of our production with a finding and development cost of $0.54 per Mcfe through the drill bit. Adjusting for the benefit of $351 million of BG carry, our “all-in” finding and development cost would have been $1.03 per Mcfe. Our development drilling success has given us the ability to book proved reserves on 80-acre spacing in our core DeSoto Parish Haynesville shale development area.
- Our jointly-owned midstream entity with BG Group in East Texas and North Louisiana, TGGT Holdings, LLC (TGGT), had average throughput of 1.0 Bcf per day during the fourth quarter 2010. TGGT expects further increased throughput due to continued development of our DeSoto Parish acreage and a major expansion to gather and treat volumes from our upstream assets in the Shelby Trough in East Texas.
- We have entered into additional derivative contracts since the end of the third quarter 2010. Currently, we have 89.9 Bcfe hedged for 2011 at a weighted average price of $5.78 per Mcfe, representing 42-47% of our expected production.
Operations Activity and Outlook
We spent $91 million on development and exploitation activities, drilling and completing 51 gross (31.0 net) wells in the fourth quarter 2010, compared with 48 gross (24.4 net) wells during the third quarter 2010. We spent $347 million on full year 2010 development and exploration activities as we drilled and completed 154 gross (93.7 net) wells during 2010. Our 2010 net capital expenditures reflect the benefit of the BG Group carry in East Texas/North Louisiana of $338 million and $13 million in Appalachia. As of December 31, 2010, the remaining balance of the carry in East Texas/North Louisiana was $30 million and the remaining balance of the carry in Appalachia was $137 million. We had an overall drilling success rate of 100% for the fourth quarter 2010, while our full year 2010 drilling success rate was 99%, as we successfully drilled and completed 154 of the total 156 well program. We now have 7,730 gross (3,834 net) wells in our portfolio of which 94% are operated and we are continuing efforts to opportunistically acquire additional leasehold and production in our core shale areas. Our total capital expenditures, including leasing, net of acreage reimbursements from BG Group, were $132 million in the fourth quarter 2010. We also made equity contributions to our midstream affiliates of $44 million. Our 2011 capital budget, as approved by our Board of Directors, totals $976 million, and will fund the drilling and completion of 369 gross (158.9 net) wells, among other activities. Our capital spending for the fourth quarter and full year 2010 is presented in the following table:
| 2010 Actual Spending | ||||||
| (in thousands) | Fourth Quarter | Full Year | ||||
| Capital expenditures: | ||||||
| Lease purchases (1) | $ | 8,369 | $ | 37,518 | ||
| Development capital expenditures | 90,433 | 346,595 | ||||
| Seismic | 6,759 | 21,335 | ||||
| Water pipelines and gas gathering | 4,839 | 23,607 | ||||
| Corporate and other | 21,537 | 74,427 | ||||
| Total capital expenditures | $ | 131,937 | $ | 503,482 | ||
(1) Net of acreage reimbursements from BG Group totalling $7.2 million and $58.3 million for the fourth quarter and full year periods, respectively.
We also closed $530 million of acquisitions, all of which were in our Haynesville and Marcellus operating areas. Pursuant to our joint development agreements, BG Group has the right to participate for 50% of our leasing and acquisitions we close within our areas of mutual interest (AMI) in East Texas/North Louisiana and Appalachia. In addition to the acreage reimbursements noted above, during 2010 we received $151 million from BG Group for their participation in certain of our acquisitions. Assuming BG Group exercises their right to participate in the remaining 2010 transactions and the Chief Acquisition, we will receive an additional $268 million in 2011. We also contributed $144 million to our midstream affiliates during 2010.
Recent Acquisitions and Divestments
Chief Acquisition: On January 11, 2011, we closed the acquisition from Chief of over 56,000 net acres prospective for the Marcellus shale located primarily in Lycoming and Sullivan Counties in northeastern Pennsylvania along with 15 producing wells and 11 wells awaiting completion, for $459 million, subject to post closing purchase price adjustments. The purchase price was funded into escrow on December 15, 2010, pending required third party waivers which were obtained in January 2011. The acquired assets currently produce approximately 22 Mmcf per day of net production and include as many as 930 additional gross Marcellus drilling locations. These assets offset our existing acreage in the area and increase our holdings in what appears to be one of the most productive areas in the play.
Pending Appalachian Acquisition: During the fourth quarter 2010, we entered into an agreement with a private seller to acquire approximately 32,000 net acres prospective for the Marcellus shale located primarily in Jefferson County in central Pennsylvania for $95 million, before preliminary purchase price adjustments. We expect to close this acquisition in the first quarter 2011. The assets to be acquired contain approximately 3 Mmcf per day of net production from over 500 producing conventional wells which hold a substantial portion of the acquired acreage. We believe this acquisition includes as many as 340 additional gross Marcellus drilling locations and enhances our position in one of our core areas of the play.
Both groups of Appalachian assets are located within the AMI established by the existing Appalachian joint venture with BG Group, and BG Group has the right to purchase 50% of these acquisitions. Assuming BG Group elects to participate, the development of these assets will be governed by our Appalachian joint venture.
East Texas/North Louisiana
East Texas/North Louisiana is our largest division in terms of production and reserves. Our primary targets across this region include the Haynesville and Bossier shales. We also have production from the Cotton Valley, Travis Peak, Pettet and Hosston formations. Currently, our emphasis is on exploitation of our acreage in the Haynesville shale play where we hold approximately 76,000 net acres. We continue to seek additional acreage that is complementary to our existing acreage, operations and pipeline infrastructure.
Our budgeted capital expenditures in 2011 are $782 million, of which $683 million will fund the drilling and completion of 233 gross (65.2 net) horizontal shale wells (163 operated and 70 non operated). We are planning to run 22 operated rigs in this area throughout the year. In East Texas/North Louisiana, we drilled and completed 27 gross operated wells (11.6 net) in the fourth quarter 2010. We drilled and completed 92 gross operated wells (38.4 net) during the year in the region and realized a 100 % success rate.
Haynesville Shale
Our development program in the Haynesville shale play is concentrated in DeSoto Parish, Louisiana and the recently acquired Shelby Trough area in East Texas. We are developing our core DeSoto Parish position on 80-acre spacing in a manufacturing mode utilizing multi-pad development. In the Shelby Trough our efforts are focused on delineating our position, establishing units and holding our acreage. Although we will be developing some units in 2011, we expect to transition the development of the Shelby Trough acreage to full manufacturing mode in 2012.
In DeSoto Parish our development program has made a transformation from a testing and delineation program to a full field development program. In mid 2010 we initiated a manufacturing process with full unit development on 80-acre spacing. In June 2010 we completed our first four well, 80-acre spacing test across 320 acres, and we completed our first eight well, 80-acre spacing test across a full 640 acre unit in October 2010. Our manufacturing process typically involves four drilling rigs per 640 acre unit to simultaneously drill all wells in the unit, followed by two to three fracture stimulation fleets to simultaneously complete all wells in the unit. We believe this approach to full field development maximizes value and the recovery of the resource. At year end 2010, we had 12 units in progress for full 80-acre development and plan to target an additional 15 units in 2011. The multi-well pad design also minimizes surface impact and provides for a more capital efficient gathering and production system layout than can be achieved with single well locations. In late 2010 we commissioned a 12 mile, 24 inch diameter water distribution line which utilizes waste water from a local paper mill to support our frac fleets. We recently used this line to simultaneously feed three frac fleets located in the same section as we completed seven wells.
In 2010, we acquired a strong acreage position in Shelby, San Augustine and Nacogdoches Counties, Texas and we now hold 24,000 net acres in this second core area of the Haynesville shale play. By year end 2010 we had six drilling rigs running in the area and a total of 19 horizontal wells flowing to sales with a total gross production rate of approximately 100 Mmcf per day (34 Mmcf per day net). At the time of the initial acquisition, gross production in this area was 34 Mmcf per day (7 Mmcf per day net). Some of our recent wells have yielded results comparable to our DeSoto Parish area. In the fourth quarter 2010, we turned seven new wells to sales in this area. Notable highlights for the quarter included completing and turning to sales two wells with initial rates of 23 and 28 Mmcf per day with flowing pressures of 8,979 and 9,520 psi, respectively. Our 2011 development plan for this area will have a strong focus on evaluation and delineation. By year end 2011 we expect to have all of our core San Augustine and Nacogdoches acreage held by production.
Our operational focus has resulted in significant improvements in drilling and completion efficiencies. In late 2010, in our DeSoto Parish area, we achieved our best drilling time performance to date of 28 days from spud to rig release. This was accomplished by our most consistent and experienced flex rig in our fleet, the same rig that drilled our first horizontal well in 2008. We have recently set several drilling records in the play including single bit runs from surface to intermediate hole depth and single bit runs from intermediate to production hole total depth, typically 16,500 ft. This has been achieved by working closely with our in-house service providers to design the appropriate bit and motor combination for the specific area.
We continue to use the latest technologies to enhance our shale development. We recently completed 168 square miles of 3-D seismic in DeSoto Parish and acquired another 126 square miles in the Shelby Trough area. In 2010, we monitored five wells with micro-seismic and another 19 wells with our buried array monitoring system. In our completion evaluation process, we gathered production logs on 10 horizontal wells and conducted tracer evaluations on 17 horizontal wells. In 2010, we also drilled a dedicated vertical pressure monitoring well and installed permanent down hole gauges to measure and monitor the reservoir pressure in the Haynesville shale.
In addition to our success in reducing well costs with drilling time improvements and efficiencies, we are also focused on optimizing our completions. Almost 50% of our well cost is incurred during the completion phase. We plan to implement cost effective and efficient design changes as part of our manufacturing program. We are utilizing four dedicated fracture stimulation fleets and continue to see greater consistency and efficiencies in our fracturing operations. These commitments have provided the necessary level of frac equipment available to us, and we have maintained a proper alignment with our drilling to keep a low inventory of wells waiting on completion. At December 31, 2010, we had 17 wells in our completion inventory which is low considering our drilling activity level and pad development process. We target a minimum working inventory of completions and design our program to flow gas directly to the sales line once the well is completed. We have no wells currently waiting on pipeline. This is possible due to close coordination with our jointly-held company, TGGT, which installs the gathering lines in concert with our drilling operations in most of our development areas.
We are currently running 22 rigs and plan to maintain this activity level in the play throughout 2011. Our service contracts for drilling and completions are secure but flexible. We have the ability with our current contracts to drop our rig count to 11 rigs by August 2011 if product pricing does not meet our economic hurdles.
Bossier Shale
The Bossier shale that overlies the Haynesville shale is a significant resource that is present across most of our acreage. We drilled and tested two horizontal Bossier wells in our core DeSoto Parish area during 2010 with initial flow rates of 11 and 13 Mmcf per day. We will continue to monitor well performance of these two wells before we begin additional testing in this area. In the Shelby Trough area we drilled our first EXCO operated Bossier test in the fourth quarter 2010 and will complete the well in late January 2011. We also acquired a Bossier completion from Common Resources. Additional Bossier testing for the Shelby area will be evaluated following this test.
Cotton Valley, Hosston, Travis Peak, Pettet
We produced 104 Mmcfe per day net during the fourth quarter 2010 from our Cotton Valley and other non-shale formations. The Vernon Field in Jackson Parish, Louisiana is our largest Cotton Valley Field in the company, representing 20% of our company wide net production. Due to low commodity prices, we are not actively drilling in these formations. We are planning to conduct 25 recompletions in the DeSoto Parish area in 2011, primarily targeting the upper Cotton Valley and Hosston intervals. We maintain a strong emphasis on base production performance and focus on operating expense reductions. We typically run six service rigs replacing tubing, changing pumps, cleaning out fill and implementing general repairs to maintain optimum production levels.
Appalachia
In June 2010, we closed our Appalachian joint venture with BG group. Subsequently, the joint venture has positioned itself with key staff and resources to execute an appropriate appraisal and development program over the coming years. In the fourth quarter 2010, we completed eight gross (3.9 net) horizontal Marcellus shale wells, realizing a 100% success rate. During the full year 2010, we spud 15 wells and completed 10 gross (4.9 net), realizing a 100% success rate. The 2010 program was a combination of appraisal and development wells in our east central and west central Pennsylvania areas. The development wells in west central Pennsylvania had IP’s ranging from 3.7 to 6.3 Mmcf per day from lateral lengths varying from 2,500 to 5,700 feet. The east central Pennsylvania area has lower IP’s ranging from 1.5 to 4.0 Mmcf per day from lateral lengths varying from 2,500 to 4,900 feet. A significant amount of data was collected and is currently being used to formulate a development plan based on the performance drivers in each area.
We continue to move forward building our core positions in west central and northeast Pennsylvania. Concurrently, development capital will be focused in these areas, particularly where we have realized strong results, have significant acreage, and have market access that is either existing or currently under construction. We are adding to both positions with the acquisition of approximately 56,000 net acres in northeast Pennsylvania from Chief and the pending acquisition of approximately 32,000 net acres in west central Pennsylvania. These acquisitions are significant additions to our existing portfolio and provide years of multi-rig development inventory. The most recent completion on our northeast Pennsylvania acquired acreage is the best well in our Marcellus shale portfolio, and it is currently producing to sales at a rate of approximately 10 Mmcf per day at 3,900 psi.
We continue to see improvement in all cost performance metrics. Total well costs are down 20% for 2010 with meaningful reductions in both drilling and completion costs. Improvements in drilling times, water management infrastructure, efficiencies due to multi-well pad drilling and single sourcing are among the key drivers to our cost reductions in 2010. These metrics will continue to improve as infrastructure is added, development activity increased, and key findings from our 2010 program are implemented.
We currently have two horizontal drilling rigs operating in the basin with plans to exit 2011 with five operated rigs. The 2011 drilling plan includes both an appraisal program across parts of our acreage position and a three rig program in our development areas. We plan to drill 12 gross (6.0 net) appraisal wells and 52 gross (17.9 net) development wells during 2011, while spending net drilling and completion capital totaling $38 million. All of our planned 2011 drilling activity is located in areas which have sufficient gas markets and immediate take away capacity or a defined strategy to be sales ready by year end.
Permian
We drilled and completed 16 gross (15.5 net) wells in our Permian area Canyon Sand field during the fourth quarter 2010 with 100% drilling success. We drilled 54 gross (52.4 net) wells and completed 52 gross (50.4 net) wells in the region during 2010, with a 96% success rate. We continue to run two operated rigs in the Canyon Sand field and plan to spend $48 million net to drill and complete 72 gross (69.8 net) wells in 2011. Oil production at Sugg Ranch has increased by 42% in the fourth quarter 2010 as compared to the fourth quarter 2009, and this drilling activity typically produces rates-of-return in excess of 60%.
Proved Reserves
Our estimated proved reserves have grown 56%, from 959 Bcfe at December 31, 2009 to approximately 1.5 Tcfe at December 31, 2010, calculated pursuant to SEC pricing rules, which are based on the simple average of the first of the month reference natural gas and oil prices for the prior twelve month period, adjusted for energy content, quality and basis differentials. For 2010, the reference price was $4.38 per Mmbtu for natural gas and $79.43 per Bbl for oil which resulted in an adjusted price of $4.37 per Mmbtu for natural gas and $75.83 per Bbl for oil. Using the five year futures strip price at December 31, 2010 averaging $5.23 per Mmbtu for natural gas and $93.09 per Bbl of oil, as adjusted for energy content, quality and basis differentials, our estimated proved reserves would have been 1.6 Tcfe. Pro forma for the Chief and the pending Appalachian acquisitions, we estimate our total net resource potential to be approximately 13.0 Tcfe as of December 31, 2010, assuming BG Group elects to participate in these acquisitions.
During 2010, we added 646 Bcfe of proved reserves through the drill bit and produced 112 Bcfe, resulting in a production replacement ratio of 576%. Also in 2010, we sold 143 Bcfe and purchased 30 Bcfe. We had 53 Bcfe of positive revisions due to price and 66 Bcfe of positive performance related revisions. Our proved reserves grew by 73% from the prior year, adjusted for sold reserves and price related revisions. The following table presents the details of our changes in proved reserves:
| Equivalent | |||||||||
| Oil | Natural gas | natural gas | |||||||
| (Mbbls) | (Mmcfe) | (Mmcfe) | |||||||
| Proved developed | 4,633 | 793,777 | 821,575 | ||||||
| Proved undeveloped | 2,725 | 661,176 | 677,526 | ||||||
| Total | 7,358 | 1,454,953 | 1,499,101 | ||||||
| The changes in reserves for the year are as follows: | |||||||||
| December 31, 2009 | 5,518 | 925,728 | 958,836 | ||||||
| Purchase of reserves in place |
- |
30,047 |
30,047 |
||||||
| Extensions and discoveries | 1,631 | 635,841 | 645,627 | ||||||
| Revisions of previous estimates: | |||||||||
| Changes in price | 751 | 48,630 | 53,136 | ||||||
| Changes in performance | 549 | 63,089 | 66,383 | ||||||
| Sales of reserves in place |
(403 |
) |
(140,504 |
) |
(142,922 |
) | |||
| Production | (688 | ) |
(107,878 |
) |
(112,006 |
) | |||
| December 31, 2010 | 7,358 | 1,454,953 | 1,499,101 | ||||||
Our drilling and development spending in 2010 was $347 million resulting in a finding and development cost of $0.54 per Mcfe. Including revisions other than price, our finding and development cost was $0.49 per Mcfe. Including $38 million of leasehold additions, our “all-in” finding and development cost was $0.54 per Mcfe. Adjusting for the benefit of $351 million of BG carry, our “all-in” finding and development cost would have been $1.03 per Mcfe. The following table details the components of our 2010 finding and development cost:
| (dollars in thousands, except per Mcfe) | Cost | Mmcfe | Per Mcfe | |||||
| Haynesville | $ | 166,980 |
565,099 |
$ | 0.30 | |||
| Conventional | 65,998 |
38,218 |
1.73 |
|||||
| Exploratory | 113,617 | 42,310 | 2.69 | |||||
| Total development and exploration | 346,595 | 645,627 | 0.54 | |||||
| Revisions - other than price | - | 66,383 | - | |||||
| Subtotal | 346,595 | 712,010 | 0.49 | |||||
| Leasehold additions | 37,518 | - | - | |||||
| Total | $ | 384,113 | 712,010 | 0.54 | ||||
During 2010, we added 238 Bcfe to our proved developed reserves resulting in a finding and development cost of $1.24 per Mcfe. Adjusting for the benefit of $311 million of BG carry associated with our proved developed reserve additions, our finding and development cost would have been $2.54 per Mcfe. The following table details the components of our 2010 proved developed additions:
| (dollars in thousands, except per Mcfe) | Cost | Mmcfe | Per Mcfe | |||||
| Haynesville (1) | $ | 124,431 | 190,451 | $ | 0.65 | |||
| Conventional | 65,998 | 19,246 | 3.43 | |||||
| Exploratory (2) | 103,699 | 28,077 | 3.69 | |||||
| Total development and exploration | $ | 294,128 | 237,774 | 1.24 | ||||
|
|
||||||||
(1) Excludes $42.5 million of costs primarily associated with future proved developed reserve additions. Adjusting for the benefit of $253 million of BG carry associated with our Haynesville shale proved developed reserve additions, our finding and development cost would have been $1.98 per Mcfe.
(2) Excludes $9.9 million of costs associated with future proved developed reserve additions.
In our core DeSoto Parish Haynesville shale development area, we increased our average gross estimated ultimate recoverable reserves (EUR) for proved developed wells added prior to 2010 to 7.2 Bcf from 6.2 Bcf as we gained more production history from these wells during 2010. Overall in the Haynesville shale, our average gross EUR for proved developed additions during 2010 was 6.6 Bcf per well. Our estimated proved reserves also increased as a result of our successful 80-acre spacing development drilling in our core DeSoto Parish area. Our gross proved EUR per 640-acre unit has increased by 85% from 26.4 Bcf at year end 2009 to 48.8 Bcf at year end 2010. We added an average of 2.7 offsetting proved undeveloped locations with average gross EUR’s of 6.1 Bcf for each producing well drilled. As with our initial wells booked on 160-acre spacing, we will gain more confidence in the EUR’s of these wells as we continue to drill and gather production data.
Midstream
Through our jointly-held midstream company, TGGT, we are constructing a major midstream expansion in our Shelby Trough area in East Texas. We are currently installing the infrastructure and pipeline systems necessary to treat and gather the significant production volumes expected from this area and expect to have 550 Mmcf per day of treating and takeaway capacity by early third quarter 2011. Our current treating capacity in our North Louisiana area is 1.1 Bcf per day which we anticipate increasing to 1.4 Bcf per day. TGGT had revenue throughput of approximately 1.0 Bcf per day during the fourth quarter 2010. We continue to see throughput growth in all of our operating areas from both third party and company-operated production. During the fourth quarter 2010, TGGT received commitments for a $500 million revolving credit agreement and is expected to close in the first quarter 2011. TGGT anticipates borrowing $250 million at closing to fund a distribution to its owners, of which $125 million would be distributed to us. The remaining availability will be used to fund TGGT’s future capital expenditures.
Derivatives
We continue to enter into additional derivative contracts as market conditions warrant. The following table details our current derivative positions and includes all contracts entered into since the end of the third quarter 2010:
| Natural Gas | Oil | |||||||||
| Weighted average |
|
|||||||||
| strike price per |
Weighted average |
|||||||||
| (in thousands, except prices) | Mmbtus | Mmbtu | Bbls |
strike price per Bbl |
||||||
| Swaps: | ||||||||||
| Q1 2011 | 19,260 | $ | 5.36 | 135 | $ | 111.32 | ||||
| Q2 2011 | 22,295 | 5.28 | 136 | 111.32 | ||||||
| Q3 2011 | 22,540 | 5.28 | 138 | 111.32 | ||||||
| Q4 2011 | 22,540 | 5.28 | 138 | 111.32 | ||||||
| Total 2011 | 86,635 | 5.30 | 547 | 111.32 | ||||||
| 2012 | 53,070 | 5.37 | 275 | 95.70 | ||||||
| 2013 | 5,475 | 5.99 | - | - | ||||||
| Total | 145,180 |
$ |
5.35 | 822 |
$ |
106.10 | ||||
The information in this release is unaudited and subject to revision. Audited and final results will be provided in our Annual Report on Form 10-K for the year ended December 31, 2010 currently planned to be filed with the Securities and Exchange Commission by the end of February 2011.
EXCO Resources, Inc. is an oil and natural gas exploration, development and production company headquartered in Dallas, Texas with principal operations in East Texas, North Louisiana, Appalachia and West Texas.
Additional information about EXCO Resources, Inc. may be obtained by contacting EXCO’s Chairman, Douglas H. Miller, or its President, Stephen F. Smith, at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting our website at www.excoresources.com. Our SEC filings and press releases can be found under the Investor Relations tab.
We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this press release, and the risk factors included in the Annual Report on Form 10-K for the year ended December 31, 2009 and our other periodic filings with the SEC.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.
The SEC permits oil and natural gas companies in filings made with the SEC to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Beginning with reserves reported for the year ended December 31, 2009, the SEC permits optional disclosure of “probable” and “possible” reserves in its filings with the SEC. EXCO may use broader terms to describe additional reserve opportunities such as “potential,” “unproved,” or “unbooked potential,” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially greater risk of being actually realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2009, which is available on our website at www.excoresources.com under the Investor Relations tab.