Description
EXCO Resources Inc,. Director, 10% Owner WILBUR L JR ROSS bought 1,300,000 shares on 6-20-2012 at $ 6.85
BUSINESS OVERVIEW
Our business strategy
Our primary strategy is to appraise, develop and exploit our Haynesville, Bossier and Marcellus shale resources, primarily through horizontal drilling, and to leverage our complementary midstream gathering systems and treating facilities to promptly transport our production to multiple market outlets. We continue to develop vertical drilling opportunities in our Permian Basin area as this region has high oil reserves and natural gas with a high liquid content. Our shale resource plays and midstream operations are conducted through four joint ventures with affiliates of BG Group plc, or BG Group. A brief description of each joint venture follows:
• East Texas/North Louisiana JV
A joint venture with BG Group covering an undivided 50% interest in a substantial portion of our assets in the East Texas/North Louisiana area including the Haynesville/Bossier shale and conventional shallow producing assets, or the East Texas/North Louisiana JV. The East Texas/North Louisiana JV is governed by a joint development agreement with our subsidiary, EXCO Operating Company, LP, or EXCO Operating, serving as operator. Under the terms of the agreement, BG Group funded 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $400.0 million, or the East Texas/North Louisiana Carry. During the first quarter of 2011, we utilized the balance of the East Texas/North Louisiana Carry.
• TGGT
A joint venture with BG Group in which we each own a 50% interest in TGGT Holdings, LLC, or TGGT, which holds most of our East Texas/North Louisiana midstream assets.
• Appalachia JV
A 50/50 joint venture with BG Group covering our shallow producing assets and Marcellus shale acreage in the Appalachia region, or the Appalachia JV. EXCO and BG Group operate the Appalachia JV operations through a 50% jointly owned operating entity, or OPCO, which holds a 0.5% working interest in all of the shallow conventional assets and the deep rights in the Appalachia JV. Under the terms of the agreement, BG Group agreed to fund 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $150.0 million, or the Appalachia Carry. As of December 31, 2011, the remaining balance of the Appalachia Carry was approximately $54.6 million.
Appalachia Midstream JV
A joint venture with BG Group in which we each own a 50% interest in a midstream company, or the Appalachia Midstream JV, which will develop infrastructure and provide take-away capacity in the Marcellus shale.
Our acquisition strategy for the past several years has been focused on the shale resources and consisted primarily of undeveloped acreage acquisitions. We have entered into the manufacturing phase in our core DeSoto Parish, Louisiana area of the Haynesville shale, or DeSoto Parish, and have substantially completed drilling activities to hold our acreage positions in Shelby, Nacogdoches and San Augustine Counties in East Texas, or the Shelby Area. Our Marcellus shale areas of interest have been identified and we have begun a development program in Northeast Pennsylvania. While we expect to continue to seek acquisition opportunities in our Haynesville/Bossier and Marcellus shale areas, we have deployed our business development and technical staff to evaluate opportunities in new areas.
We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations and seeking opportunities outside of our existing operating areas. We employ the use of debt along with a comprehensive derivative financial instrument program to support our strategy. These approaches enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments and manage our capital structure.
Our business plan is summarized below:
• Manage our liquidity in a low natural gas price environment
The price of natural gas has a history of volatility and has recently experienced significant declines. Most of our revenues are derived from the sale of natural gas and our interim liquidity is expected to be significantly impacted by these recent price declines. Although our board of directors approved a 2012 capital expenditure budget of $710.0 million in November 2011, we have revised the capital expenditure budget to $470.0 million. We expect the capital expenditure program will be funded primarily by our operating cash flow. In addition, we are evaluating potential transactions which would further enhance our liquidity, including a partial sale of our interest in TGGT, and implementing cost reduction initiatives in operating and administrative costs.
• Develop our shale resource plays
We hold significant acreage positions in two prominent shale plays in the United States. In East Texas and North Louisiana we currently hold approximately 64,500 net acres in the Haynesville/Bossier shales and in Appalachia we currently hold approximately 140,200 net acres in the Marcellus shale. Our Haynesville operations began in 2008 when we completed our first horizontal well in the play. Since we commenced our horizontal drilling program in the Haynesville shale, we have spud 333 operated horizontal wells through December 31, 2011, entered into the East Texas/North Louisiana JV, and in 2010, identified our second Haynesville/Bossier development region in the Shelby Area. We also own working interests in 160 Haynesville horizontal wells operated by others. We continue to work closely with our midstream operations to coordinate drilling and completion timing of our wells, which allows us to flow new wells to sales promptly after completion.
We entered into the Appalachia JV in June 2010, covering our holdings in the Appalachia region, including the Marcellus shale resource play. We have used a similar process in the Marcellus region that was used in the Haynesville shale, with principal activities focused on technical evaluations of our acreage holdings, expansion of our technical staff, evaluation of test wells and a disciplined appraisal drilling program. We have identified our initial development area in Northeast Pennsylvania and most of our 2012 activities will be focused in this area.
• Enhance our midstream assets
Our midstream companies jointly owned with BG Group in East Texas/North Louisiana and Appalachia enhance our ability to promptly hook-up our wells for delivery after completion.
TGGT’s throughput in 2011 exceeded 1.4 Bcf per day, primarily due to increased throughput volumes in DeSoto Parish and significant throughput growth from the Shelby Area. The strong development activity in the Haynesville area of East Texas/North Louisiana contributed to this increase in throughput for 2011. TGGT expects to complete its major pipeline infrastructure projects in the Shelby Area in early 2012, and its first Shelby Area treating facility is expected to be fully operational by late in the first quarter of 2012. Due to reductions in drilling programs across the Haynesville area, TGGT is reducing certain capital projects and working to increase third party throughput opportunities. However, with the number of wells currently connected into the TGGT system and the projected well connections in 2012, TGGT anticipates stable throughput volumes in 2012 relative to 2011.
The Appalachia Midstream JV capital expansion is expected to be limited in 2012 as our upstream focus will be in Northeast Pennsylvania, where third party gathering infrastructure and facilities are in place.
• Exploit our multi-year development inventory
Our prior strategy of acquiring producing properties created a portfolio with a multi-year inventory of shale and conventional drilling locations and exploitation projects. This inventory ranges from low risk infill or development drilling locations, workovers and recompletions to higher risk exploration or appraisal locations. In 2011, we drilled and completed 335 wells with a 98.8% drilling success rate. In our East Texas/North Louisiana area, we plan to selectively drill horizontal wells, implement down spacing of wells, and recomplete existing wells to enhance our production and reserve position. In Appalachia, our focus will be directed toward our development program in Northeast Pennsylvania and a limited appraisal program. We continue to exploit our Permian assets, which have resulted in higher oil production than originally expected. Presently, our natural gas vertical drilling program remains suspended primarily due to low commodity prices. In addition, a substantial portion of our undeveloped acreage in our two shale resource plays is held-by-production which gives us flexibility to delay drilling if prices remain low.
• Maintain financial flexibility
We employ the use of debt and equity, joint ventures and a comprehensive derivative financial instrument program to support our business strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle and protects our returns on investments and capital structure. We have a credit agreement with a $1.6 billion borrowing base, or the EXCO Resources Credit Agreement, with unused borrowing capacity of $431.3 million as of February 22, 2012 (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our liquidity, capital resources and capital commitments—Overview”). On September 15, 2010, we closed an underwritten offering of $750.0 million aggregate principal amount of 7.5% senior notes maturing on September 15, 2018, or the 2018 Notes.
We have derivative financial instruments covering approximately 44.6% of our projected 2012 production and plan to add to the portfolio as opportunities arise.
• Actively manage our asset portfolio and associated costs
We periodically review our properties to identify cost savings opportunities and divestiture candidates. We actively seek to dispose of properties with higher operating costs, properties that are not within our core geographic operating areas and properties that are not strategic. We also seek to opportunistically divest properties in areas in which acquisitions and investment economics no longer meet our objectives. Our midstream equity investments also provide us with the flexibility to seek third party investors or capital market transactions.
• Evaluate acquisitions that meet our strategic and financial objectives
Our emphasis from 2008 through 2010 on shale resource plays shifted our prior acquisition focus from producing properties to opportunistic acreage acquisitions with shale potential. Acreage acquisitions differ from our acquisitions of producing properties as the acreage does not result in immediate production and cash flows or provide an incremental borrowing base increase under our credit agreement. While we expect to continue evaluating acreage opportunities in our shale areas, we have deployed our business development and technical staff to evaluate additional opportunities, including acquisitions of producing properties.
Plans for 2012
Our initial 2012 capital budget, which was approved by our board of directors in November 2011, was constructed using an average price assumption of $4.00 per Mmbtu, adjusted for differentials. Recent prices for natural gas have fallen to less than $3.00 per Mmbtu and the 12 month NYMEX strip is significantly less than our $4.00 per Mmbtu assumption. As a result, we plan to reduce our drilling program in response to the low natural gas price environment.
Our revised 2012 capital budget is $470.0 million and includes $359.00 million for drilling and completion activities utilizing an average of nine drilling rigs in the Haynesville/Bossier shale, three drilling rigs in the Marcellus shale, primarily in our Northeast Pennsylvania development area and one drilling rig in our Permian region. Approximately 76.0% of the drilling and completion spending will be focused in the Haynesville/Bossier shale, primarily in DeSoto Parish. Our 2012 Marcellus drilling costs also benefit from $54.6 million of unused Appalachia Carry. Following utilization of the Appalachia Carry during 2012, we will be obligated to fund our 50% share of all future activities in this area. The Permian Basin region continues to provide significant rates of return due to the high liquid content of the production. We expect this capital program to be funded primarily with our operating cash flow.
Our significant held-by-production acreage provides us with the ability to dictate the pace of drilling and completing wells. During 2012, we expect to maintain our 2011 average production level and may defer the completion of a portion of our wells drilled in 2012. We continue to address reductions to the costs of drilling and completing our wells through re-negotiating supply contracts. Our management is also focused on reducing our operating and administrative costs. In addition, our derivative financial instrument program is expected to protect a significant percentage of operating cash flow during 2012 as we expect natural gas prices to remain volatile.
As with our upstream capital budget, the management of TGGT has revised their capital expenditure budget as reduced drilling activity will result in a lower level of midstream activity and allow for the deferral of certain capital projects. For 2012, TGGT’s initial capital expenditure budget was between $100.0 and $115.0 million, which has been reduced to approximately $75.0 to $85.0 million. This reduced capital program focuses primarily on completing treating facilities in DeSoto Parish and the Shelby Area. The management of TGGT continues to focus on third party producer opportunities, which may result in an increase to TGGT’s capital budget. TGGT’s cash flows from operations and borrowing capacity under its credit agreement will be sufficient to fund its 2012 capital expenditure programs.
We do not expect to make significant capital contributions in 2012 to our Appalachia Midstream JV as the majority of our Northeastern Pennsylvania development drilling accesses an existing third party gathering system.
We have deployed our business development and technical staff, many of which were critical to the success we have experienced in our shale resource plays, to identify expansion opportunities outside of our existing areas.
Significant 2011 activities
Chief transaction
On January 11, 2011, we closed the acquisition of undeveloped acreage and oil and natural gas properties primarily in the Marcellus shale from Chief Oil & Gas LLC for $454.4 million, or the Chief Transaction, after post-closing title adjustments and customary post-closing purchase price adjustments. BG Group participated in its 50% share for $227.2 million.
Appalachia transaction
On March 1, 2011, we jointly closed the purchase of Marcellus undeveloped shale acreage with BG Group, which also included certain shallow production primarily in Jefferson and Clarion counties in Pennsylvania for $82.0 million ($41.0 million net to us), or the Appalachia Transaction.
Haynesville shale acquisition
On April 5, 2011, we closed on a $225.2 million acquisition of land, mineral interests and other assets in DeSoto Parish, or the Haynesville Shale Acquisition. BG Group participated for its 50% share of the transaction and funded us $112.6 million.
TGGT incident
An incident occurred at a TGGT amine treating facility in May 2011, which resulted in shutting in two treating facilities. As of December 31, 2011, we estimate approximately 124.0 Mmcf per day of production (39.0 Mmcfe per day net to us) was curtailed since the incident occurred. One of the shut-down facilities became operational in October 2011. TGGT expects the damaged facility will be re-started during the first quarter of 2012.
Former acquisition proposal
On October 29, 2010, our Chairman and Chief Executive Officer, Douglas H. Miller, presented a letter to our board of directors indicating an interest in acquiring all of the outstanding shares of our stock not already owned by Mr. Miller for a cash purchase price of $20.50 per share. This proposal did not represent a definitive offer and there was no assurance that a definitive offer would be made or accepted, that any agreement would be executed or that any transaction would be consummated.
Our board of directors established a special committee on November 4, 2010 comprised of two of our independent directors to, among other things, evaluate and determine the Company’s response to the October 29, 2010 proposal. On July 8, 2011, after consultation with its independent financial and legal advisors, the special committee released a statement that its review of strategic alternatives did not result in any firm proposal or any other proposal that was in the best interests of the Company and its shareholders and that they had terminated the review process. See “Note 19. Former acquisition proposal” of the notes to our consolidated financial statements for further information regarding the proposal.
CEO BACKGROUND
David N. Fitzgerald (73) 1993(1)
Chairman of the Board, Chief Executive Officer and President of the Company since January 1996; resident of Dave Fitzgerald, Inc. and Exit Oilfield Equipment, Inc.
Charles W. Gleeson (54) New Nominee
Independent Oil and Gas Consultant (1995-1996); various executive positions with Parker and Parsley Petroleum Co. ("P&P") from 1991-1995, including Senior Vice President, Vice President - Gas Processing, President of Parker and Parsley Gas Processing Co., Managing Director of Bridge Oil Ltd. (P&P's Australian subsidiary) and Senior Vice President-Permian Production Region; Vice- President-Production of Damson Oil Corporation (1983-1991)(2)
William R. Granberry (54) 1994
President of Tom Brown, Inc. since January 1996; Chairman of the Board, President and Chief Executive Officer of the Company (Oct. 1994-1995); Vice President of PG&E Resources Company (1989- 1994); Director of Tom Brown Inc. since 1995.
Richard D. Collins (63) 1993(3)
Secretary of the Company since May 1994 and Director of the Company since January 1993; Independent Financial Consultant since 1988; Director of International Star Resources, Ltd. and
Minute Man of America, Inc. since 1994.
Glenn L. Seitz (39) 1988
Treasurer of the Company since April 1988 and Director of the Company since May 1988; President of the Company (1989-1994).
MANAGEMENT DISCUSSION FROM LATEST 10K
Overview and history
We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore U.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areas including East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia.
Our shale resource plays and midstream operations are conducted through four joint ventures with BG Group. A brief description of each joint venture follows.
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East Texas/North Louisiana JV
A joint venture with BG Group covering an undivided 50% interest in a substantial portion of our assets in the East Texas/North Louisiana area including the Haynesville/Bossier shale and conventional shallow producing assets. The East Texas/North Louisiana JV is governed by a joint development agreement with our subsidiary, EXCO Operating, serving as operator. Under the terms of the agreement, BG Group funded 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $400.0 million. During the first quarter of 2011, we utilized the balance of the East Texas/North Louisiana Carry.
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TGGT
A joint venture with BG Group in which we each own a 50% interest in TGGT, which holds most of our East Texas/North Louisiana midstream assets.
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Appalachia JV
A 50/50 joint venture with BG Group covering our shallow producing assets and Marcellus shale acreage in the Appalachia region. EXCO and BG Group jointly operate the Appalachia JV operations through OPCO, which holds a 0.5% working interest in all of the shallow conventional assets and the deep rights in the Appalachia JV. Under the terms of the agreement, BG Group agreed to fund 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $150.0 million. As of December 31, 2011, the remaining balance of the Appalachia Carry was approximately $54.6 million.
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Appalachia Midstream JV
A joint venture with BG Group in which we each own a 50% interest in a midstream company which will develop infrastructure and provide take-away capacity in the Marcellus shale.
Our primary strategy is to appraise, develop and exploit our Haynesville, Bossier and Marcellus shale resources, primarily through horizontal drilling, and to leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. Future acquisitions are primarily targeted on supplementing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. We continue to develop vertical drilling opportunities in our Permian Basin area as this region has high oil reserves and natural gas with a high liquid content.
During 2011, we completed a number of significant transactions.
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On January 11, 2011, we funded the Chief Transaction for approximately $459.4 million, after post-closing purchase price adjustments, subject to post-closing title adjustments and customary post-closing purchase price adjustments. The $459.4 million preliminary purchase price was funded into an escrow account pending receipt of a waiver from a third party, which was received on January 11, 2011 and all properties were released to us. During the third quarter of 2011, the post-closing adjustments were completed on the Chief Transaction resulting in a final purchase price of $454.4 million ($227.2 million net to us). BG Group participated in its 50% share of the transaction.
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On March 1, 2011, we jointly closed the purchase of Marcellus shale properties with BG Group, which included certain shallow production primarily in Jefferson and Clarion counties in Pennsylvania for $82.0 million ($41.0 million net to us).
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On April 5, 2011, we closed the Haynesville Shale Acquisition for $225.2 million acquisition, which included land, mineral interests and other assets in the DeSoto Parish. On May 12, 2011, BG Group elected to participate in this acquisition for its 50% share.
As of December 31, 2011, the related PV-10 of our Proved Reserves was approximately $1.7 billion, and the Standardized Measure of our Proved Reserves was $1.4 billion (see “Item 1. Business—Summary of geographic areas of operations” for a reconciliation of PV-10 to the Standardized Measure of Proved Reserves). For the year ended December 31, 2011, we produced 182.7 Bcfe of oil and natural gas resulting in a Reserve Life of approximately 7.3 years.
Our 2011 development, exploitation and other oil and natural gas property capital expenditures totaled $855.5 million, net of $30.2 million of East Texas/North Louisiana Carry and $72.2 million of Appalachia Carry paid for our benefit by BG Group. In addition, we leased $19.0 million of undeveloped acreage in the Haynesville/Bossier shale resource play in East Texas/North Louisiana and $10.6 million of undeveloped acreage in the Marcellus shale resource play in Appalachia, net of reimbursements from BG Group. Contributions to our equity investments were $13.8 million. Corporate, gathering, and seismic capital expenditures totaled $82.4 million. We completed $396.4 million of acquisitions, net of reimbursements from BG Group. These acquisitions were mostly undeveloped acreage in the Haynesville/Bossier and Marcellus shale resource plays.
Our initial 2012 capital budget of $710.0 million was constructed using an average natural gas price assumption of $4.00 per Mmbtu, as adjusted for differentials. As of January 31, 2012, the NYMEX strip for the remainder of 2012 was $2.88 per Mmbtu. Although our board of directors approved the $710.0 million capital budget in November 2011, we have revised our spending plans to $470.0 million. Management is also addressing cost reduction initiatives in operating and administrative areas in response to the reduced drilling program. Our significant held-by-production acreage and derivative financial instruments allow us flexibility to manage the pace of drilling as we expect natural gas prices to remain volatile.
For 2012, TGGT’s initial capital budget was between $100.0 and $115.0 million, which included 2012 projects focusing primarily on completing treating facilities in DeSoto Parish and the Shelby Area. In light of the low natural gas environment and significant reductions in the East Texas/North Louisiana JV’s drilling in the Shelby Area, TGGT has reduced its capital expenditure budget to approximately $75.0 to $85.0 million. The management of TGGT continues to evaluate several expansion projects, which will be primarily driven by natural gas prices and third party producer opportunities and believes cash flows from operations and borrowing capacity under its credit agreement will be sufficient to fund its 2012 capital expenditure programs.
We do not expect to make significant capital contributions in 2012 to our Appalachia Midstream JV as the majority of our Northeastern Pennsylvania development drilling accesses an existing third party gathering system.
Like all oil and natural gas production companies, we face the challenge of natural production declines. We attempt to offset this natural decline by drilling to identify and develop additional reserves and add reserves through acquisitions. As of December 31, 2011, 97.1% of our estimated Proved Reserves were natural gas. Consequently, our results of operations are particularly impacted by the natural gas markets.
Critical accounting policies
In response to the SEC’s Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified the most critical accounting policies used in the preparation of our consolidated financial statements. We determined the critical policies by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our Proved Reserves, accounting for business combinations, accounting for derivatives, share-based payments, our choice of accounting method for oil and natural gas properties, goodwill, asset retirement obligations and income taxes.
We prepared our consolidated financial statements for inclusion in this report in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.
Estimates of Proved Reserves
The Proved Reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:
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the quality and quantity of available data;
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the interpretation of that data;
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the accuracy of various mandated economic assumptions; and
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the technical qualifications, experience and judgment of the persons preparing the estimates.
Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. The assumptions used for our Haynesville and Marcellus well and reservoir characteristics and performance are subject to further refinement as more production history is accumulated.
You should not assume that the present value of future net cash flows represents the current market value of our estimated Proved Reserves. In accordance with the SEC requirements, we based the estimated discounted future net cash flows from Proved Reserves according to the requirements in the SEC’s Release No. 33-8995 Modernization of Oil and Gas Reporting, or Release No. 33-8995. Actual future prices and costs may be materially higher or lower than the prices and costs used in the preparation of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates.
Proved Reserve quantities directly and materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in the estimate of Proved Reserves may result from lower market prices, making it uneconomical to drill or produce from higher cost fields. In addition, a decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties and require an impairment of the carrying value of our oil and natural gas properties.
Proved Reserves are defined as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimates are a deterministic estimate or probabilistic estimate. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
The area of the reservoir considered as proved includes both the area identified by drilling and limited by fluid contacts, if any, and adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.
Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and the project has been approved for development by all necessary parties and entities, including governmental entities.
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Business combinations
For the periods covered by this Annual Report on Form 10-K, we use the FASB ASC Subtopic 805-10, Business Combinations, or ASC 805-10, to record our acquisitions of oil and natural gas properties or entities which we acquired beginning on January 1, 2009. ASC 805-10 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value, with any excess purchase price being recognized as goodwill. Application of ASC 805-10 requires significant estimates to be made by management using information available at the time of acquisition. Since these estimates require the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available.
Accounting for derivatives
We use derivative financial instruments to manage price fluctuations, protect our investments and achieve a more predictable cash flow in connection with our acquisitions. These derivative financial instruments are not held for trading purposes. We do not designate our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative’s fair value as a component of current earnings.
Share-based payments
We account for share-based compensation in accordance with FASB ASC Topic 718, Compensation—Stock Compensation, or ASC 718. At December 31, 2011, our employees and directors held options under EXCO’s 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, to purchase 15,670,168 shares of EXCO’s common stock at prices ranging from $6.33 per share to $38.01 per share. The options expire five to ten years from the date of grant, depending on the terms of the grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% of the options vesting on each of the next three anniversaries of the date of grant. We use the Black-Scholes model to calculate the fair value of issued options. The gross fair value of the 2011 granted options using the Black-Scholes model range from $5.14 per share to $11.62 per share. As December 31, 2011, our employees also held 2,562,409 restricted shares under the 2005 Incentive Plan with grant prices ranging from $10.63 to $14.83 per share. The restricted shares vest over three to five years, depending on the terms of the grant. ASC 718 requires share-based compensation be recorded with cost classifications consistent with cash compensation. EXCO uses the full cost method to account for its oil and natural gas properties. As a result, part of our share-based payments is capitalized. Total share-based compensation for the year ended December 31, 2011 was $17.4 million, of which $6.4 million was capitalized as part of our oil and natural gas properties. For the years ended December 31, 2010 and 2009, a total of $23.2 million and $24.1 million, respectively, of share-based compensation was incurred, of which $6.4 million and $5.1 million, respectively, was capitalized.
Accounting for oil and natural gas properties
The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess possible impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus costs of acquired proved and unproved leaseholds.
When we acquire significant amounts of undeveloped acreage, we capitalize interest on the acquisition costs in accordance with FASB ASC Subtopic 835-20, Capitalization of Interest. We began capitalizing interest in April 2008, upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs, is divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our exploration, exploitation and development activities.
Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves. The impacts on our depletion rate from the formation of the Appalachia JV in 2010 and the formation of the East Texas/North Louisiana JV in 2009, along with certain other divestiture transactions in 2009, as discussed in “Note 4. Divestitures, acquisitions and other significant events” of our notes to consolidated financial statements, were considered significant and we recognized gains of $528.9 million and $691.9 million in 2010 and 2009, respectively, on our divestitures. There were no sales of oil and natural gas properties in 2011 that resulted in recognition of gains or losses.
Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs, or ceiling test. The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, a ceiling test write-down of oil and natural gas properties to the value of the full cost ceiling limitation is required. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying average prices as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.
The ceiling test is computed using the simple average spot price for the trailing twelve month period using the first day of each month. For the twelve months ended December 31, 2011, the trailing twelve month reference price was $96.19 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma and $4.12 per Mmbtu for natural gas at Henry Hub. Each of the aforementioned reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation.
The ceiling test calculation is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Goodwill
In accordance with FASB ASC Subtopic 350-20 for Intangibles-Goodwill and Other, goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of December 31 of each year. Losses, if any, resulting from impairment tests will be reflected in operating income in the Consolidated Statement of Operations.
To determine the fair value of our exploration and production reporting unit, a two-part, equally weighted approach is applied. We perform an income approach, which uses a discounted cash flow model to value our business, and a market approach, in which our value is determined using trading metrics and transaction multiples of peer companies.
As a result of testing, the fair value of the business exceeded the carrying value of net assets and we did not record an impairment charge for the periods ending December 31, 2011, 2010 or 2009.
The Appalachia JV and the East Texas/North Louisiana JV and other 2009 divestitures discussed in “Note 4. Divestitures, acquisitions and other significant events” caused significant alterations to the depletion rate and the relationship between capitalized costs and Proved Reserves. As a result of their significance, we reduced goodwill by $51.4 million in 2010 and $177.6 million in 2009 when computing our gains on those transactions. In addition, the TGGT Transaction, as discussed in “Note 4. Divestitures, acquisitions and other significant events” in our notes to consolidated financial statements, resulted in a reduction of $11.4 million in goodwill in 2009 against the associated gain and the transfer of $11.4 million of goodwill to the equity investment in TGGT.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Financial Condition
Changes in the Company's financial condition since March 31, 1995 are related primarily to the effects of well completions and workover activities and to increased general and administrative costs. The Company's cash flow is used primarily for property acquisitions, well workovers and capital expenditures on new wells. Management is of the opinion that the Company's cash flow and ability to raise additional capital will be adequate to meet its current obligations as well as fund additional property acquisitions, new projects, and generation and/or participation in new drilling and recompletion work.
Results of Operations
Revenues for the three months ended September 30, 1995 were $247,672 compared with $235,485 for the corresponding period of the prior fiscal year, a 5% increase. This was primarily due to the increase in Oil & Gas revenue from new wells which more than offset normal production declines and somewhat lower oil and gas prices. The $29,845, or 6%, increase in revenues for the six moths ended September 30, 1995 versus the prior period was due primarily to an increase in Management Fees from increased drilling and completion activity for the current period. Costs and expenses for the six months ended September 30, 1995 increased $150,946, or 32%, from $469,546 in the prior period to $620,492 in the current period. This was primarily due to a $101,575 increase in General & Administrative costs as a result of the hiring of the new Chairman of the Board, President and CEO in August, 1994, and to increased engineering consulting work done for the Company. In addition, there was $26,115 in Dry Hole & Abandonment costs for the current period versus $857 in the prior period due primarily to the drilling of an exploratory dry hole in the second quarter of the current fiscal year. The net income for the six months ended September 30, 1995 and 1994, $(118,756) and $2,345, respectively, represent $(.04) and $.00 per share.
CONF CALL
J. Douglas Ramsey
All right, thanks, Doug. I'd like to remind everyone that you can go to www.excoresources.com and click on the presentations link in the Investor Relations section at the bottom of our homepage to access today's presentation slides.
The statements that may be made on this conference call regarding future financial and operational plans, projections, structure, results, business strategy, market prices and derivative activities or other plans, forecasts and statements that are not historical facts are forward-looking statements as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on a variety of assumptions that may change depending on future events which are difficult to predict. Actual results may differ materially from those forward-looking statements. We caution you not to place undue, if any, reliance on such statements. Please refer to Pages 24 and 25 of the slide presentation for the complete text regarding our forward-looking statements, as well as the cautionary information set forth in our most recent Form 10-K, Form 10-Q, and other SEC filings, which are available on our website at www.excoresources.com.
In addition, the slide presentation contains information, including reconciliations regarding certain non-GAAP financial numbers, which will be discussed on today's call.
Doug?
Douglas H. Miller
Okay. Welcome, everybody, to our call. We have a slide show that is on our website, that we'll be going over today. With me today, I have 10 people, lawyers, all our financial guys and our operating guys. And we're going to be going over, in some detail, our quarter and we'll be sticking with you through -- as long as you want, as far as Q&A goes.
Just to get started. We have been -- with gas prices going down -- I could sometimes feel like we were driving across Kansas going 90 miles an hour, a year ago, with gas prices high and working as hard as we can. And here about, beginning of the year, we ran into a school zone. And so, I think we've had to figure out how to go slower and we're doing it and I think we still have guys in our industry speeding. So some of them are starting to get tickets. With that -- what we've been doing is we have been ramping down and cutting our capital budget. We do believe that you run a company, an oil and gas company inside your cash flow. We've been doing that. We've cut our capital expenditures 3 times since our November capital meeting. We'll continue to do so as gas prices stay cheap.
But with that, we report 533 million a day of production. In most times, that would be good. But it's mostly gas, so that was bad. We did have a spacing test in Shelby that was very successful. Hal will go over that a little later. Our TGGT, our treating has resumed. We did have a borrowing base redetermination, it did go down as we had forecast. It's $1.4 billion versus $1.6 billion. It was voted on and signed, I think, last Friday. Is that right?
We started adding some hedges for '13 through '15. But a little bit -- I think a lot of people have criticized us for not moving fast enough into the oil side. This has been a gas company. It was set up to be a gas company. We're still looking at gas transactions, but we do have a small oil property that has been successful. We've been running 1 rig over there and we are, now, in evaluation on how to get into it on both the Wolfcamp and the Cline. There has been some recent results in our neighborhood over there. We are drilling a vertical test, doing some coring as we speak. With the idea that if we can get it figured out, we would bring another rig in there later on this year.
And on top of that, we have quite a bit of -- across the Cotton Valley and even in West Texas. We do have some NGLs. We're going to start reporting them separately but we have 2 deals we're working on, in the Cotton Valley, that'll separate the NGLs. I did note -- however, I do note that we have a couple of thousand barrels a day of oil and maybe 1,300 barrels of NGLs out in West Texas. But we're going to start separating that in the Cotton Valley and expect to see that -- start reporting next quarter.
What's going on in the industry -- we've got too much gas. We've got too many independents that have been outspending their capital for the last 5 years. And the equity markets and the capital markets have allowed them to do it. So it is coming back to haunt all of us right now. We do have an abundance of gas, but I think what you're going to see -- and I've recently seen a couple of really good reports coming out, I think Joe Allman [ph] did one of them and somebody else talking about how fast the decline is occurring. I believe that you're going to see, at least in the Haynesville, maybe a 2 Bcf year-over-year decline with what's going on out there. Rigs got up to -- what, what is called? 186 down to around 50. And you can really see the declines. A lot of people have just quit over there. We're slowing down and we're willing to quit, but we're taking it at a proper pace. And if we have to quit, we will. But right now, I think we have 7 rigs, 8 rigs running. 7 as of this morning, and we're prepared to go to 4 if gas prices stay where they are. But I think you're going to see supply coming down faster than anybody expected. And I think -- the other side of that is I think you're going to see demand going up a little faster than anybody expected. We're seeing a lots of power getting turned on gas. I think we've had a lot of power companies in here looking for long-term supply. We have not made a deal and will not at these prices, of course. But I think you're starting to see some of the results coming out of the EIA and others, January, February, maybe 5 to 7 Bcf a day for power. But I think that's going to expand. I think you'll start seeing it in the second half of the year. There's just a lot of activity going on but I think, as people quit drilling dry gas, it's going to come down a lot faster.
And finally, up in the Marcellus, I saw where Anadarko's cutting a lot of rigs, Talisman's leaving. So that has been a boon for the industry. People are going a little bit too fast up there. Including us. But we're down to 3 rigs out there. We have 850,000 acres in the Appalachia, a couple of hundred thousand in the Marcellus. And we're at 3 rigs and prepared to go to fewer. We have had some interesting results here recently, on an area that I think everybody gave us 0 credit, including us. And Hal will talk about that a little later.
But again, where supply and demand -- you're starting to see 15, 16 -- you're starting to see some potential export. And I think everybody thinks that gas is not going to go up until then. I'm not in that camp, I think you're going to start seeing some direction, maybe, as soon as the second half of this year. I'm hoping it stays days down because we are actively seeking some acquisitions in the gas market.
We have been approached by a lot of potential partners to participate with us. There are a lot of deals in the market today. We are reviewing them. We would not drill for the gas if we bought it. The 3 deals that we bid on this year were all oily. We missed all 3 of them. One of them we got real close on, again they were joint ventures with third parties. But Jacobi's been here and he's busier today than he's ever been. We think there's probably $40 billion or $50 billion worth of assets on the market today, both oil and gas. And there is plenty of money and we've been approached, domestic partners, and more recently, some foreign partners that are interested in buying dry gas in the U.S. because they expect to be exporting to their own country.
Monetization, I think we've got criticized on the TGGT a little. It's an asset that is pretty much fully developed with our drilling program right now. So we did sign a 45-day exclusive with an infrastructure fund. We did get an offer for 1/3 of it from them but during that process we received a lot of indications from strategics. We have reviewed that and we are entertaining and discussing with 3 today and we have 2 more coming in. The possibility of selling 100% of it. BG is on board and so we continue that process but I think, right now, we're leaning towards selling 100% of that instead of just selling 1/3.
We continue in negotiations on our conventional joint venture that we've discussed. As recently as yesterday, we have shared some information with a partner. I expect something on that. We'll either happen with them or backup that we have 2 or 3 other people that have shown an interest. I expect something to happen there within the next 30 days.
With that, I'm going to turn it over to Steve and I'll get back to you later.
Stephen F. Smith
All right, I'm going be -- my remarks will be starting on Slide 5. We'll talk about kind of the highlights of the quarter, and particularly, I want to spend a little more time on cost and then Hal will also spend some time there. Obviously, I mean, we -- the production level that we're at right now is pretty much right on our guidance. It's what we expected, and of course, it's a big increase over last year. And it's flat, pretty much flat with the fourth quarter. The average realized price, obviously, at $2.78 versus $4.40 is a problem. Gas only is $2.45. So that, of course, makes things difficult. But our hedges have been working and our revenues, including the cash settlements, are flat between years and so that's been a plus for us from a cash standpoint. Direct operating cost, G&A, all of the cost and we will talk about them in more detail in just a minute. But they are trending downward, both in absolute dollars on a Q1 to Q4 basis. They're down by -- operating cost are down like 5% between quarters and all those costs are trending down and which we're very pleased with and which is -- it has to happen in this kind of environment.
Our adjusted EBITDA, our cash flow from operations also are pretty much in line, given the fact that the gas price is lousy and we're pretty much in line with what we had thought -- of where we thought we would be.
In our adjusted net income line, there are 2 things that are not included in adjusted net income. One is the saving cash write-down of $276 million on an a pretax noncash write-down. We used the 12-month average at the beginning of the month. So March 1 of '11 -- I mean, '12, back through the April period. And that was $3.73 on gas, $98.15 on oil. So that's why we had the write-down. We would expect that if the gas doesn't strengthen, we'll have additional write-downs. It's just the way the math works on the full cost pool.
In addition to the write-off on the full cost pool, we also have an impairment of our -- of some assets at TGGT and it affected our equity net income in that entity. It doesn't have any impact on our EBITDA, et cetera, because they're not included in EBITDA. But the write-down -- we have some temporary -- we've started out with temporary units to restore the production in the plant that -- where there was an explosion back in -- about a year ago. And we ramped that temporary unit construction up pretty heavily. But this quarter, we decided that the permanent facilities out there were not damaged, one of them was not damaged very much at all, and so we're going to put that unit online probably in the next few months, 6 months or so. And as a result, we didn't really need all of the temporary treating capacity that we have. And the treating capacity that we got online, right now, we're not going to need for very long. So we went ahead and took a write-off in the first quarter, in the equity income line.
All right, let's look at Page 6 and let's talk a little bit about the rig count and Doug has covered it pretty well. We've got a couple of more rigs that are just coming off contract by their own terms here pretty soon and those will -- if prices don’t firm, we're going to let -- we'll let those go. We might even let an additional rig go. We're expecting to be in the 5 -- 4 to 5 in the Haynesville at the end of the year, and 8 or 9 overall. We could cut back in Marcellus if we need to, from a cost standpoint.
Douglas H. Miller
But it could go up in the Permian, yes.
Stephen F. Smith
That's right, exactly. As far as the drilling costs are concerned, we have had good news in that area in the Haynesville. We were quite around $9.5 million at the -- during the fourth quarter. We're down to about $8.5 million now and we feel like, about the end of the year, we'll be down to $8 million. We've had a lot of cooperation from the supplier of our drilling services, of our frac services, et cetera, and I'll get into a little bit more detail on that on the next slide also. But we're very pleased with where we're headed. We need to get lower, obviously, with this kind of prices but at least we're on the right track.
As far as expenses are concerned, you'll see down at the bottom, I'm just comparing the Q1 of '12 with Q4 of '11, good progress in all areas there and on a -- both an absolute dollar basis, which is what's in this table. But also, on a per Mcf basis, good progress. So we're pleased with where we're headed on cost.
Over on Slide 7. I'll talk a little bit more about the drilling completion reductions. We've been able to obtain a great improvement in our frac cost from $220,000 a stage down to $165,000 and that's about $600,000 per well, which is a real jump start to getting those costs down. We've also changed our tubing design and how we run tubing and that saved us -- will save us at least $200,000 per well. We've gone from chrome to steel tubing. We've also had good reaction from the service suppliers of wire line, car [ph] tubing and a lot of the other pumping services that we use. In our operating cost, we've reduced our headcount, obviously, when we reduced the rigs like we have. We've also renegotiated our saltwater disposal cost in our principal area in DeSoto Parish. And we've removed a lot of wellhead compressors that we didn't really need over there. So we've had -- and Hal will get into some more details but those are just some of the highlights. G&A, we're down of strong percentage between quarters. And we're headed on down on that and it's primarily a headcount situation in the G&A.
The last Slide on 8, for me, is just our production and debt profile. I'd like to share this each quarter. As you know, we have redetermined our borrowing base, and Paul will get into a little more detail there, but this slide just shows where we're from a debt standpoint at the end of the quarter. Where we expect to be without any potential monetizations of assets and then, obviously, with a little bit of success on monetizations, we're going to be able to drive that down pretty quickly.
So at this point, I'll now turn it over to Paul and let him pick up with our guidance, liquidity, et cetera.
Paul B. Rudnicki
Thanks, Steve. I'll pick up on Slide 10. Looking at our liquidity and derivative position at the end of quarter. We ended the quarter with $194.6 million of cash. We had a $177 million -- sorry $1.1 billion drawn on the credit facility and we can see we had $750 million of notes outstanding for a total net debt of $1.7 billion at quarter end. Looking at where we are at the end of April, we paid down little bit on the debt. We're down to -- still holding at the $1.1 billion level, paid down about $30 million in the month. As we talked about in the press release, our borrowing base was redetermined, as we expected, from the $1.6 billion level, down to $1.4 billion. And we also amended the debt-to-EBITDA covenant up to 4.5:1 from the current 4:1 that it was at. With the cash on hand of $183 million at the end of April, left us with $427 million of liquidity.
Looking at our derivative position, our 2012 hedges remain as they were. We have 60 Bcf hedged for the rest of this year, at $5.27, 412,000 barrels of oil at $98 for a total equivalent, $229 million per day or right at 50%.
We did add some hedges here in April, as we lay out in our Q, it'll be filed shortly. What we did is we went out and swapped 2013 through 2015 for 35 million a day of natural gas, 35 million Mcf a day, and at a price of $4.18. We also sold 35 million a day of calls at $4.18. So effectively, we have 35 million a day swapped at $4.18 and a ceiling of 35 million a day at $4.18. And we're going to continue to look at additional structures, as well as just straight hedges
Moving on to Slide 11, as we compare our results for the quarter versus our guidance. As you can see, our oil production came in above the high end of guidance. Gas production came in right at the midpoint of the guidance and our overall was right at the midpoint, slightly a little bit above. The one thing to point out on our differentials, we have seen a widening of our Permian oil differentials, as reflected in the first quarter. And we'll talk about that in the guidance going forward.
Our gas differentials came in at the low end of guidance. And our lease operating expenses also came in at the low end of the guidance as we've been successful in getting those operating cost down. Gathering expenses right at the midpoint. Production taxes, a little bit higher than expected, partly as a result of the new Pennsylvania impact fee. In this number that we're reporting, this is just the ongoing current position. We also recognize the $2 million retroactive impact fee for everything before 2012. We've excluded that from our earnings as an out-of-period nonrecurring number. That will be paid out in September of this year.
Looking at our DD&A rate, it came in at $1.84 versus the guidance of $2.10 to $2.20, and that's a reduction of the ceiling test write-off that we took at year end. Cash G&A, as we've discussed, we've had good success in bringing those costs down and we came in substantially below guidance on that number.
Interest expense was right in line with guidance, as well as our equity income from TGGT and our other investments, excluding the items that Steven mentioned already.
Our capital budget, capital spending for the quarter was $162 million versus the guidance of $180 million to $200 million. A part of that is the result of the timing of certain capital projects that we expect to flow into the second quarter. And also just a regular reduction in the activity level that we're seeing.
All that said, our adjusted EBITDA which, again, does not include any impact of our equity investments, including TGGT, this is basically just the upstream EBITDA, it was $110.5 million versus our guidance of $110.6 million. And the TGGT EBITDA, net to our interest which, again, is not included in our corporate EBITDA, was near the high end of the guidance and came in at $17.4 million.
Slide 12, looking at the guidance for the rest of this year. We're keeping our production guidance flat to where we had guided previously. The one thing we are doing, as Doug mentioned, is we are going to breakout our NGLs. Currently, we forecasted the effect of the NGL production we have in the Permian basin. As Doug discussed, we are looking at some additional processing upgrades in our East Texas position, which is not reflected in this guidance as well.
Hal will get into the some of the Permian upside that we're working on. But I will note that none of the upsides for many potential horizontal drilling or the water flood project that we're working on are in this guidance. This is just our normal Canyon Sand development drilling.
Look at our differentials. As we show here, we're showing the expanded oil differential out to $6 to $7, under NYMEX for the rest of this year. And we started, again, showing our NGLs separately. We're expecting 45% to 55% of NYMEX oil for those differentials. I will highlight that the Permian NGLs that we have are relatively low in ethane. There are only about 1/3 ethane. The other 2/3 are the heavier components. That kind of compares to our liquids production, and expect the liquids production coming out of the East Texas, which is closer to 60% ethane. So we're able to get some -- still get some pretty good prices on our overall NGL mix on the Permian due to the component balance out there. On our gas differentials, we're showing a wider differential than we have in our prior guidance. The main effect there is for stripping out the liquid revenue that was included in our prior gas differential.
For all of the other items, we're essentially keeping them flat at this point. We brought G&A down a little bit to coincide with where we are at the end of the quarter. I do want to point out, on our capital, we have shifted some of the capital dollars out and we are still guiding towards $450 million to $488 million of total capital for the year, with roughly a $470 million midpoint. We do expect that number to be lower. We want to get another quarter under our belt and see exactly where we end up with the rig count this quarter. But at this point, we're just going to hold guidance equal at that level.
And with that, I'll turn it over to Hal to get in to some more details on the operations.
Harold L. Hickey
Thanks, Paul. First, I'd like to say that in this tough environment, our teams' have responded very, very well and I'm really proud of the way the teams has reacted during this low natural gas price environment challenge that we face. And we've had some really good operational results and we foresee good operational results going forward because of their activities.
On Slide 14, you can see the map we always show of our operations. I'll emphasize that we have 8 Tcf of reserves and resources across our portfolio based on March 30, NYMEX strip price. At 8 Tcf, we have 1.7 Tcf of proved reserves and of that 1.7 Tcf, we have -- 60% of that is PDP, and overall, 70% or so is proved/developed. We continue to see the bulk of our production from East Texas, North Louisiana and in the Permian, holding steady with our production rates but there's a big push toward liquids and I'm going to emphasize, in a few minutes, the opportunities are presenting themselves.
In Appalachia, we're down to 3 rigs now. The teams are very focused on operations and production in Northeast Pennsylvania, particularly in Lycoming County. But we've had some really good results in the central area, like Doug said, nobody was giving us credit for. I'm going to talk about that in a minute. But I will say that, also in Pennsylvania, West Virginia and the whole Appalachian area, our teams, both here and in Warrendale, where our office is, just outside Pittsburgh, are evaluating liquids opportunities there as well, in the Appalachian region.
We achieved our operational targets for the year. In the Haynesville/Bossier, our big focus is now going to be on drilling in Holly area, primarily in DeSoto Parish, where we have 7 rigs operating today. We're implementing a very, very successful, at this point, restricted choke flowback program. What we do is we set our limit on the high end of the choke at 18/64ths. We manage to a 25 psi drawdown on our surface pressures, and what we're seeing is some enhancement in our overall type curve, leading to an overall EUR improvements. Down in Shelby, we completed the delineation effort. We drilled 8 wells on 880-foot or about 130-acre spacing. A partner of ours drilled, on an adjacent unit, 6 wells on 1,200-foot or 160-acre spacing. We flow that back, we got about 215 million a day IP. This was in late March. We put a restricted choke on that program as well, the chokes range from 18 to 22/64ths. And what we're seeing down in the Shelby Area, that's very, very encouraging to us, is with this restricted choke program, we're seeing our cumes [cumulative volumes] actually crossover. So, before, we were opening chokes up higher, 26/64ths to 30/64ths and we're having a big bump of the initial production. Now we've restricted that initial production but the cumulative rate coming out of these wells with restricted production are actually equaling, on a couple of our most recent wells, the higher flow rate wells at 100 days. So we're really excited about that. We've only seen 2,000 psi drawdown and after that 100-day, 200-day period and so we think that this is going to leave us some positive, positive results down there. Now, as we evaluate the spacing, as gas prices are lower, noting that our costs are higher in Shelby, because of the deeper, higher pressure, higher temperature, we have deferred drilling there, and at least for 2012, we're not going to drill anymore. Talking about some of the activities up in the Marcellus. I've noted that the focus is in Northeast Pennsylvania, particularly in Lycoming County. We're making about 116 million a day gross production out of the Marcellus now. We're continuing to build out our water infrastructure, and of significant amount of that is in place, we're actually building more. But look at water infrastructure does for us is -- obviously, it takes trucks off the road but it's saving is $300,000 to $500,000 per well about being able to pipe as opposed to truck.
Permian area, of course, we're continuing our Sugg Ranch Canyon Sand development where we're seeing 50%-plus rates of returns and really strong cash margins. We are testing Wolfcamp and Cline shales in our acreage, we've got a vertical well that we're working right now. We're coring that well. I'll give you some details on that in just a moment. And we're pursuing opportunities to increase acreage. I'm going to give you some more information on that shortly.
Flipping over to 15 is our capital budget. The $470 million budget is actually 54% less than what we spent in 2011, and as Paul said, we're likely to drop this even more as we manage our programs going forward. We do have the 1-rig forecast for Permian, and I will say, if some opportunities materialize out there, that we're hoping for, we could increase that rig count. The 3 rigs in Appalachia, we have 2 rigs in Northeast PA now, shortly we'll have 3 rigs operating there. And with the 7 rigs in the Haynesville, we have 11 operated rigs in the portfolio as we previously noted.
Look at our capital budget of $470 million which is, again, likely to go down. I'll note that we still have $30 million of BG carry [ph] remaining as of end of Q1 for our Appalachia drilling and completion operations. A big focus of our spending will remain in the Haynesville/Bossier area, which represents about -- just on the drilling side, 57% of our total budget. And of just looking at the whole drilling and completion budget right now, about 75% of our drilling completion dollars will be spent in the Haynesville/Bossier region.
I will say that, as we've released rigs, the cost to do that is actually been less than we had forecast in our budget. We forecast about $15 million and I think we'll end up spending somewhere $8 million or $9 million per rig termination cost. So that's a positive that's occurred.
On Slide 16, you will note that we were at a peak operated rig rate of 28 back in 2011. We got a big focus on cost and Steve's already talked about how the costs have come down in our Haynesville operations. I will note that in the Northeast area of the Marcellus, we're targeting, right now, about a $6.3 million, $6.4 million well cost. We've got a plan to get down to $5.8 million or so by the start of 2013. I talked about how the water infrastructure will help us in that regard. I will say that we're working very diligently on drilling and completion efficiencies as well. I'll talk a little bit about of those more so in a minute. And I better note that the well cost we're talking about is for an average lateral of about 4,200 feet.
On the OpEx side, we have shut in some of our less profitable wells. We've shut in about 655 Cotton Valley wells at this point, that make a lot of water. It's only resulted in a production decrease of about 1.2 million a day, net our interest. The gross cost associated with the shut-ins is about $5 million of cost that we've taken out of our system, that's about $2 million or so of net cost to us. We are targeting the significant reduction of our work-over program. We're still doing the things that are important and that payout very quickly. We have 6 work-over rigs, at one point, working in our Shelby area. We're down to 2 or 3 now. We've got several other initiatives underway to reduce our operating expenses. We've cut company vehicles, we've cut about 10% of our company vehicles out. We're carpooling. We're finding other means for our people to get around. Wellhead compression, we have continued to cut down. I know Steve noted that there was about $1.1 million in annual savings that we're realizing from wellhead compression, and with the plans that we actually have in place now, we may double that impact on our annual savings up to as much as $2 million.
Labor cost, we've cut out a lot of our field contract labor, as Steve noted. What I do want to say is we're not cutting back on maintenance when we do that. Our people, our EXCO employees have actually stepped up. They're doing some routine maintenance now and filling the work that was vacated by Lou [ph], letting go some of the field contract labor with some of their time and their efforts. So we're in good shape there.
Other reductions we're looking at. Chemicals, we've cut about $600,000 a year out of our chemicals in our Cotton Valley area, in our Haynesville area. Also on the Haynesville, with this restricted choke program, we've actually cut back some of our water production, and in turn, we aren't having to have as many coolers on our wellhead. So we've cut those back significantly and that's actually going to save a couple of million dollars of years as well. So really some good efforts that are ongoing in managing our cost.
Slide 17, getting into some of the details on East Texas and North Louisiana. First, I'll say that the 264,000 gross acres is actually for our -- all of our North Louisiana, East Texas holdings. We have 132,000 net acres there and our net acreage in the Haynesville/Bossier shale is about 64,500 to our interest. The majority of this shale acreage is HBP, in Holly, virtually everything's held. In Shelby, we've got 85%-plus held and we have plans of going forward working with our partners. While we may not be drilling there, others are and we've negotiated some deals that we'll able to hold our acreage through some of the partners drilling, as well as just if we choose to do some lease extensions.
Average gross shale production, 1.2 Bcf in the first quarter. That includes an OBO, we averaged about 390 million a day, we're up from that now. Actually, saw a number of well over 400. Yesterday, we got 324 operated horizontal shale wells flowing to sales as of the end of March. Big point, average in the first quarter was about 72 million a day of curtailment, and that was from off-set operations and well work and the treating facility. I need to make sure that everyone knows that. Now, that number is down to less than 30. So where we were at -- hell, I don't know, lot of times last quarter I was seeing 15% to 20% net shut-ins a day. We're down to about 6% or 7% net shut-ins a day. So really good movement and a lot of that has to do with the startup of the treating facility that Holly takes over and right over Parish. We've seen continuous improvement on our drilling days and optimization of our frac designs, our drilling days. Talked about this before, but our spud to rig release is now 37 days, that's down about 40% over the last couple of years. On our frac designs, we continue to manage our profit mix, we're using less chemicals, and in addition to the discussions and bidding and working with our frac stimulation service, obviously, our frac costs are coming down.
One thing we're targeting, like Steve said, all of our services procedures -- one thing that I will note is our drill costs, there is some threat there because of the availability of the cross, that's actually grown, that's used in production of gel. I think they call it guar. And we'll see how that works out but that is one little threat that could drive, raise cost a little bit across the whole industry.
Slide 18. Talking about Appalachia, we've got nearly 800,000 gross acres there, as Doug said. About 140,000 net acres, net to EXCO, have Marcellus shale potential. About 2/3 of our acreage there is HBP and we have plans, of course, in place on how we'll hold that acreage through a combination of drilling and lease extensions renewals. So we're in good shape there on our HBP. We're -- actually entered this year with a plan to have as many as 7 rigs operating there with the gas price. We've dropped that down to 3. We actually had 4 on contract and we released 1. So we're at the 3-rig level I talked about. Some major ongoing evaluations could add some substantial production later in this year and some of our activity will also add substantial production later in this year.
We've had some good results with seasoning. We'll actually bring on the well, flow it back for a week or 2 and then shut it in for 3 or 4 weeks and allow the pressures to build. And couple of examples, we've actually seen 2 million a day wells jump up to 5 or 6 million a day rates following the seasoning period. We're looking at completion methods and how we can optimize our completions. We're looking at our volumes of sand, we're looking at cluster spacing and our numbers of stages. We're, obviously, looking at how we manage, during simultaneous operations, where there's doing fracs or some of our hookups. We're going to plan to put our facilities in before we complete and that'll give us some online time quicker. Present delineation of some of our acreage is going well. I said earlier we've got the focus in Lycoming County. We have had a really, really strong result with the well over in Armstrong County. We brought it on, this is -- before we tubed it up, before we seasoned it, it was flowing 6.2 million a day, 1,500 psi flow-in pressure. We've now shut that well in to tube it up. I'll attribute it to a combination of good rock, good choke management, good completion method and so we're excited about how -- what opportunities that could present.
If you look the table on the right-hand bottom side of Slide 18, you can see how our turn to sales activity is really going to ramp up in Q3 and Q4 this year. We plan to spud 49 wells through the year and we'll complete 51 but you can see 42 wells will actually turn to sales in Q3 or Q4. So that's when you'll see most of our ramp-up in production occurring.
While we did see, recently, that one of the river basin commissions put a stop to some water takes from about 10 or so points of water sources. That has no impact on us, we have multiple water sources. So the water moratorium, from a certain amount of the take points, is not going to have an impact on us at all.
Going over to Slide 19 and looking at our non-shale asset. We have over 1 Tcf of reserves and resources potential and 65% of that is proved. Good production from East Texas, North Louisiana, Cotton Valley, Vernon. Appalachia, about 16 million a day. Shelby and Permian, you can see we're starting to report that on a Boe per day basis. Some 1,700, 1,800 barrels of oil, some 1,300 to 1,400 barrels of NGLs and about 6 million a day of natural gas make up the 4,000 BOE.
Like I said, drilling in the Permian with 1 rig, but we could add to that if some of our opportunities materialize. Cotton Valley is very focused on cost management. We've got some really good re-completions lately, in the Cape field, in our Vernon area. We've got a good footprint in our shale development area and I'm excited about the footprint that the Permian provides for some of future opportunities we may realize out in that area.
We're negotiating a potential joint venture, that Doug's noted, in certain of our shallow and conventional assets. I will note that, in that, we'll continue to operate. Other opportunities, we talked about some processing deals with third parties. We'll be extracting NGLs from some of our higher BTU Cotton Valley gas. And another thing we're doing in our immediate area is looking at some of our offset operators, drilling of Cotton Valley horizontal well. And I think what they're doing is pursuing high-BTU content opportunities in the Cotton Valley that could lead to some ideas for us and obviously some processing opportunities as well.
So going now to the Permian on Slide 20. You can see nearly 27,000 net acres in the Permian that's dominated by our Sugg Ranch position in Irion County. We've got a good operating cost, it's about $1.20 per Mcf, and you realize really good cash margin out there of about 9.47. We're evaluating Cline and Wolfcamp. In addition to other opportunities with Cline and Wolfcamp, we're looking at some shale opportunities. The water flood that Paul referenced earlier has forecast EUR of nearly 900,000 BOE. At 1 injector and 2 producers that we're going to use out there, we actually started injecting water in February. To this point, the pressures have risen just as forecast, and we anticipate that we'll start realizing production from this water flood come summer -- summertime.
Another thing that we've done out there is, with some of our 3-D activity, we've actually identified some carbonate mounds. We've drilled 6 of them, 5 of them had been very successful, 2 recent ones. IP-ed at 200 barrels of oil a day, each one was cumed 100,000 plus barrels and is still making 60 barrels of oil and I think we have another 10 or 12 with some of those identified that we'll evaluate their prospectivity and make decisions on whether we drill more of those.
21 shows Cline Shale and horizontal Wolfcamp activity and potential. Let me point out on this map. It's kind of deceiving the way it's depicted, but the blue, which is where a whole lot of our acreage is and some of the opportunities that we're looking at are, frankly, contains both Wolfberry and Cline potential. So that's where we are. We're looking at both Wolfberry and Cline potential. Our acreage is, of course, depicted in yellow. If you look at the green, that's really where you're forecasting of Cline only. So we think we're in a good position there, and like I said, this footprint really gives us a good, good opportunity to expand our operations out there. There's significant industry activity around us. We're seeing some IPs in the 800 to 900-plus range of oil. We're drilling a vertical test now in on our acreage. We've already taken about 290 feet of core in the Wolfcamp. We're drilling down to the Cline. We'll take roughly 360 feet of Cline core or 90-foot cores and we're optimistic. And if this thing plays out as we anticipate, we'll start drilling our first horizontal test later this year, based on what we learned after we get the data and evaluate the opportunity.
Last slide I'll talk about is on 22. TGGT, of course, is our 50-50 equity investment with BG, a midstream company. Average 1.5 Bcf a day in the first quarter. Throughput has been up around 1.6 Bcf a day now. It's very, very important to note that we have no current volume curtailments because of treating capacity. Treating facilities in Red River Parish are operating very well since we started them up in March. I'll note that, over in the Shelby Area, we've started up a 250 million a day treating facility there as well. It's now treating 160 to 180 million a day. It's just recently started up. And with those, and with some pipes we've put in, our major infrastructure and treating facilities work is really behind us. We've spent about $300 million in TGGT between us. Well TGGT, spent about $300 million of capital last year. We'll spend about $130 million of capital this year, $100 million of that has effectively been spent or will be spent by the first of the year. And marching forward, we'll look at, probably, $30 million for the rest of the year after we reach 1st of July and about $30 million to $50 million for the next several years as the major work's been done there.
We've increased our credit facility at TGGT as well, as we did at EXCO, at TGGT. And we increased to $600 million. We've got about $495 million outstanding as of the end of March. We are doing a little work, we're looking at third-party volumes. And as Doug noted, we are evaluating the monetization of either part or all of our interest in TGGT and working with BG on that.
With that, I'll turn the discussion back over to Mr. Miller for Q&A -- in time for Q&A.
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