ITEM 1. BUSINESS
GENERAL
EXCO Resources, Inc. is an independent oil and natural gas company. We have been engaged in the oil and natural gas business since 1955. We currently conduct our primary operations in Texas and Louisiana. At the end of 1997 and the beginning of 1998, new management bought a controlling interest in EXCO and redirected its focus. We now focus on acquiring, developing and exploiting properties which already produce oil or natural gas or are capable of producing oil or natural gas.
Historically, we have financed our exploration, exploitation and development expenditures primarily through cash flow from operations, bank borrowings, equity capital from private sales of stock and promoted funds from industry partners. With respect to our acquisition activities, we are shifting our emphasis to larger scale acquisitions of producing properties with additional development and exploitation potential. Initially, we plan to use a combination of debt and equity financing to fund these larger acquisitions.
We prefer to act as operator of the oil and natural gas properties and prospects in which we own an interest. The operator of an oil and natural gas property:
o supervises production; o maintains production records; o employs field personnel to oversee the general operations of the properties; o performs other functions required for the production of oil and natural gas; and o monitors performance, both operating and financial, necessary to optimize cash flows derived from the properties.
Industry Language
The oil and natural gas industry is characterized by the use of very precise specialized language. The following is a brief explanation of certain industry terms which we use in this annual report. We believe this explanation will help you understand our operations, risks and strategies. (Certain other technical terms are defined in a "Glossary" located at page 21.)
We use five different terms to describe the nature of our oil and natural gas wells. A "development well" is a well drilled within a known oil and natural gas reservoir with the intention of installing permanent equipment to produce oil and natural gas. An "exploratory well" is a well drilled in an area not known to be an oil and natural gas reservoir. A "producing well" (also called a production well or a productive well) is a well that is currently producing oil or natural gas or that is capable of production. A "dry hole" is an exploratory or development well that is incapable of producing oil or natural gas in sufficient quantities to justify completion of the well. Finally, a "completed well" refers to a well in which permanent equipment for oil and natural gas production has been installed, or in the case of a dry hole, reporting the abandonment of the well to the appropriate agency.
When we count our wells, we use the terms gross wells and net wells. A "gross well" is a well in which we own an interest that gives us the right to drill, produce and conduct operating activities for the well and gives us the right to a share of the oil and natural gas produced from the well. The interest that gives us these rights is called a "working interest." Gross wells means the total number of wells in which we own such an interest. A "net well" exists when the sum of the fractional ownership interests in gross wells equals one. The number of net wells we own equals the sum of the fractional working interests owned in gross wells expressed as whole numbers or percentages.
When we describe the nature of our oil and natural gas properties, we use the terms developed and undeveloped acreage. "Developed acreage" are those acres assignable to producing wells. "Undeveloped acreage" are those acres on which wells have not been drilled or completed to a point that permits the production of
- 1 -
commercial quantities of oil and natural gas. When we count the acres in which we own a working interest we use the terms "gross acres" and "net acres." A "gross acre" is an acre in which we own a right to drill, produce and conduct operating activities on the property and to a share of the oil and natural gas production. A "net acre" exists when the sum of such fractional working interests in gross acres equals one. The total net acreage is the sum of the fractional working interests owned in gross acres expressed in whole numbers or percentages.
When we describe our oil or natural gas reservoirs within current developed and undeveloped acreage we use the term "reserves." We obtain geological and engineering information which we use to estimate the amount of reserves contained in our developed and undeveloped acreage. These estimates are known as "proved reserves." We use two terms to describe our proved reserves. "Proved developed" reserves are proved reserves which may be recovered from known oil and natural gas reservoirs under existing economic and operating conditions. "Proved undeveloped" reserves are proved reserves which may be recovered from existing wells but would require a relatively large expense to develop or proved reserves in current undeveloped acreage.
DEVELOPMENTS DURING 1998
We Completed Acquisitions
On February 11, 1998, we acquired oil and natural gas working interests from Osborne Oil Company, Gypsy Production Company and other sellers in the Chittim/Barclay Ranch properties located in Maverick County, Texas. We paid approximately $760,000 for the Maverick County properties. On May 8, 1998, we acquired all of the outstanding common stock of Jacobi-Johnson Energy, Inc. We paid approximately $1.5 million in cash and stock for Jacobi-Johnson Energy, Inc. The acquisition was effective January 1, 1998. On June 30, 1998, we completed the acquisition of properties from J. M. Hill, J. M. Hill, trustee, Walter O. Hill, Stephen J. Devos, Humphrey Oil Interest, L.P. and other working interest owners, in Dawson and Brazos counties, Texas. We paid approximately $3.5 million for these properties. On December 21, 1998, we acquired properties from Colony Petroleum, L.L.C. and Cumulus 2 Limited in Carter County, Oklahoma, for a purchase price of approximately $706,000. The completion of these and other smaller acquisitions during 1998 added 1,642 Mboe to our proved reserves.
We Succeeded in Raising Capital
On July 16, 1998, we commenced a rights offering to our existing shareholders. Each shareholder received ten rights for each share of our common stock held. Each right entitled the shareholder to purchase one share of our common stock for $6.00 per share. The rights offering expired August 12, 1998. We received net proceeds of $35.2 million from the rights offering. We have used and intend to use the remaining proceeds of the rights offering for acquisitions, development drilling and recompletions, the repayment of our bank indebtedness, working capital and general corporate purposes.
We Moved to the Nasdaq National Market System
On September 16, 1998, trading of our common stock moved from the OTC Bulletin Board to the Nasdaq National Market System. Our trading symbol remained "EXCO".
We Formed an Acquisition Joint Venture
On October 9, 1998, we formed, EXCO Energy Investors, L.L.C., a $50 million joint venture with OCM Principal Opportunities Fund, L.P. to acquire oil and natural gas related assets and securities. Under the terms of the joint venture agreement, we are required to contribute 5% of any capital expenditures. As of February 15, 1999, the joint venture has invested in various debt securities in National Energy Group, Inc. Through February 15, 1999, our investment in the joint venture has been approximately $341,000.
- 2 -
We Acquired a Promissory Note That Will Consummate with an Acquisition
On November 2, 1998, we acquired a $13 million promissory note from a Texas bank for $6.4 million which is secured by substantially all of the assets of Rio Grande, Inc., its subsidiaries and affiliated entities. Rio Grande, Inc. is an oil and natural gas producer with principal operations in Texas, Oklahoma, Louisiana, and Mississippi. At the same time we purchased the note, we also entered into an agreement with Rio Grande, Inc. and Rio Grande, Inc.'s sole holder of preferred stock regarding plans for the ultimate satisfaction of Rio Grande, Inc.'s debt, including the proposed acquisition of Rio Grande, Inc. or its assets by us through a plan of reorganization in bankruptcy court.
On November 12, 1998, Rio Grande, Inc. announced that it had filed for reorganization under Chapter 11 of the Bankruptcy Code. As the largest secured creditor, we negotiated a plan for financial restructuring with Rio Grande, Inc. and the holder of its preferred stock. On March 5, 1999, the court confirmed the proposed plan. Pursuant to the terms of the plan, Rio Grande, Inc. has fully repaid its trade creditors. The plan provides for the merger of several subsidiaries or affiliates into Rio Grande, Inc. After the mergers, the outstanding shares of Rio Grande, Inc.'s common and preferred stock will be canceled. We will be issued new shares of Rio Grande, Inc. as settlement of Rio Grande Inc's $13 million secured indebtedness owed to us. The new shares will represent all of the outstanding capital stock of Rio Grande, Inc., and we will be the owners of Rio Grande, Inc. effective on or about March 16, 1999.
We Expanded the Board of Directors
On August 18, 1998, we expanded our board of directors from seven to nine members, and two new board members were elected to fill the newly created board positions in conjunction with our rights offering. The new members of the board of directors are Jeff M. Moore, a representative of Ares Management, L.P. and Jeffrey D. Benjamin, a representative of Oaktree Capital Management, L.L.C.
INVESTMENT CONSIDERATIONS AND RISK FACTORS
Forward-Looking Statements
Before you invest in our common stock, you should be aware that there are various risks associated with an investment, including the risks described below and risks that we have highlighted in other sections of this annual report. You should consider carefully these risk factors together with all of the other information included in this annual report before you decide to purchase shares of our common stock.
Some of the information in this annual report may contain forward-looking statements. We use words such as "may," "will," "expect," "anticipate," "estimate," "believe," "continue," "intend" or other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they: (1) discuss future expectations; (2) contain projections of results of operations or of our financial conditions; or (3) state other "forward-looking" information. We believe that it is important to communicate our future expectations to our investors. However, there may be events in the future that we are unable to accurately predict or over which we have no control. When considering our forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this annual report. The risk factors noted in this section and other factors noted throughout this annual report, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement.
Our Revenue Depends On Oil and Natural Gas Prices Which Are Currently Low
Our future financial condition and results of operations depend upon (1) the prices we receive for our oil and natural gas and (2) the costs of acquiring, developing and producing oil and natural gas. Currently, U.S. oil and natural gas prices are depressed. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are also beyond our control. Factors that affect the prices we receive for our oil and natural gas include, without limitation:
o the level of domestic production; o the availability of imported oil and natural gas; o actions taken by foreign oil and natural gas producing nations;
- 3 -
o the availability of transportation systems with adequate capacity; o the availability of competitive fuels; o fluctuating and seasonal demand for natural gas; o conservation and the extent of governmental regulation of production; o weather; o foreign and domestic government relations; o the price of domestic and imported oil and natural gas; and o the overall economic environment.
A substantial or extended decline in oil and/or natural gas prices may have a material adverse effect on the estimated value of our natural gas and oil reserves, and on our financial position, results of operations and access to capital. Our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms is substantially dependent upon oil and natural gas prices.
Our Production Comes From a Small Number of Wells
Our existing proved oil and natural gas reserves and production are highly concentrated in a small number of wells. Accordingly, to the extent that we experience any operating difficulties with the wells, or to the extent our actual proved reserves are less than those currently estimated to exist, we may experience increased expenses and lower revenue.
We Have Incurred Losses in the Past
We had net losses of $326,000, $205,000 and $511,000 for the years ended December 31, 1996, 1997, and 1998, respectively. We may continue to incur net losses and these losses may be substantial. Consequently, our liquidity may be reduced and we may be unable to raise capital. If our ability to raise capital is impaired, then we may be unable to implement our current business strategy.
We May Be Unable to Develop Additional Reserves
Our future success as an oil and natural gas producer, as is generally the case in the industry, depends upon our ability to find, develop and acquire additional oil and natural gas reserves that are profitable. If we are unable to conduct successful development activities or acquire properties containing proved reserves, our proved reserves will generally decline as reserves are produced. We cannot assure you that we will be able to locate additional reserves or that we will drill economically productive wells or acquire properties containing proved reserves.
We May Not Identify All Acquisition Risks
Generally, it is not feasible for us to review in detail every individual property involved in an acquisition. Our business strategy includes focused acquisitions of producing oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other similar factors. Ordinarily, our review efforts are focused on the higher-valued properties. However, even a detailed review of these properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect every well. Potential problems, such as mechanical integrity of equipment and environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we do inspect a well. Even if we identify problems, the seller may be unwilling or unable to provide effective contractual protection against all or part of these problems. We cannot assure you that newly acquired oil and natural gas properties will be successfully integrated into our operations or will achieve desired profitability.
We May Incur Significant Debt in the Future Which We May Be Unable to Repay
We have arranged a $150 million credit agreement with NationsBank, N.A., as agent and lender. The pledge of substantially all of our assets as collateral for the credit facility will make it difficult in the foreseeable future for us to obtain financing on an unsecured basis or to obtain secured financing other than certain "purchase money" indebtedness collateralized by the acquired assets. Our credit limit may provide
- 4 -
an additional source of capital to finance our acquisition, development and exploitation strategy. Our level of indebtedness in the future may affect our operations in the following ways:
o a substantial portion of our cash flow from operations may be dedicated to the payment of interest and principal on our indebtedness and will not be available for other purposes;
o the covenants contained in the credit facility which require us to meet certain financial tests and other restrictions, will limit our ability to borrow additional funds, to grant liens and to dispose of assets and will affect our flexibility in planning for and reacting to changes in our business, including possible acquisition activities; and
o our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired.
Our ability to meet any future debt service obligations will be dependent upon our future economic performance. Our future bank credit may not be available in an amount sufficient to enable us to service our indebtedness or make necessary expenditures. In that event, we would be required to obtain financing from the sale of equity securities or other debt financing. Financing may be unavailable on terms acceptable to us. Without sufficient capital, we may be unable to continue to implement our business strategy.
We May Need Additional Financing for Growth
The growth of our business will require substantial capital on a continuing basis. We may be unable to obtain additional capital on satisfactory terms and conditions. Thus, we may lose opportunities to acquire oil and natural gas properties and businesses. In addition, our pursuit of additional capital may result in the incurrence of additional indebtedness or potentially dilutive issuances of additional equity securities. We also may utilize the capital currently expected to be available for our present operations. The amount and timing of our future capital requirements, if any, will depend upon a number of factors, including:
o drilling costs; o transportation costs; o equipment costs; o marketing expenses; o staffing levels and competitive conditions; and o any purchases or dispositions of assets.
Our failure to obtain any required additional financing may have a material adverse effect on our growth, cash flow and earnings.
We Will Encounter Risks While Drilling
Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to identify and acquire properties and to drill and complete wells. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. In addition, we may use 3-dimensional seismic and other advanced technology to explore for oil and natural gas which may require greater pre-drilling expenditures than traditional drilling strategies. We may be unsuccessful in our future drilling activities.
- 5 -
Uncertainty of Our Estimates of Oil and Natural Gas Reserves
Numerous uncertainties are inherent in estimating quantities of proved oil and natural gas reserves, including many factors beyond our control. This annual report contains an estimate of our proved oil and natural gas reserves and the estimated future net cash flows and revenue generated by the proved oil and natural gas reserves. These estimates are based upon reports of our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the Securities and Exchange Commission, as to constant oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These reports should not be construed as the current market value of our estimated proved reserves. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. As a result, these estimates are inherently an imprecise evaluation of reserve quantities and future net revenue. Our actual future production, revenue, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we have assumed in the estimate. Any significant variance in our assumptions could materially affect the estimated quantity and value of reserves set forth in this annual report. In addition, our reserves may be subject to downward or upward revision, based upon production history, results of future exploitation and development, prevailing oil and natural gas prices and other factors.
Our Properties are Geographically Concentrated
Currently, most of our properties are located in Texas, Oklahoma, and Louisiana. Because of this concentration, we will be impacted more adversely by regional events that increase our costs or level of competition, reduce availability of equipment or supplies, reduce demand or limit production, than if we were geographically diversified.
We Are Exposed to Operating Hazards and Uninsured Risks
Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:
o fire, explosions, and blowouts; o pipe failure; o abnormally pressured formations; and o environmental accidents such as oil spills, gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).
These events may result in substantial losses to the Company from:
o injury or loss of life; o severe damage to or destruction of property, natural resources and equipment; o pollution or other environmental damage; o clean-up responsibilities; o regulatory investigation; and o penalties and suspension of operations.
In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks we have described above. We cannot assure you that our insurance will be adequate to cover these losses or liabilities. Further, we cannot predict the continued availability of insurance, or availability of insurance at commercially acceptable premium levels. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events may have a material adverse effect on our financial condition and operations.
From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which we own an interest have been subject to reduced or terminated production. These curtailments may last from a few days to several months or longer.
- 6 -
We are not currently experiencing any material curtailment on our production.
We May Writedown Our Asset Values
We may writedown the value of our oil and natural gas properties. This may affect the Company's net worth which may result in a covenant violation under our credit facility.
Our Stock Price May Be Volatile Due to Small Public Float
Because the number of shares of our common stock held by the public is relatively small, the sale of a substantial number of shares of the common stock in a short period of time may adversely affect the market price of the common stock.
We Do Not Pay Dividends
We have never paid cash dividends on our common stock and do not anticipate paying cash dividends on our common stock in the foreseeable future. Our common stock is not a suitable investment for persons requiring current income.
Our Articles of Incorporation or a Possible Issuance of Preferred Stock May Prevent a Takeover Attempt
Provisions in our restated articles of incorporation effective September 11, 1996 may delay, defer or prevent a tender offer or takeover attempt that a shareholder might consider to be in such shareholder's best interest, including attempts that might result in a premium to be paid over the market price for the stock held by shareholders. The articles of incorporation permit the board to issue up to 10,000,000 shares of preferred stock and to establish by resolution one or more series of preferred stock and to establish the powers, designations, preferences and relative, participating, optional or other special rights of each series of preferred stock. The preferred stock may be issued on terms that are unfavorable to the holders of common stock, including the grant of superior voting rights, the grant of preferences in favor of preferred shareholders in the payment of dividends and upon liquidation of the Company and the designation of conversion rights that entitle holders of preferred stock to convert their shares into common stock on terms that are dilutive. The issuance of preferred stock may make a takeover or change in control of the Company more difficult. We do not intend to use the provisions of the articles of incorporation to delay, defer or prevent a tender offer or takeover attempt.
Our Business Depends on a Limited Number of Key Personnel
We are substantially dependent upon the skills of two key individuals within our management, Mr. D. H. Miller and Mr. Eubank. Both individuals have experience in restructuring oil and natural gas companies. Because we are engaged in a new strategy, the loss of the services of either one of these individuals may have a material adverse impact upon us.
We May Encounter Marketing Risks
Our future ability to market our oil and natural gas production will depend upon the availability and capacity of natural gas gathering systems and pipelines and other transportation facilities. We do not currently operate our own pipelines or transportation facilities, thus we are dependent on third parties to transport our products.
- 7 -
BUSINESS STRATEGY
We intend to become a leading independent oil and natural gas acquisition, exploitation and production company by implementing the following business strategies:
o Financial Growth. We plan to achieve asset, revenue and cash flow growth as a result of the acquisition and further development of producing oil and natural gas properties.
o Acquire and Enhance Producing Oil and Natural Gas Properties. We plan to take advantage of opportunities that currently exist in the United States to acquire producing oil and natural gas properties. We plan to continue to focus our acquisition activities onshore in Texas, New Mexico, Oklahoma and Louisiana in order to complement our existing properties and operations; however, we plan to review potential acquisitions in other regions of the United States if they represent a significant concentration of energy-related assets. We believe that numerous opportunities exist to acquire additional energy assets and to enhance the value of these assets through improved operating practices and by aggressively developing reserve potential.
o Emphasize Exploitation and Development Activities. We plan to exploit existing oil and natural gas properties and to conduct development evaluation and drilling on our existing and future oil and natural gas properties. We intend to concentrate on enhancement opportunities from activities such as infill drilling, recompletions, secondary recovery projects, repairs and equipment changes. We may participate, from time to time, in a limited number of exploratory wells.
o Corporate Efficiencies. We plan to maximize corporate efficiencies through the development and operation of a larger asset base with the potential to limit increases in overhead in the future.
o Capital Management. We plan to maintain financial strength and flexibility through effective management of debt and equity.
o Technology. We plan to increase exploitation efforts, focusing on established geological trends where we can employ geological, geophysical and engineering expertise. We are considering the application of 3-D seismic and advanced drilling technologies.
In 1998, we evaluated approximately 120 acquisition opportunities with an aggregate estimated market value of over $1.9 billion. We made offers on properties totaling more than $320 million and successfully completed the purchase of approximately $6.8 million. Offers varied in amounts from less than $100,000 to $92 million. We intend to pursue large acquisitions that will have a significant impact on our growth and smaller projects that have the potential for high levels of profitability. We plan to focus on properties in Texas, Oklahoma, Louisiana, and New Mexico and prefer to acquire properties with shallow production, which offer lower geologic and mechanical risk of operations. In evaluating prospective acquisitions, we generally focus on estimates of future cash flows, rates of return, and net present values expected to be generated by the acquired properties.
RECENT DEVELOPMENTS SINCE DECEMBER 31, 1998
We Canceled the Merger with Gladstone
On May 1, 1998, the Company entered into an agreement and plan of merger with Gladstone Resources, Inc. Under terms of the merger agreement, Gladstone stockholders would have received approximately $1.4 million, or $.33 per share, in cash. The transaction was subject to customary conditions of closing including review by the Securities and Exchange Commission of Gladstone's proxy materials, approval by
- 8 -
Gladstone's board of directors and stockholders, approval by our board of directors and the completion of our due diligence inspection.
In addition to the merger agreement, on May 1, 1998, we entered into a stock option agreement with one Gladstone stockholder, E. B. Brooks, Jr., to acquire 1,910,000 shares, or approximately 44.8%, of Gladstone's issued and outstanding common stock at a price of $.33 per share. On May 1, 1998, we also entered into a stockholder agreement whereby three Gladstone stockholders, Deborah Brooks Garrett, Rebecca B. Feldt and Carol Brady, agreed to vote their shares in favor of the merger. These stockholders owned 351,000 shares or approximately 8.3% each of Gladstone's common stock.
After the date of the merger agreement and the stock option agreement, the financial and oil and natural gas assets of Gladstone materially decreased. As a result, on January 22, 1999 the merger agreement and stock option agreements were canceled.
We Presented A Proposal To Acquire National Energy Group, Inc.
On February 24, 1999, we presented a restructuring plan to National Energy Group, Inc.'s bondholders' committee. For the assets of National Energy, we propose to issue shares of our common stock and approximately $58 million cash. Our plan is subject to approval by numerous parties including the U. S. Bankruptcy Court and our shareholders.
OUR EXPLOITATION AND DEVELOPMENT ACTIVITIES
We made exploitation and development expenditures of $17,000, $74,000, and $257,000 during the years ended December 31, 1996, 1997, and 1998, respectively. We made net acquisition expenditures of $1,000, $2,000, and $6.8 million during the years ended December 31, 1996, 1997, and 1998, respectively. Our ability to continue to fund our exploitation and development activities depends upon cash flow and our ability to secure the necessary financing for these activities.
OUR OPERATING ACTIVITIES
As of December 31, 1998, we were the operator of 76 gross (36.5 net) wells, which represented approximately 65.5% of the gross wells and 69.5% of the net wells in which we had an interest on that date. The remainder of the wells in which we had an interest on December 31, 1998 are operated by third party operators. The wells that we operate are located in Texas and Louisiana. Although we elect to operate and manage most of our properties and drilling activities, our wells are drilled by independent drilling contractors.
OUR OIL AND NATURAL GAS PROPERTIES
The following table sets forth the fields in which we have significant oil and natural gas properties, and information as of December 31, 1998, with respect to each of the fields.
- 9 -
Ackerly Field
The Ackerly field is located in Dawson County, Texas. In 1998, we acquired 8 gross (3.99 net) producing wells as the principal properties in the Dawson County acquisition. These wells produce primarily oil from the Canyon Reef and Dean formations at depths between 8,100 and 9,300 feet.
Chittim Field
The Chittim field is located in Maverick County, Texas. In 1998, we acquired our interests in this field when we purchased the Chittim/Barclay Ranch properties. Our wells produce natural gas from the Glen Rose Formation at depths between 5,000 and 5,700 feet.
Logansport Field
We own working interests in two natural gas wells in the Logansport field located in Desoto Parish, Louisiana. Our wells produce from a series of low permeability reservoirs with long life natural gas reserves. Our reserves are produced from the Hosston (Travis Peak) and Pettit formations from depths between 6,000 and 7,500 feet.
Nine Mile Draw Field
The Nine Mile Draw field is located in Reeves County, Texas, and we derive natural gas production from a low permeability fractured limestone formation. Presently, we operate 1 gross (.62 net) well in the Fusselman formation, which produces from depths between 13,700 and 14,400 feet.
Other
The other category consists of numerous unconcentrated fields located in Texas, Oklahoma, Kansas and North Dakota.
TITLE TO OUR PROPERTIES
As is common industry practice, we conduct little or no investigation of title at the time we acquire undeveloped properties, other than a preliminary review of local mineral records. However, we do conduct title investigations and, in most cases, obtain a title opinion of local counsel before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire good title to properties. Some title risks, however, cannot be avoided, despite the use of customary industry practices.
Our properties are generally subject to:
o customary royalty and overriding royalty interests; o liens incident to operating agreements; and o liens for current taxes and other burdens and minor encumbrances, easements and restrictions.
We believe that none of these burdens either materially detract from the value of our properties or materially interfere with their use in the operation of our business. Substantially all of our properties are pledged as collateral under our credit facility.
OUR OIL AND NATURAL GAS RESERVES
On December 31, 1998, our oil and natural gas reserves included direct working interests in 116 wells in the states of Texas, Louisiana, North Dakota, Kansas, and Oklahoma, as well as overriding royalties in an additional 10 wells in Texas. We have no reserves offshore or outside of the United States. On December 31, 1998, approximately 87.7% of the present value of the estimated future net revenues attributable
- 10 -
to our properties were attributable to proved developed reserves and approximately 12.3% were attributable to proved undeveloped reserves. In addition, approximately 42.8% of the proved reserves were attributable to oil and approximately 57.2% were attributable to natural gas, on a Boe basis.
The following table summarizes our proved reserves on December 31, 1998, and was prepared in accordance with the rules and regulations of the Securities and Exchange Commission:
PROVED RESERVES On December 31, 1998
A significant portion of the value of our proved undeveloped reserves are in the Logansport and the Nine Mile Draw fields. We must incur costs and undertake risks associated with drilling and workover operations to recover these reserves.
The reserve estimates presented as of December 31, 1998 have been prepared by Lee Keeling and Associates, Inc., independent petroleum engineers, Tulsa, Oklahoma, and are a part of their report on our oil and natural gas properties. Estimates of oil and natural gas reserves are, of necessity, projections based on engineering data and, thus, are forward-looking in nature. Moreover, because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves set forth herein will ultimately be realized. Our actual results could differ materially. See "Supplementary Financial Data" included with our financial statements located elsewhere in this annual report for additional information regarding our oil and natural gas reserves, including the present value of future net revenues. Lee Keeling and Associates, Inc. also prepared our reserve estimates as of December 31, 1996, and December 31, 1997.
WE HAVE NOT REPORTED RESERVES TO OTHER AGENCIES
As of December 31, 1998 our estimates of oil and natural gas reserves have not been filed with or included in reports to any federal authority or agency other than the Securities and Exchange Commission.
- 11 -
OUR PRODUCTION
The following table summarizes for the periods indicated, our revenues, net production of oil (including condensate) and natural gas sold, the average sales price per unit of oil (Bbl) and natural gas (Mcf) and costs and expenses associated with the production of oil and natural gas:
Our total oil and natural gas revenues for the year ended December 31, 1998 increased 107% from the prior year primarily due to increases in production volumes resulting from acquisitions we completed during 1998. The effect of these increased volumes outweighed the decreased sales prices for both oil and natural gas. Our average sales price per barrel of oil decreased $7.55 or 39%, and our average sales price per Mcf of natural gas decreased $.32, or 15%, from prices for the year ended December 31, 1997.
Our total oil and natural gas revenues for the year ended December 31, 1997 decreased 23% from the period ended December 31, 1996 due to decreases in our production volumes resulting from the sale of properties during 1997 and the normal depletion of our producing wells. Our average sales price per barrel of oil decreased $.86, or 4% and our average sales price per Mcf of natural gas increased $.27, or 14%, from our prices for the period ended December 31, 1996.
The net production we reported in the preceding table only includes revenue, production, production costs, and sales prices for our share of the oil and natural gas after payment of royalties, if any. Our oil production for the year ended December 31, 1998 was 265% higher and our natural gas production was 128% higher than for the year ended December 31, 1997. Our oil production for the year ended December 31, 1997 was 35% lower and natural gas production was 19% lower than the period ended December 31, 1996. On a Boe basis, our total production for the year ended December 31, 1998 increased 172% from the year ended December 31, 1997 and our total production for the year ended December 31, 1997 decreased 25% from the period ended December 31, 1996.
- 12 -
OUR INTEREST IN PRODUCTIVE WELLS
The following table sets forth our interest in productive wells (producing wells and wells capable of production) on December 31, 1998. The number of total gross oil and natural gas wells excludes any multiple completions. On December 31, 1998, we did not own an interest in any well that was being completed.
OUR DRILLING ACTIVITIES
We intend to concentrate on lower risk, development-type properties by drilling to reservoirs from which production is, or was, being obtained. In the past, we have drilled higher risk, exploratory-type wells. The number and type of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well and the estimated recoverable reserves attributable to each well.
The following table summarizes our approximate gross and net interests in the exploratory and development wells drilled during the periods indicated and refers to the number of wells (holes) completed at any time during a period, regardless of when drilling was initiated:
We conducted all drilling activities referenced in the above tables in the State of Texas. As of February 23, 1999, we were participating in drilling one exploratory well. This 5,542 foot Glen Rose test in Maverick County, Texas was dry in the primary objective. The cost to the Company was approximately $120,000. At this time, we have no additional commitments to drill any wells.
- 13 -
OUR INTEREST IN DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth our interest in developed and undeveloped acreage on December 31, 1998:
The primary terms of the oil and natural gas leases covering the majority of our undeveloped acreage expire at various dates, generally ranging from one to five years. We can retain our interest in undeveloped acreage by drilling activity that establishes commercial reserves sufficient to maintain the lease. Some of our undeveloped acreage in Texas is being "held by production," meaning our lease is active as long as we produce oil and natural gas from the acreage. Upon ceasing production, the lease will expire.
OUR PAST SALES OF PRODUCING PROPERTIES AND UNDERDEVELOPED ACREAGE
We evaluate properties on an ongoing basis to determine the economic viability of the properties and whether these properties enhance objectives. During the course of normal business, we may dispose of producing properties and undeveloped acreage if we believe that it is in our best interest.
In the year ended December 31, 1998, we had no material sales of producing properties. In the year ended December 31, 1997, we sold our interest in three major groups of producing oil properties in Texas and Illinois for a total of $270,000 which reduced the full cost pool accordingly. In the year ended December 31, 1996, we exchanged our interest in four non-operated producing wells for an interest in each of four operated producing wells.
OUR PRODUCTS, MARKETS AND REVENUES
We produce oil and natural gas. We do not refine or process the oil and natural gas that we produce. We sell the oil we produce under short-term contracts at market prices in the areas in which the producing properties are located, generally at F.O.B. field prices posted by the principal purchaser of oil in these areas.
We sell the natural gas we produce under both short-term and long-term contracts. We sell the natural gas to transmission and utility companies that have pipelines in the vicinity of our producing properties or to companies that will construct pipelines to our properties. Our sales contracts are of a type common within the industry, and we negotiate a separate contract for each property. Typically, we negotiate sales contracts for terms ranging from day-to-day up to six months.
The availability of a ready market for oil and natural gas and the prices of oil and natural gas are dependent upon a number of factors that are beyond our control. These factors include, among other things:
o the level of domestic production and economic activity generally;
o the availability of imported oil and natural gas, actions taken by foreign oil producing nations;
o the availability of natural gas pipelines with adequate capacity and other transportation facilities;
o the availability and marketing of other competitive fuels, fluctuating and seasonal demand for oil, natural gas and refined products; and
- 14 -
o the extent of governmental regulation and taxation (under both present and future legislation) of the production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels.
Accordingly, in view of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot predict accurately the prices or marketability of the oil and natural gas from any producing well in which we have or may acquire an interest.
Oil prices have been subject to significant fluctuations over the past several decades. Levels of production maintained by the Organization of Petroleum Exporting Countries member nations and other major oil producing countries are expected to continue to be a major determinant of oil price movements in the future. As a result, future oil price movements cannot be predicted with any certainty. Similarly, during the past several years, the U.S. market price for natural gas has been subject to significant fluctuations on a monthly basis as well as from year to year. These frequent changes in the market price make it impossible for us to predict natural gas price movements with any certainty.
We cannot assure you that we will be able to market all the oil or natural gas that we produce or, if our oil or natural gas can be marketed, that we can negotiate favorable price and contractual terms. Changes in oil and natural gas prices may significantly affect our revenues and cash flow and the value of our oil and natural gas properties. Further, significant declines in the prices of oil and natural gas may have a material adverse effect on our business and financial condition.
We engage in oil and natural gas production activities in areas, where from time to time the supply of oil and natural gas available for delivery exceeds the demand. In this situation, companies purchasing oil and natural gas in these areas reduce the amount of oil and natural gas that they will purchase or "take." If we cannot locate buyers for newly discovered oil and natural gas reserves, we may shut-in newly completed oil and natural gas wells for periods of time. As a result, the over-supply of oil and natural gas in certain areas may cause us to experience "take" problems or may adversely affect our ability to obtain contracts to market oil and natural gas discovered in wells in which we own an interest.
The following table sets forth the amount of our oil sales, natural gas sales and the percent of sales to total oil and natural gas revenues for the periods indicated:
OUR CURRENT DELIVERY COMMITMENTS
We are not presently obligated to provide a fixed and determinable quantity of oil or natural gas under any existing contract or agreement.
OUR PRINCIPAL CUSTOMERS
During the year ended December 31, 1998, sales of oil and natural gas to two purchasers, EOTT Energy Operating Limited Partnership and Scurlock Permian LLC accounted for 17% and 10%, respectively, of our total revenues. During the year ended December 31, 1997, sales of oil and natural gas to three purchasers, Scurlock Permian Corporation, Delhi Gas Pipeline Corporation, and Aurora National Gas, L.L.C., accounted for 22%, 19%, and 14%, respectively, of our total revenues. If we were to lose any one of our oil and natural gas purchasers, then the loss could temporarily cease or delay our production and sale of our oil and natural gas in the purchaser's particular service area. We believe we would be able, under current economic circumstances, to
- 15 -
contract with other purchasers for our oil and natural gas production if we were to lose any one of our oil and natural gas purchasers.
WE ENCOUNTER STRONG COMPETITION
The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, in contracting for drilling equipment and in securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than those available to us. As a result, our competitors may be able to pay more for desirable leases and they may pay more to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit us.
We are also affected by competition for drilling rigs and the availability of related equipment. While the oil and natural gas industry has experienced shortages of drilling rigs and equipment, pipe and personnel, we are not presently experiencing any shortages and do not foresee any shortages in the near future. We are unable to predict how long current market conditions will continue.
Competition for attractive oil and natural gas producing properties, undeveloped leases and drilling rights is also strong, and we cannot assure you that we will be able to compete satisfactorily in acquiring properties. Many major oil companies have publicly indicated their decisions to concentrate on overseas activities and have been actively marketing some of their existing producing properties for sale to independent producers. We cannot assure you that we will be successful in acquiring any of these properties.
WE ARE AFFECTED BY VARIOUS REGULATION
General
From time to time political developments and federal and state laws and regulations affect our operations in varying degrees. Price control, tax and other laws relating to the oil and natural gas industry, and changes in these laws and regulations affect our oil and natural gas production, operations and economics. There are currently no price controls on oil, condensate or natural gas liquids. To the extent price controls remain applicable after the enactment of the Natural Gas Wellhead Decontrol Act of 1989, we are of the opinion that price controls will not have a significant impact on the prices we receive for natural gas we produce in the near future.
We review legislation affecting the oil and natural gas industry for amendments. The legislative review frequently increases our regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the oil and natural gas industry and its individual members, compliance with which is often difficult and costly and some of which may carry substantial penalties if we were to fail to comply. We cannot predict how existing regulations may be interpreted by enforcement agencies or the courts, nor whether amendments or additional regulations will be adopted, nor what effect such interpretations and changes may have on our business or financial condition.
Matters subject to regulation include:
o discharge permits for drilling operations; o drilling and abandonment bonds or other financial responsibility requirements; o reports concerning operations; o the spacing of wells; o unitization and pooling of properties; and o taxation.
Natural Gas Regulation and the Effect on Marketing
Historically, interstate pipeline companies generally acted as wholesale merchants by purchasing natural gas from producers and reselling the natural gas to local distribution companies and large end users. Commencing in late 1985, the Federal Energy Regulatory Commission issued a series of orders that have had a
- 16 -
major impact on interstate natural gas pipeline operations, services, and rates, and thus have significantly altered the marketing and price of natural gas. The FERC's key rule making action, Order No. 636, issued in April 1992, required each interstate pipeline to, among other things, "unbundle" its traditional bundled sales services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and standby sales and natural gas balancing services), and to adopt a new rate making methodology to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate makes natural gas sales as a merchant in the future, it does so pursuant to private contracts in direct competition with all other sellers, such as the Company; however, pipeline companies and their affiliates were not required to remain "merchants" of natural gas, and most of the interstate pipeline companies have become "transporters only." In subsequent orders, the FERC largely affirmed the major features of Order 636 and denied a stay of the implementation of the new rules pending judicial review. By the end of 1994, the FERC had concluded the Order 636 restructuring proceedings, and, in general, accepted rate filings implementing Order 636 on every major interstate pipeline. However, even through the implementation of Order 636 on individual interstate pipelines is essentially complete, many of the individual pipeline restructuring proceedings, as well as Order 636 itself and the regulations promulgated thereunder, are subject to pending appellate review and could possibly be changed as a result of future court orders. We cannot predict for you whether the FERC's orders will be affirmed on appeal or what the effects will be on our business.
In recent years the FERC also has pursued a number of other important policy initiatives which could significantly affect the marketing of natural gas. Some of the more notable of these regulatory initiatives include:
o a series of orders in individual pipeline proceedings articulating a policy of generally approving the voluntary divestiture of interstate pipeline owned gathering facilities by interstate pipelines to their affiliates (the so-called "spin down" of previously regulated gathering facilities to the pipeline's nonregulated affiliate);
o the completion of a rule making involving the regulation of pipelines with marketing affiliates under Order No. 497;
o the FERC's ongoing efforts to promulgate standards for pipeline electronic bulletin boards and electronic data exchange;
o a generic inquiry into the pricing of interstate pipeline capacity;
o efforts to refine the FERC's regulations controlling operation of the secondary market for released pipeline capacity; and
o a policy statement regarding market based rates and other non-cost-based rates for interstate pipeline transmission and storage capacity.
Several of these initiatives are intended to enhance competition in natural gas markets, although some, such as "spin downs," may have the adverse effect of increasing the cost of doing business to some in the industry as a result of the monopolization of those facilities by their new, unregulated owners. The FERC has attempted to address some of these concerns in its orders authorizing such "spin downs," but it remains to be seen what effect these activities will have on access to markets and the cost of doing business. As to all of these recent FERC initiatives, the ongoing, or in some instances, preliminary nature of these regulatory initiatives makes it impossible at this time for us to predict their ultimate impact on our business.
We own, directly or indirectly, certain natural gas facilities that we believe meet the traditional tests the FERC has used to establish a company's status as a gatherer not subject to FERC jurisdiction under the Natural Gas Act of 1938. Moreover, recent orders of the FERC have been more liberal in their reliance upon or use of the traditional tests, such that in many instances, what was once classified as "transmission" may now be classified as "gathering." We transport our own natural gas through these facilities. We also transport a portion of our natural gas through gathering facilities owned by others, including interstate pipelines. With respect to the preceding paragraph, on May 27, 1994, the FERC issued orders in the context of the "spin off" or "spin down" of interstate pipeline owned gathering facilities. A "spin off" is a FERC approved sale of such facilities to a
- 17 -
non-affiliate. A "spin down" is the transfer by the interstate pipeline of its gathering facilities to an affiliate. A number of "spin offs" and "spin downs" have been approved by the FERC and have been implemented. The FERC held that it retains jurisdiction over gathering provided by interstate pipelines, but that it generally does not have jurisdiction over pipeline gathering affiliates, except in the event of affiliate abuse (such as actions by the affiliate undermining open and nondiscriminatory access to the interstate pipeline). These orders require nondiscriminatory access for all sources of supply, prohibit the tying of pipeline transportation service to any service provided by the pipeline's gathering affiliate, and require the new gathering company to submit a "default" contract if a satisfactory contract cannot be mutually agreed upon by the interstate pipeline and its existing customers. On November 30, 1994, the FERC issued a series of rehearing orders largely affirming the May 27, 1994, orders. The FERC clarified that "default" contracts are intended to serve only as a transition mechanism to prevent arbitrary termination of gathering service to existing customers. Also, the FERC now requires interstate pipelines to not only seek authority under Section 7(b) of the Natural Gas Act to abandon certificated facilities, but also to seek authority under Section 4 of the Natural Gas Act to terminate service from both certificated and uncertificated facilities. On December 31, 1994, an appeal was filed with the U.S. Court of Appeals for the D.C. Circuit to overturn three of the FERC's November 30, 1994, orders. We cannot predict what the ultimate effect of the FERC's orders pertaining to gathering will have on our production and marketing, or whether the Appellate Court will affirm the FERC's orders on these matters.
Federal Taxation
The federal government may propose tax initiatives that affect us. We are unable to determine what effect, if any, future proposals would have on product demand or our results of operations.
State Regulation
The various states in which we conduct activities regulate our drilling, operation and production of oil and natural gas wells, including the method of developing new fields, spacing of wells, the prevention and clean-up of pollution, and maximum daily production allowables based on market demand and conservation considerations.
Environmental Regulation
Our exploration, development and production of oil and natural gas, including our operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic activities are subject to a variety of environmental laws and regulations, including, but not limited to:
o the Oil Pollution Act of 1990; o the Clean Water Act; o the Comprehensive Environmental Response, Compensation and Liability Act; o the Resource Conservation and Recovery Act; o the Clean Air Act; and o the Safe Drinking Water Act,
as well as state regulations promulgated under comparable state statutes. These laws and regulations:
o require the acquisition of a permit before drilling commences;
o restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
o limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
- 18 -
o impose substantial liabilities for pollution which might result from our operations.
We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain activities, limit or prohibit other activities because of protected areas or species and impose substantial liabilities for cleanup of pollution.
Under the Oil Pollution Act, a release of oil into water or other areas designated by the statute could result in the Company being held responsible for the costs of remediating a release, specified damages and natural resource damages. The extent of that liability could be extensive, as set forth in the statute, depending on the nature of the release. A release of oil in harmful quantities or other materials into water or other specified areas could also result in the Company being held responsible under the Clear Water Act for the cost of remediation, and civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws, can impose joint, several and retroactive liability, without regard to fault or the legality of the original conduct, on certain classes of persons for the release of a "hazardous substance" into the environment. In practice, cleanup costs are usually allocated among various responsible parties. Potentially liable parties include site owners or operators, past owners or operators under certain conditions and entities that arrange for the disposal or treatment of, or transport of hazardous substances found at the site. Although CERCLA, as amended, currently exempts petroleum, including, but not limited to, crude oil, gas and natural gas liquids from the definition of hazardous substance, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA. Furthermore, we cannot assure you that the exemption will be preserved in future amendments of the Act, if any.
RCRA and comparable state and local requirements impose standards for the management, including treatment, storage and disposal of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. From time to time, proposals have been made that would reclassify certain oil and natural gas wastes, including wastes generated during pipeline, drilling and production operations, as "hazardous wastes" under RCRA which would make these solid wastes subject to much more stringent handling, transportation, storage, disposal and clean-up requirements. This development could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes may have a similar impact on our operations.
Because oil and natural gas exploration and production, and possibly other activities, have been conducted at some of our properties by previous owners and operators, materials from these operations remain on some of the properties and in some instances require remediation. In addition, we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties. While we do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, we cannot guarantee that these potential costs will not result in material expenditures.
Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials occur, and we may incur costs for waste handling and environmental compliance associated with these leaks. Moreover, we are able to control directly the operations of only those wells which we operate. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may be, in certain circumstances, attributable to us.
It is not anticipated that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as these laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance. More stringent laws and regulations protecting the environment may be
- 19 -
adopted and we may be required to incur material expenses in connection with environmental laws and regulations in the future.
Other Proposed Legislation
The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain crude oil and natural gas exploitation and production wastes as "hazardous wastes" which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If this legislation were to be enacted, it may have a significant impact on our operating costs, as well as the oil and natural gas industry in general. Initiatives to further regulate the disposal of crude oil and natural gas wastes are also pending in various states, and these various initiatives may have a similar impact on us. We may incur substantial costs to comply with environmental laws and regulations. In addition to compliance costs, government entities and other third parties may assert substantial liabilities against owners and operators of oil and natural gas properties for oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, including damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not available or because of high premium costs. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premium costs or for other reasons. The imposition of any of these liabilities on us may have a material adverse effect on our financial condition and results of operations.
OUR EMPLOYEES
As of December 31, 1998, we employed nineteen persons of which two were involved in field operations and seventeen were engaged in office and administrative activities. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems and we consider our relations with our employees to be good. We also utilize the services of independent consultants on a contract basis.
OUR EXECUTIVE OFFICERS
DOUGLAS H. MILLER, 51, was elected Chairman and Chief Executive Officer of EXCO in December 1997. Mr. Miller was Chairman of the Board and Chief Executive Officer of Coda Energy, Inc., an independent oil and gas company, from October 1989 until November 1997 and served as a director of Coda from 1987 until November 1997.
T. W. EUBANK, 56, was elected President, Treasurer and a director of EXCO in December 1997. Mr. Eubank was a consultant to various private companies from February 1996 to December 1997. Mr. Eubank served as President of Coda from March 1985 until February 1996. He was a director of Coda from 1981 until February 1996.
J. DOUGLAS RAMSEY, PH.D., 38, was elected a Vice President and Chief Financial Officer of EXCO in December 1997. Dr. Ramsey has been a director of EXCO since March 1998. Dr. Ramsey most recently was Financial Planning Manager of Coda and has worked in various capacities for Coda from 1992 until 1997. Dr. Ramsey also teaches finance at Southern Methodist University.
CHARLES R. EVANS, 45, joined EXCO in February 1998 and became a Vice President in March 1998. Mr. Evans graduated from Oklahoma University with a B.S. degree in Petroleum Engineering in 1976. After working for Sun Oil Co., he joined TXO Production Corp. in 1979 and was elected Vice President of Engineering and Evaluation in 1989 and Vice President of Engineering and Project Development for Delhi Gas Pipeline Corporation, a natural gas gathering, processing and marketing company, in 1990. Mr. Evans most recently was Director-Environmental Affairs and Safety for Delhi until December 1997.
- 20 -
JOHN D. JACOBI, 44, became a Vice President of EXCO in February 1999. Mr. Jacobi received his B.S. degree from West Texas State University. He founded Jacobi-Johnson Energy, Inc., an independent oil and natural gas producer, in 1991 and was its President until January 1997. He then served as its Vice President and Treasurer until May 8, 1998, when the company was sold to EXCO.
DANIEL A. JOHNSON, 47, became a Vice President of EXCO in February 1999. Mr. Johnson graduated from Texas A&M University with a B.S. degree in Petroleum Engineering. In 1991, he founded Jacobi-Johnson Energy, Inc., an independent oil and natural gas producer. He served as its President from January 1997 until the company was sold to EXCO on May 8, 1998.
RICHARD E. MILLER, 44, became General Counsel and General Land Manager and was elected Secretary of EXCO in December 1997. Mr. Miller was a senior partner and head of the Energy Section of Gardere & Wynne, L.L.P., a Dallas based law firm, from December 1991 to September 1994. Mr. Miller practiced law as a sole practitioner from September 1994 to December 1997.
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and this annual report.
"BBL." One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
"BOE." Barrels oil equivalent. Calculated by converting 6 Mcf of natural gas to 1 Bbl of oil.
"INFILL DRILLING." Drilling of a well between known producing wells to better exploit the reservoir.
"MBOE." One thousand barrels oil equivalent.
"MCF." One thousand cubic feet of natural gas.
"OVERRIDING ROYALTY INTEREST." An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.
"PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES." The present value of estimated future net revenues is an estimate of future net revenues from a property at its acquisition date, at December 31, 1998, or as otherwise indicated, after deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating costs at the acquisition date, at December 31, 1998, or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not in accordance with generally accepted accounting principles, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions.
ITEM 2.
ITEM 2. PROPERTIES
GENERAL
We lease approximately 7,144 square feet of office space in Dallas, Texas, for our corporate offices. The lease expires December 31, 1999 and requires a monthly rental payment of approximately $8,232. We consider this space adequate for our present needs. We also have an office in Tyler, Texas.
- 21 -
OTHER
We have described our oil and natural gas properties, oil and gas reserves, acreage, wells, production and drilling activity in Item 1 beginning on page 1 of this annual report.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
During 1998, we were not a party to any material legal proceeding.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the last three months of the year ended December 31, 1998, we did not submit any matter to a vote by our shareholders through the solicitation of proxies or otherwise.
- 22 -
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
MARKET INFORMATION FOR OUR COMMON STOCK
Our common stock is currently quoted on the Nasdaq NMS under the symbol "EXCO", but there is limited trading in the common stock. The following table sets forth the high and low bid prices from January 1, 1997 through December 31, 1998, based upon quotations periodically published on the Nasdaq NMS. The price quotations below have been adjusted to estimate the effect of our one-for-two reverse stock split of the common stock in the case of quotations for periods prior to March 31, 1998, the effective date of the stock split. All price quotations represent prices between dealers, without retail mark-ups, mark-downs or commissions and may not represent actual transactions.
The bid price for our common stock was $6.50 on March 1, 1999.
OUR SHAREHOLDERS
According to the records of our transfer agent, there were 1,625 holders of record of our common stock on February 19, 1999 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders).
OUR DIVIDEND POLICY
We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit facility currently prohibits us from paying dividends. We anticipate that any income generated in the foreseeable future will be retained for the development and expansion of our business. Our future dividend policy is subject to the discretion of the board of directors and will depend upon a number of factors, including future earnings, debt service, capital requirements, restrictions in our credit facility, business conditions, our financial condition and other factors that the board of directors deems relevant.
- 23 -
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected historical financial data. You should read this financial data in conjunction with our financial statements, the notes to our financial statements and the other financial information, including pro forma information, included in this annual report. This information does not replace the financial statements. In our opinion, the data we have presented reflects all adjustments we consider necessary for a fair presentation of the results for such periods.
- ------------------
(1) The data for all prior years has been restated to reflect the change in our method of accounting for oil and natural gas operations to the full cost method of accounting. See Note 2 to our Financial Statements. As a result of the change in the accounting method, the net loss for the fiscal year ended March 31, 1995, the nine month period ended December 31, 1995 and the year ended December 31, 1996, has been decreased by $40,000 ($0.12 per share), $184,000 ($0.54 per share) and $3,000 ($0.01 per share), respectively.
(2) The $303,000 expense in 1996 represents the legal, accounting and other expenses associated with our attempted acquisition of Taurus Energy Corp.
(3) Per share data has been restated to reflect the one-for-five reverse stock split effective July 19, 1996, and the one-for-two reverse stock split effective March 31, 1998. The adoption of Financial Accounting Standards Board No. 128, Earnings per Share, did not have a material impact on earnings per share amounts.
(4) We have not declared nor paid any dividends during any of the periods presented.
- 24 -
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OUR RESULTS OF OPERATIONS
Comparison of Year Ended December 31, 1997 and December 31, 1998
Revenues. Oil and natural gas sales increased $715,000, or 107%, to $1.4 million for the year ended December 31, 1998 from $670,000 for the year ended December 31, 1997. The increase was due primarily to the acquisition we made in Maverick County, the Jacobi-Johnson Energy, Inc. acquisition, and the acquisition we made in Dawson County.
We sold 52,707 Bbls of oil during the year ended December 31, 1998 versus 14,453 Bbls in the corresponding period of 1997, a 265% increase. We sold 412,124 Mcf of natural gas during the year ended December 31, 1998 versus 181,091 Mcf in the corresponding period of 1997, a 128% increase. The increases in oil and natural gas volumes were also attributable to our acquisitions.
During 1998 we received an average oil price of $12.01 per Bbl versus $19.56 per Bbl during 1997, a $7.55 per Bbl or 39% decrease. During 1998 we received an average natural gas price of $1.82 per Mcf versus $2.14 per Mcf for 1997, a $.32 per Mcf or 15% decrease.
Our other income for the year ended December 31, 1998 was $690,000 as compared to $28,000 for the year ended December 31, 1997. This income primarily includes interest income, salt water disposal income, and well supervision fees. Other income increased due primarily to a $591,000 increase in interest income which we received from cash equivalent investments and an additional $64,000 in income we received from our two salt water disposal wells. We have reclassified amounts in the prior years' statements of operations to reflect a change in the way we classify fees from overhead charges billed to working interest owners, including ourselves. We previously recorded these overhead charges as management fee revenue, and we now record them as a reduction in general and administrative expenses.
Costs and Expenses. Our costs and expenses increased $1.7 million, or 186%, to $2.6 million for the year ended December 31, 1998 as compared to costs and expenses of $903,000 for the year ended December 31, 1997. Our costs and expenses primarily increased due to a $745,000 increase in general and administrative costs. This increase reflects expenses associated with our increased staffing and our new focus on reserve acquisitions. Our costs and expenses also increased due to a $464,000 increase in oil and natural gas production expenses and a $381,000 increase in depreciation, depletion and amortization expenses, both increases due to our 1998 acquisitions. We also had an increase of $93,000 in interest expense as a result of periodic borrowings against our credit facility.
In 1997, we changed our method of accounting for oil and natural gas properties from successful efforts to the full cost method of accounting. We have restated prior years to reflect this change in accounting method as though we had been using the full cost method for all periods we are comparing in this annual report. Effective December 31, 1997, we effected a quasi-reorganization by applying approximately $8.8 million of our additional paid-in capital account to eliminate our accumulated deficit.
Net Loss. We had a net loss for the year ended December 31, 1998 of $511,000, or $.18 per share, compared to a loss of $205,000, or $.51 per share, for the year ended December 31, 1997. We have based our earnings per share figures on restated weighted average shares outstanding after the retroactive effect of the one-for-two reverse stock split approved at our shareholders' meeting held on March 31, 1998.
Comparison of Year Ended December 31, 1996 and December 31, 1997
Revenues. Our oil and natural gas sales decreased $202,000, or 23%, to $670,000 for the year ended December 31, 1997 from $872,000 for the year ended December 31, 1996. During 1997, we sold various non-strategic oil and natural gas properties which decreased our production volumes and oil and natural gas sales. For 1997 our oil prices were 4% lower and our natural gas prices were 14% higher than the same prices in 1996.
- 25 -
For 1997, our oil sales volume decreased 35% and our natural gas sales volume decreased 19% from 1996. These decreases were caused by property sales and the depletion of existing properties. Our other income for the year ended December 31, 1997 was $38,000 as compared to $39,000 for the year ended December 31, 1996. This income primarily includes well supervision fees and interest income.
Costs and Expenses. Our costs and expenses decreased $334,000, or 27%, to $903,000 for the year ended December 31, 1997 from approximately $1.2 million for the year ended December 31, 1996. This decrease was due primarily to expenses of $303,000 incurred in 1996 in connection with our attempted acquisition of Taurus Energy Corp. Our oil and natural gas production costs decreased $107,000 to $322,000 for 1997 from $429,000 in 1996 as a result of the property sales. Our general and administrative expenses increased $113,000 to $486,000 in 1997 from $373,000 in 1996 due to increases in our office expenses and a reduction in our billed salary reimbursement as a result of the disposition of an oil property.
Net Loss. Our net loss decreased $121,000 for the year ended December 31, 1997 to $205,000, or $.51 per share, as compared to a loss of $326,000, or $.85 per share, for the year ended December 31, 1996. This decrease was primarily due to a reduction in revenues being partially offset by a decrease in expenses as more fully described above.
1997 QUASI-REORGANIZATION
Effective December 31, 1997, we effected a quasi-reorganization by applying approximately $8.8 million of our additional paid-in capital account to eliminate our accumulated deficit. Our board of directors decided to effect this quasi-reorganization given the change in management in December 1997, the infusion of new equity capital during December 1997 and an expected increase in acquisition, exploitation and development activities. Based on these factors and the establishment of a strategic growth plan, our board of directors and management believed reflecting prior losses on our balance sheet would not be meaningful in presenting our financial position. Our accumulated deficit was primarily related to past operations and properties that had been disposed of; the accumulated deficit was not, in management's view, reflective of our financial condition at that time. We did not adjust the historical carrying values of our assets and liabilities in connection with the quasi-reorganization.
WE CHANGED OUR METHOD OF ACCOUNTING FOR OIL AND NATURAL GAS OPERATIONS
In the fourth quarter of 1997, we changed from the successful efforts method to the full cost method of accounting for our oil and natural gas operations. We have restated all of the prior financial statements which we present in this annual report to reflect the change.
During the ten years ending in December 1997, we incurred minimal exploration and acquisition costs, liquidated substantially all our properties and completed "out of court" debt structurings. The "out of court" debt structurings were completed during 1987 and 1988. During the fourth quarter of 1997, we experienced a change in ownership control and we appointed new management. Our management views us as a new company and believes our past operations are insignificant and not relevant to our future plans.
Our new management changed the accounting method for oil and natural gas properties because management believes the full cost method will more appropriately reflect our change in focus for future
- 26 -
operations. Further, our new management does not believe that using the successful efforts method of accounting is appropriate for a small to medium size acquisition, development and exploitation company.
OUR LIQUIDITY AND CAPITAL RESOURCES
General
On December 31, 1998 we had working capital of $21.5 million compared to $399,000 on December 31, 1997. The sale of common stock through a rights offering in August 1998 for net proceeds of $35.2 million contributed to the $21.1 million increase in our working capital. Our working capital on December 31, 1997 was $399,000 compared to a negative $285,000 on December 31, 1996. This $684,000 increase in our working capital resulted from the sale of non-strategic oil and natural gas properties in 1997. Our 1999 budget for capital expenditures is approximately $2.4 million.
Deferred Income Taxes
In order to realize the benefit of our deferred tax asset, we must generate enough income prior to the expiration of this asset. We believe there is a risk, in light of current economic conditions in the oil and gas industry, that our net operating loss carryforwards may expire unused. In accordance with generally accepted accounting principles, we must reduce the value of the deferred tax asset if we estimate that the asset will not be utilized in future periods. Accordingly, we have established a valuation allowance of $457,000 in 1998 to reduce the value of the asset. As a result, it is likely that our effective tax rate in 1999 will be minimal if we recognize a loss before income taxes. If we recognize positive earnings before taxes, the effective tax rate will be reduced based on limitations described in the tax code. Additional discussion can be found in Item 8 - Financial Statements and Supplementary Data, Note 4 - Income Taxes.
Long-Term Debt
On December 31, 1998, we had no long-term debt.
Sale of Equity
On July 16, 1998, we commenced a rights offering to our existing shareholders. Each shareholder received ten rights for each share of our common stock held. Each right entitled the shareholder to purchase one share of our common stock for $6.00 per share. The rights offering expired on August 12, 1998. We received net proceeds of approximately $35.2 million. The exercise of the rights by some existing shareholders or their assignees has resulted in the dilution of the shares of common stock held by those shareholders who did not exercise their rights. To date, we have used $6.4 million to repay our indebtedness, $6.5 million for the acquisition of Rio Grande, Inc., $341,000 for our share of capital contributions to EXCO Energy Investors, L.L.C. and $400,000 for general corporate purposes. We intend to use the remaining proceeds of the rights offering for acquisitions, development drilling and recompletions, the repayment of bank indebtedness, working capital and general corporate purposes.
New Credit Facility
On February 11, 1998, we entered into a credit facility with NationsBank of Texas, N.A. The credit facility initially provided for borrowings up to $50 million, subject to borrowing base limitations. On September 21, 1998, we entered into an amendment to the credit facility with NationsBank, N.A. (successor by merger to NationsBank of Texas, N.A.). The amended credit facility provides for borrowings up to $150 million, subject to borrowing base limitations. The bank has sole discretion to determine our borrowing base based on its valuation of our reserves valued semi-annually.
The credit facility consists of a regular revolver which on December 31, 1998, had a borrowing base of approximately $5.5 million. On March 1, 1999, we had approximately $5.5 million available for borrowing under the credit facility. A portion of the borrowing base is available for the issuance of letters of credit. All borrowings under the credit facility are secured by a first lien deed of trust providing a security interest in tangible and intangible assets representing at least 90% of the assessed present value of our oil and natural gas properties.
The credit facility provides that if our aggregate outstanding indebtedness is less than $5 million, advances will bear interest at 1.5% over the appropriate LIBOR rate. If our aggregate outstanding indebtedness is greater than $5 million, then our advances will bear interest at 1.0% over LIBOR if the borrowing base usage is less than 50%, 1.25% over LIBOR if the borrowing base usage is between 59-70%, 1.5% over LIBOR if the borrowing base usage is between 70-90%, and 1.75% over LIBOR if the borrowing base usage exceeds 90%. The credit facility also permits us to repay and reborrow amounts under the credit facility without any penalty, thereby allowing us the flexibility to utilize any available cash to reduce our outstanding indebtedness and thus, our costs of borrowed funds.
- 27 -
Under the terms of the credit facility, we must not permit our current ratio of consolidated current assets to our consolidated current liabilities to be less than 1.0 to 1.0 at any time. Furthermore, we must not permit our consolidated tangible net worth to be less than $500,000 at any time between February 11, 1998 and March 31, 1999. In addition, by March 31, 1999, our consolidated tangible net worth must increase by 50% of our consolidated net income for the fiscal quarter then ended and for every fiscal quarter thereafter must increase by 50% of our consolidated net income for the fiscal quarter then ended. Our consolidated tangible net worth must increase on the date we issue any equity securities after December 31, 1998, by an amount equal to 75% of the net proceeds we receive from the issuance of these securities. On March 1, 1999, we were in compliance with both the consolidated tangible net worth covenant and the current ratio covenant.
No principal amortization will be required during the term of the credit facility as long as the aggregate principal balance does not exceed the borrowing base then in effect. However, if a borrowing base deficiency were to exist after giving effect to a redetermination, then we would have to do one of the following:
o eliminate the borrowing base deficiency by making a single mandatory prepayment of principal on the revolving loan in an amount equal to the entire amount of the borrowing base deficiency on the first monthly date following the date on which the borrowing base deficiency is determined to exist;
o eliminate the deficiency by making six consecutive mandatory prepayments of principal on the revolving loan each of which shall be in the amount of one sixth (1/6th) of the amount of the borrowing base deficiency commencing on the first monthly date following the date on which the borrowing base deficiency is determined to exist and continuing on each monthly date thereafter; or
o eliminate the borrowing base deficiency by submitting additional mineral interests to the banks on the first monthly date following the date on which the borrowing base deficiency is determined to exist for evaluation as borrowing base properties which the banks, in their sole discretion, determine have a value sufficient to increase the borrowing base by at least the amount of the borrowing base deficiency.
The credit facility matures on February 11, 2000. Our next borrowing base redetermination is scheduled for no later than April 1, 1999, and semi-annually thereafter. We may seek additional borrowing capacity at that time for our development drilling program. However, we cannot assure you that our current development program will result in increased collateral values or that these values will enable us to borrow the funds we need to continue the program.
The credit facility contains a number of covenants affecting our liquidity and capital resources, including restrictions on our ability to incur indebtedness at any time in an amount exceeding $100,000 or to pledge assets outside of the credit facility, our maintenance of a minimum net worth and restrictions on the payment of dividends on our capital stock.
Need to Raise Additional Capital
The growth of our business will require substantial capital on a continuing basis. For example, in order for us to consummate our proposal with respect to acquiring National Energy Group, Inc., we will need to obtain additional financing. We cannot assure you that additional funds we may require will be available on satisfactory terms and conditions, if at all. We may pursue, from time to time, opportunities to acquire oil and natural gas properties and businesses that may utilize the capital we currently expect to be available for our present operations. The amount and timing of our future capital requirements, if any, will depend upon a number of factors, including drilling costs, transportation costs, equipment costs, marketing expenses, staffing levels, competitive conditions, and any purchases or dispositions of assets. We do not control many of these factors. If we fail to obtain any required additional financing, then our growth, cash flow and earnings may be adversely affected. In addition, we may incur additional debt or engage in potentially dilutive issuances of equity securities in our pursuit of additional capital.
- 28 -
EFFECT OF INFLATION AND CHANGING PRICES ON OUR BUSINESS
It is difficult for us to assess the impact of inflation on our business. In 1998 and through the first quarter of 1999, we have experienced a weakness in the prices we receive for our oil and natural gas production. We cannot anticipate whether inflation will remain at its present level. However, a sudden increase in inflation and/or an increase in our operating costs or drilling costs coupled with a continuation of low oil prices could have an adverse effect on our operations.
OUR YEAR 2000 COMPLIANCE
Project. We have placed a high priority on proactively resolving computer or imbedded chip problems related to the "Year 2000" which may have adverse material effects on our continuing operations or cash flow. This problem would be caused by the inability of a component (software, hardware or equipment with embedded microprocessors) to correctly process date data in and between the 20th and 21st centuries and therefore fail to properly perform its intended functions, and/or to exchange correct date data with other components. This problem would most typically be caused by erroneous date calculations, which results from using two digits to signify a year (century implied), handling leap years incorrectly or the use of "special" values that can be confused with legitimate calendar dates. The scope of the Year 2000 project includes conducting an inventory of our software, hardware and "embedded systems" equipment, assessing potential for failure and the associated risk, prioritizing the need for remediation, repairing or replacing significant noncompliant items, and testing. In addition, we will take a similar approach to mitigating risks associated with the Year 2000 readiness of material business partners (vendors, suppliers, customers, etc.). The project will also identify contingency plans to cope with unexpected events resulting from Year 2000 issues.
Beginning in mid 1998, we began an assessment of our core financial and operational software systems. We identified three critical systems with date sensitivities: oil and gas financial accounting, production accounting and land/lease administration. We currently use a Year 2000 ready release of an oil and gas financial accounting package. We also use a Year 2000 ready production accounting system. The land/lease administration package we use is also Year 2000 ready. All of these packages will be updated for any releases of new versions of the vendors' software as it becomes available. We expect to receive the respective vendors' support and to take advantage of additional features and performance enhancements. We rely on vendors' representations that our software is Year 2000 ready and we do not intend to test it. Assessments continue for lower priority software systems.
In addition, we use a Year 2000 ready AS/400 on which our accounting software resides.
Other activities which we have started or scheduled to start during the balance of 1999 include testing of desktop PC's, assessment of material business partners, and an inventory of embedded systems in field locations. We have engaged an outside consultant to assist in reviewing equipment used in our oil and natural gas producing operations. We are also seeking written verification from our major operators, suppliers and customers that they will be Year 2000 compliant. We anticipate that the costs of seeking verification will be minimal. We believe that it is not practical to independently verify the responses we receive because we do not believe we will be given access to carry out verification or that the cost will be affordable. The cost of replacing non-compliant or non-responsive operators, suppliers and customers will not be determined until the review has progressed. The following table summarizes the current overall status of the project with anticipated completion dates:
- 29 -
In addition to the above, during the second quarter of 1999 we will develop an overall contingency plan designed to provide for continued operations which will include precautionary measures.
Cost. As of February 28, 1999, we have incurred no consulting costs for Year 2000 project planning and scope definition. All software packages requiring an upgrade which have been identified will be upgraded and may require additional out-of-pocket expenses which are expected to be minimal. An accurate cost cannot be determined prior to the conclusion of the Assessment/Prioritization phase, but it is expected that our total project expenditures including the use of outside consultants, if any, should not exceed $20,000 paid from our working capital. This excludes any costs which may be assessed by joint venture partners on properties not operated by us.
Risks/Contingency. The failure to remediate critical systems (software, hardware or embedded systems), or the failure of a material business partner to resolve critical Year 2000 issues could have a serious adverse impact on our ability to continue operations and meet obligations. Any Year 2000 problems that do occur will likely manifest themselves in reduced production through equipment shut down or impaired liquidity through an inability of our customers to take delivery or to process payment. At the current time, we believe that any interruption in operation will be minor and short-lived and will pose no safety or environmental risks. However, until all assessment phases have been completed it is impossible to accurately identify the risks, quantify potential impacts or establish a contingency plan. We have not yet clearly identified the most likely worst case scenario if we and our material business partners do not achieve Year 2000 readiness on a timely basis. We currently intend to complete our contingency planning by June 30, 1999.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not Applicable.
- 30 -
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EXCO RESOURCES, INC.
FINANCIAL STATEMENTS
Years Ended December 31, 1996, 1997, and 1998
CONTENTS
- 31 -
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders EXCO Resources, Inc.
We have audited the accompanying balance sheets of EXCO Resources, Inc., as of December 31, 1997 and 1998, and the related statements of operations, cash flows, and changes in stockholders' equity for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of EXCO Resources, Inc., at December 31, 1997 and 1998, and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles.
As explained in Note 2 to the financial statements, EXCO Resources, Inc. has given retroactive effect to the change in accounting for oil and natural gas properties from the successful efforts method to the full cost method.
/s/ ERNST & YOUNG LLP
ERNST & YOUNG LLP Dallas, Texas February 26, 1999
- 32 -
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders EXCO Resources, Inc.
We have audited the accompanying statements of operations, cash flows and changes in stockholders' equity for the year ended December 31, 1996 of EXCO Resources, Inc. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of EXCO Resources, Inc. for the year ended December 31, 1996, in conformity with generally accepted accounting principles.
As explained in Note 2 to the financial statements, EXCO Resources, Inc. has given retroactive effect to the change in accounting for all oil and natural gas properties from the successful efforts method to the full cost method.
/s/ BELEW AVERITT LLP
BELEW AVERITT LLP
Dallas, Texas March 13, 1997, except Note 2, as to which the date is February 11, 1998 and Note 1, Reverse Stock Split-1998, as to which the date is March 31, 1998
- 33 -
EXCO RESOURCES, INC.
BALANCE SHEETS
See accompanying notes.
- 34 -
EXCO RESOURCES, INC.
STATEMENTS OF OPERATIONS
See accompanying notes.
- 35 -
EXCO RESOURCES, INC.
STATEMENTS OF CASH FLOWS
- 36 -
EXCO RESOURCES, INC.
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
See accompanying notes.
- 37 -
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
EXCO Resources, Inc., (the Company), a Texas corporation, was formed in 1955. Our operations consist primarily of acquiring interests in producing oil and natural gas properties located in the continental United States. We also act as the operator on some of these properties and receive overhead reimbursement fees as a result.
QUASI-REORGANIZATION
Effective December 31, 1997, we effected a quasi-reorganization by applying approximately $8.8 million of our additional paid-in capital account to eliminate our accumulated deficit. Our board of directors decided to effect a quasi-reorganization given the change in management, the infusion of new equity capital and an increase in activities. Our accumulated deficit was primarily related to past operations and properties that have been disposed of. We did not adjust the historical carrying values of our assets and liabilities in connection with the quasi-reorganization.
MANAGEMENT ESTIMATES
In preparing financial statements in conformity with generally accepted accounting principles, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results may differ from management's estimates.
CASH EQUIVALENTS
We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.
CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and trade receivables. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion, and operation of oil and natural gas wells. Substantially all of our accounts receivable are due from either purchasers of oil, natural gas, or natural gas liquids or participants in oil and natural gas wells for which we serve as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. Oil and natural gas sales are generally unsecured. We have provided for credit losses in the financial statements and these losses have been within management's expectations. The allowance for doubtful accounts receivable aggregated $18,000 and $9,000 at December 31, 1997 and 1998, respectively.
OIL AND NATURAL GAS PROPERTIES
We have recorded oil and natural gas properties at cost using the full cost method of accounting, as prescribed by the Securities and Exchange Commission. Under the full cost method, all costs associated with the acquisition, exploration or development of oil and natural gas properties are capitalized as part of the full cost pool. Capitalized costs are limited to the aggregate of the present value of future net reserves plus the lower of cost or fair market value of unproved properties.
Depreciation, depletion, and amortization of evaluated oil and natural gas properties are provided using the unit-of-production method based on total proved reserves, as determined by independent petroleum reservoir engineers.
- 38 -
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.
OFFICE AND FIELD EQUIPMENT
Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives.
REVENUE RECOGNITION
We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers.
OVERHEAD REIMBURSEMENT FEES
We have classified fees from overhead charges billed to working interest owners, including us, of $138,000, $136,000, and $278,000 for the years ended December 31, 1996, 1997, and 1998, respectively, as a reduction of general and administrative expenses in the accompanying statements of operations. For the year ended December 31, 1996, this amount was previously shown as revenue.
EARNINGS PER SHARE
Statement of Financial Accounting Standards No. 128, Earnings per Share, which became effective in 1997, requires presentation of two calculations of earnings per common share. Basic earnings per common share equals net income divided by weighted average common shares outstanding during the period. Diluted earnings per common share equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive shares assumed to be issued. Common stock equivalents are shares assumed to be issued if outstanding stock options were exercised. We have restated all prior period amounts, where appropriate, to reflect these calculations. We were not materially impacted when we adopted Statement No.128.
REVERSE STOCK SPLITS
At our 1996 annual meeting of shareholders, our shareholders approved an amendment to our articles of incorporation, authorizing a one-for-five reverse stock split of our common stock, which became effective July 19, 1996. At our 1998 annual meeting of shareholders, our shareholders approved an amendment to our articles of incorporation, authorizing a one-for-two reverse stock split of our common stock, which became effective March 31, 1998. We have adjusted all share and per share numbers retroactively to record the effects of the reverse stock split.
PREFERRED STOCK
At the 1996 annual meeting, our shareholders also authorized the issuance of up to 10,000,000 shares of preferred stock, $.01 par value per share, that the board of directors may issue from time to time in one or more series. With respect to each series of preferred stock, the amendment authorizes the board to fix and determine by resolution the number of shares of each series, the designation thereof and all rights and preferences including voting, dividend, conversion, redemption and liquidation rights. To date no shares have been issued. The board of directors deemed it in our best interest to provide for corporate planning and to have shares available for future equity financings through issuance to the general public, future acquisitions, stock dividends or splits or for other corporate purposes for which the issuance of preferred shares may be advisable.
- 39 -
2. CHANGE IN METHOD OF ACCOUNTING FOR OIL AND NATURAL GAS OPERATIONS
In the fourth quarter of 1997, we changed from the successful efforts method to the full cost method of accounting for our oil and natural gas operations. All prior year's financial statements presented in this annual report have been restated to reflect the change.
During the past ten years ending in 1997, we incurred minimal exploration and acquisition costs which resulted in the liquidation of substantially all of our properties. During 1987 and 1988 we completed "out of court" debt restructurings. During the fourth quarter of 1997 we experienced a change in control of ownership and new management was appointed. New management views us as a new company and believes our past operations are insignificant and not relevant to our future plans.
New management believes that the change in accounting for oil and natural gas properties is proper because the full cost method will more appropriately reflect our future operations which will result from our significant management changes. Further, new management does not believe that the use of the successful efforts method of accounting is appropriate for a small to medium size acquisition, development and exploitation company.
We have restated the financial statements to apply the new accounting method retroactively. The effect of the change in accounting principle on our 1997 net loss and earnings per share data was immaterial due to our relative inactivity in exploration and development activities. The effect of the accounting change on the results of operations for the year ended December 31, 1996 is as follows (in thousands except per share amounts):
- 40 -
3. LONG-TERM DEBT
Long-term debt is summarized as follows (in thousands):
NATIONSBANK CREDIT AGREEMENT
On February 11, 1998, we entered into a credit facility with NationsBank of Texas, N.A. The credit facility provided for borrowings up to $50 million, subject to borrowing base limitations. On September 21, 1998, we entered into an amendment to the credit facility with NationsBank, N.A. (successor by merger to NationsBank of Texas, N.A.). The amended credit facility provides for borrowings up to $150 million, subject to borrowing base limitations, as determined by the lenders from time to time. Under the credit facility, we are required to pay a fee equal to .25% on any accepted increase in the borrowing base in excess of the previously determined borrowing base and a commitment fee of .30% to .425% based on the ratio of outstanding credit to the borrowing base. The maturity date of the credit facility is February 11, 2000.
The credit facility provides that if our outstanding credit is less than $5 million, then our interest rate will be LIBOR plus 1.5%. If our outstanding credit is greater than $5 million, then the credit facility provides that our interest rate will be either NationsBank's prime rate or LIBOR plus between 1% and 1.75% based on the ratio of outstanding credit to the borrowing base.
There are no scheduled principal payments due on the credit facility until maturity. However, the borrowing base will be redetermined on or around April 1st and October 1st of each year. A borrowing base deficiency is created in the event that the outstanding loan balances exceed the borrowing base, as determined by the lenders in their sole discretion. Upon such event the borrowing base deficiency must be repaid by:
(1) mandatory reductions of the deficiency over a period of not more than 6 months;
(2) making a lump sum payment equal to the deficiency; or
(3) providing additional collateral acceptable to lenders in their sole discretion sufficient to increase the borrowing base and eliminate the deficiency.
Borrowings under the credit facility are secured by first and prior liens covering 90% of the recognized value of all proved mineral interests owned by us. The credit facility contains various restrictive covenants, including limitations on the granting of liens, restrictions on the issuance of additional debt, requirements to maintain a net worth of at least $500,000 and to maintain a current ratio of not less than 1.0 to 1.0, and currently prohibits the payment of dividends on our capital stock.
4. INCOME TAXES
At December 31, 1998, we had net operating loss carryforwards (NOLs) for income tax purposes that expire beginning in 1998. Our ability to use the NOLs is significantly restricted because of a change in our ownership, as defined by the Tax Reform Act of 1986, which occurred December 19, 1997, as described in Note 1. We estimate that approximately $2.6 million of the NOLs will become available in the future at the rate of approximately $127,000 per year through 2018. We also have available statutory depletion carryforwards of approximately $16,000. For financial reporting purposes, a valuation allowance has been recognized to offset the deferred tax assets related to carryforwards prior to our quasi-reorganization. When realized, the tax benefit for those carryforwards will be credited to additional paid-in capital.
- 41 -
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows (in thousands):
The following is a reconciliation, stated as a percentage of pretax income (loss) taxable at the corporate level, of the U.S. statutory federal income tax rate to our effective tax rate:
- 42 -
5. STOCK TRANSACTIONS
ISSUANCE OF COMMON STOCK
On March 5, 1998 we issued 6,250 shares of common stock as consideration for the acquisition of working interests from J. Michael Muckleroy, an outside director. On May 8, 1998 we issued 85,436 shares of common stock as partial consideration for the Jacobi-Johnson Energy, Inc. acquisition. On July 16, 1998 the Securities and Exchange Commission declared our registration statement effective authorizing the commencement of a rights offering to our existing shareholders. Each shareholder received ten rights for each share of our common stock held. Each right entitled the shareholder to purchase one share of our common stock for $6.00 per share. The rights offering expired on August 12, 1998. We received net proceeds of approximately $35.2 million and issued approximately 5.9 million shares. On September 15, 1998 several of our directors and executive officers exercised stock options covering 150,000 shares of common stock at a strike price of $6.00 per share. Of the $900,000 in aggregate proceeds, these directors and executive officers paid $75,000 in cash with $825,000 being borrowed from us.
The following table summarizes our stock option activity:
In October 1995, the Financial Accounting Standard Board issued Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). SFAS 123 defines a fair value based method of accounting for employee stock compensation plans, but allows for the continuation of the intrinsic value based method of accounting to measure compensation cost prescribed by Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees" ("APB 25"). For companies electing not to change their accounting, SFAS 123 requires pro-forma disclosures of earnings and earnings per share as if the change in accounting provision of SFAS 123 has been adopted.
We have elected to continue to utilize the accounting method prescribed by APB 25, under which no compensation cost has been recognized, and adopt the disclosure requirements of SFAS 123. As a result, SFAS 123 has no effect on our financial condition or our results of operations at December 31, 1996, 1997 and 1998.
Had compensation costs for these plans been determined consistent with SFAS 123, our net income and earnings per share would have been adjusted to the following pro-forma amounts.
- 43 -
The present value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used: fair market value of stock at date of grant of $6.00; option exercise price of $6.00; option term of 10 years; risk-free rate of return is based on 10-year U.S. Treasury Notes; company stock volatility is based on prior 20 month stock prices; company dividend yield of 0%; and calculated Black-Scholes value of $2.54 per option.
6. RELATED PARTY TRANSACTIONS
In the past, certain of our directors, and the companies with which they are affiliated, participated in oil and natural gas joint ventures with us upon the same terms and conditions as unrelated parties. In addition, we have purchased certain oil and natural gas prospects as well as drilling services and oil field supplies and services in the normal course of business from directors or from companies in which certain directors have financial interest. We made no significant purchases during the year ended December 31, 1997. During the year ended December 31, 1998, we purchased working interests from an outside director, in exchange for 6,250 shares of our common stock.
7. COMMITMENTS AND CONTINGENCIES
We lease our offices and certain equipment. Our rental expenses were approximately $41,000, $63,000, and $84,000 for 1996, 1997 and 1998, respectively. Our future minimum rental payments under operating leases with remaining noncancellable lease terms in excess of one year at December 31, 1998 are as follows (in thousands):
8. ENVIRONMENTAL REGULATION
Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the near future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these laws and regulations are constantly being changed, we are unable to predict the conditions and other factors, over which we do not exercise control, that may give rise to environment liabilities affecting us.
- 44 -
9. TERMINATED ACQUISITION
In September 1996, we entered into a stock purchase agreement to acquire Taurus Energy Corp., a processor and marketer of natural gas. In addition, we initiated a public stock offering to raise the $35.0 million necessary to complete the acquisition.
In connection with these activities, we incurred and capitalized approximately $303,000 of legal, accounting and other costs. In 1996, we terminated the proposed Taurus acquisition and canceled our planned public offering. As a result, we expensed the costs associated with these actions.
10. OIL AND NATURAL GAS PRODUCING ACTIVITIES
The results of operations from our oil and natural gas producing activities are as follows (in thousands):
Costs incurred in oil and natural gas producing activities are as follows (in thousands, except per equivalent barrel amounts):
Most of our oil and natural gas revenues are produced from a limited number of wells or properties located in the United States.
Our oil and natural gas production is sold to various purchasers. During the year ended December 31, 1996, sales of oil and natural gas to two purchasers accounted for 26% and 15% of gross revenues, respectively. During the year ended December 31, 1997, sales of oil and natural gas to three purchasers accounted for 22%, 19% and 14% of gross revenues, respectively. During the year ended December 31, 1998, sales of oil and natural gas to two purchasers accounted for 17% and 10%, respectively, of our total revenues. Management believes that the loss of these purchasers would not have a material impact on our financial condition or results of operations.
In an effort to reduce the effects of the volatility of the price of crude oil and natural gas on our operations, management has adopted a policy of hedging oil and natural gas prices whenever such prices are in excess of the prices anticipated in our operating budget and profit plan through the use of commodity futures, options, and swap agreements. Hedging transactions require the approval of the board of directors. We had no outstanding hedging agreements at December 31, 1998.
- 45 -
11. SUPPLEMENTAL OIL AND NATURAL GAS RESERVE AND STANDARDIZED MEASURE INFORMATION (UNAUDITED)
We retain independent engineering firms to provide annual year-end estimates of our future net recoverable oil, natural gas, and natural gas liquids reserves. Estimated proved net recoverable reserves we have shown below include only those quantities that you can expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves that we may recover through existing wells. Proved undeveloped reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.
ESTIMATED QUANTITIES OF PROVED RESERVES
ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES
* Boe - Barrels of oil equivalent calculated by converting 6 Mcf of natural gas to 1 Bbl of oil.
We have summarized the standardized measure of discounted net cash flows related to our proved oil, gas, and natural gas liquids reserves. We have based the following summary on a valuation of proved reserves using discounted cash flows based on year-end prices, costs, and economic conditions and a 10% discount rate. The additions to proved reserves from new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.
- 46 -
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
During recent years, prices paid for oil in the world markets have fluctuated significantly. This situation has had a destabilizing effect on the posted prices of oil in the United States, including the posted prices paid by purchasers of our oil. The weighted average prices of oil and natural gas at December 31, 1996, 1997 and 1998, used in the above table, were $24.29, $16.74 and $10.41 per Bbl, respectively, and $3.40, $2.11 and $1.74 per Mcf, respectively.
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
CHANGES IN STANDARDIZED MEASURE
12. ACQUISITIONS
We have accounted for the following acquisitions in accordance with Accounting Principles Board No. 16, "Business Combinations" where applicable.
On February 11, 1998, we acquired from Osborne Oil Company, Gypsy Production Company, and other working interest owners oil and natural gas properties in Maverick County, Texas. The purchase price consisted of approximately $760,000 cash partially paid for using funds available under the credit facility.
On May 8, 1998, we acquired all of the outstanding common stock of Jacobi-Johnson Energy, Inc. from its four stockholders. Jacobi-Johnson, owns oil and natural gas working interests in Polk, Nacogdoches, Navarro, Smith and Wood Counties of Texas. We paid approximately $1.5 million for the stock which consisted of $703,000 cash and 85,436 shares of our common stock with a value of $513,000. In addition, we assumed approximately $261,000 of Jacobi-Johnson indebtedness. We obtained the cash for the purchase price under our credit facility with NationsBank, N.A. The Jacobi-Johnson properties have been mortgaged under the credit facility.
- 47 -
On June 30, 1998 we acquired oil and natural gas properties from J. M. Hill, J. M. Hill, Trustee, Walter O. Hill, Steven J. Devos, Humphrey Oil Interests, L.P. and other working interest owners, in Dawson and Brazos Counties, Texas. The purchase price consisted of approximately $3.5 million cash paid for using funds available under our credit facility.
On December 21, 1998, we acquired properties from Colony Petroleum, L.L.C. and Cumulus 2 Limited in Carter County, Oklahoma. The purchase price consisted of approximately $706,000 cash paid from proceeds of our rights offering.
Pro forma results of operations. The following table reflects the pro forma results of operations as though the acquisitions of the Maverick County properties, Jacobi-Johnson Energy, Inc., and the Dawson County properties had occurred on January 1, 1997. The pro forma results of operations of the Carter County acquisition are not presented as they are not material to our consolidated financial statements.
On October 9, 1998, we formed a $50 million joint venture with an institutional investor to acquire oil and natural gas related assets and securities. Under the terms of the joint venture agreement, we are required to contribute 5% of the joint venture's capital expenditures. As of February 15, 1999, the joint venture has invested in various
- 48 -
debt securities. Through February 15, 1999, our investment in the joint venture was approximately $341,000.
Related to an investment made by the joint venture, we presented a restructuring plan to National Energy Group, Inc.'s bondholders' committee on February 24, 1999. The proposal consists of a combination of shares of EXCO common stock and approximately $58 million cash to satisfy all secured and unsecured liabilities and to acquire the assets of National Energy. The plan anticipates no consideration for the preferred or common equity of National Energy.
The proposal is subject to conditions which include approval by (1) EXCO's board of directors; (2) EXCO's shareholders; (3) EXCO's bank lenders; (4) due diligence and (5) the U. S. Bankruptcy Court. We cannot assure you that this proposal will be acceptable to National Energy, its creditors' constituencies or the U. S. Bankruptcy Court or that any transaction will be completed.
On November 2, 1998, we acquired a promissory note from a Texas bank for $6.4 million which is secured by substantially all of the assets of Rio Grande, Inc., its subsidiaries and affiliated entities. Rio Grande, Inc. is an oil and natural gas producer with principal operations in Texas, Oklahoma, Louisiana, and Mississippi. At the same time we purchased the note, we also entered into an agreement with Rio Grande, Inc. and Rio Grande, Inc.'s sole holder of preferred stock, regarding plans for the ultimate satisfaction of Rio Grande, Inc.'s debt, including the proposed acquisition of Rio Grande, Inc. or its assets by us. We believe that historical cost equates to the fair market value on these securities.
On November 12, 1998, Rio Grande, Inc. announced that it had filed for reorganization under Chapter 11 of the Bankruptcy Code. As the largest secured creditor, we have negotiated a plan for financial restructuring with Rio Grande, Inc. and the holder of its preferred stock. On March 5, 1999, the court is scheduled to confirm the proposed plan. Pursuant to the terms of the plan, Rio Grande, Inc. will fully repay its trade creditors. The plan provides for the merger of several subsidiaries or affiliates into Rio Grande, Inc. Then, the outstanding shares of Rio Grande, Inc.'s common and preferred stock will be canceled. We will be issued new shares of Rio Grande, Inc. as settlement of Rio Grande Inc.'s $13 million secured indebtedness owed to us. The new shares will represent all of the outstanding capital stock of Rio Grande, Inc., and we will be the owners of Rio Grande, Inc. effective on or about March 16, 1999.
- 49 -
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
On January 14, 1998, we dismissed Belew Averitt LLP as our independent auditors and on January 14, 1998, we retained Ernst & Young LLP as our independent auditors to perform the audit of our financial statements for the year ended December 31, 1997. Our board of directors and shareholders approved the decision to engage Ernst & Young LLP and to dismiss Belew Averitt LLP.
Belew Averitt's reports on our financial statements for the year ended December 31, 1996, did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles.
We did not disagree with Belew Averitt LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of Belew Averitt LLP, would have caused them to make reference to the subject matter of the disagreement in connection with their report.
- 50 -
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be set forth under the captions "Election of Directors," "Section 16(a) Beneficial Ownership Reporting Compliance," "Certain Relationships Between the Company and Directors, Officers or Shareholders," and "Directors and Executive Officers" of our proxy statement for our 1999 annual meeting of shareholders which was filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 and is incorporated herein by reference. The proxy statement was filed on March 16, 1999.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth under the caption "Executive Compensation" in Appendix E of our proxy statement which was filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is set forth in Appendix B under the caption "Shareholders" of our proxy statement which was filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under the captions "Certain Relationships Between the Company and Directors, Officers or Shareholders" of our proxy statement which was filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 and is incorporated herein by reference.
- 51 -
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
1. FINANCIAL STATEMENTS
See Index to Financial Statements on page 31 to this annual report.
2. FINANCIAL STATEMENT SCHEDULES
All schedules are omitted because the information is not required under the related instructions or is inapplicable or because the information is included in the Financial Statements or related Notes.
3. EXHIBITS
3.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Annual Report on Form 10-K for the year ended December 31, 1996 and incorporated by reference herein
3.2 Bylaws of EXCO, as amended filed as an Exhibit to EXCO's Annual Report on Form 10-K for the year ended December 31, 1996 and incorporated by reference herein
4.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Annual Report on Form 10-K for the year ended December 31, 1996 and incorporated by reference herein
4.2 Restated Bylaws of EXCO, as amended filed as an Exhibit to EXCO's Annual Report on Form 10-K for the year ended December 31, 1996 and incorporated by reference herein
4.3 Specimen Stock Certificate for the Common Stock of EXCO filed as an Exhibit to EXCO's Pre-Effective Amendment No. 1 to Form S-2 filed on June 2, 1998 and incorporated by reference herein
10.1 Standby Purchase Commitment between EXCO Resources, Inc. on the one hand and Ares Management, L.P. on behalf of Ares Leveraged Investment Fund, L.P. on the other hand dated July 16, 1998 filed as an Exhibit to EXCO's Form 8-K filed August 25, 1998 and incorporated by reference herein
10.2 Standby Purchase Commitment between EXCO Resources, Inc. on the one hand and Oaktree Capital Management, LLC on behalf of OCM Principal Opportunities Fund, L.P. on the other hand, dated July 16, 1998 filed as an Exhibit to EXCO's Form 8-K filed August 25, 1998 and incorporated by reference herein
10.3 Credit Agreement among EXCO Resources, Inc., as borrower, and NationsBank of Texas, N.A., as agent, and financial institutions listed on Schedule I, dated February 11, 1998 filed as an Exhibit to EXCO's Form 8-K filed February 25, 1998 and incorporated by reference herein
10.4 First Amendment to Credit Agreement among EXCO Resources, Inc., as borrower, NationsBank, N.A. (successor by merger to NationsBank of Texas, N.A.), as agent, and financial institutions listed on Schedule I, dated September 21, 1998, filed as an Exhibit to EXCO's Form 8-K filed September 28, 1998 and incorporated by reference herein
10.5 Purchase and Sale Agreement among EXCO Resources, Inc. and Osborne Oil Company, et al., dated January 27, 1998 filed as an Exhibit to EXCO's Form 8-K filed August 25, 1998 and incorporated by reference herein
10.6 EXCO Energy Investors, L.L.C. Operating Agreement (filed herewith)
- 52 -
10.7 Purchase and Sale Agreement among EXCO Resources, Inc. and Osborne Oil Company, et al., dated January 27, 1998, filed as an Exhibit to EXCO's Form 8-K dated February 25, 1998 and incorporated by reference herein
10.8 Stock Purchase Agreement between EXCO Resources, Inc. and Jacobi-Johnson Energy, Inc., dated May 1, 1998, filed as an Exhibit to EXCO's Form 8-K dated May 1, 1998 and incorporated by reference herein
10.9 EXCO Resources, Inc. 1998 Stock Option Plan, filed as Appendix A to EXCO's Proxy Statement dated May 17, 1998 and incorporated by reference herein
10.10 Purchase and Sale Agreement dated June 24, 1998, by and between Humphrey Oil Interests, L.P. on the one hand and EXCO Resources, Inc. on the other, filed as an exhibit to EXCO's Form 8-K dated June 30, 1998 and incorporated by reference herein
10.11 Purchase and Sale Agreement dated June 24, 1998, by and between J. M. Hill, Individually and as Trustee, Walter O. Hill, and Steven J. Devos on the one hand and EXCO Resources, Inc. on the other, filed as an exhibit to EXCO's Form 8-K dated June 30, 1998 and incorporated by reference herein
16.1 Letter from Belew Averitt LLP regarding change in certifying accountant dated January 20, 1998 filed as an Exhibit to EXCO's Form 8-K filed January 21, 1998 and incorporated by reference herein
18.1 Letter from Ernst & Young LLP regarding change in accounting principles dated February 11, 1998 filed as an Exhibit to EXCO's Annual Report on Form 10-K for the year ended December 31, 1997 and incorporated by reference herein
23.1 Consent of Independent Auditors, Belew Averitt LLP (filed herewith)
23.2 Consent of Independent Auditors, Ernst & Young LLP (filed herewith)
23.3 Consent of Lee Keeling and Associates, Inc. (filed herewith)
27.1 Financial Data Schedule (filed herewith)
------------------
- 53 -
4. REPORTS ON FORM 8-K
During the last quarter of the year ended December 31, 1998, we did not file any current reports on Form 8-K.
- 54 -
SIGNATURE PAGE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act, the Registrant has duly caused this report to be signed on its behalf by the undersigned, there unto duly authorized in the City of Dallas, Texas on the 17th of March, 1999.
EXCO RESOURCES, INC.
By: /s/ DOUGLAS H. MILLER ---------------------------------- Douglas H. Miller Chairman of the Board of Directors And Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
March 17, 1999 /s/ DOUGLAS H. MILLER ---------------------------------- Douglas H. Miller Chairman of the Board of Directors And Chief Executive Officer
March 17, 1999 /s/ T.W. EUBANK ---------------------------------- T. W. Eubank Director, President and Treasurer
March 17, 1999 /s/ J. DOUGLAS RAMSEY ---------------------------------- J. Douglas Ramsey, Ph.D. Director, Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
March 17, 1999 /s/ JEFFREY D. BENJAMIN ---------------------------------- Jeffrey D. Benjamin Director
March 17, 1999 /s/ EARL E. ELLIS ---------------------------------- Earl E. Ellis Director
March 17, 1999 /s/ JEFF M. MOORE ---------------------------------- Jeff M. Moore Director
- 55 -
March 17, 1999 /s/ J. MICHAEL MUCKLEROY ---------------------------------- J. Michael Muckleroy Director
March 17, 1999 /s/ BOONE PICKENS ---------------------------------- Boone Pickens Director
March 17, 1999 /s/ STEPHEN F. SMITH ---------------------------------- Stephen F. Smith Director
- 56 - INDEX TO EXHIBITS
- 57 -
------------------
- 58 -