ITEM 1. BUSINESS ------- ---------
GENERAL - -------
Energy Corporation of America (the "Company") is a privately held, integrated energy company primarily engaged in natural gas distribution in West Virginia and in the development, production, transportation and marketing of natural gas and oil, primarily in the Appalachian Basin. The Company was formed in June 1993 through an exchange of shares with the common stockholders of Eastern American Energy Corporation ("Eastern American"). For the fiscal year ended June 30, 1999, the Company had total revenues of $286.0 million and EBITDA (earnings before interest, taxes, depreciation and amortization) of $28.5 million.
The Company conducts business through its principal wholly owned subsidiaries, Mountaineer Gas Company ("Mountaineer"), Eastern American, Westech Energy Corporation ("Westech") and Westech Energy New Zealand Limited ("WENZL"). Mountaineer owns and operates the largest natural gas distribution utility in West Virginia. Eastern American is one of the largest oil and gas operators in the Appalachian Basin, including exploration, development and production, and is engaged in the transportation and marketing of natural gas. Westech is involved in oil and gas exploration and development in the Rocky Mountain region. WENZL is involved in oil and gas exploration and development in New Zealand.
The principal offices of the Company are located at 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237, and the telephone number is (303) 694-2667.
As used herein the "Company" refers to the Company alone or together with one or more of its subsidiaries.
SEGMENT INFORMATION - --------------------
The Company's principal businesses constitute three operating segments. For financial information on these segments, see Note 19 to the Consolidated Financial Statements.
NATURAL GAS DISTRIBUTION UTILITY - -----------------------------------
Mountaineer owns the largest natural gas distribution system in West Virginia, consisting of approximately 3,900 miles of natural gas distribution pipelines. Mountaineer provides natural gas sales and transportation services to approximately 201,000 residential, commercial, industrial and wholesale customers in 45 of the 55 counties in West Virginia, including the cities of Charleston, Beckley, Huntington and Wheeling. During fiscal 1999, Mountaineer sold or transported 57 Bcf of gas.
Mountaineer continues to pursue expansion of its customer base and to this end acquired substantially all of the West Virginia assets of Shenandoah Gas Company effective July 1, 1999 at a cost of approximately $12.6 million. The acquired assets consist of natural gas distribution facilities and related equipment, including approximately 3,600 customers, located in the eastern panhandle of West Virginia.
COMPARATIVE GAS SALES AND TRANSPORTATION DATA - --------------------------------------------------
The table below sets forth certain information with respect to the operating revenue and related gas volumes of the utility for the years ended June 30:
- ------ GAS SUPPLY - -----------
On September 30, 1998, Mountaineer entered into a Natural Gas Supply Management Agreement (the "Supply Agreement") with Coral Energy Resources, L.P. ("Coral") an affiliate of Shell Oil Company, pursuant to which Coral became the principal gas supplier for Mountaineer for a three-year period commencing as of November 1, 1998. The term of this Supply Agreement coincides with the three-year Rate Moratorium as discussed below.
The Supply Agreement with Coral provides that Coral will be responsible for supplying 100% of Mountaineer's annual gas requirements for the three-year term, less 2.7 Bcf of local production. The gas is supplied by Coral at a fixed price per dth at the city gate up to approximately 24.4 Bcf annually. Any volumes in excess of 24.4 Bcf on an annual basis are priced at the lesser of a specified index or a previously agreed upon maximum cost. As a result of the Supply Agreement Mountaineer will purchase approximately 90% of its natural gas supply from Coral. The remaining 10% of the gas supply will be purchased from local producers, including Company owned production. Because of the Coral Supply Agreement, during fiscal 1999, natural gas sold by Mountaineer that came from Company operated production declined from 43% to 23%.
Prior to the Supply Agreement, Mountaineer purchased its gas supply pursuant to a balanced portfolio of intermediate term (one to five years) and short term (less than one year) contractual arrangements from various sources, including supplies from the Gulf Coast and Appalachian regions of the United States. The following table sets forth the volume of natural gas purchased and percentage of total volume of natural gas purchases, with respect to those suppliers accounting for five percent or more of Mountaineer's purchases for the years ended June 30:
The following table sets forth certain information relating to Mountaineer's gas supply purchases for the years ended June 30:
TRANSPORTATION AND STORAGE CAPACITY - --------------------------------------
The gas purchased from producer/suppliers in the Gulf Coast region is transported through the interstate pipeline systems of Columbia Gulf Transmission Company ("Columbia Gulf"), Columbia Gas Transmission Corporation ("Columbia Gas"), and Tennessee Gas Pipeline Company ("Tennessee Gas") to Mountaineer's local distribution facilities in West Virginia. Approximately 83% of the gas purchased by Mountaineer in the Appalachian region is transported by Columbia Gas, with the balance transported by Tennessee Gas or directly delivered into Mountaineer's gas utility distribution system.
To ensure continuous, uninterrupted service to its customers, Mountaineer has in place long-term transportation and service agreements with Columbia Gas, Columbia Gulf and Tennessee Gas. These contracts cover a wide range of transportation services and volumes, ranging from firm transportation service to no-notice service and storage with such contracts expiring on various dates ranging from October 31, 2000 through October 31, 2004. Under the terms of the Supply Agreement, Coral has assumed the management and the financial obligations of virtually all of Mountaineer's total firm transportation and storage entitlements. The combination of this Supply Agreement and the Rate Moratorium, discussed below, substantially reduces Mountaineer's exposure to gas cost fluctuations.
Gas sales and/or transportation contracts with interruption provisions have been used for load management by Mountaineer, and the gas industry as a whole, for many years. Under such contracts, the users purchase gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the gas is needed for higher priority customers. In addition, during times of special supply problems, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal and state regulatory agencies.
REGULATION AND RATES - ----------------------
Mountaineer is regulated by the Public Service Commission of West Virginia ("WVPSC"). Under traditional rate making in West Virginia, Mountaineer is prohibited from increasing its base rate unless it obtains the approval of the WVPSC. In general, the WVPSC reviews any requested base rate increase based upon an analysis of the cost of service, as adjusted for known and measurable changes in expenses and revenues, and a reasonable return on equity. In determining the overall rate of return on equity allowed in the rate proceeding, the WVPSC employs a methodology, which computes both the natural gas distribution utility's cost of debt capital as well as cost of equity capital. The allowable return on equity is designed to compensate the equity owner at rates commensurate with the rate of return on investments at comparable risks. In order to determine the allowable return on equity, the WVPSC utilizes two market-oriented methodologies; the discounted cash flow and the capital asset pricing model. A further review utilized by the WVPSC to check the reasonableness of the allowable return on equity involves an analysis of the overall return required to provide reasonable interest coverage, dividend pay-out ratios and internally generated cash flow. Finally, the WVPSC utilizes a sample group of approximately ten to twelve gas distribution utilities located within and outside of West Virginia for comparison purposes with respect to its discounted cash flow calculation and the capital asset pricing model. The cost of debt capital allowed is determined by utilizing the utility's actual interest rates as set forth in its loan documents, provided the rate is determined by the WVPSC to be reasonable. While the cost of debt capital is normally based on long-term debt, if the utility uses short-term debt on a regular basis, the WVPSC may determine that such debt should be treated as a component of the utility's debt capital. Because the rate regulatory process has certain inherent time delays, rate orders may not reflect the operating costs at the time new rates are put into effect.
Any change to the rate that Mountaineer charges its customers for natural gas costs must be approved by the WVPSC. In order to obtain approval of changes to gas purchase costs, Mountaineer makes purchase gas adjustment filings with the WVPSC on an annual basis which include a forecast for the upcoming twelve month period of gas costs and a true-up mechanism for the previous period for any over or under-recovery balances. The WVPSC reviews Mountaineer's gas purchasing activities during the previous year to determine the prudence of gas purchase expenditures and to determine that dependable lower-priced supplies of natural gas are not readily available from other sources. The forecast of gas costs submitted by Mountaineer in its annual filings incorporates known and measurable pipeline fees during the upcoming period and an estimate of gas costs based on several natural gas futures indices. The WVPSC also reviews Mountaineer's forecast of gas costs in such filings for reasonableness.
All of the requests of natural gas distribution utilities in West Virginia for rate changes are reviewed by the staff of the WVPSC as well as the Consumer Advocate Division of the WVPSC. The Consumer Advocate Division is charged with representing and protecting the interests of residential customers in regulating the utility.
Prior to October 1995, Mountaineer was subject to traditional regulatory rate making in West Virginia as that procedure is described above. However, following a proposal by Mountaineer, the WVPSC issued an order implementing a three-year rate moratorium effective November 1995. The moratorium provided rate certainty to Mountaineer's customers by fixing the price of gas for three years. By entering into the moratorium, Mountaineer assumed the risks and benefits of fixed utility rates, its gas purchasing activities, ancillary business activities and achieving operational efficiencies.
In January 1998, Mountaineer filed with the WVPSC for an increase in its base rates, effective upon expiration of the moratorium period on October 31, 1998. In July 1998, Mountaineer agreed to a Joint Stipulation and Agreement for Settlement with various parties including the staff of the WVPSC and the Consumer Advocate Division regarding Mountaineer's rate filing. Under the terms of the agreement, Mountaineer was granted an increase in its rates, which assuming certain weather conditions, would generate additional annual revenues of approximately $9.4 million. The agreement provides for a three year rate moratorium period from November 1, 1998 to October 31, 2001. The terms and conditions of the agreement are similar to those under which Mountaineer operated under the earlier moratorium period. Mountaineer is also required to make minimum capital expenditures of $9.0 million per year in its utility operations during the moratorium period. In addition, as a result of the Shenandoah Gas Company acquisition, Mountaineer is required to spend, at a minimum, an additional $1.5 million in capital expenditures over a three year period, ending October 31, 2001.
COMPETITION - -----------
Competition in the residential and commercial sales market from alternative energy sources is minimal in West Virginia. Such competition comes primarily from sources such as electricity, propane, and to a lesser degree, oil, coal and wood. However, natural gas continues to be the preferred fuel for West Virginia homes and businesses. Based on 1990 census data, approximately 51% of the occupied housing units in the state utilized natural gas for home heating, 25% utilized electricity, with fuel oil, coal and wood comprising the balance.
Mountaineer's demand from commercial and industrial customers is dependent on local business conditions and competition from alternate sources of energy. Demand from residential customers likewise is subject to competition from alternate energy sources. Mountaineer is also subject to competition from interstate and intrastate pipeline companies, natural gas marketers, producers and other utilities that may be able to serve commercial and industrial customers from their transmission, gathering and/or distribution facilities. In certain markets, gas has a competitive advantage over alternate fuels, while in other markets it is not as price competitive.
Mountaineer began offering gas transportation service to its industrial customers in 1984. The availability of both firm and interruptible transportation service, which enables industrial end users to purchase lower cost gas supplies directly from producers and/or natural gas marketers is an important factor in maintaining gas usage by those end users during periods of low residual oil prices. Continued evolution in the natural gas industry, resulting primarily from Federal Energy Regulatory Commission Order Nos. 436, 500 and 636, has served to increase the ability of large gas end users to bypass Mountaineer in obtaining gas supply and transportation services. Although no bypass by customers has occurred to date, Mountaineer generally realizes lower transportation revenues from large industrial and commercial end users due to the possibility of such a bypass. In addition, Mountaineer has negotiated reduced rates for certain end users to: (1) provide economic relief to aid the end user in remaining an ongoing concern; and (2) add an incentive to end users to add incremental load.
SEASONALITY - -----------
More than 95% of Mountaineer's residential and commercial customers use natural gas for heating purposes. Accordingly, a significant portion of Mountaineer's utility gas volumes are attributable to sales during the heating season, with highest sales volumes occurring in December, January and February. In fiscal 1999, gas sales from October through March accounted for approximately 78.1% of utility gas sales. Weather patterns experienced in the markets served by Mountaineer significantly impact the demand for natural gas sales, particularly during the peak heating season and, as a result, will have a significant impact on Mountaineer's financial performance, liquidity and capital resources.
GAS AND OIL EXPLORATION AND PRODUCTION - -------------------------------------------
The Company's proved net gas and oil reserves are estimated as of June 30, 1999 at 166 Bcf and 962 Mbbls, respectively. For the fiscal year ended June 30, 1999, the Company's net gas production was approximately 8.8 Bcf and net oil production was approximately 133.1 Mbbls, for a total of 9.6 net Bcfe. Revenues from the sale of oil and gas production accounted for 7.6% of the Company's consolidated revenues for 1999.
REGIONAL OPERATIONS - --------------------
APPALACHIAN BASIN. The Company holds interests in 4,783 gross (2,825 net) ------------------ wells in the Appalachian Basin and serves as operator of substantially all of such wells in which it has a working interest. The Company's proved gas and oil reserves attributable to its Appalachian Basin properties are estimated as of June 30, 1999 at 161 Bcfe, of which approximately 97% was gas reserves and 3% was oil reserves. For the fiscal year ended June 30, 1999, the Company's gas production from its Appalachian Basin properties was approximately 8.8 net Bcf. In the Appalachian Basin, the Company has interests in approximately 570,980 gross acres (433,550 net) of producing properties and an additional 112,890 gross acres (76,270 net) of undeveloped properties located primarily in West Virginia, Pennsylvania and Ohio. During fiscal 1999, the Company drilled 26 successful gross wells (19 net) and added 3.8 net Bcfe in reserves.
ROCKY MOUNTAINS. Westech owns developed and undeveloped leasehold ---------------- interests in approximately 455,000 gross acres (327,000 net) located in the Rocky Mountain area. The Company has identified and is currently focusing on five exploratory plays which are located in the Blanding Basin, Utah; Powder River Basin (Minnelusa-Muddy), Wyoming; Williston Basin, North Dakota; Wind River Basin, Wyoming and the Danforth area, Colorado. Commencing in June 1999, the Company entered into a 10 well exploratory drilling program in the Powder River Basin. Currently, six wells have been drilled, with one successful well.
INTERNATIONAL. WENZL currently operates four offshore permits and two ------------- onshore permits on the East Coast of the North Island of New Zealand, totaling 7,237,000 gross acres (3,618,500 net). Onshore, a total of six exploratory and four appraisal wells have been drilled. Currently, additional well testing is being performed to confirm the threshold deliverability requirements for commercialization. Offshore a 212 square mile 3-D survey has been acquired to define drillable prospects. WENZL has also been awarded three new onshore permits in the producing Taranaki Basin of the North Island of New Zealand totaling 20,000 gross and net acres. WENZL's obligations under these permits require a 10 square mile 3-D survey, which is planned during fiscal 2000. Westech is negotiating an agreement to acquire a 35% working interest in the Cooper Basin, Queensland, Australia. Two wells are planned during fiscal 2000.
OIL AND GAS RESERVES - -----------------------
The following information relating to estimated reserve quantities, reserve values and discounted future net revenues is derived from, and qualified in its entirety by reference to, the more complete reserve and revenue information and assumptions included in the Company's Supplemental Oil and Gas Disclosures at Item 8. The Company's estimates of proved reserve quantities of its properties have been subject to review by Ryder Scott Company, independent petroleum engineers. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve information represents estimates only and should not be construed as being exact. Future reserve values are based on year-end prices except in those instances where the sale of gas and oil is covered by contract terms providing for determinable escalation. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalations.
The following table sets forth the Company's estimated proved and proved developed reserves and the related estimated future value, as of June 30:
The following table sets forth the Company's estimated proved reserves and the related estimated future value by region, as of June 30, 1999:
PRODUCING WELLS - ----------------
The following table sets forth certain information relating to productive wells at June 30, 1999. Wells are classified as oil or gas according to their predominant production stream.
ACREAGE - -------
The following table sets forth the developed and undeveloped gross and net acreage held at June 30, 1999 (in thousands).
PRODUCTION - ----------
The following table sets forth certain production data and average sales prices attributable to the Company's properties for the years ended June 30:
DRILLING ACTIVITIES - --------------------
The Company's gas and oil exploratory and developmental drilling activities are as follows for the years ended June 30. The number of wells drilled refers to the number of wells commenced at any time during the respective fiscal year. A well is considered productive if it justifies the installation of permanent equipment for the production of gas or oil.
COMPETITION - -----------
The Company encounters substantial competition in acquiring properties, marketing oil and gas, securing equipment and personnel and operating its properties. The competitors in acquisitions, development, exploration and production include major oil companies, numerous independent oil and gas companies, gas marketers, individual proprietors and others. Many of these competitors have financial and other resources, which substantially exceed those of the Company and have been engaged in the energy business for a much longer time than the Company. Therefore, competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company will permit.
Natural gas competes with other forms of energy available to customers, primarily on the basis of price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for natural gas.
REGULATIONS AFFECTING OPERATIONS - ----------------------------------
The Company's operations are affected by extensive regulation pursuant to various federal, state and local laws and regulations relating to the exploration for and development, production, gathering, marketing, transportation and storage of oil and gas. These regulations, among other things, can affect the rate of oil and gas production. The Company's operations are subject to numerous laws and regulations governing plugging and abandonment, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations require the acquisition of a permit before drilling commences, restricts the types, quantities and concentration of various substances that can be released into the environment in connection with drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution which might result from the Company's operations.
GAS AGGREGATION AND MARKETING - ---------------------------------
The Company, primarily through the wholly owned subsidiary of Eastern American, Eastern Marketing Corporation ("Eastern Marketing"), aggregates natural gas through the purchase of production from properties in the Appalachian Basin in which the Company has an interest, the purchase of gas delivered through the Company's gathering pipelines located in the Appalachian Basin, the purchase of gas from smaller Appalachian Producers that are not large enough to have marketing departments, the purchase of gas produced in the Southwestern areas of the United States pursuant to contractual arrangements and the purchase of gas in the spot market. The Company sells gas to local gas distribution companies, industrial end users located in the Northeast, other gas marketing entities and into the spot market for gas delivered into interstate pipelines. The Company has historically attempted to balance its gas sales mix with approximately one-third of its total gas sales being made under long term contracts (contracts with terms of five years or more), one-third being sold under intermediate term contracts (contracts with terms of one to five years), and one-third being sold under short term contracts (contracts with terms of less than one year) or on a spot market basis. The demand for long term contracts has decreased substantially and no new long term contracts were entered into in fiscal year 1999. Volumes that became available from expired long term contracts were sold under intermediate and short term contracts.
The Company owns and operates approximately 2,100 miles of gathering lines and intrastate pipelines that are used in connection with its gas aggregation and marketing activities. In addition, the Company has entered into contracts with interstate pipeline companies that provide it with rights to transport specified volumes of natural gas. During the fiscal year ended June 30, 1999, the Company aggregated and sold an average of 95.7 Mmcf of gas per day, of which 39.7 Mmcf per day represented sales of gas produced from wells operated by the Company. This represents a decrease compared to fiscal year 1998, during which the Company aggregated and sold an average of 129.5 Mmcf of gas per day.
GAS SALES AND PURCHASE CONTRACTS - -------------------------------------
The termination of one long term and one intermediate term sales contract resulted in the 33.8 Mmcf per day decrease in sales in fiscal year 1999. The sale of gas on a contract basis to the Company's natural gas distribution utility expired on October 31, 1998 (23.8 Mmcf per day). The Company elected not to renew the contract, allowing both parties to seek more economical sales and purchases of natural gas from independent third parties.
The Company satisfied its obligations under all gas sales contracts in fiscal year 1999 through gas production attributable to its own interests in oil and gas properties and through production attributable to third party interests in oil and gas properties (14.5 Bcf in fiscal 1999), and from natural gas aggregated by the Company pursuant to its aggregation and marketing activities from third parties (20.5 Bcf in fiscal 1999).
Eastern American has a gas sales contract with Hope Gas, Inc. ("Hope"), a subsidiary of Consolidated Natural Gas, which requires Eastern American to sell up to 4,000 but not less than 1,500 Mmbtu per day during the winter months of November through March to Hope through December 31, 2001. Pricing under the contract requires Hope to pay Eastern American a ten cent premium above the posted Appalachian Index.
In March 1993, the Company conveyed to the Eastern American Natural Gas Trust (the "Royalty Trust"), a trust whose units are traded on the New York Stock Exchange, certain net profits interests derived from the Company's working interest in certain natural gas properties located in the Appalachian Basin whose production is eligible for tax credits under Section 29 of the Internal Revenue Code. In connection with the Royalty Trust, Eastern Marketing entered into a gas purchase contract to purchase all gas production attributable to the Royalty Trust until termination of the Royalty Trust in May 2013. The purchase price under this gas purchase contract through December 1999 is based in part on a fixed price component, which escalates each year, and in part on a variable price component, which fluctuates with certain spot market prices, provided that the purchase price during such period will not be less than a specified floor price. The floor price was $2.84 per Mcf in calendar year 1998 and is $3.09 per Mcf in calendar year 1999. The fixed price component was $3.39 in calendar year 1998 and is $3.56 in calendar year 1999. The variable price is equal to the future contract price per Mmbtu for natural gas delivered to Henry Hub, Louisiana plus $0.30 per Mmbtu, multiplied by 110% to reflect a fixed adjustment for Btu content. The fixed price component is given a weighting of 66 2/3% and the variable price component is given a weighting of 33 1/3% through December 1999. Beginning in January 2000, the purchase price under this gas purchase contract will be determined solely by reference to the variable price component without regard for any minimum purchase price. Eastern American is a party to a standby performance agreement with the Royalty Trust to support the obligations of Eastern Marketing under this gas purchase contract.
MARKET POSITION - -----------------
During fiscal 1999, Eastern Marketing purchased call options on 5,000 Mmbtu of natural gas per day for the period March 1999 through October 1999. The options were purchased for approximately $0.4 million, or $0.31 per Mmbtu. The options provided the Company with the right to purchase up to 5,000 Mmbtu per day during the option period at a price of $2.25 per Mmbtu.
MARKETING FOCUS CHANGE - -------------------------
At the close of the 1999 fiscal year, it was determined that Eastern Marketing would no longer enter into contracts to purchase independent producers gas as this business was becoming less economical to maintain each year. The strong competition among various marketing companies for this business is causing margins to "shrink" each year, and in the Company's opinion, this type of business is rapidly losing its economic validity. Third party contract business is labor intensive, requiring a sales staff and related accounting services. It is the intention of Eastern Marketing to sell this portion of its business, provided an acceptable offer can be achieved, or to operate the existing contracts until they expire. Most of the effected contracts expire within a one year period. With this new marketing focus, Eastern Marketing should be better poised to concentrate its efforts on marketing Eastern American's natural gas.
REGULATIONS AFFECTING MARKETING AND TRANSPORTATION - ------------------------------------------------------
As a marketer of natural gas, the Company depends on the transportation and storage services offered by various interstate and intrastate pipeline companies for the delivery and sale of its own gas supplies as well as those it processes and/or markets for others. Both the performance of transportation and storage services by interstate pipelines and the rates charged for such services are subject to the jurisdiction of the FERC. In addition, the performance of transportation and storage services by intrastate pipelines and the rates charged for such services are subject to the jurisdiction of state regulatory agencies.
EMPLOYEES - ---------
As of June 30, 1999, the Company had approximately 760 full-time employees. Approximately 290 employees are covered by six separate collective bargaining agreements. None of these agreements will expire during the next fiscal year. Management believes that its relationship with its employees is good.
ITEM 2.
ITEM 2. PROPERTIES ------- ----------
See Item 1. Business, for information concerning the general location and characteristics of the important physical properties and assets of the Company and information regarding production, reserves, development and interests in oil and gas producing properties of the Company.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS ------- -----------------
The Company is involved in various legal actions and claims arising in the ordinary course of business. While the outcome of these lawsuits against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the Company's operations or financial position.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ------- ---------------------------------------------------
No matters were submitted to a vote of security holders during the fourth quarter of fiscal year 1999.
PART II -------
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK ------- ---------------------------------------- AND RELATED STOCKHOLDER MATTERS -------------------------------
The Company's common stock is not traded in a public market. As of September 1, 1999, the Company had 25 holders of record of its common stock.
The Company declared dividends in fiscal years 1999, 1998 and 1997 of $644,505, $1,131,000 and $1,007,000, respectively.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA ------- -----------------------
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF ------- -------------------------------------------------- OPERATIONS AND FINANCIAL CONDITION ----------------------------------
The following should be read in conjunction with the Company's Financial Statements and notes (including the segment information) at Item 8 and the Selected Financial Data at Item 6.
This discussion and analysis of financial condition and results of operations, and other sections of this Form 10-K, contain forward-looking statements that are based on management's beliefs, assumptions, current expectations, estimates and projections about the oil and gas industry, the economy and about the Company itself. Words such as "anticipates," believes," "estimates," "expects," "forecasts," "intends," "is likely," "plans," "predicts," "projects," variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence. Therefore, actual results and outcomes may materially differ from what may be expressed or forecasted in such forward-looking statements. Furthermore, the Company undertakes no obligation to update, amend or clarify forward-looking statements, whether as a result of new information, future events or otherwise.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to, weather conditions, changes in production volumes, worldwide demand and commodity prices for petroleum natural resources, the timing and extent of the Company's success in discovering, acquiring, developing and producing oil and natural gas reserves, risks incident to the drilling and operation of oil and natural gas wells, future production and development costs, the effect of existing and future laws, governmental regulations and the political and economic climate of the United States and New Zealand, the effect of hedging activities, and conditions in the capital markets.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1999 AND 1998 - --------------------------------------------------------------------------------
The Company recorded a net loss of $14.9 million for the year ended June 30, 1999 compared to net income of $3.0 million for the same period in 1998. The decrease in income of $17.9 million is attributed to a $78.7 million decrease in revenue, which was partially offset by a $60.7 million decrease in operating expenses, an $11.1 million increase in impairment and exploratory costs, a $3.9 million increase in other income and a $7.2 million increase in income tax benefits.
OPERATING MARGINS. Operating Margins (defined as revenue less operating ------------------ costs, taxes other than income taxes, and direct general and administrative expense) for the Company's operating subsidiaries totaled $49.4 million for the current year compared to $33.9 million for the prior period. The Company's Utility Operating Margin (defined as total revenue less utility gas purchased, utility operations and maintenance expense, taxes other than income taxes and direct general and administrative expense) totaled $32.6 million for the current period versus $20.8 million for the prior year. The Company's Oil and Gas Operating Margin (defined as oil and gas sales and well operations and service revenues less field operating expenses, taxes other than income, and direct general and administrative) totaled $12.3 million versus $15.4 million for the prior year. The Company's Marketing and Pipeline Operating Margin (defined as gas marketing and pipeline sales less gas marketing pipeline cost of sales) totaled $4.5 million for the current period versus a loss of $2.3 million for the prior period.
REVENUES. Total revenues decreased $78.7 million or 21.6% during the -------- periods. The decrease was due to a 32.4% decrease in gas marketing and pipeline sales, a 12.0% decrease in oil and gas sales, and a 95.6% decrease in other operating revenue. Utility gas sales and transportation and well and service operating revenue remained relatively constant between the periods.
Revenues from gas marketing and pipeline sales decreased $46.6 million from $144.1 million during the period ended June 30, 1998 to $97.5 million in the period ended June 30, 1999. The decrease in revenue is primarily attributable to a 12% decrease in the average unit price from $2.63 to $2.32 and a 27% decline in marketed volumes from 50.7 million dth at June 30, 1998 to 37.2 million dth at June 30, 1999. The decrease in volumes is primarily a result of the termination of two contracts that accounted for 9.5 Bcfe and reduced volumes associated with trading activities. See other operating revenue, discussed below.
Revenues from oil and gas sales decreased $3.0 million from $24.7 million for the period ended June 30, 1998 to $21.7 million for the period ended June 30, 1999. The decrease in revenue is primarily attributable to a 29.6% decrease in the average oil sales price from $15.30 to $10.76 per Bbl and an 8.59% decrease in the average gas sales price from $2.52 to $2.30 per Mcf between June 30, 1998 and June 30, 1999. The price decline was partially offset by production increasing 6.21% for oil and 1.23% for gas.
Other operating revenues decreased $30.8 million from $32.2 million to $1.4 million between the periods. This was primarily because 1998 included revenue from the termination of a long-term gas delivery contract. See Note 17 to the Consolidated Financial Statements for discussion.
COSTS AND EXPENSES. The Company's costs and expenses decreased $60.7 -------------------- million or 18.9% during this period primarily as the result of a 13.3% decline in the cost of utility gas purchased, a 36.5% decrease in gas marketing and pipeline costs, which was partially offset by a 7.6% increase in general and administrative expenses, a 10.0% increase in depreciation, depletion and amortization and a 134.7% increase in impairment and exploratory costs. Field and lease operating expenses, utility operations and maintenance costs and taxes other than income remained relatively constant between the periods.
The $11.3 million decline in the cost of utility gas purchased was primarily the result of the nonrecurring effect of the initial implementation of Mountaineer's gas supply management agreement with a third party, which was effective November 1, 1998.
The $53.4 million decrease in gas marketing and pipeline costs is primarily the result of a 27% decline in purchased gas volumes from 51.1 Bcfe to 37.6 Bcfe from June 30, 1998 and June 30, 1999. Contributing to the decline in costs was a 15% decrease in the average price paid for gas purchased, from $2.67 per Mmbtu to $2.26 per Mmbtu between the respective periods. Additionally, approximately $2.4 million of purchased gas costs was charged against a reserve for losses on future gas purchases, which was primarily related to the contract settlement. See Note 17 to the Consolidated Financial Statements for discussion.
General and administrative expense increased $1.8 million as a result of higher labor and benefit costs at the utility and increased overhead at the corporate level.
Depreciation, depletion and amortization costs increased $2.0 million primarily due to additions to the utility gas plant in service and corporate fixed assets.
Impairment and exploratory expenses increased $11.1 million primarily due to the current year cost of drilling exploratory dry holes of $5.9 million in New Zealand and $1.6 million domestically. In addition, approximately $2.2 million of leasehold and well in progress costs were written off late in fiscal 1999.
INTEREST EXPENSE. Interest expense remained relatively constant between ----------------- the periods.
OTHER (INCOME) EXPENSE. Other income increased $3.9 million primarily due ----------------------- to the recognition of gains on the sale of property during fiscal 1999, compared to losses in the prior year. Also, during fiscal 1998 a reserve of $1.1 million was established against a note receivable.
PROVISION FOR INCOME TAXES. The provision for income taxes changed $7.2 ----------------------------- million primarily because of the current year loss.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1998 AND 1997 - --------------------------------------------------------------------------------
The Company recorded net income and income before extraordinary loss of $3.0 million for the year ended June 30, 1998 compared to a net loss of $5.8 million and income before extraordinary loss of $2.0 million for the same period in 1997. The increase in income before extraordinary loss of $1.0 million is attributed to the contract settlement under which the company received approximately $30 million (net) in cash and related partnership distributions as described in Note 17 to the Consolidated Financial Statements. The increase resulting from the contract settlement was partially offset by a $15 million decrease in operating income resulting generally from the effects of a warmer heating season resulting in a $1.3 million reduction in operating income, lower oil and gas sales, and lower gas marketing and pipeline margins resulting in a $12.5 million reduction in operating income and increased corporate expenses of $1.0 million. Additionally, interest expense increased $2.5 million and gain on sales of assets and other income and expenses decreased $11.7 million between the two periods.
OPERATING MARGINS. Total Operating Margins for the Company's operating ------------------ subsidiaries totaled $33.9 million for 1998 compared to $50.6 million for 1997. The Company's Utility Operating Margin decreased from $22.3 for 1997 to $20.8 million for 1998. The Company's Oil and Gas Operating Margin decreased from $18.9 million for 1997 to $15.4 million for 1998. The Company's Marketing and Pipeline Operating Margin decreased from $9.3 million for the prior year to a loss of $2.3 million for the current year.
REVENUES. Total revenues decreased $9.6 million or 2.6% during the -------- periods. The decrease was due to a 9.7% decrease in utility gas sales and transportation, an 10.1% decrease in gas marketing and pipeline sales and a 25.9% decrease in oil and gas sales, which were partially offset by a $31.9 million increase in other operating revenue. See Note 17 to the Consolidated Financial Statements for discussion.
Revenues from utility gas sales and transportation decreased $16.9 million or 9.7% from $173.5 million during the year ended June 30, 1997 to $156.6 million for the same period ended June 30, 1998. The decrease is primarily due to approximately 3.0 million Mcf less in volumes of gas sold as a result of a 6.3% decrease in the weighted average number of Degree Days in the current period, partially offset by a 3.2% increase in transportation revenue due to increased usage by commercial and industrial customers.
Revenues from gas marketing and pipeline sales decreased $16.2 million from $160.3 million during the period ended June 30, 1997 to $144.1 million in the period ended June 30, 1998. The decrease in revenue is primarily attributable to a 3.7% decrease in the average unit price and a 7.5% decline in marketed volumes from 56.0 million dth at June 30, 1997 to 51.8 million dth at June 30, 1998. The decrease in volumes is a result of a change in pipeline sales and transportation components, discontinued pipeline sales to a customer, and reduced volumes associated with trading activities.
Revenues from oil and gas sales decreased $8.6 million from $33.3 million for the period ended June 30, 1997 to $24.7 million for the period ended June 30, 1998. The decrease in revenue is primarily attributable to a 22.9% decline in units sold from 12.4 Bcfe at June 30, 1997 to 9.3 Bcfe and a 3.9% decrease in the average unit sales price from $2.69 to $2.58 per Mcfe for the respective periods. The 22.9% decline in units sold between June 30, 1997 and 1998 was primarily as a result of the sale of the Company's limited partnership interests in Westside Operating Partnership LP ("WOPLP"), which accounted for 2.7 Bcfe and 96.8% of the total decline in units sold. The sale of WOPLP occurred in March 1997.
Other operating revenues increased $31.9 million between the periods primarily as a result of an agreement to terminate an existing long-term gas delivery contract. See Note 17 to the Consolidated Financial Statements for discussion.
COSTS AND EXPENSES. The Company's costs and expenses decreased $25.0 -------------------- million or 7.0% during this period primarily as the result of a 15.5% decline in the cost of utility gas purchased, a 3.0% decrease in gas marketing and pipeline costs, a 29.5% decline in the field and lease operating expenses and an 18.4% decline in impairment and exploratory expenses.
The $15.6 million decline in the cost of utility gas purchased was the result of a decrease in purchased gas volumes of 3.7 Bcf and a decrease in the average commodity price of natural gas of approximately $0.15 per Mcf purchased and a $1.9 million decrease in demand charges resulting primarily from a rate settlement with Columbia Gas Transmission Corporation during fiscal year 1997.
The $4.6 million decrease in gas marketing and pipeline costs is the result of a 3.9 million dth decline in volumes marketed offset by a $0.09 increase in the average unit cost of gas sold during fiscal year 1997.
The $4.1 million decline in field and lease operating expense was primarily the result of the reduction in operating costs of $3.5 million associated with the sale of the limited partnership interests previously discussed.
Utility operations and maintenance costs increased 3.8% as a result of increased outside services ($0.3 million) and increased labor costs ($0.3 million)
General and administrative expense increased 3.0% as a result of the inclusion of the selling expenses of Mapcom Systems, Inc. ($1.3 million) acquired by Mountaineer in November 1997 partially offset by generally lower expenses for outside services.
Taxes other than income decreased 7.5% generally as a result of lower revenues.
Impairment and exploratory expenses decreased $1.9 million primarily due to non-recurring write-offs of exploratory properties in fiscal 1997 resulting from decreased domestic exploratory activities and unsuccessful exploratory drilling.
Depreciation of pipelines, other property and equipment increased $1.7 million or 16.8% as a result of higher depreciation related to an increase in property in service and the effective depreciation rate.
Depletion and depreciation of oil and gas properties decreased $0.7 million. The decrease related to the sale of the WOPLP properties in fiscal year 1997 which accounted for 2.7 Bcfe of production partially offset by a 17.0% increase in depletion and depreciation rates.
INTEREST EXPENSE. Interest expense increased 10.5% from $23.9 million to ----------------- $26.4 million in the current year. The increase was due to the additional average long-term debt outstanding during the periods resulting from the issuance of the Senior Subordinated Notes and higher interest rates during the fiscal year ended June 30, 1998.
OTHER (INCOME) EXPENSE. Other income decreased $9.5 million primarily due ----------------------- to the sale of WOPLP, which occurred in March 1997 resulting in a gain of $7.8 million compared to a loss of $1.2 million on the disposal of certain oil and gas properties during the year ended June 30, 1998.
PROVISION FOR INCOME TAXES. The provision for income taxes excluding the ---------------------------- tax benefit for the extraordinary loss was relatively unchanged between the years.
EXTRAORDINARY LOSS. The extraordinary loss of $7.9 million (net of a $4.2 - -------------------- million tax benefit) recorded during the fiscal year ended June 30, 1997 was due to the early extinguishment of debt. In May 1997, the Company issued $200 million Senior Subordinated Notes using the proceeds therefrom to repay debt at Eastern Systems Corporation ("ESC") and Eastern American of $35 million and $136 million, respectively.
LIQUIDITY AND CAPITAL RESOURCES - ----------------------------------
Despite improved Operating Margins (as defined above) from the Company's operating subsidiaries, $49.4 million for the current period versus $33.9 million for the prior period, the Company's financial condition declined during the current period. The Company's consolidated working capital and funds available from unused short-term credit facilities and revolving credit facilities declined from $105.7 million at June 30,1997 to $89.5 million at June 30, 1998 and $37.3 million at June 30, 1999.
Historically, the Company's growth has been accomplished through direct investment in utility operations ($11.4 million 1999, $15.8 million 1998, $9.9 million 1997) and exploration and development drilling activities ($25.3 million 1999, $20.6 million 1998, $18.0 million 1997). These investments were primarily financed through a combination of cash provided from operations and through short and long-term debt financing consisting of $6.2 million cash provided by operating activities and $22.0 million in proceeds from debt facilities for the current period, $6.6 million (excluding $30.1 million from a non-recurring transaction) and $4.5 million respectively for the prior period and $11.4 million and $22.4 million for the period ending June 30, 1997.
In general, the investment return on the Company's capital expenditures for its utility subsidiary has enabled management of the utility to increase its Operating Margins and cash provided (used) from operations from $22.3 million and $(5.1) million in 1997, to $20.8 million and $25.2 million in 1998 to $32.6 million and $28.7 million in 1999, respectively. However, returns on the Company's investments in its oil and gas operating subsidiaries has fallen below expectations of management during the same three year period. Operating Margins and cash provided (used) in operations for the Company's oil and gas operating subsidiaries totaled $18.9 million and $14.2 million for 1997, $15.4 million and $6.3 million for 1998, and $12.3 million and $0.4 million in 1999, respectively. As a result of the lower than expected returns on the Company's investments in its oil and gas operating subsidiaries, the Company's primary sources of liquidity (cash provided by operating activities and short and long-term debt) has been adversely impacted.
In addition to, and primarily as a result of the foregoing, the Company was in violation of certain covenants of its Revolving Debt Agreement at June 30, 1999 relating to (1) Tangible Net Worth, (2) Current Ratio, and (3) Minimum Interest Coverage Ratio. The Company's lenders have not accelerated the debt. However, as a result of the non-monetary violations described above, the Company was prohibited from drawing down additional borrowings under the Revolving Debt Agreement. Moreover, if the debt had been accelerated, the Company would have been required to repay the $25 million drawn under the Revolving Debt Agreement. Furthermore, an acceleration of the debt under the Revolving Debt Agreement would have also triggered a cross-default provision of the Company's $200 million Senior Subordinated Notes. Under this circumstance, the Company would have considered various alternatives, including seeking new and or additional credit facilities, the sale of certain assets, or other options, to acquire such funds or restructure its debt.
Since June 30, 1999, the Company and its lenders have agreed to amend the Revolving Debt Agreement to include (1) a reduction of the credit availability under the Revolving Debt Agreement from $50 million to $22 million, (2) a waiver of the non-monetary violations as described above, and (3) certain amendments to the Revolving Debt Agreement which would restructure certain financial covenants as follows (a) Tangible Net Worth, as defined in the Amendment, will not be less than $20 million plus fifty percent (50%) of Consolidated Net Income earned during the period from June 30, 1997, after adding back approximately $19 million, (b) Current Ratio, as defined in the Amendment, requirement from 1 to 1 to 0.6 to 1 through December 30, 1999 and 1 to 1 thereafter, such current ratio calculation shall be calculated without including any payments of principal on the Notes or Subordinated Notes which might be required to be repaid within one year from the time of the calculation, and (c) Interest Coverage ratio, as defined in the Amendment, reduced from a minimum of 1.5 to 1 to 1.15 to 1 for the next four quarters and 1.5 to 1 thereafter, except that Adjusted EBITDA, as defined in the Amendment, and as utilized in the numerator within such calculation shall have an amount of $19 million added thereto and such adjustment shall be effective for the calculation during the fiscal quarters ended September 30, 1999, December 31, 1999, March 31, 2000, and June 30, 2000.
As part of the foregoing waivers and amendments, the Company has agreed to (1) make an immediate principal reduction payment of $3 million, (2) make four consecutive quarterly principal payments of $750,000, (3) set the interest rate on borrowed amounts at LIBOR plus 300 basis points, (4) pay certain fees totaling $335,000, and (5) permit subsequent redeterminations of the Borrowing Base as defined under the Revolving Debt Agreement, to be determined, at the discretion of the lenders, more than once during a fiscal year.
Mountaineer plans to issue approximately $40 million in unsecured, long-term notes during the fourth quarter of calendar 1999. The proceeds from this issuance will be used to reduce short-term borrowings ($16.8 million at June 30, 1999) and for general corporate uses of the utility. While this financing will significantly improve the consolidated current ratio, restrictions limit dividend and other payments to the Company from Mountaineer. Currently, Mountaineer has $67 million of unsecured revolving bank lines of credit, under which approximately $16.8 million (see above discussion) was drawn at June 30, 1999. Under Mountaineer's debt covenants, which restrict cash outflow, $7.3 million of dividends are available to the Company.
The Company believes that its existing capital resources and expected fiscal year 2000 results of operation will be sufficient for the Company to remain in compliance with the requirements of the amended Revolving Debt Agreement, and its Senior Subordinated Note Agreement, and to fund non-discretionary capital expenditures. However, although the Company expects that Operating Margins and cash provided from operations will improve, the Company can give no assurances that such improvements will be realized or that certain violations of the amended Revolving Debt Agreement and Senior Subordinated Note Agreement will not occur, since the future profitability, debt service capability and levels of capital resource as well as capital availability will depend to a great extent on future weather patterns, oil and gas prices, and future exploration and development drilling success. In the event that Operating Margins and cash provided from operations do not meet expectations of management or if additional debt covenant or debt service violations occur, the Company may elect to increase debt levels, restructure debt agreements, sell certain assets or operating subsidiaries, defer certain discretionary capital spending (including oil and gas exploration and development drilling activities), consolidate certain field operations, or take other actions to mitigate liquidity short-falls and remedy any foreseeable or potential debt covenant issues, although no assurances can be given that such actions will be successful.
YEAR 2000 COMPLIANCE. The year 2000 issue arose because many computer ---------------------- systems and software applications as well as embedded computer chips currently in use were constructed using an abbreviated date field that eliminates the first two digits of the year. On January 1, 2000, these systems, applications and embedded computer chips may incorrectly recognize the date as January 1, 1900. Accordingly, many computer systems and software applications, as well as embedded chips, may incorrectly process financial or operating information or fail to process such information completely. The company recognized this problem and is addressing its potential effects on its computer systems, software applications and operating assets.
The Company began its Year 2000 compliance efforts in 1996 and has substantially completed its assessment of its key business information systems to determine what issues, if any, exist regarding these systems' compliance with Year 2000 issues and is taking the necessary steps to ensure its systems will be compliant by the year 2000.
These steps include the purchase and implementation of an integrated application software package, that together with the associated hardware and external consulting resources, is expected to cost approximately $7.1 million. In addition, the Company is presently in the process of modifying existing operating and application systems that are not Year 2000 compliant and anticipates that it will be successful in completing such modifications before the calendar year ended 1999. With the exception of the new application package discussed above, the Company anticipates that it can complete the necessary modifications to its information systems to ensure Year 2000 compliance utilizing internal resources.
The costs associated with modification of existing information systems are expected to consist primarily of personnel expense for staff dedicated to the effort. The Company's policy is to expense these costs as incurred. The Company also may invest in new or upgraded technology, which has definable value lasting beyond 2000. In these instances, such as the implementation of the integrated software application discussed above, the Company anticipates capitalizing and depreciating such costs over their estimated useful life.
In addition to reviewing its own computer operating and application systems, the Company has initiated communications with its significant suppliers and vendors to determine the extent to which these parties have addressed Year 2000 issues. To the extent such vendors cannot provide reasonable assurances to the Company of their readiness to handle Year 2000 issues, contingency plans will be developed. There is no assurance that such parties can complete the necessary modifications and conversions in a timely manner. To the extent such modifications and conversions are not completed on a timely basis and issues outside of the companies control arise, the Year 2000 issue could have an adverse impact on the operations of the Company.
The costs associated with addressing Year 2000 issues and the date on which the Company believes it will complete the necessary modifications are based upon management's best estimates. There can be no guarantee that these estimates will be achieved and actual results could differ from those anticipated.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES -------- ---------------------------------------- ABOUT MARKET RISK -----------------
INTEREST RATE RISK - ---------------------
Interest rate risk is attributable to the Company's debt. The Company utilizes United States dollar denominated borrowings to fund working capital and investment needs. There is inherent rollover risk for borrowings as they mature and are renewed at current market rates. The extent of this risk is not predictable because of the variability of future interest rates and the Company's future financing needs. If interest rates changed by 1%, it would have an impact of approximately $0.4 million. The Company has not attempted to hedge the interest rate risk associated with its floating rate debt of which $41.8 million was outstanding at year end. The Company has fixed interest rate debt of $261.7 million, representing 86.2% of the total debt.
COMMODITY RISK - ----------------
The Company's operations, as described in detail at Item 1 Business, consists primarily of exploring for, producing, aggregating and distributing natural gas and oil. The Company attempts to mitigate its commodity price risk by entering into a mix of short, medium and long-term supply contracts. Contracts to deliver gas at pre-established prices mitigate the risk to the Company of falling prices but at the same time limit the Company's ability to benefit from the effects of rising prices. The Company occasionally uses derivative instruments to hedge its commodity price risk. Notwithstanding the above, the Company's future cash flows from gas and oil production are exposed to significant volatility as commodity prices change.
The Company periodically enters into hedging activities on a portion of its projected natural gas production through a variety of financial and physical arrangements intended to support natural gas prices at targeted levels and to manage its exposure to price fluctuations. The Company may use futures contracts, swaps, options and fixed price physical contracts to hedge its commodity prices. Realized gains and losses from the Company's price risk management activities are recognized in oil and gas sales when the associated production occurs. The Company does not hold or issue derivative instruments for trading purposes. For fiscal 2000, the Company has elected to enter into a combination of forward sale collars and floors, covering the majority of its Appalachian natural gas.
Mountaineer has entered into a new rate moratorium with the WVPSC through 2001 thereby potentially exposing itself to volatility in its gas supply costs. If such risk was left unhedged, its future cash flows could vary significantly from historical cash flows. Mountaineer has entered into the Supply Agreement with Coral, under which Mountaineer will purchase approximately 90% of its natural gas supply at a fixed cost for the full duration of the rate moratorium thereby substantially reducing its exposure to market volatility.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ------- -------------------------------------------
INDEPENDENT AUDITORS' REPORT - ------------------------------
To the Stockholders and Board of Directors of Energy Corporation of America:
We have audited the accompanying consolidated balance sheets of Energy Corporation of America and Subsidiaries as of June 30, 1999 and 1998, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended June 30, 1999. Our audits also included the financial statement schedules listed in the Index at Item 14. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Corporation of America and Subsidiaries as of June 30, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 1999 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP Denver, Colorado September 27, 1999
See notes to consolidated financial statements. (Continued)
See notes to consolidated financial statements. (Concluded)
See notes to consolidated financial statements.
See notes to consolidated financial statements.
See notes to consolidated financial statements.
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997 - ---------------------------------------------------------
1. NATURE OF ORGANIZATION
Energy Corporation of America (the "Company") was formed in June 1993 through an exchange of shares with the common stockholders of Eastern American Energy Corporation ("Eastern American"). The Company is an independent integrated energy company. All references to the "Company" include Energy Corporation of America and its consolidated subsidiaries.
Natural Gas Distribution System - The Company operates, through its wholly owned - ------------------------------- subsidiary Mountaineer Gas Company ("Mountaineer"), a natural gas distribution system in West Virginia. Mountaineer provides natural gas sales, transportation and distribution service to residential, commercial, industrial and wholesale customers. As a public utility, Mountaineer is subject to regulation by the Public Service Commission of West Virginia ("WVPSC").
Oil and Gas Exploration, Development, Production and Marketing - The Company, - ----------------------------------------------------------------- primarily through Eastern American, is engaged in exploration, development and production, transportation and marketing of natural gas primarily within the Appalachian Basin of West Virginia, Pennsylvania and Ohio.
The Company, through its wholly owned subsidiaries Westech Energy Corporation ("Westech") and Westech Energy New Zealand Limited ("WENZL"), is also engaged in the exploration for and production of oil and natural gas primarily in the Rocky Mountains and New Zealand.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following is a summary of the significant accounting policies followed by the Company.
Principles of Consolidation - The consolidated financial statements include the - ---------------------------- accounts of the Company; Eastern American and its subsidiaries; Eastern Systems Corporation ("ESC") and its wholly owned subsidiary, Mountaineer and its subsidiaries; Westech and WENZL and its investment in certain New Zealand oil and gas exploration joint ventures. The Company has investments in oil and gas limited partnerships and joint ventures and has recognized its proportionate share of these entities' revenues, expenses, assets and liabilities. All significant intercompany transactions have been eliminated in consolidation except gas sales between Eastern American and Mountaineer (see Note 14).
The Company owned an 80% interest in a limited partnership, Westside Operating Partnership LP ("WOPLP"), until the end of March 1997 (see Note 3). This investment had been consolidated prior to March 31, 1997 (see Note 12).
Fourth Quarter Results - During the fourth quarter of fiscal 1999, the Company - ------------------------ had the normal weather related decline in earnings and unproved property impairments. However, due to significantly more drilling and other exploratory related activities in New Zealand and the Rocky Mountains, the fourth quarter loss is greater than usual.
Cash and Cash Equivalents - Cash and cash equivalents include short-term - ---------------------------- investments maturing in three months or less from the date acquired.
Property, Plant and Equipment - Oil and gas properties are accounted for using - ------------------------------- the successful efforts method of accounting. Under this method, certain expenditures such as exploratory geological and geophysical costs, exploratory dry hole costs, delay rentals and other costs related to exploration are recognized currently as expenses. All direct and certain indirect costs relating to property acquisition, successful exploratory wells, development costs, and support equipment and facilities are capitalized. The Company computes depletion, depreciation and amortization of capitalized oil and gas property costs on the units-of-production method using proved developed reserves. Direct production costs, production overhead and other costs are charged against income as incurred. Gains and losses on the sale of oil and gas property interests are generally recognized as income.
The provision for depreciation of Mountaineer's utility plant is based on a composite straight-line method. The average composite depreciation rate was 3.98%, 3.73% and 3.77% for 1999, 1998 and 1997, respectively. Mountaineer's property, plant and equipment includes capitalized overhead for payroll related costs and administrative and general expenses and an allowance for funds used during construction in accordance with WVPSC policies.
Other property, equipment, pipelines and buildings are stated at cost and are depreciated using straight-line and accelerated methods over estimated useful lives ranging from three to 30 years. During fiscal 1999, $8.6 million of retired other property and equipment was charged against its related accumulated depreciation.
Repairs and maintenance costs are charged against income as incurred; significant renewals and betterments are capitalized. Gains or losses related to retirement of utility property, net of any salvage and cost of removal are credited or charged to accumulated depreciation. Gains and losses on dispositions of other property, equipment, pipelines and buildings are recognized as income.
At June 30 property, plant and equipment consisted of the following (in thousands):
Long-Lived Assets - Statement of Financial Accounting Standards ("SFAS") No. - ------------------ 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", requires all companies to assess long-lived assets and assets to be disposed of for impairment and requires rate-regulated companies to write-off regulatory assets whenever those assets no longer meet the recognition criteria as defined by SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation". For the three years ended June 30, 1999, the Company determined that no impairment needed to be recognized for applicable assets.
Gas in Storage - Gas in storage is stated at the lower of average cost or market - -------------- value.
Deferred Financing Costs - Certain legal, underwriting fees and other direct - -------------------------- expenses associated with the issuance of credit agreements, lines of credit and other financing transactions have been capitalized. These financing costs are being amortized over the term of the related credit agreement.
Foreign Currency Translation - The translation of applicable foreign currencies - ----------------------------- into U.S. dollars is performed for balance sheet accounts using current exchange rates in effect at the balance sheet date and for revenue and expense accounts using an average exchange rate during the period. The cumulative translation adjustment is included in stockholders' equity.
Income Taxes - Deferred income taxes reflect the impact of "temporary - ------------- differences" between assets and liabilities recognized for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined in accordance with SFAS No. 109, "Accounting For Income Taxes".
Gas Delivery Obligation - Gas delivery obligation represents deferred revenues - ------------------------- on gas sales where the Company has received an advance payment. The Company recognizes the actual gas sales revenue in the period the gas delivery takes place.
Revenues and Purchased Gas Costs - Utility gas sales and transportation revenues - -------------------------------- included in income are based on amounts billed to customers on a cycle basis and estimated amounts for gas delivered but unbilled at the end of each accounting period.
Gas costs are expensed as incurred. For the years ended June 30, 1999, 1998 and 1997, purchased gas costs included $2.8 million, $4 million and $4 million, respectively, in amortization of overrecovered gas costs recorded prior to November 1, 1995. (See Note 18).
Oil and gas sales are recognized as income when the oil or gas is produced and sold.
Stock Compensation - As permitted under SFAS No. 123, "Accounting for - ------------------- Stock-Based Compensation", the Company has elected to continue to measure compensation costs for stock-based employee compensation plans using the intrinsic value method as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees".
Hedging Activities - The Company periodically hedges a portion of its oil and - ------------------- gas production through futures and swap agreements. The purpose of the hedges is to provide a measure of stability in the volatile environment of oil and gas prices. The Company recognizes gains and losses in the futures and swap agreements at the time the hedged volumes are sold as part of oil and gas revenues.
Use of Estimates - The preparation of financial statements in conformity with - ------------------ generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The Company's financial statements are based on a number of significant estimates including oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization and impairment of oil and gas properties. Management emphasizes that reserve estimates are inherently imprecise. In addition, utilization of tax credit carryforwards is based largely on estimates of future taxable income.
Regulatory Accounting - Mountaineer is subject to the provisions of SFAS No. 71, - --------------------- "Accounting for the Effects of Certain Types of Regulation." Accordingly, Mountaineer has recorded certain assets and liabilities that result from the effects of the ratemaking process that would not be recorded under generally accepted accounting principles for non-regulated entities. Such amounts are primarily related to future amounts recoverable for income taxes (see Note 6). Discontinuance of cost-based regulation or increased competition might require regulated entities to reduce their asset balances to reflect a market basis less than cost and to write off their associated regulatory assets and liabilities.
The Company has evaluated the continued applicability of SFAS No. 71, considering such factors as regulatory changes and the impact of competition. The Company cannot predict the likelihood of discontinuance of cost-based regulation in the future or the impact of increased competition on the Company's future financial position and results of operations.
Prior Year Reclassifications - Certain amounts in the financial statements of - ------------------------------ prior years have been reclassified to conform to the current year presentation.
Concentration of Credit Risk - The Company maintains its cash accounts primarily - ---------------------------- with a single bank and invests cash in money market accounts, which the Company believes to have minimal risk. As operator of jointly owned oil and gas properties, the Company sells oil and gas production to numerous U.S. oil and gas purchasers, and pays vendors on behalf of joint owners for oil and gas services. Both purchasers and joint owners are located primarily in the northeastern United States. The risk of nonpayment by the purchasers or joint owners is considered minimal. The Company as owner of a utility has receivables from both residential and commercial customers who are located in West Virginia, where no one customer constitutes a significant credit risk. The risk of nonpayment by purchasers, joint owners or utility customers has been considered in the Company's allowance for doubtful accounts.
Environmental Concerns - The Company is continually taking actions it believes - ----------------------- necessary in its operations to ensure conformity with applicable federal, state and local environmental regulations. As of June 30, 1999, the Company has not been fined or cited for any environmental violations, which would have a material adverse effect upon capital expenditures, earnings or the competitive position of the Company.
Recent Accounting Pronouncements - The Company adopted SFAS No. 130, "Reporting - --------------------------------- Comprehensive Income", effective July 1, 1998. The standard establishes rules for the reporting of comprehensive income and its components. The Company's comprehensive income (loss) consists of foreign currency translation adjustments and is presented in the Consolidated Statement of Stockholders' Equity. The adoption of SFAS No. 130 had no impact on the Company's total Stockholders' equity. Prior year financial statements have been reclassified to conform. In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" was issued, which is effective for all fiscal quarters of all fiscal years beginning after June 15, 2000. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets or liabilities in the Company's balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. The Company has not fully analyzed the impact of the provisions of SFAS No. 133 will have on the Company's financial statements.
Supplemental Disclosures of Cash Flow Information - Supplemental cash flow - ------------------------------------------------------ information for the years ended June 30 is as follows (in thousands):
3. DISPOSITIONS
Westside Operating Partnerships LP - In March 1997, the Company exchanged - ------------------------------------- warrants held representing a 30% ownership interest of a third party for a 30% interest in a newly formed oil and gas limited liability company, Breitburn Energy Company, LLC ("BEC"), the successor to WOPLP. BEC redeemed the Company's previous interest and purchased certain oil and gas properties, paying the Company $11.3 million plus a $1.5 million variable rate note with certain conversion options and distributing certain WOPLP oil and gas properties and real estate to the Company. The Company recognized a gain of $7.8 million in fiscal 1997 on the transaction. During fiscal 1999, BEC sold additional shares of stock, which reduced the Company's interest to approximately 25.35%. For accounting purposes, the Company's equity interest carrying value in BEC has been eliminated due to the recognition of its proportionate share of operating losses.
4. RISK MANAGEMENT
Options, Future Contracts, and Swap Agreements -The Company is a party to - --------------------------------------------------- natural gas options, future contracts and swap agreements in the normal course of business. These instruments involve, to varying degrees, elements of market and credit risk in excess of the amount recognized in the consolidated balance sheets.
At June 30, 1999, the Company had over-the-counter natural gas futures and options contracts related to gas sale commitments covering 3,553,000 Mmbtu of gas maturing through June 2000. As these contracts have been designated as hedges, any gains or losses resulting from market price changes will be included in oil and gas sales for the month to which the contract is applicable. The Company's net unrealized loss related to these contracts was approximately $88,000 at June 30, 1999.
In addition to futures and options contracts, the Company enters into over-the-counter price swap agreements to manage its exposure to commodity price risk under existing sales commitments. At June 30, 1999, the Company had swap agreements maturing from November 1999 through June 2000 covering 772,000 Mmbtu under which the Company receives a fixed price in exchange for a variable price. The Company's net unrealized gain related to these agreements was approximately $28,000 at June 30, 1999.
Also at June 30, 1999, the Company had natural gas fixed price purchase option contracts for the purchase and physical delivery of 615,000 Mmbtu of gas expiring through October 1999. The cost of these options, which totaled approximately $190,000 for the year ended June 30, 1999, is included in Cost of Gas Sales for the month to which the options were applicable. At June 30, 1999, the remaining options, for the months of July 1999 through October 1999, are carried at cost that totaled $189,875 and approximates fair value.
As of June 30, 1998, the Company had natural gas swap agreements maturing through October 1998 covering 320,000 Mmbtu. At June 30, 1998, the market value of these swaps, the net amount the Company would receive to terminate these swap agreements was nominal.
For the years ended June 30, 1999 and 1998, the Company recognized a net loss on its natural gas hedging activities of $32,240 and $47,000, respectively.
Fixed Price Gas Purchase Contracts - Mountaineer has entered into fixed price - ------------------------------------- contracts to purchase gas in the future. Effective November 1, 1998, Mountaineer entered into a contract with a third party to purchase up to 24 million dth of natural gas annually for a fixed price. The third party assumed management and financial obligation of Mountaineer's firm transportation and storage agreements. In addition, Mountaineer transferred ownership of all storage volumes owned on November 1, 1998 to the third party in exchange for the third party to provide delivery of such volumes during the fiscal 1999 heating season, which has been recorded as a current asset. The contract expires October 31, 2001.
5. DEBT
Long-Term Debt - At June 30 long-term debt consisted of the following (in - --------------- thousands):
The Company's various debt agreements contain certain restrictions and conditions among which are limitations on indebtedness, funding of certain subsidiaries, dividends and investments, and certain tangible net worth and debt and interest coverage ratio requirements. The agreements require the Company to maintain certain financial conditions, including a minimum net worth, restriction on funded debt and restrictions on the amount of dividends that can be declared. Additionally, under its debt covenants, Mountaineer is restricted in the payment of dividends to the Company. As of June 30, 1999, Mountaineer had approximately $7.3 million available for declaration of dividends.
Scheduled maturities of the Company's long-term debt at June 30, 1999 for each of the next five years and thereafter are as follows (in thousands):
Revolving Credit - The Company had a $50 million revolving credit facility - ----------------- secured by certain properties, interest and contracts. The interest rate is variable based on Eurodollars or other defined basis. The annual commitment fee ranges between 0.3% and 0.625% depending on usage. As of June 30, 1999, $25 million was outstanding under this facility. The Company was in violation of certain financial covenants including tangible net worth, current ratio and interest coverage at June 30, 1999. The lenders have waived the violations and amended the agreement. The amendment reduces the borrowing arrangement to $22 million, requires a principal reduction of $6 million during fiscal 2000 and an amendment fee of $335,000. Interest rates were increased as reflected above while the minimum financial covenant requirements were reduced through June 30, 2000.
Extinguishment of Debt - In May 1997, the Company issued $200 million senior - ------------------------ subordinated notes using the proceeds therefrom to repay debt outstanding at ESC and Eastern American of $35 million and $136 million, respectively. As a result, the Company recorded an extraordinary loss of $7.86 million, net of a tax benefit of $4.23 million.
Short-Term Debt - Mountaineer had unsecured bank lines of credit totaling $67 - ---------------- million and $74 million as of June 30, 1999 and 1998, respectively. During the years ended June 30, 1999 and 1998, the maximum outstanding balance was $53.2 million and $44.9 million, respectively, and the average daily balance was $32.5 million and $26.2 million, respectively. The weighted average interest rate was 5.5% and 6.02% on the balance outstanding during the years ended June 30, 1999 and 1998, respectively.
Other Credit Facilities - Eastern American had a $3 million and $6 million - ------------------------- letter of credit, as of June 30, 1999 and 1998, respectively, issued by a bank in support of Eastern American's obligations under a gas purchase contract with the royalty trust (see Note 15). The letter of credit reduces by $3 million on June 30 of each year until its expiration on June 30, 2000. As of June 30, 1999 and 1998, no amounts had been drawn under the letter of credit. Eastern American also has an unsecured revolving line of credit totaling $2 million, which expires December 31, 1999 and charges an interest rate of prime plus 0.5%. As of June 30, 1999 and 1998, no amounts were outstanding under the line of credit.
Seller Financed Note - The Company purchased a natural gas gathering system in - ---------------------- West Virginia for $1.2 million. The Company paid $0.3 million in cash and issued a note for the balance payable to the seller in 100 consecutive equal monthly payments. As of June 30, 1999 and 1998, the balance of the note was $0.8 million and $0.9 million.
6. INCOME TAXES
The following table summarizes components of the Company's provision (benefit) for income taxes for the years ended June 30 (in thousands):
A reconciliation of the provision for income taxes computed at the statutory rate to the provision for income taxes as shown in the consolidated statements of operations for the years ended June 30 is summarized below (in thousands):
During fiscal 1999, the Company finalized an IRS examination resulting in payments for prior taxes of $0.5 million. In addition, Section 29 credits for 1998 were not utilized because of reductions to regular taxable income and have been added to the current year's tax provision.
Components of the Company's federal and state deferred tax assets and liabilities, as of June 30, are as follows (in thousands):
At June 30, 1999, the Company has the following federal and state tax credits and carryforwards (in thousands):
The Company is eligible for relocation incentives taken in the form of tax credits from West Virginia. The incentive amounts are based upon investments made and jobs created in that state. Tax credits generated by the Company are used primarily to offset the payment of severance, property and state income taxes. Based on existing future taxable temporary differences and projections of future West Virginia severance, property and state income taxes, management has provided a valuation allowance for that portion of the credits not expected to be utilized.
Included in other long-term assets as of June 30, 1999 and 1998 is a net regulatory asset recorded by Mountaineer in accordance with state utility ratemaking practices related to future amounts recoverable for income taxes of $10.9 million and $11.3 million, respectively.
7. EMPLOYEE BENEFIT PLANS
The Company and certain subsidiaries, have a Profit Sharing/Incentive Stock Plan (the "Plan") for the stated purpose of expanding and improving profits and prosperity and to assist the Company in attracting and retaining key personnel. The Plan is noncontributory, and its continuance from year to year is at the discretion of the Board of Directors. The annual profit sharing pool is based on calculations set forth in the Plan. One-half of the pool is generally paid to eligible employees within 120 days of the end of the fiscal year and one-half is deferred to the following year. Generally, to be eligible to participate, an employee must have been continuously employed for two or more years; however, employees with less than two years of employment may participate under certain circumstances. The Company recognized $0.5 million, $2.6 million and $1.1 million of profit sharing expense during the years ended June 30, 1999, 1998, and 1997, respectively.
For certain subsidiaries, the Company sponsors a Section 401(k) plan covering all full-time employees who wish to participate. The Company's contributions, which are principally based on a percentage of the employee contributions, and charged against income as incurred, totaled $182,600, $153,600 and $140,300 for the years ended June 30, 1999, 1998 and 1997, respectively.
8. PENSION PLAN
Mountaineer sponsors a Retirement Income Plan (the "Pension Plan"), which covers substantially all qualified Mountaineer employees 21 years of age and over. Employees become fully vested upon completion of five years of credited service, as defined. Retirement income is based on credited years of service and the employees' level of compensation, as defined. The Pension Plan is subject to the provisions of the Employee Retirement Income Security Act of 1974 ("ERISA"). The determination of contributions is made in consultation with the Pension Plan's actuary and is based upon anticipated earnings of the Pension Plan, mortality and turnover experience, the funded status of the Pension Plan and anticipated future compensation levels. Mountaineer's funding policy is to be in compliance with ERISA guidelines and to make annual contributions to the Pension Plan to assure that all employees' benefits will be fully provided for by the time they retire.
The following table sets forth the Pension Plan's funded status and amounts recognized in the consolidated balance sheets as of June 30, as determined by an independent actuary (in thousands):
Net periodic pension cost for the years ended June 30 as determined by an independent actuary, included the following components (in thousands):
The assumptions used at the beginning of the fiscal year in accounting for Mountaineer's Pension Plan at June 30 are as follows:
9. POST-RETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
Mountaineer provides certain medical and life insurance benefits for retired employees. Substantially all employees, who meet the service requirements of 10 continuous years of service prior to retirement at age 55 or 5 continuous years of service prior to retirement at age 60, may become eligible for medical benefits. Medical benefits are provided to retirees until age 65. Life insurance benefits of approximately two times annual salary are provided while an employee is active and working at Mountaineer. On the date of an employee's retirement and on the date the employee reaches age 70, life insurance benefits decrease to approximately 80% and 50% of annual salary, respectively. The plan is unfunded.
The following table sets forth the postretirement medical and life insurance plans' funded status and amounts recognized in the consolidated balance sheets, as determined by an independent actuary, as of June 30 (in thousands):
The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 7.75% for the years ended June 30, 1999 and 1998. The average assumed annual rate of salary increase for the life insurance benefit plan was 4.5 % and 4.5% in 1999 and 1998, respectively.
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 8.0% in 1999, declining by a half percent to 5.5% in 2004 and remaining at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. A one percentage point increase in the assumed health care cost trend rate would increase the aggregate service and interest cost by $63,000 for the year ended June 30, 1999 and increase accumulated postretirement benefit obligation as of June 30, 1999 by $315,000. A one percentage point decrease in the assumed health care cost trend rate would decrease the aggregate service and interest cost by $57,000 for the year ended June 30, 1999 and decrease accumulated postretirement benefit obligation as of June 30, 1999 by $290,000.
As part of a WVPSC rate order dated October 29, 1993, the WVPSC ruled that the permitted rate recovery mechanism for other post retirement benefits would be a modified accrual method. The modified accrual method allows for the recovery of current service costs on an accrual basis and recovery of the transition obligation on a cash basis.
10. CAPITAL STOCK
Voting Common Stock- In May 1995, the Company was reincorporated in the State of - ------------------- West Virginia. As part of this reincorporation, each outstanding share of then existing no-par value common stock was converted to one share of $1 par value common stock.
The Company has an agreement with a stockholder covering the sale or disposition of 61,000 shares of common stock, at June 30, 1999, that provides the stockholder cannot sell stock without first offering such shares to the Company. Under certain circumstances, the Company would be required to purchase the related stock if not previously tendered to the Company or otherwise sold or disposed of in accordance with the provisions of the agreement.
Class A Non-Voting Common Stock - In August 1998, the Company amended its - ----------------------------------- articles of incorporation authorizing the issuance of up to 100,000 shares of Class A non-voting common stock. The Company then offered and exchanged 13,517 shares of its new Class A stock for the outstanding Class A stock of its subsidiaries, owned by certain employees, officers and directors. The minority interest carrying value prior to exchange, which reflected the subsidiaries' Class A shares, was the basis used to record the issuance of the Company's new Class A stock.
Treasury Stock - At June 30, 1999, the Company had 75,352 shares of voting - --------------- common stock in treasury, carried at cost. The Company purchased 20,704 and 6,980 shares of voting common stock during the years ended June 30, 1999 and 1998, respectively. At June 30, 1999, the Company also had 4,516 shares of non-voting Class A stock in treasury, carried at cost, all of which were purchased during the current year.
Stock Plans - During fiscal 1999, the Company created an incentive stock - ------------ purchase agreement, primarily for outside Directors. Under the agreement, options to purchase voting common stock were granted at $75, based on the fair market value as determined by the Board of Directors, per share and are exercisable based on the following schedule:
A summary of the plan as of June 30, 1999 and the changes during the year is presented below:
Fair value of the options at the date of grant, as estimated by management, was nominal.
During fiscal 1999, the Company created an employee stock purchase plan. Under the plan, 12,003 Class A shares were issued to employees at $75 per share in exchange for cash and promissory notes bearing interest of 6.5% or 8%, depending on the initial cash payment and recourse nature of the notes. The Company has agreed to forgive the notes over a seven year period assuming continued employment; therefore, the notes are being amortized over the term of employment. The Company has a right-of-first refusal to repurchase any shares employees wish to sell and in the event of death, disability or termination, the Company has an option to repurchase the shares.
11. EARNINGS PER SHARE
A reconciliation of the components of basic and diluted net income (loss) per common share as of June 30, for the years indicated, is as follows:
The effect of stock options was not included in the computation of diluted net loss per share during fiscal years 1997 and 1999 because to do so would have been antidilutive. There were no stock options exercisable during fiscal 1998.
12. UNCONSOLIDATED AFFILIATE
The Company's investment in BEC is accounted for under the equity method (see Note 3). Summarized financial information for BEC as of and for the years ended June 30, is as follows (in thousands):
BEC began operations in March 1997. Results of operations were not material for the three months ended June 30, 1997.
13. OPERATING LEASES
The Company has noncancelable operating lease agreements for the rental of office space, computer and other equipment. Certain of these leases contain purchase options or renewal clauses. Rental expense for operating leases was approximately $1.8, $1.7 and $1.3 million for the years ended June 30, 1999, 1998 and 1997, respectively.
At June 30, 1999 future minimum lease payments for each of the next five years and thereafter are as follows (in thousands):
14. RELATED PARTY TRANSACTIONS
The Company has entered into a rental arrangement for office space from a partnership in which certain officers are partners. Rent payments totaled $374,200, $339,470 and $336,000 for the years ended June 30, 1999, 1998 and 1997, respectively.
Mountaineer purchases a portion of its gas supply requirements from a subsidiary and from Eastern American. The price paid for such purchases has been approved by the WVPSC. During 1999, 1998 and 1997 Mountaineer purchased approximately $5.4 million, $5.6 million and $5.3 million respectively, from its subsidiary and $7.8 million, $22.2 million and $23.2 million respectively, from Eastern American. The contract with Eastern American expired October 31, 1998. The related revenues and expenses between Mountaineer and its subsidiary and Eastern American have not been eliminated in these financial statements due to the regulated nature of Mountaineer.
The Company advanced funds to certain officers, generally at 8% interest. Balances totaled $0.5 million and $0.2 million, respectively, at June 30, 1999 and 1998.
The Company advanced funds to certain officers in 1991 and 1994, at 8% interest that were secured by non-voting common shares of Eastern American. Balances totaled $0 and $320,400, respectively, at June 30, 1999 and 1998.
The Company advanced funds in 1988 to certain officers and directors at 8% interest, secured by interests in oil and gas properties and were payable out of net proceeds from the oil and gas production on these properties. During fiscal 1999, Eastern American purchased the related working interest from the officers and directors, canceling the related notes.
During fiscal 1999, the Company purchased from certain officers and directors, for $2.4 million, volumetric production from wells in New Zealand. Future production, totaling 3.3 million Mcf, otherwise allocable to the officers and directors will be allocated to the Company. The Company has recorded the payment as an investment in oil and gas properties.
15. COMMITMENTS AND CONTINGENCIES
In 1993, the Company sold working interests in certain Appalachian gas properties in connection with the formation of a royalty trust. A portion of the proceeds from the sale of these interests, representing a term net profits interest, was accounted for as a production payment. Unamortized proceeds totaling $12.0 million and $13.5 million at June 30, 1999 and 1998, respectively, have been classified as deferred trust revenue.
Certain gas production attributable to the royalty trust is purchased by a wholly owned subsidiary of the Company pursuant to a gas purchase contract, which expires in 2013. The purchase price under the contract is based on escalating fixed price and spot market components. The fixed price component expires on January 1, 2000. The obligation of the subsidiary to make payments under the contract is partially supported by a standby letter of credit with a face amount of $3 million. The letter of credit is subject to annual reductions of $3 million beginning June 30, 1996, and fully expires on June 30, 2000.
The Company entered into an agreement whereby it funded a specified monthly amount, through December 31, 1996, to assist in the development of oil and gas projects by a third party. No remaining commitment existed as of June 30, 1998. Amounts funded were accounted for as an advance and all outstanding amounts were due on January 1, 1999. As settlement, during fiscal 1999, the third party transferred $1.0 million of property and the Company has written off the remaining balance of $0.3 million.
In connection with an existing gas delivery obligation agreement, whereby Eastern American received an advance payment, a subsidiary of Eastern American entered into a credit line deed of trust, which has an available balance of $6.5 million as of June 30, 1999 to collateralize its performance under the gas delivery obligation. This credit line deed of trust declines at a rate of 7.5% per year.
The Company is involved in various legal actions and claims arising in the ordinary course of business. Management does not expect these matters to have a material adverse effect on the Company's financial position.
16. FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of June 30, have been determined using appropriate market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount that the Company could realize upon the sale or refinancing of such financial instruments (in thousands):
The Company in estimating the fair value of its financial instruments used the following methods and assumptions:
Notes Receivable - The notes receivable accrue interest at a fixed rate. Fair - ----------------- value was estimated using discounted cash flows based on current interest rates for notes with similar credit characteristics and maturities.
Long-Term Debt - A portion of long-term debt was borrowed under a senior - --------------- revolving credit facility, which accrues interest at variable rates; as a result, carrying value approximates fair value. The Company's subordinated debt is traded publicly. The market value at the end of the year was used for valuation purposes. The remaining portion of the Company's long-term debt is comprised of fixed rate facilities; for this portion, fair value was estimated using discounted cash flows based upon the Company's estimated current borrowing rates for debt with similar maturities.
Futures, swaps and options - The fair value of these instruments are based on - ----------------------------- quoted market prices.
17. CONTRACT SETTLEMENT
In March 1998, the Company entered into a Termination Agreement (the "Agreement") with Seneca Power Partners, L.P. ("Seneca"), which provided for the termination of a long-term gas sale and purchase contract between the Company and Seneca. Prior to such termination, the Company was obligated to deliver up to 12,000 Mcf of natural gas per day to Seneca's cogeneration facility. The Agreement was a direct result of an amendment to the existing Power Purchase Agreement by and between Seneca and Niagara Mohawk Power Corporation ("Niagara"). Niagara negotiated amendments to all of its existing Power Purchase Agreements as part of a Master Restructuring Agreement. Pursuant to the Agreement, the Company received cash consideration of approximately $22 million on June 30, 1998. As a result of this termination, the Company estimated it would incur future losses of approximately $2 million on its gas purchase commitments. Accordingly, the provision for anticipated losses was recorded as an offset to the contract settlement income in fiscal 1998 and amortized against the cost of gas purchased during fiscal 1999.
Although the Company terminated all rights and obligations under the contract, the Company retained its 10% limited partnership interest in Seneca. For the fiscal year ended June 30, 1998, the Company recorded partnership distributions of $10.0 million, comprised of $7.2 million in cash and $2.8 million of Niagara common stock. The Niagara stock was sold in November 1998 for $2.9 million.
18. RATE MATTERS
Since November 1995, Mountaineer has operated under a regulatory structure whereby Mountaineer maintains its rates at an agreed upon level for a specific period of time (the "Rate Moratorium"). In addition, during the Rate Moratorium, Mountaineer's annual purchased gas adjustment filing with the WVPSC is suspended. This regulatory structure results in Mountaineer assuming the risks and rewards of changes in the cost of gas purchases, changes in interstate pipeline costs and of all other aspects of Mountaineer's business. The Rate Moratorium began in November 1995 and ended in October 1998. During this period, deferral accounting for the majority of gas purchase costs was suspended and Mountaineer was permitted to amortize $12 million of the $12.7 million recorded balance of overrecovered gas costs as an offset to purchased gas expense. In fiscal 1999, Mountaineer recorded total amortization of $1.3 million in accordance with the Rate Moratorium. The excess of the overrecovered gas costs over the amount to be amortized and certain transportation revenues, storage balancing fees and standby charges were subject to deferral accounting in accordance with the Rate Moratorium.
In January 1998, Mountaineer filed with the WVPSC for an increase in its base rates, which would become effective upon expiration of the initial Rate Moratorium. In July 1998, Mountaineer agreed to a Joint Stipulation and Agreement for Settlement (the "Settlement") with various parties including the Staff of the WVPSC and the Consumer Advocate Division regarding Mountaineer's rate filing. Under the terms of the Settlement, Mountaineer was granted an increase in its rates which, assuming certain weather conditions, would generate additional annual revenues of approximately $9.4 million and which provided for a new three year Rate Moratorium which began on November 1, 1998 and continues through October 31, 2001. Other significant terms and conditions of the Settlement are similar to those under which Mountaineer operated during the prior Rate Moratorium. Beginning November 1, 1998, the remaining balance of overrecovered gas costs and certain transportation revenues, storage balancing fees and standby charges, totaling $6.4 million, previously deferred during the initial Rate Moratorium will be credited to gas expense over the three-year period ending October 31, 2001. During fiscal 1999, Mountaineer credited $1.4 million against gas costs in accordance with the Settlement.
19. INDUSTRY SEGMENTS
The Company adopted SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information," in fiscal 1999. The information for fiscal 1998 and 1997 has been restated from the prior year's presentation to conform to the fiscal 1999 presentation.
The Company's reportable business segments have been identified based on the differences in products and service provided. Revenues for the exploration and production segment are derived from the production and sale of natural gas and crude oil. The regulated utility segment generates revenue from the transportation and sale of natural gas at retail. Revenues for the marketing and pipeline segment arise from the marketing of both Company and third party produced natural gas volumes and the related transportation. The Company utilizes earnings before interest, taxes, depreciation, depletion, amortization and exploratory costs ("EBITDAX") to evaluate each segment's operations.
Summarized financial information for the Company's reportable segments is shown in the following table. The "other" column includes items related to corporate items (in thousands):
Operating profit represents revenues less costs which are directly associated with such operations. Revenues are priced and accounted for consistently for both unaffiliated and intersegment sales. Intersegment sales between the exploration and production and the utility segments have not been eliminated in consolidation because of the regulated nature of the gas distribution segment. The 'Other' column includes items related to non-reportable segments, corporate and elimination items. Included in the exploration and production segment are net long-lived assets located in New Zealand of $1.8, $1.4 and $0.1 million, as of June 30, 1999, 1998, and 1997.
20. SUBSEQUENT EVENTS
On July 1, 1999, Mountaineer acquired substantially all of the West Virginia assets of Shenandoah Gas Company for the purchase price of approximately $12.6 million. The acquired assets consist primarily of natural gas distribution facilities and related equipment located in the eastern panhandle of West Virginia.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Costs - The following tables set forth capitalized costs as of June 30 and costs - ----- incurred, including capitalized overhead, for oil and gas producing activities for the years ended June 30 (in thousands):
Results of Operations - The results of operations for oil and gas producing - ----------------------- activities, excluding corporate overhead and interest costs for the years ended June 30 are as follows (in thousands):
Production costs include those costs incurred to operate and maintain productive wells and related equipment and include costs such as labor, repairs and maintenance, materials, supplies, fuel consumed and insurance. Production costs are net of well tending fees, which are included in well operations revenues in the accompanying consolidated statements of operations.
Exploration and impairment expenses include the costs of geological and geophysical activity, unsuccessful exploratory wells and leasehold impairment allowances.
Depletion, depreciation and amortization include costs associated with capitalized acquisition, exploration, and development costs.
The provision for income taxes is computed at the statutory federal income tax rate and is reduced to the extent of permanent differences which have been recognized in the Company's tax provision, such as investment tax credits, and the utilization of Federal tax credits permitted for fuel produced from a non-conventional source.
Reserve Quantity Information - Reserve estimates are subject to numerous - ------------------------------ uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered commercially recoverable fluctuate with changes in prices and operating costs. Reserve estimates, by their nature, are generally less precise than other financial statement disclosures.
The following table sets forth information for the years indicated with respect to changes in the Company's proved reserves, substantially all of which are in the United States.
Standardized Measure of Discounted Future Net Cash Flows - Estimated discounted - --------------------------------------------------------- future net cash flows and changes therein were determined in accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.
Future cash inflows are computed by applying period-end prices of oil and gas relating to the Company's proved reserves to the period-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at period-end.
The assumptions used to compute estimated future net revenues do not necessarily reflect the Company's expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rates also could result directly or indirectly from factors outside of the Company's control, such as unintentional delays in development, changes in prices or regulatory controls. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, this could affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on period-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates and existing tax credits, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the Company's proved oil and gas reserves.
An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future net cash flows related to its proved oil and gas reserves as of June 30 is as follows (in thousands):
Principal changes in the standardized measure of discounted future net cash flows for the years ended June 30 are as follows (in thousands):
* * * * *
See notes to condensed financial information.
See notes to condensed financial information.
See notes to condensed financial information.
ENERGY CORPORATION OF AMERICA SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT NOTES TO CONDENSED FINANCIAL INFORMATION FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997 - ---------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Investments in Subsidiaries - The financial statements of Energy Corporation of - ---------------------------- America (the "Company") reflect investments in Eastern American Energy Corporation, Eastern Systems Corporation, Westech Energy Corporation and Westech Energy New Zealand Limited ("the subsidiaries"), wholly owned subsidiaries, using the equity method.
Income Taxes - The benefit for income taxes is based on losses recognized for - ------------- financial statement purposes determined on a separate company basis. Deferred income taxes are recognized for the tax effects of temporary differences between such losses and those recognized for income tax purposes. The Company files a consolidated U.S. income tax return with its subsidiaries.
2. CONSOLIDATED FINANCIAL STATEMENTS
Reference is made to the Consolidated Financial Statements and related Notes of Energy Corporation of America and Subsidiaries for additional information.
3. LONG-TERM DEBT
Information concerning debt of the Company on a consolidated basis is disclosed in Note 5 of the Notes to Consolidated Financial Statements of Energy Corporation of America and Subsidiaries included elsewhere herein. The Company's $200 million in 9 1/2% senior subordinated notes are due in 2007. The Company's $22 million revolving line of credit is due in 2002.
4. DIVIDENDS RECEIVED
The Company received dividends from its subsidiaries of $15.5 million, $41.6 million and $10.4 million for the years ended June 30, 1999, 1998 and 1997, respectively.
*****
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ------- ---------------------------------------------- ON ACCOUNTING AND FINANCIAL DISCLOSURE --------------------------------------
There have been no changes in or disagreements with accountants on accounting and financial disclosure.
PART III --------
ITEM 10.
ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT -------- ------------------------------------
The executive officers and Directors of the Company and the executive officers of its subsidiaries on June 30, 1999 are listed below, together with a description of their experience and certain other information. All of the Directors were re-elected for a one year term at the Company's December 1998 annual meeting of stockholders. Executive officers are appointed by the Board of Directors.
Isobel M. Allan joined the Company as Vice President of Finance in November 1998. Prior to joining the Company, Miss Allan was Assistant Treasurer with Occidental Petroleum Corporation. Miss Allan graduated from the University of Edinburgh, Scotland with a Bachelor of Science degree with Honors and a Master of Science degree in Business Studies.
W. Gaston Caperton, III, has been a Director of the Company since September 25,1997. He served as the Governor of the State of West Virginia for two terms, from 1989 to 1997. Mr. Caperton presently serves as President of The Caperton Group. He currently serves as President and Chief Executive Officer of The College Board. Mr. Caperton presently serves on the Board of Directors of Owens Corning and United Bankshares.
Joseph E. Casabona is Executive Vice President of the Company and has been a Director since its formation. Mr. Casabona joined Eastern American in 1985 and was Executive Vice President of Eastern American and a Director from 1987 until 1993. Mr. Casabona was employed in various audit staff capacities from 1967 to 1979 in the Pittsburgh, Pennsylvania office of KPMG Main Hurdman ("KPMG, Peat Marwick"), became a partner in the Firm in 1980 and was named Director of Accounting and Auditing of the Pittsburgh office in 1983. Mr. Casabona graduated from the University of Pittsburgh with a B.S. in Business Administration and from the Colorado School of Mines with a M.S. in Mineral Economics. Mr. Casabona has been a Certified Public Accountant since 1969. Mr. Casabona has been a member of the Boards of Directors of the West Virginia and Pennsylvania Independent Oil and Gas Associations.
Peter H. Coors has been a Director of the Company since 1996. Mr. Coors is Vice Chairman of the Board and Chief Executive Officer of Coors Brewing Company and Vice President of Adolph Coors Company. He received his Bachelors Degree in Industrial Engineering from Cornell University in 1969, and he earned his Masters Degree in Business Administration from the University of Denver in 1970. Mr. Coors also serves on the Board of Directors of First Bank Systems.
L.B. Curtis has been a Director of the Company since 1993. Mr. Curtis was a Director of Eastern American from 1988 until 1993. Mr. Curtis is retired from a career at Conoco, Inc. where he held the position of Vice President of Production Engineering with Conoco Worldwide. Mr. Curtis was highly recognized across the Petroleum Industry in the upstream (exploration and production) segment of the industry. Mr. Curtis graduated from The Colorado School of Mines with an Engineer of Petroleum Professional degree.
Edward J. Davies has been President of Westech Energy Corporation and Managing Director of Westech Energy New Zealand Limited since 1994. Previously, Mr. Davies was with Conoco Inc., where his most recent positions were General Manager Exploration and Managing Director Nigeria. Mr. Davies holds a Bachelors of Science in Geology from the University of Wales, a Doctor of Philosophy in Geology from the University of Alberta, and a Masters of Science from the Massachusetts Institute of Technology Sloan School of Management.
John J. Dorgan has been a Director of the Company since 1993. He served as a Director for Eastern American in 1992. He is a former Executive Vice President and consultant to Occidental Petroleum Corporation where he had worked in various capacities since 1972.
Michael S. Fletcher has been President of Mountaineer Gas Company since August 1998. Prior to that time, he also held the positions of Senior Vice President and Chief Financial Officer of Mountaineer. Before joining Mountaineer in 1987, Mr. Fletcher was a partner of Arthur Andersen and Company and was employed by that firm for fifteen (15) years. Mr. Fletcher is a Certified Public Accountant and a board member for the Board of Risk and Insurance Management for the State of West Virginia. Mr. Fletcher graduated from Utah State University with a Bachelors Degree in Accounting.
J. Michael Forbes has been Vice President of the Company since 1995. Prior to that, Mr. Forbes was an officer with Eastern American, which he joined in 1982. Mr. Forbes graduated with a Bachelors of Arts in Accounting and Finance from Glenville State College and is a Certified Public Accountant. He also holds a Masters of Business Administration from Marshall University and is a graduate of Stanford University's Program for Chief Financial Officers.
Richard E. Heffelfinger is President of Eastern American and Eastern Marketing. Mr. Heffelfinger joined Eastern American in 1980. Mr. Heffelfinger currently serves on the Board of Directors of Capital State Bank of West Virginia. He is a member of the Young Presidents' Organization, Mountain States Chapter, and a past President and current Board Member of the Independent Oil and Gas Association of West Virginia. In addition, Mr. Heffelfinger currently serves as Chairman of the Greater Kanawha Valley YMCA. Mr. Heffelfinger is a graduate of Glenville State College.
F. H. McCullough, III, has been a Director of the Company since 1993. Mr. McCullough joined Eastern American in 1977. Mr. McCullough currently serves as Vice President of the Company. Mr. McCullough was a Director of Eastern American from 1978 until 1993. Mr. McCullough is a graduate of the University of Southern California with a Bachelor of Arts Degree in International Economics and two Masters Degrees in Business Administration and Financial Systems Management. He is a graduate of the Northwestern University Kellogg Graduate School of Management Executive Marketing Program. Effective October 1, 1999, Mr. McCullough resigned as Vice President of the Company and retained his position as Director.
John Mork has been President and Chief Executive Officer of the Company and a Director of the Company since its formation. Mr. Mork served in various capacities at Union Oil Company until 1972 when he joined Pacific States Gas and Oil, Inc. and subsequently founded Eastern American. Mr. Mork was President and a Director of Eastern American from 1973 until 1993. Mr. Mork is a past Director of the Independent Petroleum Association of America, and the Independent Oil and Gas Association of West Virginia. He was chapter chairman of the Young Presidents' Organization, Inc., Rocky Mountain Chapter from 1994 to 1995. Mr. Mork also founded the Mountain State Chapter of the Young Presidents' Organization located in Charleston, West Virginia. Mr. Mork holds a Bachelor of Science Degree in Petroleum Engineering from the University of Southern California and he is a graduate of the Stanford Business School Program for Chief Executive Officers. He is the husband of Julie Mork.
Julie M. Mork has been a Director of the Company since 1993. She was a Director of Eastern American from 1974 until 1993. Mrs. Mork served as a founder and Secretary/Treasurer of Pacific States Gas and Oil, Inc. and Eastern American. Mrs. Mork received a Bachelor of Arts Degree in history from the University of California in Los Angeles. She is the wife of John Mork.
Arthur C. Nielsen, Jr. has been a Director of the Company since 1993. He was a Director of Eastern American from 1985 until 1993. He serves on the Board of Directors of General Binding Corporation. He also serves as senior advisor to the Toshiba Corporation.
Donald C. Supcoe has been the Senior Vice President of Mountaineer Gas Company since August 1998. Prior to joining Mountaineer, he was the Vice President, General Counsel and Secretary of Eastern American with whom he had been employed since 1981. Mr. Supcoe is a past President of the Independent Oil and Gas Association of West Virginia and a past Vice President of the Independent Petroleum Association of America. Mr. Supcoe graduated from West Virginia University with a Bachelor of Science Degree in Business Administration. Mr. Supcoe received a Doctor of Jurisprudence Degree from West Virginia University College of Law.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION -------- ----------------------
The following table sets forth for fiscal year 1999 the total value of compensation of (i) the Company's Chief Executive Officer and (ii) each other executive officer of the Company.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN -------- ----------------------------- BENEFICIAL OWNERS AND MANAGEMENT --------------------------------
The following table sets forth certain information regarding (i) the share ownership of the Company by each person known to the Company to be the beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii) the share ownership of the Company by each Director, (iii) the share ownership of the Company by certain executive officers and (iv) the share ownership of the Company by all directors and executive officers as a group, in each case as of September 1, 1999. The business address of each officer and director listed below is: c/o Energy Corporation of America, 4643 S. Ulster, Suite 1100, Denver, Colorado 80237.
The following table sets forth certain information regarding (i) the share ownership of the Company by each person known to the Company to be the beneficial owner of more than 5% of the outstanding shares of Class A Stock, (ii) the share ownership of the Company's Class A Stock by each Director, (iii) the share ownership of the Company's Class A Stock by certain executive officers and (iv) the share ownership of the Company's Class A Stock by all directors and executive officers as a group, in each case as of September 1, 1999. The business address of each officer an director listed below is : c/o Energy Corporation of American, 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND -------- ------------------------- RELATED TRANSACTIONS --------------------
Certain officers and Directors of the Company and members of their families regularly participate in the wells drilled by the Company on an actual costs basis and share in the costs and revenues on the same basis as the Company. The Company has the right to select the wells drilled and each participant is involved in all wells included within a Company drilling program (the "Drilling Program") and cannot selectively choose the wells in which to participate. The Company typically has a development drilling component and an exploration-drilling component within each year's Drilling Program. The officers and Directors and their family members may participate in either or both of the components. The following table identifies the participants' aggregate investment in the calendar years shown:
Certain officers, Directors and key employees of the Company have notes payable to the Company related to employee incentive stock options that were granted and exercised. The notes bear various interest rates, ranging from LIBOR to 8% per annum. As of June 30, 1999, in excess of $60,000, the following were indebted to the Company (in thousands):
Certain officers and Directors of the Company have borrowed money from the Company and have executed promissory notes. The notes bear interest at 8% per annum. As of June 30, 1999, the following were indebted to the Company (in thousands):
During fiscal 1999, the Company purchased from certain officers and directors volumetric production from wells in New Zealand. Future production, otherwise allocable to the officers and directors will be allocated to the Company. The following table identifies the participants' interest:
The Company rents office space in Charleston, West Virginia from Energy Centre, Inc. a corporation owned 40.0% by John Mork, 20.0% by each of F. H. McCullough, III and Joseph E. Casabona and 6.67% by each of Donald C. Supcoe, Richard E. Heffelfinger and J. Michael Forbes. The aggregate amount paid by the Company for rent to Energy Centre, Inc. was $339,470 for fiscal year 1999. The Company believes that such rental terms are no less favorable than could have been obtained from an unaffiliated party.
PART IV -------
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT -------- ----------------------------- SCHEDULES AND REPORTS ON FORM 8-K ---------------------------------
PART V ------
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto, duly authorized, on the 27th day of September 1999.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork ----------------------------------------- John Mork President and Chief Executive Officer
POWER OF ATTORNEY -----------------
Each of the undersigned officers and directors of Energy Corporation of America (the "Company") hereby constitutes and appoints John Mork, Joseph E. Casabona and Isobel M. Allan and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file this Form 10-K under the Securities Act of 1934, as amended, and any or all amendments (including, without limitation, post-effective amendments), with all exhibits and any and all documents required to be filed with respect thereto, with the Securities and Exchange Commission or any regulatory authority, granting unto such attorneys-in-fact and agents, and each of them acting alone, full power and authority to do and perform each of every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same, as full to all intents and purposes as he himself might or could do if personally present, hereby ratifying and confirming all the such attorneys-in-fact and agents, or any of them, or their substitute or substitutes, may lawfully do or cause to be done.
Pursuant to the requirements of the Securities Act of 1934, this Form 10-K has been signed on the ___ day of September 1999, by the following persons in the capacities indicated.