Item 1. - Business
General
Energy West Incorporated ("the Company") is a regulated public utility, with certain non-utility operations conducted through its subsidiaries. The Company was incorporated in Montana in 1909. The Company's regulated utility operations involve the distribution and sale of natural gas to the public in and around Great Falls and West Yellowstone, Montana and Cody, Wyoming, and the distribution and sale of propane to the public through underground propane vapor systems in and around Payson, Arizona and Cascade, Montana. The Company's West Yellowstone, Montana operation is supplied by liquefied natural gas ("LNG").
Certain non-regulated, non-utility operations are conducted by three wholly-owned subsidiaries of the Company: Energy West Propane, Inc. ("EWP"); Energy West Resources, Inc. ("EWR"); and Energy West Development, Inc. ("EWD"). EWP is engaged in wholesale distribution of bulk propane in Wyoming, Arizona and Montana, and is engaged in retail distribution of bulk propane in Arizona. EWR markets gas and electricity in Montana and Wyoming. EWD owns one parcel of real estate property and conducts a gas appliance retail business in Great Falls, Montana.
The Company reports financial results for three business segments: Natural Gas Operations, Propane Operations, and Marketing and Wholesale Operations. The results of all three of these segments are seasonal in nature. Summarized financial information for these three segments is set forth in Note 11 to the Company's Consolidated Financial Statements included in this Report.
Natural Gas Operations
The Company's primary business is the distribution and sale of natural gas to residential, commercial and industrial customers. The Company's natural gas operations consist of two divisions. The Energy West - Montana Division serves customers in and around Great Falls and West Yellowstone, Montana. The Energy West - Wyoming Division serves customers in and around Cody, Meeteetsee and Ralston, Wyoming. Generally, residential customers use natural gas for space heating and water heating, commercial customers use natural gas for space heating and cooking, and industrial customers use natural gas as a fuel in industrial processing and space heating. The Company's revenues from natural gas operations are generated under tariffs regulated by the state utility commissions of Montana and Wyoming, respectively.
EWD's operations are reported as part of the Company's natural gas operations.
Energy West - Montana ("EWM") Division
The EWM division provides natural gas service to customers in and around Great Falls and West Yellowstone, Montana. The division's service area has a population of approximately 79,000 in the Great Falls area and 1,200 in the West Yellowstone area.
The division has a franchise to distribute natural gas within the city of Great Falls that expires in 2021. The division also provides natural gas transportation service to certain customers who purchase natural gas from other suppliers.
The following table shows the EWM division's revenues by customer class for the fiscal year ended June 30, 2002 and the two preceding fiscal years:
Gas Revenues (in thousands)
The following table shows the volumes of natural gas, expressed in millions of cubic feet ("MMcf") (measured at standard operating pressure) sold or transported by the division for the fiscal year ended June 30, 2002 and the two preceding fiscal years:
Gas Volumes (MMcf)
The EWM division has 855 transportation customers. No customer of the EWM division accounted for more than 1% of the consolidated revenues of the Company in fiscal 2002.
The operations of the EWM division are subject to regulation by the Montana Public Service Commission ("MPSC"). The MPSC regulates rates, adequacy of service, issuance of securities, compliance with U.S. Department of Transportation Safety Regulations and other matters.
In December, 1998, the MPSC approved a proposed plan filed by the Company ("Plan") to allow customers to choose a natural gas supplier other than the EWM division. Under the Plan, the EWM division continues to provide delivery service to customers who purchase from other suppliers. Customers who do not wish to choose another supplier are free to continue purchasing natural gas from the EWM division.
The EWM division uses the NorthWestern Energy (NWE) pipeline transmission system to transport supplies of natural gas for its core load. The division also uses this pipeline system to provide transportation, distribution and balancing services to customers who have chosen to obtain natural gas from other suppliers. The Company has a 10-year transportation agreement with NWE that fixes the cost of pipeline and storage capacity for the EWM division at rates which are currently lower than the rates applicable to most other pipeline customers of NWE.
In October 2000, the Company filed its annual gas cost recovery application for the EWM division with the MPSC. The MPSC granted interim rate relief in December 2000. During late 2000, however, the EWM division's costs of gas rose due to very high index prices, and as a result the Company amended its application in February 2001. In response, the MPSC issued a second interim order in March, 2001 (which the MPSC made final in August 2001). This order established a monthly cost tracking process under which the Company was required to file for an increase or decrease in rates if natural gas costs changed more than $.10 per thousand cubic feet (Mcf) in any month, subject to an audit of the unrecovered balance by the MPSC and Montana Consumer Counsel once a year.
In May 2002, after fully recovering the previous increase in gas costs experienced by the EWM division, the Company filed for a reduction in the rates as required by the MPSC's order. In June 2002, the Company received approval from the MPSC to reduce the rates charged by the EWM division effective July 1, 2002.
In September 2002, the Company filed an application for the EWM division with the MPSC seeking a general increase in rates, related primarily to increases in costs of operations. The application is presently pending.
Energy West - Wyoming ("EWW") Division
The EWW division provides natural gas service to customers in and around Cody, Meeteetsee and Ralston, Wyoming. This service area has a population of approximately 12,000. The EWW division has a certificate of public convenience and necessity granted by the Wyoming Public Service Commission (the "WPSC") for transportation and distribution covering
the west side of the Big Horn Basin, which stretches approximately 70 miles north and south and 40 miles east and west from Cody. As of June 30, 2002, the EWW division provided service to approximately 5,700 customers, including one industrial customer. The division also offers transportation service for natural gas producers and other parties.
The following table shows the EWW division's revenues by customer class for the fiscal year ended June 30, 2002 and the two preceding fiscal years:
Gas Revenues (in thousands) Years Ended June 30,
The following table shows the volumes of natural gas, expressed in millions of cubic feet ("MMcf") (measured at standard operating pressure), sold by the EWW division for the fiscal year ended June 30, 2002 and the two preceding fiscal years:
Gas Volumes (MMcf) Years Ended June 30,
The EWW division's industrial customer, BPB America, (dba "Celotex"), a manufacturer of gypsum wallboard, purchases gas pursuant to a special industrial tariff, which fluctuates with the cost of gas. In fiscal 2002 Celotex accounted for approximately 31% of the revenues of the EWW division and approximately 3% of the consolidated revenues of the Company. Celotex's business is cyclical and dependent on the level of national housing starts. The division's sales to Celotex in FY 2002 were approximately 7% greater than in FY 2001. No assurance can be given that Celotex will continue to be a significant customer of the EWW division.
EWR is the EWW division's primary supplier of natural gas, pursuant to a three-year agreement entered into in May of 2000. In addition, the division has a backup contract to purchase natural gas from Coastal Gas Marketing, but has purchased only immaterial amounts of gas under this backup agreement.
The EWW division transports gas for third parties pursuant to a tariff filed with and approved by the WPSC. The terms of the transportation tariff (currently between $.08 and $.30 per Mcf) are established by the WPSC.
During fiscal 2002, the Company was a party to financial swap agreements for natural gas for its regulated operations in the EWW division. These agreements expired on March 31, 2002. The net cash payments and receipts under these agreements did not have a material effect on the Company's income or financial condition.
The EWW division's revenues are generated under regulated tariffs that are designed to recover a base cost of gas, administrative and operating expenses and provide sufficient return to cover interest and profit. The division also serves some customers under separate contract rates that were individually approved by the WPSC. The division's tariffs include a purchased gas adjustment clause which allows the division to adjust its rates to recover changes in gas costs from base gas costs.
The EWW division's last general rate order was effective in 1989. The Company anticipates filing an application for a general rate increase for the division during fiscal year 2003.
Propane Operations
For financial reporting purposes, the Company reports as a separate business segment the distribution of propane by the Company and the Company's wholly-owned subsidiary, Energy West Propane, Inc. ("EWP"). The Company is engaged in the regulated distribution of propane through two divisions, Energy West Arizona ("EWA") and Energy West Montana - Cascade ("EWM - Cascade"). EWP is engaged in the unregulated distribution of propane in Montana, Wyoming and Arizona.
Regulated Propane Operations
The EWA division distributes propane in the Payson, Arizona area. The service area of the EWA division has a population of approximately 30,000. The operations of the EWA division are subject to regulation by the Arizona Corporation Commission (the "ACC"), which regulates rates, adequacy of service, and other matters. The EWA division's properties include approximately 190 miles of underground distribution pipeline and an office building leased from a third party. The division purchases its propane supplies from EWP under terms reviewed periodically by the ACC. The EWA division has approximately 7,100 customers. The division's principal
competition comes from bulk propane retailers who sell to customers who draw propane for use from storage tanks located at their homes or businesses, rather than using propane from the division's underground distribution system.
The following tables show the EWA division's revenues and propane volumes by customer class for the fiscal year ended June 30, 2002 and the two preceding fiscal years:
Propane Revenue (in thousands)
Propane Volumes (in gallons)
The EWM - Cascade division distributes propane in the Cascade, Montana area. The service area of the EWM - Cascade division has a population of approximately 1,000. The operations of the EWM - Cascade division are subject to regulation by the Montana Public Service Commission, which regulates rates, adequacy of service, issuance of securities and other matters. The EWM Cascade division's properties include approximately 10 miles of underground distribution pipeline. The division purchases its propane supplies from EWP under terms reviewed periodically by the MPSC.
Unregulated Propane Operations
The Company's subsidiary Energy West Propane, Inc. ("EWP") is engaged in the bulk sale of propane through its three divisions: Energy West Propane-Arizona, which serves the Payson, Arizona area; Energy West Propane-Montana, which sells bulk propane in the Cascade County area, surrounding Great Falls, Montana; and Rocky Mountain Fuels Wholesale which has
wholesale operations primarily in Montana, Wyoming and Arizona. EWP had 4,530 customers as of June 30, 2002.
Energy West Propane - Arizona sells propane to residential and commercial customers in the Payson, Arizona area.
EWP's wholesale division, Rocky Mountain Fuels Wholesale, supplies propane for the Company's underground propane-vapor systems serving the cities of Payson, Arizona and Cascade, Montana and surrounding areas.
In March and June of 2002, as a result of a decision to shift its strategic emphasis to wholesale propane operations, EWP sold its retail operations in Montana and Wyoming. The before tax gain on the sale of these two operations was approximately $338,000. EWP has entered into long-term agreements to supply wholesale propane, through Rocky Mountain Fuels Wholesale, to the purchaser of these assets.
EWP faces competition from other propane distributors and suppliers of alternative fuels that compete with natural gas. Competition is based primarily on price and there is a high degree of competition with other propane distributors in each of EWP's service areas.
Energy Marketing and Wholesale Operations
The Company's wholly owned subsidiary, EWR, conducts certain marketing and trading activities and wholesale distribution activities involving the sale of natural gas and electricity in Montana and Wyoming.
Montana legislation enacted in 1997, and subsequent MPSC orders, permitting open access on the Montana Power Company gas transportation and electricity transmission system and other systems in Montana have presented opportunities for EWR to do business as a broker of natural gas and electricity, using these systems. Although EWR has concentrated its efforts on industrial and large commercial customers, EWR began to market gas and electricity to small commercial and residential customers in fiscal 2000. EWR has from time to time entered into certain financial agreements to hedge against the risks of fluctuation in prices of natural gas and electricity. If the price obtained through such instruments is favorable or unfavorable compared to subsequent market conditions, net earnings or losses can result from such arrangements. See Item 7, "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF CONSOLIDATED OPERATIONS -- Derivatives and Risk Management," in this Report.
In order to provide a stable source of natural gas to provide for a portion of its requirements, in May 2002, EWR purchased a 56% interest in a group of producing natural gas reserves located in northern Montana. EWR's portion of the estimated daily gas production from the reserves is approximately 600,000 cubic feet (600 Mcf), or approximately 5% of EWR's present volume requirements. This production gives EWR a natural hedge, due to fixed production expenses when market prices of natural gas are above the costs of production. One of the other owners of a partial interest in these reserves is serving as the operator of the wells. As part of the transaction, EWR received a $300,000 discount on the purchase price as a settlement
of certain claims. The $300,000 was recorded in "nonoperating income" during the fourth quarter of fiscal year 2002.
In order to take advantage of certain natural synergies resulting from the location of the Company's operations in Cody, Wyoming, and to expand its options in procuring natural gas supplies, in August 2000, EWR purchased two pipelines in northern Wyoming. One of the pipelines is classified as a gathering system, and has been placed into service. The other pipeline is presently being renovated. This other pipeline is expected to become operational during fiscal 2003. This pipeline will serve as a transmission pipeline. An application is being filed with the Federal Energy Regulatory Commission (FERC) to obtain FERC approval for the pipeline to be operated as a transmission pipeline. Both of the pipelines will be sold to, and operated by, the Company's wholly-owned subsidiary, EWD.
Capital Expenditures
The Company conducts ongoing construction activities, in all of its utility service areas, in order to support expansion, maintenance and enhancement of its gas and propane pipeline systems. The Company also continues to experience growth in its unregulated retail and wholesale propane operations, requiring additional capital expenditures. In fiscal years 2002, 2001 and 2000, total capital expenditures for the Company were approximately $6,442,000, $3,276,000 and $4,757,000 respectively. The increase in capital expenditures by approximately $3,166,000 from fiscal year 2001 to fiscal year 2002 was the result of the purchase of production properties (described in "Energy Marketing and Wholesale Operations", above) and renovations of the pipelines in Wyoming (described in "Energy Marketing and Wholesale Operations", above) and construction of a gas transmission pipeline around the City of Cody, Wyoming.
Competition
The principal competition faced by the Company in its distribution and sale of natural gas is from suppliers of alternative fuels, including electricity, oil, propane and coal. The principal considerations affecting a customer's selection of utility gas service over competing energy sources include service, price, equipment costs, reliability and ease of delivery. In addition, the type of equipment already installed in businesses and residences significantly affects the customer's choice of energy. However, where previously installed equipment is not an issue, households in recent years have generally preferred the installation of gas heat. The Company's statistics indicate that approximately 95% of the houses and businesses in the Great Falls service area use natural gas for space heating fuel, approximately 91% use gas for water heating and approximately 99% of the new homes built on or near the Company's Great Falls service mains in recent years have selected natural gas as their energy source.
The EWW division believes that approximately 95% of the houses and businesses in the division's service area use natural gas for space heating fuel, approximately 90% use gas for water heating, and approximately 99% of the new homes built on or near the division's service mains in recent years have selected gas as their energy source.
The EWA division believes that approximately 59% of the houses and businesses adjacent to the division's distribution pipeline use the division's propane for space heating or water heating.
The principal competition faced by the Company and its subsidiaries in the distribution and sales of propane is from other propane distributors and suppliers of the alternate fuels and sources that compete with natural gas and electricity. Competition is based primarily on price and there is a high degree of competition with other propane distributors in the service areas.
EWR's principal competition is from other gas and electricity marketing firms doing business in the State of Montana. As of June 30, 2002, EWR had 163 customers for natural gas services and 709 for electricity services. EWR believes that the recent changes in applicable law, which allow its customers to choose a natural gas supplier other than their local utility company, will continue to provide future opportunities for gas marketing operations.
Employees
The Company and its subsidiaries had an aggregate total of 131 employees as of June 30, 2002. Six of these were employed by EWR, 27 by the propane operations, 85 were employed by the Company's natural gas operations and the remaining 13 individuals are employed at the corporate office. The Company's natural gas operations include 19 employees represented by two labor unions. Contracts with each of these unions are in place until June 30, 2003. The Company believes that its relationship with its employees is good.
Executive Officers
The following table sets forth the names and ages of, and the positions and offices within the Company presently held by, the executive officers of the Company:
Edward J. Bernica was appointed President and Chief Executive Officer on September 17, 2001. From March 1999 until September 17, 2001, he was Executive Vice-President, Chief Operating Officer and Chief Financial Officer of the Company. He joined the Company in November 1994, as Vice-President and Chief Financial Officer.
Sheila M. Rice has been Vice-President of Energy West Incorporated and Corporate Administrator since October of 2001. She was Vice President of Marketing from 1998 to 2001 and was Vice President and Division Manager of Energy West Montana from 1993 until 1998.
John C. Allen has been General Counsel, Vice-President and Secretary of the Company since 1992.
Tim A. Good has been Vice-President of the Company and Manager of the Company's Natural Gas Operations since July 1, 2000. He served as Vice President and Division Manager of the EWW Division from 1988 to July 1, 2000.
Douglas R. Mann has been Vice-President and Manager of Energy West Propane, Inc. since July 1, 2000. From February, 1999 until July 1, 2000, he served as Vice-President and Manager of the EWA Division. From 1995 until July 1, 1999, he served as Assistant Vice-President and Manager of the Arizona Division.
JoAnn S. Hogan has been Assistant Vice-President and Treasurer of the Company since January 2002. She served as Controller from 2000 to 2002. From 1995 to 2000, she served in various financial capacities for the Company including assistant controller and tax manager.
Robert B. Mease has been Assistant Vice-President and Controller of the Company since joining the Company in February 2002. From October 2000 to February 2002, he served as a business consultant with Junkermier, Clark, Campanella & Stevens, a public accounting firm. From 1998 to 2000 he was Vice-President and CFO of TMC Sales, a steel manufacturer and wholesale distributor located in Seattle, Washington. From 1994 to 1998, he was Vice-President of Finance for American Agri-Technology, located in Great Falls, Montana.
PART I
Item 2.
Item 2. - Properties
The Company owns and leases properties located in the following states:
MONTANA: In Great Falls, Montana, the Company owns a 9,000 square foot office building, which serves as the Company's headquarters, and a 3,000 square foot service and operating center (with various outbuildings) which supports day-to-day maintenance and construction operations. The Company owns approximately 400 miles of underground distribution lines ("mains"), and related metering and regulating equipment in and around Great Falls, Montana. In West Yellowstone, Montana, the Company owns an office building, and a liquefied natural gas plant that provides natural gas through approximately 13 miles of underground mains owned by the Company. The Company owns approximately 10 miles of underground mains in the town of Cascade.
EWP owns several large bulk propane tanks to serve the areas in and around the towns of Cascade and Superior, Montana.
During fiscal year 2002, EWR purchased a 56% ownership interest in natural gas production properties that provide approximately 600 Mcf of natural gas daily for resale.
During fiscal 2002, as part of its strategic emphasis on wholesale propane operations, EWP sold its retail propane operations located in Wyoming and Montana. The assets sold represented approximately 7% of EWP's total assets and less than 2% of the Company's consolidated assets.
WYOMING: In Cody, Wyoming, the Company leases office and service buildings for the EWW division under long-term lease agreements. The Company owns approximately 300 miles of mains, and related metering and regulating equipment, all of which are located in or around Cody.
EWP owns two large bulk propane tanks, located in Cody, to serve its customers in northern Wyoming.
EWR owns two pipelines in Wyoming. One pipeline is currently being operated as a gathering system, and the other will upon receipt of the necessary FERC approvals operate as an interstate pipeline transmission system. The pipelines are located north of Cody, Wyoming.
ARIZONA: The Company owns approximately 190 miles of distribution mains located in and around the community of Payson. The Company owns five acres of land in Payson, on which the Company maintains and operates a propane vapor system for its operations in Payson. The Company leases an office building in Payson under an agreement that expires in 2006. The Company has the right to extend the lease for two successive five (5) year periods.
EWP owns several large bulk propane tanks located in Pine, Strawberry, Payson and Starr Valley, Arizona which are utilized to serve customers in these and other surrounding areas.
Item 3.
Item 3. - Legal Proceedings
From time to time the Company is involved in litigation relating to claims arising from its operations in the normal course of business. The Company utilizes various risk management strategies, including maintaining liability insurance against certain risks, employee education and safety programs and other processes intended to reduce liability risk.
In addition to other litigation referred to above, the Company or its subsidiaries are currently involved in the following described litigation.
EWR is currently involved in a lawsuit with PPL Montana, LLC (PPLM) which is pending in the United States District Court for the District of Montana. The lawsuit was filed on July 2, 2001, and involves a wholesale electricity supply contract between EWR and PPL dated March 17, 2000 and a confirmation letter thereunder dated June 13, 2000 (together, the "Contract"). EWR has received substantial imbalance payments as a result of the amount of power that it has scheduled and purchased from PPLM under the Contract. PPLM claims that, as a result of EWR's scheduling under the Contract, PPLM was deprived of the fair market value of energy which PPLM contends it could have subsequently sold. PPLM estimates the fair market value of the excess energy scheduled by EWR to be approximately $18.0 million. Any recovery of damages by PPLM could have a material adverse effect on the Company and its financial condition. EWR denies liability to PPLM. EWR believes that its scheduling practices were reasonable under the circumstances, and that in any event PPLM did not sustain any damages. The Company believes that it has established adequate reserves with respect to the litigation with PPLM; however, there can be no assurance that any liability will not exceed such reserves. A liability in excess of the recorded reserves could a have material adverse effect on the Company and its financial condition.
The Montana Department of Revenue ("DOR"), by letter dated August 30, 2002, has advised the Company that based on property tax audit of the Company for the period January 1, 1997 through December 31, 2001, DOR is assessing the Company for willfully under-reporting its personal property and that a two and one-half times penalty should be assessed. The Company estimates that if the proposed assessment stands, it would owe approximately $3.9 million in property taxes and penalties. The Company believes it has valid defenses to the assessment of tax and penalties and intends to vigorously oppose the DOR's position. The Company also believes that any tax deficiency that may be imposed on the Company would (to the extent the deficiency relates to regulated property, which is substantially all of the deficiency) be properly classified as a regulatory asset (i.e., an amount that can be recovered through increased rates to utility customers). Assuming authorization for such treatment is received from regulatory authorities the assessment of taxes would not have a material affect on the Company. However, if the DOR prevails in its imposition of penalties, the Company anticipates that such penalties would not be recoverable through rates. The Company believes that any interest associated with the property tax assessment also should be classified as a regulatory asset. An adverse outcome in this matter (including imposition of penalties on the Company, or failure of the Company to obtain classification of any tax liability or interest as a regulatory asset) could have a material adverse effect on the Company and its financial condition.
Item 4.
Item 4. - Submission of Matters to a Vote of Security Holders
None
PART II
Item 5.
Item 5. - Market for registrant's common equity and related stockholder matters
Common Stock Prices and Dividend Comparison - Fiscal 2002 and 2001
Shares of the Company's Class "A" Common Stock are traded on the Nasdaq National Market under the symbol: "EWST." The following table sets forth the high and low bid prices for the Company's common stock. These prices reflect inter-dealer prices, without retail mark-up, markdown or commission, and may not necessarily represent the actual transactions.
At September 25, 2002, there were 493 holders of record of the Company's common stock. The Board of Directors normally considers approving common stock dividends for payments in March, June, September and January. Quarterly dividend payments per common share for Fiscal Years 2002 and 2001 were:
The following chart sets forth information concerning the number of shares of common stock to be issued upon exercise of outstanding options, warrants and rights, the weighted average exercise price, and the number of shares remaining available for issuance under such plans.
EQUITY COMPENSATION PLAN INFORMATION
Unregistered Issuances of Securities
During the last 3 years, the Company has issued certain securities that have not been covered by a registration statement filed with the Securities and Exchange Commission. These issuances are as follows:
On October 12, 2001, the Company issued a total of 4,332.751 shares of common stock of the Company to four members of the board of directors of the Company. The shares were issued at the request of the directors in lieu of cash payments due under the Company's long term incentive plan. The shares were issued at a price of $11.45 per share, or an aggregate of $49,610. With respect to this issuance of shares, the Company claims an exemption from registration under Section 4(2) of the Securities Act of 1933 ("Section 4(2)") because of the limited number of individuals to whom shares were issued, and the fact that the individuals who received the shares were well informed about the Company and its affairs and in general are sophisticated investors.
The Company has issued shares of its common stock to certain Company executives upon the exercise by such executives of options previously granted pursuant to the Company's 1992 Incentive Stock Option Plan. With respect to these issuances of shares, the Company claims an exemption from registration under Section 4(2) because of the limited number of individuals to whom shares were issued, the fact that each of the individuals who received the shares was either a current senior Company executive, or had recently retired from a position as a senior executive of the Company, and that each of such individuals was well informed about the Company and its affairs. The issuances upon stock option exercise were as follows:
Item 6.
Item 6. - Selected Financial Data
Selected Financial Data on a Consolidated Basis (2002-1998)
(dollar amounts in thousands, except per share data)
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF CONSOLIDATED OPERATIONS
CRITICAL ACCOUNTING POLICIES
Note 1 to the Company's Consolidated Financial Statements contains a summary of the Company's significant accounting policies. The Company believes that its critical accounting policies are as follows:
EFFECTS OF REGULATION -- The Company follows SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, and its financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating the Company. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).
RECOVERABLE/ REFUNDABLE COSTS OF GAS AND PROPANE PURCHASES -- The Company accounts for purchased-gas costs in accordance with procedures authorized by the MPSC, the WPSC and the ACC under which purchased-gas and propane costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes.
DERIVATIVES -- The Company accounts for certain derivative contracts that are used to manage risk in accordance with Statement of Financial Accounting Standard (SFAS) 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, which the Company adopted July 1, 2000.
RESULTS OF CONSOLIDATED OPERATIONS
FISCAL YEAR ENDED JUNE 30, 2002 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2001
NET INCOME The Company's net income for fiscal 2002 was $1,401,000 compared to $2,765,000 in fiscal 2001, a decrease of $1,364,000. The Company's subsidiary, Energy West Resources, Inc. ("EWR"), had an earnings decrease of $1,946,000 primarily due to reductions in revenues from the remarketing of power. EWR's unusually high margins in fiscal year 2001 resulted from a combination of unusual factors, including historically high market prices and remarketing of uncommitted power. The reduction in EWR's net income from fiscal 2001 to fiscal 2002 was partially offset by an increase in net income in the natural gas operations of $300,000 and the propane operations of $282,000. The increase in natural gas net income was due primarily to record cold temperatures experienced during the months of April, May and June, 2002. In addition, the natural gas operations implemented reductions in discretionary expenses due to warmer-than-normal weather conditions experienced during the first nine months of the year. The increase in net income from propane operations is due to the sale of EWP's retail propane business in Montana and Wyoming.
REVENUE
Operating revenues of the Company decreased by 17% from approximately $120,161,000 in fiscal 2001 to $99,635,000 in fiscal 2002. This decrease was due primarily to a reduction in EWR's power remarketing revenues of $16,122,000, a reduction of revenues from the propane operations of $3,123,000, and a reduction in revenues from the natural gas operations of $1,281,000 due to lower prices of natural gas.
GROSS MARGIN
Gross margins (operating revenues less cost of goods sold) decreased approximately $5,856,000 from fiscal 2001 to fiscal 2002. EWR's gross margins decreased by $5,990,000 due mainly to a decline in revenue from remarketing of power. The unusually high margins from EWR's operations in fiscal 2001 resulted from a combination of unusual factors, including historically high market prices and remarketing of uncommitted power. The Company does not expect the combination of unusual factors that resulted in the unusually high gross margins in fiscal 2001 to be repeated in future years. The gross margins from the natural gas operations increased by $170,000 due to an increase in volumes of gas sold while the gross margin in the propane operations decreased by $36,000 due to higher propane costs.
OPERATING INCOME
The Company's operating income decreased by approximately $2,902,000 from fiscal 2001 to fiscal 2002. Operating income from EWR's operations decreased by $3,589,000 due to lower gross margins from the remarketing of power. This lower margin was partially offset by a reduction in EWR's other operating expenses of $2,401,000.
Operating income from the regulated natural gas operations increased by approximately $411,000 due to increased gross margins of $170,000 and reductions in other operating expenses of $241,000.
Propane operations experienced an increase of $275,000 in operating income primarily due to the gain from the sale of the retail propane assets reducing general and administrative expenses by $338,000 offset by an increase in other expenses of $27,000 and gross margin reductions of $36,000.
The Company's total operating expenses decreased by approximately $2,955,000 from fiscal 2001 to fiscal 2002. This reduction was due primarily to reduced incentive payments made during fiscal year 2002 compared to fiscal year 2001, and a reduction in corporate overhead and the reduction attributable to the sale of the propane assets. Also, the Company implemented cutbacks in non-essential operating and maintenance expenses in fiscal 2002. The cutbacks were implemented primarily in reaction to the expectation that warmer than normal temperatures in Montana, Wyoming and Arizona during the first nine months of fiscal year 2002 would cause reduced earnings.
INTEREST EXPENSE
Interest expense decreased by $392,000 from fiscal 2001 to fiscal 2002 due to a reduction in short term borrowings and a decrease in short term average interest rates from 8.4% during fiscal 2001 to approximately 4.6% during fiscal 2002.
NONOPERATING INCOME Nonoperating income increased by $376,000 from fiscal 2001 to fiscal 2002 due in part to a $300,000 settlement received by EWR in connection with its purchase a group of certain producing natural gas reserves. EWR received the $300,000 discount on the portion of its purchase price from the seller as a settlement on certain claims.
FISCAL YEAR ENDED JUNE 30, 2001 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2000
NET INCOME
The Company's net income for fiscal 2001 was $2,765,000 compared to $1,121,000 in fiscal 2000, an increase of $1,644,000. Net income from natural gas operations decreased by $198,000, primarily due to increases in distribution, general and administrative costs over the prior year. In fiscal year 2000, the Company implemented a planned reduction in certain discretionary expenses due to the warmer-than-normal weather conditions the Company was experiencing. In addition, increased corporate overheads from non-recurring costs increased distribution, general and administrative costs. In fiscal 2001, the propane operations experienced a decrease in net income of $118,000 also due to the spending restrictions imposed in the year 2000 that were not repeated in 2001. EWR had an earnings increase of $1,960,000 due to remarketing of electricity at unusually high market prices. The Company believes that such remarketing margins are unlikely to continue into the future at the higher levels experienced during fiscal 2001. The margins resulted from a combination of unusual factors, including historically high market prices and remarketing of uncommitted power. The Company does not expect the combination of unusual factors that resulted in the unusually high income for energy marketing and wholesale operations to be repeated in the future.
REVENUE Operating revenues increased by $47,775,000, or 66% from fiscal 2000 to fiscal 2001. This was due to colder temperatures in all the Company's operations, higher costs of natural gas which are passed directly to the customers, and remarketing of electricity at unusually high market prices. The Company does not expect the combination of unusual factors that resulted in the unusually high income for energy marketing and wholesale operations to be repeated in the future.
GROSS MARGIN Gross margins (operating revenues less cost of gas and electric trading) increased approximately $7,841,000, or 58% from fiscal 2000 to fiscal 2001. The Company's natural gas operations contributed $709,000 of this increase due to colder temperatures in both the Montana and Wyoming markets served by this operation. The propane operations contributed $568,000 due to significantly colder temperatures in all three markets served - Arizona, Wyoming and Montana. EWR's operations contributed $6,564,000 in increased margins due to remarketing of electricity at unusually high market prices. The Company does not expect the combination of unusual factors that resulted in the unusually high income for energy marketing and wholesale operations to be repeated in the future.
OPERATING INCOME
Operating income increased by approximately $3,169,000 from fiscal 2000 to fiscal 2001. EWR's operating income increased by $3,349,000, due mainly to the remarketing of power at unusually high market prices. Operating income for the natural gas and propane operations decreased by $175,000 and $4,000 respectively. Gross margin for natural gas operations increased by $709,000; however, increased operating expenses of nearly $884,000 caused a net reduction in operating income. The Company had implemented cutbacks in non-essential operating and maintenance expenses in fiscal 2000, but had not done so during fiscal 2001. In addition, the Company incurred approximately $473,000 in corporate overhead costs related to non-recurring strategic expenses, of which $179,000 was allocated to the natural gas operation.
The breakout of the decrease in operating income from the propane operations was as follows: gross margins increased by $568,000, but were offset by an increase in operating expenses of $572,000. The increase in operating expenses was due to a reduction in non-essential expenses during year 2000, which were not in place during 2001.
EWR's operating income increased by $3,349,000 due almost entirely to the remarketing of electricity at unusually high market prices. Gross margin increased by $6,564,000, which was offset by increased incentives and commissions of $2,293,000, equating to approximately 3% of the operation's revenue, an allocation of $224,000 related non-recurring fiscal 2001 strategic expenses allocated to EWR, and other cost increases resulting from EWR's expanded operations.
INTEREST EXPENSE
Interest expense increased by $423,000 or 25% from $1,674,000 in fiscal 2000 to $2,097,000 in fiscal 2001, due to higher short-term borrowing, as a result of higher gas and propane inventories and a higher level of gas costs in Montana (which were recoverable eventually through the regulatory cost tracking system.).
NONOPERATING INCOME
Nonoperating income decreased approximately $168,000 or 37% from $450,000 in fiscal 2000 to $282,000 in fiscal 2001. The primary reason for this decrease was due to a one-time gain in fiscal 2000 on the sale of various assets of EWD, which is included with the results of the natural gas operations.
OPERATING RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
FISCAL YEAR ENDED JUNE 30, 2002 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2001
REVENUES AND GROSS MARGINS Natural gas operating revenues in fiscal 2002 decreased to $39,709,000 from $40,991,000 in fiscal 2001. This was primarily due to warmer temperatures in the two states served by these operations, and lower cost of gas. In March 2001, the MPSC approved recovery of approximately $6,500,000 over one year for increased gas costs the Company had incurred prior to that period. As of June 2002 the EWM division had recovered all of the increased costs, and therefore the surcharge previously approved by the MPSC was eliminated. Going forward, the MPSC requires a monthly filing to adjust customer rates if natural gas prices increase or decrease by $.10 per Mcf.
Gross margin, which is defined as operating revenues less gas purchased, was approximately $9,958,000 for fiscal 2002 compared to approximately $9,788,000 in fiscal 2001 primarily due to lower cost of gas.
Gas purchases in the natural gas operations decreased by $1,452,000 from $31,203,000 in fiscal 2001 to $29,751,000 in fiscal 2002. The decrease in gas costs are reflective of the lower volumes sold due to the warmer temperatures, the lower cost of gas and the new gas cost recovery mechanism in Montana, which allowed for a more responsive treatment of the regulated gas costs to reflect market prices.
OPERATING EXPENSES Natural gas operating expenses, exclusive of the cost of gas purchased and federal and state income taxes were approximately $7,540,000 for fiscal 2002, as compared to $7,781,000 for fiscal 2001. The reduction of $241,000 is due to the reduction in non-essential operating expenses and reductions in the amount of overhead allocated to the natural gas operations.
NONOPERATING INCOME Nonoperating income increased by $59,000 from $110,000 in fiscal 2001 to $169,000 in fiscal 2002. The increase was due primarily to miscellaneous fixed asset sales during the current fiscal year.
INTEREST CHARGES Interest charges allocable to the Company's natural gas divisions reduced by $78,000 from $1,239,000 in fiscal 2001 compared to $1,161,000 during fiscal 2002. The reduction is the result of lower annual interest rates experienced in fiscal 2002 and lower short term borrowings by the Company.
INCOME TAXES State and federal income taxes allocated to the Company's natural gas divisions increased by $248,000 from $317,000 in fiscal 2001 to $565,000 during fiscal 2002. The increase was the result of an increase in taxable income of the natural gas operations.
FISCAL YEAR ENDED JUNE 30, 2001 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2000
REVENUES AND GROSS MARGINS Natural gas operating revenues in fiscal 2001 increased to $40,991,000 from approximately $24,301,000 in fiscal 2000, or 69%. This was primarily due to colder temperatures in the two states served by these operations, and higher rates recovered from customers for the additional costs of gas. The majority of this increase was in the EWM division. In March 2001, the Montana Public Service Commission (MPSC) approved recovery of approximately $6,500,000 over one year for gas costs the Company had incurred prior to that period. Going forward from that date, the MPSC requires a monthly filing to adjust customer rates if commodity prices increase or decrease by $.10 per Mcf.
Gross margin, which is defined as operating revenues less gas purchased, was approximately $9,788,000 for fiscal 2001 compared to approximately $9,079,000 in fiscal 2000. This increase resulted from colder temperatures in fiscal 2001. Weather in the Company's Montana operations was 16% colder than fiscal 2000, and 5% colder than normal. In the Company's Wyoming operations, weather was 25% colder in fiscal 2001 than fiscal 2000, and 2% warmer than normal.
Gas purchases in the natural gas operations increased by $15,981,000 from $15,222,000 in fiscal 2000 to $31,203,000 in fiscal 2001, an increase of nearly 105%. These increased costs are reflective of the additional volumes sold due to the colder temperatures, and the new gas cost recovery mechanism in Montana, which allowed for a more responsive treatment of the regulated gas costs to reflect market prices. The market price of natural gas hit historic highs during the winter months of fiscal 2001.
OPERATING EXPENSES Natural gas operating expenses, exclusive of the cost of gas purchased and federal and state income taxes were approximately $7,781,000 for fiscal 2001, as compared to approximately $6,897,000 for fiscal 2000. In fiscal 2000, the Company reduced non-essential discretionary expenses in response to the warmer temperatures. The 13% increase in fiscal 2001 is representative of a return to budgeted expenditures.
OTHER INCOME Other income declined from $252,000 in fiscal year 2000 to $110,000 in fiscal year 2001. In fiscal 2000, EWD realized a one-time capital gain of approximately $95,000 from the sale of property.
INTEREST CHARGES Interest charges allocable to the Company's natural gas divisions were approximately $1,239,000 in fiscal 2001, as compared to approximately $1,186,000 in fiscal 2000, primarily due to higher short-term borrowing, as a result of higher costs of gas, and increased gas costs in Montana that were not recovered until following the MPSC's ruling in March 2001.
INCOME TAXES State and federal income taxes allocated to the Company's natural gas divisions were approximately $317,000 in fiscal 2001, as compared to approximately $489,000 in fiscal 2000 primarily due to the decrease in pre-tax earnings.
OPERATING RESULTS OF THE COMPANY'S PROPANE OPERATIONS
FISCAL YEAR ENDED JUNE 30, 2002 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2001
REVENUES AND GROSS MARGINS Propane revenues decreased from $14,130,000 in fiscal 2001 to $11,007,000 in fiscal 2002, a reduction of $3,123,000 or 22%. This decrease in revenues was due mainly to lower spot market prices for propane sold during fiscal year 2002 as well as a 10% reduction in volumes sold from fiscal 2001 compared to fiscal 2002. In addition, the sale of EWP's retail propane operations in Montana and Wyoming caused a reduction in total revenues of approximately $383,000. The propane operations were able to utilize the lower market prices advantageously to purchase lower priced propane. The cost of propane sold decreased from $9,711,000 during fiscal 2001 to $6,624,000 in fiscal 2000, a reduction of approximately 32%. Gross margins decreased by $36,000, or less than 1%.
OPERATING EXPENSES Operating expenses were $3,129,000 for fiscal 2002 compared to $3,440,000 for fiscal 2001, a decrease of $311,000. The operating expenses decreased due to a reduction in general and administrative expenses of $338,000 resulting from the sale of EWP's retail propane assets in Montana and Wyoming. This was offset by costs incurred for propane pipeline safety maintenance in the EWA division.
NONOPERATING INCOME Other income increased by $68,000 from $128,000 in fiscal 2001 to $196,000 in fiscal year 2002.
INTEREST EXPENSE AND INCOME TAXES Interest expense was reduced from $518,000 in fiscal 2001 to $450,000 in fiscal 2002. The reduction of $68,000 is due to lower interest costs allocated to the propane operations resulting from lower overall borrowings by the Company and the lower average interest rates on short term borrowings. Income taxes increased from $231,000 in fiscal 2002 to $362,000 in fiscal 2002 due to higher taxable income for the year.
FISCAL YEAR ENDED JUNE 30, 2001 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2000
REVENUES AND GROSS MARGINS Propane revenues increased approximately $5,649,000 or 67% from $8,481,000 in fiscal 2000 to $14,130,000 in fiscal 2001. These increases occurred primarily because of significantly colder temperatures in EWP's market areas in Arizona, Wyoming and Montana, and higher propane prices during the winter months of fiscal 2001. Gross margin increased by approximately $568,000, again due to the weather related increases. Weather in 2001 was closer to normal versus much warmer than normal temperatures in fiscal year 2000.
EXPENSES FOR OPERATIONS, INTEREST AND INCOME TAXES Operating expenses for propane operations increased from approximately $2,868,000 in fiscal 2000 to approximately $3,440,000 in fiscal 2001, an increase of $572,000. The increase in operating expenses was primarily due to the fact that the Company had imposed certain spending reductions during fiscal 2000 in response to the unusually warm temperatures. In fiscal year 2001, the Company returned to more normal spending patterns. Interest charges allocable to the Company's propane divisions were approximately $518,000 in fiscal 2001 compared to approximately $366,000 in fiscal 2000. The increased interest costs were primarily due to increased average capital employed in fiscal year 2001. State and federal income taxes decreased to approximately $231,000 for fiscal 2001 from $287,000 for fiscal 2000 due to lower pre-tax income in the propane operations in fiscal 2001.
OPERATING RESULTS OF ENERGY WEST RESOURCES, INC.
FISCAL YEAR ENDED JUNE 30, 2002 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2001
REVENUES
EWR's revenues decreased $16,122,000 from fiscal 2001 to fiscal 2002. The 25% decrease was attributable to the reduction in revenues associated with the remarketing of power. Additionally, lower commodity prices in fiscal 2002 were reflected in revenue.
GROSS MARGINS EWR experienced a reduction in gross margin from fiscal 2001 to fiscal 2002 of $5,990,000. The majority of this 83% decrease in gross margin was attributable to the reduction in margins associated with the remarketing of electricity. EWR benefited from unusually high market prices during fiscal year 2001. The same market conditions were not present during fiscal year 2002.
OPERATING EXPENSES Operating expenses for EWR were $1,593,000 during fiscal 2002 compared to $3,994,000 during fiscal 2001. The $2,401,000 decrease was due mainly to a reduction in incentives and commissions related to the decrease in gross margins. These reductions were offset in part by approximately $535,000 in legal expenses incurred by EWR in fiscal 2002 related to its ongoing litigation with PPL, Montana (described in Part II, Item 1, Legal Proceedings).
NONOPERATING INCOME EWR's nonoperating income was $250,000 higher in fiscal year 2002 compared to fiscal year 2001. The majority of this increase was due to a $300,000 settlement received by EWR as in connection with its purchase of a group of producing natural gas reserves located in northern Montana. EWR received the $300,000 discount on its purchase price from the seller as a settlement on certain claims against the seller. This transaction took place during the fourth quarter of fiscal 2002.
INTEREST EXPENSE Interest expense decreased during fiscal year 2002 by $244,000 due mainly to a decrease in short-term borrowing rates, as well as an overall reduction in borrowing.
INCOME TAXES The EWR operations realized an income tax benefit of $54,000 during fiscal 2002 compared to an expense of $1,095,000 in fiscal year 2001 due to the reduction in taxable income from its operations.
FISCAL YEAR ENDED JUNE 30, 2001 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2000
REVENUE EWR's revenue increased by $25,435,000 from fiscal 2000 to fiscal 2001. The 69% increase was a result of the remarketing of power at unusually high market prices. Additionally, the commodity price of gas in fiscal 2001 was higher than in fiscal 2000 which is also reflected in increased revenue.
GROSS MARGINS EWR's gross margins increased by $6,564,000 from fiscal 2000 to fiscal 2001 mainly as result of a combination of unusual factors, including historically high market prices and remarketing of uncommitted power. The Company does not expect these unusual conditions to continue in future periods.
EXPENSES FOR OPERATIONS, INTEREST AND INCOME TAXES EWR's operating expenses related to energy marketing and wholesale activities increased from approximately $779,000 in fiscal 2000 to approximately $3,994,000 in fiscal 2001. The increase of $3,215,000 (or 5% of EWR's revenue) was mainly due to higher incentive and commissions related to higher margins in fiscal 2001, and costs related to non-recurring strategic expenses. Interest charges increased approximately $216,000 from fiscal 2000 to fiscal 2001 due to increased working capital requirements in fiscal 2001. State and federal income taxes increased in fiscal 2001 to approximately $1,095,000 from a benefit of $67,000 in fiscal 2000, due to the increase in pre-tax earnings.
CASH FLOW ANALYSIS
The primary cash flows during the last three years are summarized below:
Cash provided by operating activities consists of net income and noncash items including depreciation, depletion, amortization and deferred income taxes. Additionally, changes in working capital are also included in cash provided by operating activities. The Company expects that internally generated cash, coupled with short-term borrowings, will be sufficient to satisfy its operating, normal capital expenditure and dividend requirements.
LIQUIDITY AND CAPITAL RESOURCES
The Company's utility operations are subject to regulation by the MPC, the WYPSC, and the ACC. This factor plays a significant role in determining the Company's return on equity. The various commissions approve rates that are intended to permit a specified rate of return on
investment. The Company's tariffs allow the cost of gas to be passed through to customers. The pass-through causes some delay, however, between the time that the gas cost are incurred by the Company and the time that the Company recovers such costs from customers.
The business of the Company and its subsidiaries in all segments is temperature-sensitive. In any given period, sales volumes reflect the impact of weather, in addition to other factors, with colder temperatures generally resulting in increased sales by the Company. The Company anticipates that this sensitivity to seasonal and other weather conditions will continue to be reflected in the Company's sales volumes in future periods.
Because of the seasonal nature of the Company's sales, cash generated from operations during the warmer months (when sales volumes decrease considerably) is significantly lower than during colder months. Additionally, most of the Company's construction activity takes place during the non-heating season because of more favorable weather conditions. During these warmer, non-heating months, cash needs for operations and construction are primarily met through short-term borrowings.
Capital expenditures for the Company and its subsidiaries for fiscal 2003 are expected to be $3.3 million. The capital expenditures will be made for system extensions as well as the replacement and improvement of existing transmission, distribution, gathering and general facilities.
At June 30, 2002, the Company had $26,000,000 in bank lines of credit, of which $3,500,000 had been borrowed the application at June 30, 2002. The Company's short-term borrowings under these lines of credit during fiscal 2001 had a daily weighted average interest rate of 4.60% per annum. At the June 30, 2002, the Company had outstanding letters of credit totaling $4,150,000 related to electricity and gas purchase contracts. These letters of credit are netted against the Company's bank lines of credit, resulting in net availability of $18,350,000 under the lines of credit at June 30, 2002.
In addition to its bank lines of credit, the Company has outstanding certain notes and industrial development revenue obligations (collectively "Long Term Debt"). The Company's Long Term Debt is made up of three separate obligations: $8.0 million of Series 1997 unsecured notes bearing interest at the rate of 7.5%; $7.8 million of Series 1993 unsecured notes bearing interest at rates ranging from 6.20% to 7.60%; and Cascade County, Montana Series 1992B Industrial Development Revenue Obligations in the amount of $1.8 million.
The total amount of such obligations was $15,856,000 and $16,346,000, at June 30, 2002 and June 30, 2001, respectively. The portion of such obligations due within one year was $500,000 and $465,000, at June 30, 2001, and June 30, 2002, respectively. Under the terms of such Long-Term Debt obligations, additional principal payments of $530,000 will be due during fiscal 2004, $570,000 during fiscal 2005, $610,000 during fiscal 2006, $655,000 during fiscal 2007, and $12,991,000 during periods after fiscal 2007.
A table of the Company's long-term debt, as well as other long-term commitments and contingencies, and the corresponding maturity dates are listed below. The "Less than 1 year" amount listed below for "Unconditional Purchase Obligations" represents purchase obligations of natural gas under take or pay agreements and obligations due within one year related to operating lease commitments.
Payments Due by Period
Under the terms of the Long Term Debt obligations, the Company is subject to certain restrictions, including restrictions on total dividends and distributions, senior indebtedness, and asset sales, and the Company is required to maintain certain financial debt and interest ratios.
An adverse outcome in the litigation with PPLM or the tax dispute with the DOR could have a material adverse effect on the Company's liquidity and capital resources. See "Item 3 - Legal Proceedings."
RISK FACTORS
The major factors which will affect the Company's future results include general and regional economic conditions, weather, customer retention and growth, the ability to meet competitive pressures and to contain costs, the adequacy and timeliness of rate relief, cost recovery and necessary regulatory approvals, and continued access to capital markets. In addition, changes in the competitive environment particularly related to the Company's propane and energy marketing segments could have a significant impact on the performance of the Company.
The regulatory structure is in transition. Legislative and regulatory initiatives, at both the federal and state levels, have been designed to promote competition. The changes in the gas industry have allowed certain customers to negotiate their own gas purchases directly with producers or brokers. To date, the changes in the gas industry have not had a negative impact on earnings or cash flow of the Company's regulated segment.
The Company's regulated natural gas and propane vapor operations follow Statement of Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation," ("SFAS 71"), and its financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating the Company. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). If the Company's natural gas and
propane vapor operations were to discontinue the application of SFAS 71, the accounting impact would be an extraordinary, non-cash charge to operations that could be material to the financial position and results of operation of the Company. However, the Company is unaware of any circumstances or events in the foreseeable future that would cause it to discontinue the application of SFAS 71.
In addition to the factors discussed above, the following are important factors that could cause actual results to differ materially from any results projected, forecasted, estimated or budgeted:
- - Fluctuating energy commodity prices, including prices for fuel and purchased power;
- - The possibility that regulators may not permit the Company to pass through all such increased costs to customers;
- - Fluctuations in wholesale margins due to uncertainty in the wholesale propane and power markets;
- - Changes in general economic conditions in the United States and changes in the industries in which the Company conducts business;
- - Changes in federal or state laws and regulations to which the Company is subject, including tax, environmental and employment laws and regulations;
- - The impact of FERC and state public service commission statutes and regulation, including allowed rates of return, the pace of deregulation in retail natural gas and electricity markets, and the resolution of other regulatory matters;
- - The ability of the Company and its subsidiaries to obtain governmental and regulatory approval of various expansion or other projects;
- - The costs and effects (including the possibility of adverse outcomes) of legal and administrative claims and proceedings against the Company or its subsidiaries, particularly the litigation with PPLM and the property tax dispute with the DOR;
- - Conditions of the capital markets the Company utilizes to access capital to finance operations;
- - The ability to raise capital in a cost-effective way;
- - The effect of changes in accounting policies, if any;
- - The ability to manage growth of the Company;
- - The ability to control costs;
- - The ability of each business unit to successfully implement key systems, such as service delivery systems;
- - The ability of the Company and its subsidiaries to develop expanded markets and product offerings as well as their ability to maintain existing markets;
- - The ability of customers of the energy marketing and trading business to obtain financing for various projects;
- - The ability of customers of the energy marketing and trading business to obtain governmental and regulatory approval of various projects;
- - Future utilization of pipeline capacity, which can depend on energy prices, competition from alternative fuels, the general level of natural gas and propane demand, decisions by customers not to renew expiring natural gas or propane contracts, and weather conditions; and
- - Global and domestic economic repercussions from terrorist activities and the government's response thereto.
RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended June 30, 2002, 2001 and 2000, the Company's ratio of earnings to fixed charges was 2.20, 2.95 and 1.95 times, respectively. Fixed charges include interest related to long-term debt, short-term borrowing, certain lease obligations and other current liabilities.
INFLATION
Capital intensive businesses, such as the Company's natural gas and propane vapor operations, are significantly affected by long-term inflation. Neither depreciation charges against earnings nor the ratemaking process reflect the replacement cost of utility plant. However, based on past practices of regulators, the Company anticipates that it will be permitted to recover and earn a rate of return on the actual cost of its investment in the replacement or upgrade of plant assets. Although prices for natural gas and propane vapor may fluctuate, earnings are not impacted by such fluctuation because gas and propane vapor cost tracking procedures approved by the various public service commissions balance gas and propane vapor costs collected from customers with the costs of supplying natural gas and propane vapor. The Company believes that the effects of inflation, at currently anticipated levels, will not materially affect results of operations.
ENVIRONMENTAL ISSUES
The Company owns property on which it operated a manufactured gas plant from 1909 to 1928. The site is currently used as a service center by the Company. The coal gasification process utilized in the manufactured gas plant resulted in the production of certain by-products that have been classified by the federal government and the State of Montana as hazardous to the environment. In 1999, the Company received approval from the Montana Department of Environmental Quality ("MDEQ") for a plan proposed by the Company for remediation of soil contaminants at the site. To date, all contaminated soil has been removed, and an asphalt cap has been placed over the site. The Company and its consultants continue their work with the MDEQ relating to a remediation plan proposed by the Company for water contaminants.
At June 30, 2002, the Company had incurred cumulative costs of approximately $1,950,000 in connection with its evaluation and remediation of the site. On May 30, 1995, the Company received an order from the MPSC allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of June 30, 2002, the Company had recovered approximately $1,276,000 through such surcharges. The Company expects to recover the full amount expended through the surcharge. The Commission's decision calls for ongoing review by the Commission of any costs incurred. The Company will submit an application for review by the Commission when the remediation plan for water contaminants is approved by the MDEQ.
DERIVATIVES AND RISK MANAGEMENT
The Company and its subsidiaries are subject to certain risks related to changes in certain commodity prices and risks of counter-party performance. The Company and its subsidiaries have established certain policies and procedures to manage such risks. The Company has a Risk Management Committee ("RMC"), comprised of Company officers to oversee the Company's risk management program as defined in its risk management policy. The purpose of the risk management program is to minimize adverse impacts on earnings resulting from volatility of energy prices, counter-party credit risks, and other risks related to the energy commodity business. The RMC is overseen by the Audit Committee of the Company's Board of Directors.
GENERAL - From time to time the Company or its subsidiaries may use derivative financial contracts to mitigate the risk of commodity price volatility related to firm commitments to purchase and sell natural gas or electricity. The Company or a subsidiary may use such arrangements to protect its profit margin on future obligations to deliver quantities of a commodity at a fixed price. Conversely, such arrangements may be used to hedge against future market price declines where the Company or a subsidiary enters into an obligation to purchase a commodity at a fixed price in the future. The Company accounts for such financial instruments in accordance with Statement of Financial Accounting Standard (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities," which the Company adopted July 1, 2000.
In accordance with SFAS 133, such financial instruments are reflected in the Company's financial statements at "fair value", determined as of the date of the balance sheet. This accounting treatment is also referred to as "mark-to-market" accounting. Mark-to-market accounting treatment can result in a disparity between reported earnings and realized cash flow, because changes in the value of the financial instrument are reported as income or loss even though no cash payment may have been made between the parties to the contract. If such contracts are held to maturity, the cash flow from the contracts, and their hedges, are realized over the life of the contracts.
Quoted market prices for natural gas derivative contracts of the Company or its subsidiaries generally are not available. Therefore, to determine the fair value of natural gas derivative contracts, the Company uses internally developed valuation models that incorporate available current and historical independent pricing information. The use of such models is inherently less reliable than reference to an active market or exchange in determining fair value.
The Company classifies contracts under which the Company or a subsidiary agrees to future purchases or sales of physical volumes of natural gas as normal purchase or sale arrangements, and therefore is not required to use mark-to-market valuation for such contracts under SFAS 133.
WHOLESALE OPERATIONS - During fiscal year 2001 and part of fiscal year 2002, EWR was party to a number of contracts, which were valued on a mark-to-market basis under SFAS 133. Although certain firm commitments to purchase and sell could potentially have been classified as
normal purchases and sales, and excluded from the valuation requirements of SFAS 133, EWR elected to classify these commitments as derivatives subject to the mark-to-market valuation under SFAS 133 in order to properly match commitments to purchase and sell for financial reporting purposes. Therefore, such commitments were recorded in the Company's consolidated balance sheet at fair value. Quarterly mark-to-market adjustments to the fair values of these commitments were recorded in gross margin.
In January 2002, EWR terminated its derivative contracts with Enron Canada Corporation (ECC), a subsidiary of Enron, Inc. Most of these contracts were commodity swaps that EWR had obtained to protect against fluctuations in the market price of natural gas. The derivative contracts with ECC were entered into at various times in order to lock in margins on certain agreements under which EWR had agreed to sell natural gas to customers for future delivery at fixed prices (the "Future Supply Agreements"). EWR made the decision to terminate these ECC contracts because of concerns relating to the bankruptcy of Enron, Inc. At the time of termination, the prevailing price of natural gas was substantially lower than such price had been at the times when EWR entered into the ECC contracts, resulting in a net amount due from EWR to ECC of approximately $5,400,000. EWR paid this amount to ECC upon the termination of the ECC contracts, and thereby discharged the liability related to the contracts. The net effect of the termination on the Company's consolidated net income was immaterial. The costs related to such termination are reflected in the Company's Consolidated Income Statement as Gas Purchases.
At the time it terminated the ECC derivative contracts, EWR secured new gas purchase contracts (the "Future Purchase Agreements") at prices much lower than those provided for under the ECC contracts. The Future Supply Agreements continue to be valued on a mark-to market basis. Therefore, the value of such agreements has been reflected in the Company's consolidated net income.
As of June 30, 2002, the Future Supply Agreements were reflected on the Company's Consolidated Balance Sheet at an approximate aggregate fair value as follows:
The Company does not expect the values of such Future Supply Agreements to fluctuate significantly because the values are a function of the fixed prices under both the Future Supply Agreements and the Future Purchase Agreements. Therefore, EWR expects that the present value of future cash collections (net of the cost of the commodity supplied) under such agreements will be approximately equal to the amounts set forth above. Factors that could negatively affect the ability of EWR to realize on such net cash collections include credit risk associated with individual customers, and possible volume demands in excess of the amount for which EWR has contracted at a fixed price under the Future Purchase Agreements. The Company does not expect such factors to have a material effect, although no assurance can be given that such factors will not negatively and materially affect such expected cash collections.
Failure to realize the full amount of expected net cash collections would negatively affect the Company's future income.
Since January 2002, EWR has not entered into any new contracts that have required mark-to-market valuation under SFAS 133.
NATURAL GAS OPERATIONS - In the case of the Company's regulated divisions, gains or losses resulting from the eventual settlement of derivative contracts are subject to deferral under regulatory procedures approved by the public service regulatory commissions of Montana, Wyoming and Arizona. Therefore, related derivative assets and liabilities are offset with corresponding regulatory liability and asset amounts included in "Recoverable Cost of Gas Purchases", pursuant to SFAS 71, "Accounting for Certain Types of Regulation." Thus, SFAS 133 has no effect on earnings from the Company's regulated operations.
SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION
Supplemental quarterly financial information is set forth in Note 15 to the Company's Consolidated Financial Statements.
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
The foregoing Management's Discussion and Analysis and other portions of this annual report on Form 10-K contain various "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Sections 21E of the Securities Exchange Act of 1934, as amended, which represent the Company's expectations or beliefs concerning future events. Forward-looking statements can be identified by words such as "anticipates," "believes," "expects," "planned," "scheduled" or similar expressions. Although the Company believes these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that could cause future results to be materially different from the results stated or implied in this document.
Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of the Company from time to time, including statements contained in the Company's filings with the Securities and Exchange Commission and its reports to shareholders, involve known and unknown risks and other factors which may cause the Company's actual results in future periods to differ materially from those expressed in any forward-looking statements. Factors that could cause or contribute to such differences included, but are not limited to: (i) fluctuations in energy commodity prices, including prices for fuel and purchased power, (ii) the impact of state and federal laws and regulations, (iii) the possibility that regulators may not permit the Company to pass through all costs to customers, (iv) fluctuations in wholesale margins due to uncertainty in the wholesale gas, propane and power markets, (iv) costs and expenses of, and uncertainties relating to, pending litigation and other disputes, particularly the litigation with PPLM and the property tax dispute with the DOR, and (v) other factors discussed above, including items under the heading "Risk Factors."
Any such forward-looking statement is qualified by reference to these risks and factors. The Company cautions that these risks and factors are not exclusive. The Company does not undertake to update any forward-looking statement that may be made from time to time by or on behalf of the Company except as required by law.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company and its subsidiaries are subject to certain market risks, including commodity price risk (i.e., natural gas, electric and propane prices) and interest rate risk. The adverse effects of potential changes in these market risks are discussed below. The sensitivity analyses presented do not consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions management may take to mitigate the Company's exposure to such changes. Actual results may differ. See the notes to the financial statements for a description of the Company's accounting policies and other information related to these financial instruments.
COMMODITY PRICE RISK
The Company protects itself against price fluctuations on natural gas and electricity by limiting the aggregate level of net open positions, which are exposed to market price changes and through the use of natural gas derivative instruments. The net open position is actively managed with strict policies designed to limit the exposure to market risk, and which require at least weekly reporting to management of potential financial exposure. The risk management committee has limited the types of financial instruments the Company or its subsidiaries may trade to those related to natural gas commodities. The Company's results of operations are significantly impacted by changes in the price of natural gas. During 2002 and 2001, natural gas accounted for 66% and 77% respectively, of the Company's operating expenses. The Company's regulated operations are allowed recovery of costs associated with the purchase of natural gas. In most cases, these costs are recovered within one year which mitigates the risk associated with changes in the market price of the commodity.
INTEREST RATE RISK
The Company's results of operations are affected by fluctuations in interest rates (e.g. interest expense on debt). The Company mitigates this risk by entering into long-term debt agreements with fixed interest rates. The Company's notes payable are subject to variable interest rates. Based on the amount of the outstanding notes payable on June 30, 2002, a one percent increase (decrease) in average interest rates would result in a decrease (increase) in annual pre-tax net income of approximately $35,000. See Note 7 to the Company's Consolidated Financial Statements.
CREDIT RISK
Credit risk relates to the risk of loss that the Company would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with the Company. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances which relate to other market participants which have a direct or indirect
relationship with such counterparty. The Company seeks to mitigate credit risk by evaluating the financial strength of potential counterparties. However, despite mitigation efforts, defaults by counterparties may occur from time to time. To date, no material default has occurred.
Item 8.
Item 8. Financial Statements and Supplementary Data
Report of Independent Auditors
To the Board of Directors and Stockholders of Energy West Incorporated Great Falls, Montana
We have audited the accompanying consolidated balance sheet of Energy West Incorporated and subsidiaries as of June 30, 2002, and the related consolidated statements of income, stockholders' equity, and cash flows for the year then ended. Our audit also included the information for the year ended June 30, 2002 in the financial statement schedule listed in the Index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy West Incorporated and subsidiaries at June 30, 2002, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the information for the year ended June 30, 2002, in the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Salt Lake City, Utah September 25, 2002
Report of Independent Auditors
The Board of Directors Energy West Incorporated
We have audited the accompanying consolidated balance sheet of Energy West Incorporated and subsidiaries as of June 30, 2001, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the two years in the period ended June 30, 2001. Our audits also included the information for each of the two years in the period ended June 30, 2001 in the financial statement schedule listed in the index at item 14(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energy West Incorporated and subsidiaries at June 30, 2001, and the consolidated results of their operations and their cash flows for each of the two years in the period ended June 30, 2001, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule for each of the two years in the period ended June 30, 2001, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
ERNST & YOUNG LLP
Salt Lake City, Utah August 31, 2001
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, JUNE 30, 2002 AND 2001 - --------------------------------------------------------------------------------
See notes to consolidated financial statements. (Continued)
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, JUNE 30, 2002 AND 2001 - --------------------------------------------------------------------------------
See notes to consolidated financial statements. (Concluded)
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED JUNE 30, 2002, 2001, AND 2000 - --------------------------------------------------------------------------------
See notes to consolidated financial statements.
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED JUNE 30, 2002, 2001, AND 2000 - --------------------------------------------------------------------------------
See notes to consolidated financial statements.
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED JUNE 30, 2002, 2001, AND 2000 - --------------------------------------------------------------------------------
(Continued)
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED JUNE 30, 2002, 2001, AND 2000 - --------------------------------------------------------------------------------
See notes to consolidated financial statements. (Concluded)
ENERGY WEST INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 2002 AND 2001 - --------------------------------------------------------------------------------
1. SUMMARY OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
NATURE OF BUSINESS -- Energy West Incorporated (the "Company") is a regulated public entity with certain non-utility operations conducted through its subsidiaries. The Company's regulated utility operations involve the distribution and sale of natural gas to the public in and around Great Falls and West Yellowstone, Montana and Cody, Wyoming, and the distribution and sale of propane to the public through underground propane vapor systems in and around Payson, Arizona and Cascade, Montana. The Company's West Yellowstone, Montana operation is supplied by liquefied natural gas ("LNG").
The Company's non-regulated operations include wholesale distribution of bulk propane in Wyoming, Arizona, and Montana and the retail distribution of bulk propane in Arizona. The Company also markets gas and electricity in Montana and Wyoming through its non-regulated subsidiary, Energy West Resources ("EWR").
PRINCIPLES OF CONSOLIDATION -- The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Energy West Propane ("EWP"), EWR, and Energy West Development ("EWD"). The consolidated financial statements also include the Company's proportionate share of the assets, liabilities, revenues, and expenses of certain producing natural gas reserves that were acquired in 2002 (see Note 2) of which the Company owns a 56% undivided interest. All intercompany transactions and accounts have been eliminated.
SEGMENTS -- The Company reports financial results for three business segments: Natural Gas Operations, Propane Operations, and EWR. Summarized financial information for these three segments is set forth in Note 11.
USE OF ESTIMATES IN PREPARING FINANCIAL STATEMENTS -- The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the 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 these estimates. The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the various public service commissions with jurisdiction over the Company. Estimates are also used in the development of discount rates and trend rates related to the measurement of postretirement benefit obligations and accrual amounts, allowances for doubtful accounts, valuing derivative instruments, estimating litigation reserves, and in the determination of depreciable lives of utility plant.
NATURAL GAS AND PROPANE INVENTORIES -- Natural gas inventory and propane inventory are stated at the lower of weighted average cost or net realizable value except for Energy West Montana - Great Falls, which is stated at the rate approved by the Montana Public Service Commission ("MPSC"), which includes transportation and storage costs.
RECOVERABLE/REFUNDABLE COSTS OF GAS AND PROPANE PURCHASES -- The Company accounts for purchased gas and propane costs in accordance with procedures authorized by the MPSC, the Wyoming Public Service Commission, and the Arizona Corporation Commission. Purchased gas and propane costs that
are different from those provided for in present rates are accumulated and recovered or credited through future rate changes.
In March 2001, the Company was granted an interim order that allowed the addition of $2.12 per Mcf surcharge to recover approximately $6,824,000 of previously unrecovered gas costs. Such costs have been reflected as a recoverable asset in the accompanying financial statements as of June 30, 2001. The Company recovered in excess of these costs during fiscal 2002 resulting in a refundable gas obligation totaling approximately $2,024,000 as of June 30, 2002. Such amount has been reflected as a liability in the accompanying financial statements. Effective July 1, 2002, the MPSC approved the Company's application to discontinue this surcharge. The Company has in place an interim order that allows for the recovery of gas costs when there is a gas cost change that exceeds $.10 per Mcf.
UTILITY PLANT -- Property, plant and equipment are recorded at original cost when placed in service. Depreciation and amortization on assets are generally recorded on a straight-line basis over the estimated useful lives, as applicable, at various rates. The average rates of depreciation and amortization were approximately 3.40%, 3.47% and 3.47% during the years ended June 30, 2002, 2001 and 2000, respectively.
NATURAL GAS RESERVES -- During 2002, the Company acquired an undivided interest in certain producing natural gas reserves on properties located in northern Montana (see Note 2). The reserves are estimated to have approximately 3.4 million Mmbtu in remaining natural gas reserves. The Company is depleting these reserves using the units-of-production method. The gas reserves are included in Utility Plant in the accompanying financial statements.
IMPAIRMENT OF LONG-LIVED ASSETS -- The Company evaluates its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets or intangibles may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.
STOCK-BASED COMPENSATION -- The Company has elected to follow the accounting provisions of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees for Stock-Based Compensation, for stock options granted to employees and directors and to furnish the pro forma disclosure required under Statement of Financial Accounting ("SFAS") No. 123, Accounting for Stock-Based Compensation.
COMPREHENSIVE INCOME -- During the year ended June 30, 2002, 2001, and 2000, the Company had no components of comprehensive income other than net income.
REVENUE RECOGNITION -- Revenues are recognized in the period that services are provided or products are delivered. The Company records gas distribution revenues for gas delivered to residential and commercial customers but not billed at the end of the accounting period. The Company periodically collects revenues subject to possible refunds pending final orders from regulatory agencies. When this occurs, appropriate reserves for such revenues collected subject to refund are established.
DERIVATIVES -- The Company uses exchange traded futures and options contracts (derivative contracts) to manage the volatility related to firm commitments to purchase and sell natural gas in order to lock in a margin on a particular sales contract or group of contracts. The accounting for derivative financial instruments that are used to manage risk is in accordance with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, which the Company adopted July 1, 2000. Gains and losses from derivative instruments are included as a component of gas and electric--wholesale revenues in the accompanying consolidated statements of income. For the years ended June 30, 2002 and 2001, the Company recognized net gains totaling $2,647,000 and $221,000 respectively.
DEBT ISSUANCE AND REACQUISITION COSTS -- Debt premium, discount and issue costs are amortized over the life of each debt issue. Debt reacquisition costs for refinanced debt are amortized over the remaining life of the debt.
CASH AND CASH EQUIVALENTS -- All highly liquid investments with original maturities of three months or less at the date of acquisition are considered to be cash equivalents.
EARNINGS PER SHARE -- Net income per common share is computed by both the basic method, which uses the weighted average number of the Company's common shares outstanding, and the diluted method, which includes the dilutive common shares from stock options, as calculated using the treasury stock method. The only dilutive securities are the stock options described in Note 12. The dilutive effect of stock options for the years ended June 30, 2002 and 2001 was an increase to basic weighted average common shares outstanding of 9.837 and 14.201 respectively. The effect of stock options for the years ended June 30, 2000 would have been antidilutive.
CREDIT RISK -- The Company's primary market areas are primarily Montana, Wyoming, and Arizona. Exposure to credit risk may be impacted by the concentration of customers in these areas due to changes in economic or other conditions. Customers include individuals and numerous industries that may be affected differently by changing conditions. Management believes that its credit review procedures, loss reserves, customer deposits, and collection procedures have adequately provided for usual and customary credit related losses.
EFFECTS OF REGULATION -- The Company follows SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, and its consolidated financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating the Company. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).
INCOME TAXES -- The Company files its income tax returns on a consolidated basis. Rate-regulated operations record cumulative increases in deferred taxes as income taxes recoverable from customers. The Company uses the deferral method to account for investment tax credits as required by regulatory commissions. Deferred income taxes are determined using the asset and liability method, under which deferred tax assets and liabilities are measured based upon the temporary differences between the financial statement and income tax bases of assets and liabilities, using current tax rates.
FINANCIAL INSTRUMENTS -- The fair value of all financial instruments with the exception of fixed rate long-term debt approximates carrying value because they have short maturities or variable rates of interest that approximate prevailing market interest rates.
NEW ACCOUNTING PRONOUNCEMENTS -- In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS 142 changes the accounting for goodwill and indefinite lived intangible assets from an amortization method to an impairment-only approach. Goodwill, including goodwill recorded in past business combinations, is no longer amortized but is tested for impairment at least annually at the reporting unit level. The Company is required to adopt SFAS No. 142 for its fiscal year beginning July 1, 2002. The Company has no recorded goodwill as of June 30, 2002. Accordingly, management does not expect this statement to have a material impact on the Company's financial position or results of operations.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement addresses financial accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. The Company is required to implement SFAS No. 143 on July 1, 2002. Management has not determined the impact, if any, that this statement will have upon the Company.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. The statement retains the previously existing accounting requirements related to the recognition and measurement of the impairment of long-lived assets to be held and used but expands the measurement requirements of long-lived assets to be disposed of by sale to include discontinued operations. It also expands the previously existing reporting requirements for discontinued operations to include a component of an entity that either has been disposed of or is classified as held for sale. The Company is required to implement SFAS No. 144 on July 1, 2002. Management does not expect this statement to have a material impact on the Company's financial position or results of operations.
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement eliminates the required classification of gain or loss on extinguishment of debt as an extraordinary item of income and states that such gain or loss be evaluated for extraordinary classification under the criteria of Accounting Principles Board No. 30 "Reporting Results of Operations." This statement also requires sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions, and makes various other technical corrections to existing pronouncements. The Company is required to implement SFAS No. 145 on July 1, 2002. Management does not expect this statement to have a material impact on its financial position or results of operations.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. This statement nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). This statement requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred rather than the date of an entity's commitment to an exit plan. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. Management has not determined the impact, if any, that this statement will have on the Company.
RECLASSIFICATIONS -- Certain prior year amounts have been reclassified to conform to the current year presentation.
2. PROVED NATURAL GAS RESERVES
In November 1999, EWR entered into a contract with a seller of natural gas whereby the seller agreed to supply and EWR agreed to purchase a minimum fixed quantity of natural gas at an agreed-upon price. During the term of the contract, the seller was unable to supply EWR with the quantities specified in the contract, and, accordingly, EWR was required to purchase natural gas from other suppliers at prices that exceeded the contract price. For remedies in the event of a breach on the part of the seller, the contract required payment by the seller to EWR of an amount equal to the difference between the contract quantity and the actual quantity delivered multiplied by the difference between the contract price and the spot price of natural gas during the term of the breach.
During 2001, EWR notified the seller of its intention to pursue collection and demanded payment of damages for the breach by the seller. During December 2001, EWR and the seller agreed to terms whereby the seller would convey an interest in proved natural gas reserves to EWR for a price that was
reduced by an amount agreed upon by the two parties to cure damages for the seller's breach under the natural gas supply contract. In May 2002, EWR paid the seller approximately $956,000, which consists of an agreed upon price for the reserves and associated support equipment of $1,256,000 reduced by $300,000 to cure damages under the supply contract. The agreed-upon price for the reserves is supported by an independent third-party valuation and the contemporaneous purchase of interests in the same reserves by two independent third parties.
EWR has recorded the acquisition of the natural gas reserves and the settlement of the breach by the seller as two separate and distinct transactions. Accordingly, EWR recorded the cost of the interest in the proved natural gas reserves and associated support equipment at $1,257,000 and recorded a $300,000 settlement as non-operating income in the accompanying consolidated statement of income for the year ended June 30, 2002.
3. PROPERTY PLANT & EQUIPMENT
Utility plant consists of the following as of June 30, 2002 and 2001:
During fiscal year 2002, as part of its strategic emphasis on wholesale propane operations, EWP disposed of its retail propane operations in Wyoming and Montana. The Montana operations consisted of approximately $371,000 in customer tanks and other fixed assets and approximately $75,000 in inventory and accounts receivable. The Wyoming operations consisted of approximately $549,000 in customer tanks and other fixed assets and approximately $116,000 in inventory and accounts receivable. In conjunction with the dispositions, EWP recorded gains totaling $338,000, which are included in distribution, general, and administrative expenses in the accompanying consolidated statement of income for the year ended June 30, 2002. EWP has entered into long-term agreements to supply propane to the purchaser of these assets in both Wyoming and Montana.
4. DEFERRED CHARGES
Deferred charges consist of the following as of June 30, 2002 and 2001:
5. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following as of June 30, 2002 and 2001:
6. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consist of the following as of June 30, 2002 and 2001:
7. NOTES PAYABLE
At June 30, 2002, the Company maintained two lines of credit totaling $26,000,000. One line is for $11,000,000 with interest calculated (at the discretion of the Company at the time of each draw) at either the London Interbank Offering Rate ("LIBOR") plus 2% or prime less 0.6%, expiring January 5, 2003. The other is for $15,000,000 with interest calculated (at the discretion of the Company at the time of each draw) at either LIBOR plus 2% or prime less 0.6%, expiring May 1, 2003. Borrowings on lines of
credit, based upon daily loan balances, averaged $9,312,531, $9,488,191 and $5,045,943 during the years ended June 30, 2002, 2001 and 2000, respectively. The maximum borrowings outstanding on these lines at any month end were $17,069,732, $17,140,000 and $10,855,000 during these same periods. The daily weighted average interest rate was 4.60%, 8.43% and 8.01% for the years ended June 30, 2002, 2001 and 2000, respectively. At June 30, 2002, the Company had $18,350,000 available under its lines of credit.
The Company's lines of credit agreements contain various covenants that require the maintenance of certain financial debt, interest, and cash flow ratios. The Company was in compliance with the line of credit covenants as of June 30, 2002.
8. LONG-TERM DEBT
Long-term debt at June 30, 2002 and 2001 consists of the following:
SERIES 1997 NOTES PAYABLE -- On August 1, 1997, the Company issued $8,000,000 of Series 1997 unsecured notes bearing interest at the rate of 7.5%, payable semiannually on June 1 and December 1 of each year. All principal amounts of the 1997 notes then outstanding, plus accrued interest will be due and payable on June 1, 2012. At the Company's option, beginning June 1, 2002, notes maturing subsequent to 2002 may be redeemed prior to maturity, in whole or part, at 100% of face value, plus accrued interest.
SERIES 1993 NOTES PAYABLE -- On June 24, 1993, the Company issued $7,800,000 of Series 1993 unsecured notes bearing interest at rates ranging from 6.20% to 7.60%, payable semiannually on June 1 and December 1 of each year. Maturity dates began in 1999 and extend to 2013. At the Company's option, beginning June 1, 2003, notes maturing subsequent to 2003 may be redeemed prior to maturity, in whole or part, at redemption prices declining from 104% to 100% of face value, plus accrued interest.
SERIES 1992B INDUSTRIAL DEVELOPMENT REVENUE OBLIGATIONS -- On September 15, 1992, Cascade County, Montana issued $1,800,000 of Series 1992B Industrial Development Revenue Obligations bearing interest at rates ranging from 3.35% to 6.50%. The Series 1992B Bonds are unsecured. The Series 1992B Bonds require annual principal payments on October 1 and semiannual interest payments on April 1 and October 1 of each year. The Series 1992 Bonds have a final maturity in 2012.
AGGREGATE ANNUAL MATURITIES -- The scheduled maturities of long-term debt at June 30, 2002 are as follows:
The Company's long-term debt obligation agreements contain various covenants including: limiting total dividends and distributions made in the immediately preceding 60-month period to aggregate consolidated net income for such period, restricting senior indebtedness, limiting asset sales, and maintaining certain financial debt and interest ratios. The Company is in compliance with all long-term debt covenants as of June 30, 2002.
The estimated fair value of the Company's fixed rate long-term debt, based on quoted market prices for the same or similar issues, is approximately $17,380,158 and $17,237,406 as of June 30, 2002 and 2001, respectively.
9. EMPLOYEE BENEFIT PLANS
The Company has a defined contribution plan (the "Plan") which covers substantially all of the Company's employees. Under the Plan, the Company contributes 10% of each participant's eligible compensation. Total contributions to the plan for the years ended June 30, 2002, 2001, and 2000 were $617,275, $509,372 and $491,068, respectively.
The Company sponsors a defined postretirement health and life insurance benefit pension plan (the "Pension Plan") providing health and life insurance benefits to eligible retirees. The Company has elected to pay eligible retirees (post-65 years of age) $125 per month in lieu of contracting for health and life insurance benefits. The amount of this payment is fixed and will not increase with medical trends or inflation. The Company's Pension Plan allows retirees between the ages of 60 and 65 and their spouses to remain on the same medical plan as active employees by contributing 125% of the current COBRA rate to retain this coverage.
Included in the postretirement benefit expense amounts were $26,100 in 2002, $29,400 in 2001 and $35,800 in 2000 related to regulated operations. The MPSC allowed recovery of these costs over a 20-year period beginning on November 4, 1997 for the utility operations in Montana. Management believes it is probable that its regulators in Wyoming will allow recovery of these costs based upon recent industry rate decisions addressing this issue. The plan assets are held in a VEBA trust fund into which all the Company's contributions are made.
The following table sets forth the funded status of the Pension Plan and amounts recognized in the consolidated financial statements as of June 30, 2002 and 2001 and for the years ended June 30, 2002, 2001, and 2000:
A one-percentage-point increase in the assumed health care cost trend rate would increase interest and service cost by $2,900 and the accumulated postretirement benefit obligation by $23,200. A one-percentage-point decrease in the assumed health care cost trend rate would decrease interest and service cost by $2,500 and the accumulated postretirement benefit obligation by $20,100.
10. INCOME TAXES
Significant components of the Company's deferred tax assets and liabilities as of June 30, 2002 and 2001 are as follows:
Income tax expense (benefit) for the years ended June 30, 2002, 2001, and 2000 consists of the following:
Income tax expense differs from the amount computed by applying the federal statutory rate to pre-tax income for the following reasons:
11. SEGMENTS OF OPERATIONS
Effective July 1, 2001, the Company changed the structure of its internal organization such that the composition of its reportable segments has changed. Rocky Mountain Fuels, which was included in the marketing and wholesale segment prior to 2002, is included in propane operations for 2002. Accordingly, segment information for 2001 and 2000 has been restated to reflect the revised reportable segments. Summarized financial information for the Company's natural gas operations, propane operations, and marketing and wholesale operations (before inter-company eliminations between segments primarily consisting of gas sales from marketing and wholesale operations to natural gas operations, inter-company accounts receivable, accounts payable, equity, and subsidiary investment) is as follows:
12. STOCK OPTIONS AND OWNERSHIP PLANS
STOCK OPTIONS -- The Company has an Incentive Stock Option Plan (the "Option Plan") which provides for options to purchase up to 100,000 shares of the Company's common stock to be issued to certain key employees. The option price may not be less than 100% of the common stock fair market value on the date of grant (110% of the fair market value if the employee owns more than 10% of the Company's outstanding common stock). The options vest over three years and are exercisable over a five-year period from date of issuance.
The Company has elected to follow APB No. 25 in accounting for its stock options. Pro forma information regarding net income and earnings per share is required by SFAS No. 123 and has been determined as if the Company had accounted for its stock options under the fair value method of SFAS No. 123. In the fiscal year ended June 30, 2002, 2001, and 2000, no options were granted and accordingly, there was no pro forma effect on the accompanying consolidated financial statements from the issuance of options. Additionally, the carryover effect of options granted prior to 2000 was not significant.
A summary of activity under the plan for the years ended June 30, 2002, 2001, and 2000 is as follows:
At June 30, 2002, exercise prices range from $9.00 to $9.19 per share. The weighted-average remaining contractual life of stock options is two years. At June 30, 2002, there were approximately 12,600 shares available for grant.
EMPLOYEE STOCK OWNERSHIP PLAN -- The Company has an Employee Stock Ownership Plan ("ESOP") that covers most of the Company's employees. The ESOP receives contributions of the Company's common stock from the Company each year as determined by the Board of Directors. The contribution is recorded based on the current market price of the Company's common stock. The Company has contributed common stock and recognized as expense totaling $129,802, $240,812 and $103,886 for the years ended June 30, 2002, 2001 and 2000, respectively.
13. COMMITMENTS AND CONTINGENCIES
COMMITMENTS -- The Company has entered into long-term, take or pay natural gas supply contracts which expire at varying times through 2008. The contracts generally require the Company to purchase specified minimum volumes of natural gas at a fixed price over periods ranging from one to six years. Current prices per MMBtu for these average approximately $2.80. Based on current prices, the minimum take or pay obligation at June 30, 2002 is as follows:
Natural gas purchases under these contracts for the years ended June 30, 2002, 2001 and 2000 approximated $920,475, $1,141,000 and $1,182,000, respectively.
ENVIRONMENTAL CONTINGENCY -- The Company owns property on which it operated a manufactured gas plant from 1909 to 1928. The site is currently used as a service center where certain equipment and materials are stored. The coal gasification process utilized in the plant resulted in the production of certain by-products that have been classified by the federal government and the State of Montana as hazardous to the environment. Several years ago the Company initiated an assessment of the site to determine if remediation of the site was required. That assessment resulted in a submission to the Montana Department of Environmental Quality ("MDEQ") in 1994. The Company has worked with the MDEQ since that time to obtain the data that would lead to a remediation action acceptable to the MDEQ. In the summer of 1999, the Company received final approval from the MDEQ for its plan for remediation of soil contaminants. To date, all contaminated soil has been removed, and an asphalt cap has been placed over the site. The Company and its consultants continue their work with the MDEQ relating to the remediation plan for water contaminants.
At June 30, 2002, the costs incurred in evaluating and beginning remediation have totaled approximately $1,950,000. On May 30, 1995, the Company received an order from the MPSC allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of June 30, 2002, that recovery mechanism had generated approximately $1,276,000. The Company expects to recover the full amount expended through the surcharge. The Commission's decision calls for ongoing review by the Commission of any costs incurred. The Company will submit an application for review by the Commission when the water contaminants remediation plan is approved by the MDEQ. Future costs are not estimable at this time.
LITIGATION -- From time to time the Company is involved in litigation relating to claims arising from its obligations in the normal course of business. The Company utilizes various risk management strategies, including maintaining liability insurance against certain risks, employee education and safety programs and other processes intended to reduce liability risk.
On July 2, 2001, EWR filed a complaint against PPL Montana, LLC (PPLM) in the United States District Court for the District of Montana. In its complaint, EWR sought injunctive and declaratory relief relating to a wholesale electricity supply contract between EWR and PPL dated March 17, 2000 and a confirmation letter thereunder dated June 13, 2000 (together, referred to as the "Contract"). The Contract calls for PPL to sell wholesale electric energy to EWR for a two-year period commencing July 1, 2000. EWR filed its July 2, 2001 lawsuit because PPLM had threatened to terminate sales and deliveries of electric energy to EWR under the Contract, and also demanded that EWR make substantial payments to PPLM relating to past power sales under the Contract. On July 13, 2001, PPLM filed suit against EWR in Montana state court seeking unspecified damages and other relief.
EWR has received substantial imbalance payments as a result of the amount of power that it has scheduled and purchased from PPLM. The imbalance payments were made to EWR by its transmission provider, The Montana Power Company (MPC), pursuant to the imbalance provisions in MPC's transmission tariff on file with the Federal Energy Regulatory Commission (FERC). PPLM claims that,
as a result of EWR's scheduling under the Contract, PPLM was deprived of the fair market value of that energy which it contends it could have subsequently sold. PPLM estimates the fair market value of the excess energy scheduled by EWR to be approximately $18,000,000. Any recovery of damages by PPLM could be material to the Company and its financial condition.
EWR denies liability to PPLM. EWR believes that its scheduling practices were reasonable under the circumstances, and that in any event PPLM was not deprived of the fair market value of the energy scheduled by EWR due to the offsetting scheduling procedures utilized by the scheduler for the transmission grid.
The litigation is pending in U.S. District Court in Montana. PPLM's separate state court action has been removed to the U.S. District Court for the District of Montana and consolidated with EWR's lawsuit in that court. The parties currently are engaged in the process of discovery in the judicial proceeding. A trial has been scheduled for the week of December 9, 2002. EWR intends to vigorously advocate and defend its position in the ongoing litigation with PPLM. The Company believes that it has established adequate reserves with respect to the litigation with PPLM; however, there can be no assurance that any liability will not exceed the amounts provided. A future liability in excess of the recorded reserves could have a material adverse effect on the Company and its financial condition.
PROPERTY TAX CONTINGENCY -- By letter dated August 30, 2002, the Montana Department of Revenue (the "DOR") notified the Company that the DOR's property tax audit of the Company for the period January 1, 1997 through December 31, 2001 had concluded. The notification stated that the DOR had determined that the Company had willfully under-reported its personal property and that a penalty should be assessed. Depending on the Company's ability to successfully contest the proposed assessment, the Company estimates the maximum exposure to approximate $3.9 million in property taxes and penalties.
The Company has been in contact with the DOR and has arranged for an informal review of the proposed assessment. The Company believes it has valid defenses to the assessment of tax and penalties, and plans to vigorously contest the proposed assessment and believes that the proposed penalty is unsupportable.
The DOR review has not yet commenced. In the event the proposed assessment cannot be resolved favorably, there are other avenues of appeal and review that can be followed. The Company also believes that if any tax deficiency is ultimately imposed on the Company, such deficiency that relates to regulated property may be included in allowable costs for rate-making purposes. However, if the DOR prevails on its imposition of penalties, the Company anticipates that such penalties would not be recoverable through rates. The Company believes that any interest associated with the property tax assessment also would be included in allowable costs for rate-making purposes. Because of the uncertainties related to the DOR notification, the Company has not been able to determine a range of any potential losses for reserve purposes; accordingly, no reserve amounts have been recorded.
OPERATING LEASES -- The Company leases certain properties including land, office buildings, and other equipment under non-cancelable capital and operating leases through fiscal year 2008. The future minimum lease payments are as follows:
LETTERS OF CREDIT -- Outstanding letters of credit totaled $4,150,000 at June 30, 2002 and $6,000,000 at June 30, 2001. The letters of credit guarantee the Company's performance to third parties for gas and electric purchases and gas transportation services.
14. DERIVATIVE INSTRUMENTS AND RISK MANAGEMENT
MANAGEMENT OF RISKS RELATED TO DERIVATIVES -- The Company and its subsidiaries are subject to certain risks related to changes in certain commodity prices and risks of counter-party performance. The Company has established certain policies and procedures to manage such risks. The Company has a Risk Management Committee ("RMC"), comprised of Company officers to oversee the Company's risk management program as defined in its risk management policy. The purpose of the risk management program is to minimize adverse impacts on earnings resulting from volatility of energy prices, counter-party credit risks, and other risks related to the energy commodity business. The RMC is overseen by the Audit Committee of the Company's Board of Directors.
GENERAL -- From time to time the Company or its subsidiaries may use derivative financial contracts to mitigate the risk of commodity price volatility related to firm commitments to purchase and sell natural gas or electricity. The Company may use such arrangements to protect its profit margin on future obligations to deliver quantities of a commodity at a fixed price. Conversely, such arrangements may be used to hedge against future market price declines where the Company or a subsidiary enters into an obligation to purchase a commodity at a fixed price in the future. The Company accounts for such financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, which the Company adopted July 1, 2000.
In accordance with SFAS No. 133, such financial instruments are reflected in the Company's financial statements at fair value, determined as of the date of the balance sheet. This accounting treatment is also referred to as "mark-to-market" accounting. Mark-to-market accounting treatment can result in a disparity between reported earnings and realized cash flow, because changes in the value of the financial instrument are reported as income or loss even though no cash payment may have been made between the parties to the contract. If such contracts are held to maturity, the cash flow from the contracts, and their hedges, are realized over the life of the contract.
Quoted market prices for natural gas derivative contracts of the Company or its subsidiaries generally are not available. Therefore, to determine the fair value of natural gas derivative contracts, the Company uses internally developed valuation models that incorporate available current and historical independent pricing information.
The Company generally classifies contracts as normal purchases or sales and, therefore, is not required to use mark-to-market accounting for such contracts.
WHOLESALE OPERATIONS -- During 2002 and 2001, EWR was party to a number of contracts that were valued on a mark-to-market basis under SFAS No. 133. Although certain firm commitments to purchase and sell natural gas could have been classified as normal purchases and sales and excluded from the requirements of SFAS No. 133, EWR elected to treat these contracts as derivative instruments under SFAS No. 133 in order to match contracts to purchase and sell natural gas for financial reporting purposes. Such contracts were recorded in the Company's consolidated balance sheet at fair value. Periodic mark-to-market adjustments to the fair values of these contracts are recorded as adjustments to gas costs.
In January 2002, EWR terminated its derivative contracts with Enron Canada Corporation (ECC), a subsidiary of Enron, Inc. Most of these contracts were commodity swaps that EWR had entered into to mitigate the effects of fluctuations in the market price of natural gas. The derivative contracts with ECC were entered into at various times in order to lock in margins on certain contracts under which EWR had commitments to other parties to sell natural gas at fixed prices (the "Future Supply Agreements"). EWR made the decision to terminate these ECC contracts because of concerns relating to the bankruptcy of Enron, Inc. At the date of termination, the market price of natural gas was substantially lower than the price had been when the Company entered into the contracts, resulting in a net amount due from EWR to ECC of approximately $5,400,000. EWR paid this amount to ECC upon the termination of the contracts, and thereby discharged the liability related to the contracts. The costs related to such termination are reflected in the Company's consolidated statement of income as adjustments to gas purchased.
At the time EWR terminated the ECC derivative contracts, EWR entered into new gas purchase contracts (the "Future Purchase Agreements") at prices much lower than those provided for under the ECC contracts. The Future Supply Agreements continue to be valued on a mark-to market basis. Therefore, the value of such agreements has been reflected in the Company's consolidated net income.
As of June 30, 2002, the Future Supply and Purchase Agreements were reflected as derivative assets on the Company's consolidated balance sheet at an approximate aggregate fair value as follows:
Since January 2002, neither the Company nor any of its subsidiaries has entered into any new contracts that have required mark-to-market valuation under SFAS No. 133.
NATURAL GAS OPERATIONS -- In the case of the Company's regulated divisions, gains or losses resulting from the derivative contracts are subject to deferral under regulatory procedures approved by the public service regulatory commissions of Montana, Wyoming and Arizona. Therefore, related derivative assets and liabilities are offset with corresponding regulatory liability and asset amounts included in "Recoverable Cost of Gas Purchases", pursuant to SFAS No. 71.
15. QUARTERLY INFORMATION (UNAUDITED)
Quarterly results (unaudited) for the years ended June 30, 2002 and 2001 are as follows (in thousands, except per share data):
Effective January 1, 2002, the Company changed its policy regarding the classification of net gains from derivative instruments to include those net gains in revenues rather than in non-operating income. Accordingly, net gains from derivative instruments for quarters ended prior to January 1, 2002 have been restated to reflect the classification of net gains from derivative instruments as a component of revenues. The reclassification impacted amounts previously reported for revenues and operating income (loss), but had no impact on net income.
* * * * * *
Item 9.
Item 9. - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
The Company's current report on Form 8-K dated October 25, 2001, describes the dismissal of Ernst & Young as the Company's independent accountant and the engagement of Deloitte & Touche as the Company's new independent accountant. At the time of the dismissal of Ernst & Young, there were no reportable events with respect to the Company's relationship with its independent accountants.
PART III
Item 10.
Item 10. - Directors and Executive Officer of the Registrant
Information concerning the executive officers is included in Part I, Item 1 of this Form 10-K. The information contained under the heading "Election of Directors" in the Proxy Statement is incorporated herein by reference in response to this item.
Item 11.
Item 11. - Executive Compensation
The information contained under heading "Executive Compensation" in the Proxy Statement is incorporated herein by reference in response to this item.
Item 12.
Item 12. - Security Ownership of Certain Beneficial Owners and Management
The information contained under the heading "Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement is incorporated herein by reference in response to this item.
Item 13.
Item 13. - Certain Relationships and Related Transactions
The information contained under the heading "Certain Transactions" in the Proxy Statement is incorporated herein by reference in response to this item.
Item 14.
Item 14. - Controls and Procedures
The Company has made no significant changes in its internal controls or in other factors that could significantly affect these controls.
PART IV
Item 15.
Item 15. - Exhibits, Financial Statement Schedules and Reports on Form 8K
(a) 1. Financial Statements included in Part II, Item 8:
Report of Independent Auditors Consolidated Balance Sheets Consolidated Statements of Income Consolidated Statements of Stockholders' Equity Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements
2. Financial Statement Schedules included in Item 15(d):
Schedule II - Valuation and Qualifying Accounts
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
3. The Exhibits required to be filed by Item 601 of Regulation S-K are listed under the heading "Exhibit Index," below.
(b) None.
(c) EXHIBITS. The Exhibits required to be filed by Item 601 of Regulation S-K are listed under the heading "Exhibit Index," below.
(d) SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
ENERGY WEST INC.
JUNE 30, 2002, 2001, 2000
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.
ENERGY WEST INCORPORATED
/s/ Edward J. Bernica Edward J. Bernica, President and Chief Executive Officer (Principal Executive Officer)
/s/ JoAnn S. Hogan JoAnn S. Hogan, Assistant Vice President And Treasurer (Principal Financial and Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
CERTIFICATIONS
I, Edward J. Bernica, certify that:
1. I have reviewed this annual report on Form 10-K of Energy West Incorporated.
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and
3. Based on my knowledge, the financial statements, and other financial information included in this annual report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.
Date: September 30, 2002
/s/ Edward J. Bernica --------------------------------------- Edward J. Bernica President and Chief Executive Officer (principal executive officer)
I, JoAnn S. Hogan, certify that:
1. I have reviewed this annual report on Form 10-K of Energy West Incorporated.
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and
3. Based on my knowledge, the financial statements, and other financial information included in this annual report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.
Date: September 30, 2002
/s/ JoAnn S. Hogan --------------------------------------- JoAnn S. Hogan Assistant Vice-President & Treasurer (principal financial officer)
EXHIBIT INDEX
EXHIBITS
3.1 Restated Articles of Incorporation of the Company, as amended to date (previously filed).
3.2 Bylaws of the Company, as amended to date (previously filed).
4.1 Form of Indenture (including form of Note) relating to the Company's Series 1993 Notes (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-2, File No. 33-62680).
4.2 Loan Agreement, dated as of September 1, 1992, relating to the Company's Series 1992A and Series 1992B Industrial Development Revenue Bonds (incorporated by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-2, File No. 33-62680).
10.1 Credit Agreement dated as of January 18, 1995, by and between the Company and Norwest Bank Great Falls, National Association (previously filed).
10.2 Amendment dated April 17, 1996 to Credit Agreement dated as of January 18, 1995, by and between the Company and Norwest Bank Montana, National Association (previously filed).
10.3 Amendment dated November 7, 1996 to Credit Agreement dated as of January 18, 1995, the Company and Norwest Bank Montana, National Association (previously filed).
10.4 Promissory Note dated November 7, 1996, issued to Norwest Bank Montana, National Association (previously filed).
10.5 Credit Agreement dated as of February 12, 1997, by and between the Company and First Bank Montana, National Association (previously filed).
10.6 Delivered Gas Purchase Contract dated February 23, 1997, as amended by that Letter Amendment Amending Gas Purchase Contract dated March 9, 1982; that Amendment to Delivered Gas Purchase Contract applicable as of March 20, 1986; that Letter Agreement dated December 18, 1986; that Letter Agreement dated April 12, 1988; that Letter Agreement dated April 28, 1992; that Letter Agreement dated March 14, 1996; that Letter Agreement dated April 15, 1996; a second Letter Agreement dated April 15, 1996; that Letter dated February 18, 1997; and that Letter dated April 1, 1997, transmitting a Notice of Assignment effective February 26, 1993 (previously filed).
10.7 Delivered Gas Purchase Contract dated December 1, 1985, as amended by that Letter Agreement dated July 1, 1986; that Letter Agreement dated November 19, 1987; that Letter Agreement dated December 1, 1988; that Letter Agreement dated July 30, 1992; that Assignment Conveyance and Bill of Sale effective as of January 1, 1993; that Letter Agreement dated March 8, 1993; that Letter Agreement dated October 21, 1993; that
Letter Agreement dated October 18, 1994; that Letter Agreement dated January 30, 1995; that Letter Agreement dated August 30, 1995; that Letter Agreement dated October 3, 1995; that Letter Agreement dated October 31, 1995; that Letter Agreement dated December 21, 1995; that Letter Agreement dated April 25, 1996; that Letter Agreement dated January 29, 1997; and that Letter dated April 11, 1997 (previously filed).
10.8 Natural Gas Sale and Purchase Agreement dated July 20, 1992 between Shell Canada Limited and the Company, as amended by that Letter Agreement dated August 23, 1993; that Amending Agreement effective as of November 1, 1994; and that Schedule A Incorporated Into and Forming a art of That Natural Gas Sale and Purchase Agreement, effective as of November 1, 1996 (previously filed).
10.9 Employee Stock Ownership Plan Trust Agreement (incorporated by reference to Exhibit 10.2 to Registration Statement on Form S-1, File No. 33-1672).
10.10 1992 Stock Option Plan (previously filed).
10.11 Form of Incentive Stock Option under the 1992 Stock Option Plan (previously filed).
10.12 Management Incentive Plan (previously filed).
10.13 Energy West Incorporated Retention Bonus Plan dated September 14, 2000. (previously filed)
10.14 Memorandum of Agreement dated as of September 14, 2000 between Energy West Incorporated and Larry D. Geske. (previously filed)
10.15 Memorandum of Agreement dated as of September 14, 2000 between Energy West Incorporated and Edward J. Bernica (previously filed)
10.16 Memorandum of Agreement dated as of September 14, 2000 between Energy West Incorporated and Tim A. Good. (previously filed)
10.17 Separation Agreement, Release and Waiver of Claims dated October, 2001 between Energy West Incorporated and Larry D. Geske.
10.18 Energy West Long-Term Incentive Plan
10.19 Energy West Senior Management Incentive Plan
10.20 Energy West, Incorporated Deferred Compensation Plan for Directors
21.1 Subsidiaries of the Company (previously filed).
23.1 Consent of Independent Auditors -- Deloitte & Touche.
23.2 Consent of Independent Auditors -- Ernst & Young.
99.1 Certification of Principal Executive Officer.
99.2 Certification of Principal Financial Officer.