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 originally incorporated in Montana in 1909. The Company has four business segments:
See Note 10 to the Consolidated Financial Statements for summary results of operations for each of the Company's segments and total assets.
RECENT DEVELOPMENTS
RESTATEMENT OF FINANCIAL RESULTS
On September 29, 2004, the Company announced that it was delaying the filing of its Annual Report on Form 10-K in order to complete a review of the accounting for certain contracts. Based on the results of its review, the Company has corrected its accounting and previous valuation of certain of EWR's contracts for fiscal years 2002 and 2003, and the first three quarters of fiscal year 2004, and has restated its earnings for those periods.
The Company's review of EWR's contracts included an evaluation of a gas purchase agreement and a gas sales agreement entered into during fiscal year 2002 involving counterparties who are affiliated with each other. The gas purchase agreement has previously been reflected in the Company's financial statements as a derivative asset. The gas sales agreement was previously classified by the Company as a normal sales contract, and therefore was not reflected on the Company's financial statements as a derivative liability. The Company determined that a shorter period similar to that of the gas sales agreement should have been used in the determination of the fair value of the gas purchase agreement and that the gas sales agreement does not qualify for the "normal purchase and sale" exception. As a result the consolidated financial statements have been restated to reflect a significant reduced fair value for the gas purchase agreement and the gas sales agreement as a derivative liability at its estimated fair value.
In the course of its review, the Company also determined that the fair value of a small gas purchase contract and a small gas sales contract entered into by EWR during the fiscal quarter ended December 31, 2003, had not been properly reflected in the Company's unaudited quarterly financial statements. The Company has reflected the fair value of these contracts in its restated quarterly financial information.
None of the adjustments affects the Company's cash flows or cash balances. The Company's cumulative gain (loss) in the portfolio of contracts valued on a mark-to-market basis will be realized in later periods as contracts settle or are performed and/or as natural gas prices change. See Note 15 of the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
AMENDMENTS TO LOAN AGREEMENT
As of August 30, 2004, the Company and its lender under its credit facility (the "LaSalle Facility") amended certain covenants as follows: (1) increased the total debt to capital ratio from .65 to .70, (2) allowed the inclusion of certain expenses incurred by the Company for legal fees and costs of the PPLM litigation, expenses and costs associated with the credit facilities, proxy contest costs, and the costs of adoption of the shareholder rights plan, in determining the interest coverage ratio, and (3) waived compliance with the ratios referred to in (1) and (2) above as of June 30, 2004 in addition to a shareholder's acquisition of more than 15% of the outstanding common stock of the Company.
As of September 10, 2004, the LaSalle Facility was amended to extend from September 30, 2004 until October 31, 2004, the deadline for the Company to repay the $2,000,000 term loan under the LaSalle Facility, with an infusion of new equity.
On October 20, 2004, but effective as of September 28, 2004, the LaSalle Facility was amended to extend until October 29, 2004, the deadline for the Company to deliver its audited financial statements for the fiscal year ended June 30, 2004.
On November 2, 2004, the Company executed a letter agreement effective as of September 28, 2004 amending the LaSalle Facility. The letter agreement provides for the extension of the deadline to deliver audited financial statements for fiscal year 2004 from October 29, 2004 to November 12, 2004.
As of November 2, 2004, the Company executed an amendment to the LaSalle Facility, which provides for an extension from October 31, 2004 to November 30, 2004 of the deadlines under the LaSalle Facility in connection with: (i) the termination date of the revolving facility and
(ii) the date to consummate infusions of new equity of at least $2.0 million to repay the $2.0 million term loan under the LaSalle Facility.
As of November 30, 2004, the Company executed an agreement with its lender providing for (i) an extension of the revolving facility until November 28, 2005; (ii) an extension of the date to consummate infusions of new equity of at least $2.0 million and to repay the $2.0 million term loan to October 1, 2005; (iii) a conditional waiver of the deadline to deliver audited financial statements for fiscal year 2004 and the deadline to deliver financial statements for the fiscal quarter ended September 30, 2004; (iv) a waiver of the technical default that otherwise would have been caused by the restatement of financial results of prior periods; (v) modification of interest rates applicable to the $2.0 million term loan; (vi) a limitation of $1.0 million on total loans and additional capital investment from the Company to EWR; and (vii) waivers of certain financial covenant defaults as of September 30, 2004.
The following tables representing revenues for all operating segments are after all intercompany eliminations, by customer class for the fiscal year ended June 30, 2004 and the two preceding fiscal years.
NATURAL GAS OPERATIONS
The Company's natural gas operations consist of two divisions. The Montana Division serves customers with operations in Great Falls, West Yellowstone, and Cascade, Montana. It also manages certain storage and vaporization facilities in Cascade, Montana for Energy West Propane. The Wyoming Division serves customers in and around Cody, Meeteetse 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. The Montana division received an interim order from the Montana Public Service Commission ("MPSC") effective January 1, 2004 for a rate increase for the Great Falls operations due to increased property taxes. The MPSC approval of this increase did not cover the entire tax increase experienced by the Company due to an interpretation by the MPSC of a statute that permits such increases on an after-tax basis. The Company has filed for a general rate increase which includes the net of tax effect mentioned above. The Company has entered into a stipulation agreement with the Montana Consumer Council ("MCC") and has received an interim order from MPSC adopting the stipulation. The interim rate increase was effective November 1, 2004 and is estimated to provide additional gross margin of approximately $800,000 annually. In addition, an interim order for the West Yellowstone general rate filing was approved for approximately $200,000 annually and became effective on November 1, 2004.
NATURAL GAS - MONTANA DIVISION
The Natural Gas - Montana division provides natural gas service to customers in and around Great Falls and West Yellowstone, Montana and manages an underground vapor system in Cascade, Montana. The division's service area has a population of approximately 79,000 in the Great Falls area, 1,200 in the West Yellowstone area and approximately 900 in the Cascade 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 Natural Gas - Montana division's revenues by customer class for the fiscal year ended June 30, 2004 and the two preceding fiscal years:
GAS REVENUE (in thousands)
Note: Revenue increased in fiscal year 2004 compared to fiscal year 2003 due to increases in gas pricing and rate relief from approved rate cases in Montana. Revenues were lower in fiscal year 2003 compared to fiscal year 2002 due to termination of a surcharge for collection of previously unrecovered gas costs and a lower volume of sales due to warmer than normal temperatures.
The following table shows the volumes of natural gas, expressed in millions of cubic feet (MMCF) sold or transported by the division for the fiscal year ended June 30, 2004 and the two preceding fiscal years:
GAS VOLUMES (MMcf)
The Natural Gas - Montana division has 173 transportation customers. No customer of the Natural Gas - Montana division accounted for more than 2% of the consolidated revenues of the Company in fiscal 2004.
The operations of the Natural Gas - Montana division are subject to regulation by the MPSC. The MPSC regulates rates, adequacy of service, issuance of securities, compliance with U.S. Department of Transportation safety regulations and other matters.
The MPSC allows customers to choose a natural gas supplier other than the Energy West Natural Gas - Montana division, but the division provides gas transportation to customers who purchase from other suppliers.
The Natural Gas - Montana division uses the NorthWestern Energy ("NWE") pipeline transmission system to transport supplies of natural gas for its core load and to provide transportation, distribution and balancing services to customers who have chosen to obtain natural gas from other suppliers. In 2000, the Company entered into a ten-year transportation agreement with NWE that fixes the cost of pipeline and storage capacity for the Natural Gas - Montana division.
The Natural Gas - Montana division files monthly gas trackers that adjust the gas cost recovery component of its rates to current market pricing. This process is designed to keep deferred gas cost balances at minimum expected levels.
NATURAL GAS - WYOMING DIVISION
The Natural Gas - Wyoming division provides natural gas service to customers in and around Cody, Meeteetse and Ralston, Wyoming. This service area has a population of approximately 12,000. The Natural Gas - Wyoming division has a certificate of public convenience and necessity granted by the Wyoming Public Service Commission ("WPSC") for transportation and distribution covering the west side of the Big Horn Basin, which extends approximately 70 miles north and south and 40 miles east and west from Cody. As of June 30, 2004, the Natural Gas - - Wyoming division provided service to 5,860 customers, including one industrial customer. The division also offers transportation through its system. This service is designed to permit producers and other purchasers of gas to transport their gas to markets outside of the division's distribution and transmission system.
The following table shows the Natural Gas - Wyoming division's revenues by customer class for the fiscal year ended June 30, 2004 and the two preceding fiscal years:
GAS REVENUE (in thousands)
Note: Higher revenues were realized in fiscal year 2004 compared to fiscal year 2003 due to a general rate increase approved by Wyoming Public Service Commission at the end of fiscal year 2003 as well as higher commodity pricing in fiscal year 2004. Lower revenues were realized in fiscal year 2003 compared to fiscal year 2002 due to warmer than normal temperatures and reduced sales to a large industrial customer.
The following table shows volumes of natural gas, expressed in MMCF, sold by the Natural Gas - Wyoming division for the fiscal year ended June 30, 2004 and the two preceding fiscal years:
GAS VOLUMES (MMcf)
The Natural Gas - Wyoming division has an industrial customer whose gas sales rates are subject to an industrial tariff, which provides for lower incremental prices as higher volumes are used. In fiscal year 2004 this customer accounted for approximately 28% of the revenues of the Natural Gas - Wyoming division and approximately 8% of the consolidated revenues of the Natural Gas segment. This customer's business is cyclical and dependent on the level of national housing
starts. Gross revenues from this customer in fiscal year 2004 increased approximately 48% over revenues in fiscal year 2003.
EWR is the Natural Gas - Wyoming division's supplier of natural gas, pursuant to a three year agreement entered into in May of 2003.
The Natural Gas - Wyoming 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 $.31 per MCF) are approved by the WPSC.
The Natural Gas - Wyoming division's revenues are generated under regulated tariffs designed to recover a base cost of gas and administrative and operating expenses and provide a sufficient rate of return to cover interest and profit. The division's tariffs include a purchased gas adjustment clause which allows the division to adjust rates periodically to recover changes in gas costs from base gas costs. The Wyoming division received an approval from the WPSC for a general rate increase effective June 1, 2003, which the Company estimates will provide increased revenues of $722,000 annually.
PROPANE OPERATIONS
The Company reports as a separate business segment the regulated and unregulated distribution of propane.
REGULATED PROPANE OPERATIONS
The Company is engaged in the regulated sale of propane under the business name Energy West Arizona ("EWA"). EWA distributes propane in the Payson, Pine, and Strawberry, Arizona area located about 75 miles northeast of Phoenix in the Arizona Rim Country. The service area of EWA includes approximately 575 square miles and has a population of approximately 31,000. The operations of EWA are subject to regulation by the Arizona Corporation Commission ("ACC"), which regulates rates, adequacy of service, and other matters. EWA's properties include approximately 170 miles of underground distribution pipeline and an office building leased from a third party. EWA purchases propane from the Company's unregulated subsidiary, Energy West Propane, Inc. ("EWP"), under terms reviewed periodically by the ACC. EWA has approximately 7,600 regulated customers. Annual customer growth has averaged roughly 8% for the last five years. The principal competition comes from bulk propane retailers who sell to customers who use propane from storage tanks located at their homes or businesses rather than using propane from EWA's underground distribution system.
The following tables show EWA revenues and propane volumes by customer class for the fiscal year ended June 30, 2004 and the two preceding fiscal years:
REGULATED PROPANE REVENUE (in thousands)
REGULATED PROPANE VOLUME (in thousands of gallons)
UNREGULATED PROPANE OPERATIONS
EWP is engaged in the bulk sale of propane through its two divisions: Energy West Propane-Arizona, which serves the Payson, Pine, and Strawberry, Arizona area, and Rocky Mountain Fuels Wholesale ("RMF") which has wholesale operations primarily in Montana and Arizona. EWP had 2,163 unregulated customers as of June 30, 2004. Decreases in revenues, volumes, and customers are a result of the sale of certain assets of RMF in August 2003.
EWP's wholesale division, RMF, supplies propane for the Company's underground propane-vapor systems serving the cities of Cascade, Montana and Payson, Arizona and surrounding areas. The majority of RMF's Wyoming and Montana assets, including the Superior, Montana terminal were sold on August 21, 2003 for approximately $1,370,000. The Company realized a $252,000 before-tax gain on the sale of these assets.
EWP faces competition from other propane distributors and suppliers of alternative fuels that compete with propane. Competition is based primarily on price and there is a high degree of competition with other propane distributors in each of the Company's service areas.
The following tables show the revenues and volumes for unregulated propane operations by customer class for the fiscal year ended June 30, 2004 and the two preceding fiscal years:
UNREGULATED PROPANE REVENUE (in thousands)
Note: Revenues decreased in fiscal year 2004 compared to fiscal year 2003 due to lost sales volumes from the sale of RMF's Superior operation. The increase in revenue from fiscal year 2002 to fiscal year 2003 was due to increased sales activity from RMF's wholesale operations.
UNREGULATED PROPANE VOLUME (in thousands of gallons)
EWR
The Company's wholly-owned subsidiary, EWR, conducts certain marketing activities involving the sale of natural gas in Montana and Wyoming and electricity in Montana.
Montana legislation and subsequent MPSC orders permit open access on the NWE transportation systems, and other systems in Montana have presented opportunities for EWR to conduct business as a broker of natural gas and electricity. EWR has from time to time entered into certain financial agreements that 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." During fiscal year 2003, EWR exited the
electricity marketing business, with the exception of maintaining one customer, delivering less than one MW per hour pursuant to a contract in effect through fiscal year 2005.
In order to provide a stable source of natural gas for a portion of its requirements, EWR and EWD purchased two groups of producing natural gas properties consisting of 163 wells and three gathering systems located in north central Montana. The purchases were made in May 2002 and March 2003. The wells are depleting based upon current levels of production at approximately 10% per year.
This production gives EWR a natural hedge due to fixed production expenses when market prices of natural gas are above the cost of production. EWR's and EWD's portion of estimated daily gas production from the properties is approximately 920 MCF's per day, or 4.5% of EWR's present volume requirements.
PIPELINE OPERATIONS
Pipeline Operations was added as a new segment as of July 1, 2002. The results of this segment reflect operation of the "Glacier" natural gas gathering system placed in service in fiscal year 2001 and the "Shoshone" transmission pipeline placed in service on July 3, 2003. Both pipelines have sections located in Wyoming and Montana. The revenues and expenses associated with the pipelines are included in the "Pipeline Operations" segment.
AVAILABLE INFORMATION
The internet address for the Company is: http://www.ewst.com. The Company makes available, free of charge, on its internet website annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and additional filings of the Company filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after these filings have been made with the SEC.
COMPETITION
The traditional competition faced by the Company in its distribution and sales of natural gas is from suppliers of alternative fuels, including electricity, oil, propane and coal. Traditionally, 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, with respect to the majority of the Company's service territory, previously installed equipment is not an issue. Households in recent years have generally preferred the installation of gas heat. For example, the Company estimates that approximately 97% of the homes and businesses in the Great Falls, Montana service area use natural gas as their primary source for space heating fuel; approximately 93% use gas for water heating, and approximately 99% of the new homes built on or near the Company's Great Falls, Montana service mains in recent years have selected natural gas as their energy source. The Company's operations in West Yellowstone and Cascade, Montana and the Payson / Strawberry area of Arizona face more intense competition due to the cost of competing fuels than the Company faces in the Great Falls area of Montana and the Company's service territory in Wyoming.
The Natural Gas - Wyoming division estimates that approximately 95% of the homes and businesses in its 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 Propane - Arizona division estimates that approximately 67% of the homes and businesses adjacent to the division's distribution pipeline use the division's propane for space heating or water heating. Studies show that approximately 90% of new subdivisions within the division's distribution system are using propane as their primary fuel source.
The principal competition faced by the Company and its subsidiaries in the distribution and sale of propane is from electricity suppliers and other propane distributors. Competition is based primarily on price and customer service and there is a high degree of competition from other propane distributors in all of the service areas.
EWR's principal competition is from other gas marketing firms doing business in the State of Montana.
GOVERNMENTAL REGULATION
The Company's utility operations are subject to regulation by the MPSC, the WPSC, FERC and the ACC. Such regulation plays a significant role in determining the Company's return on equity. The commissions approve rates intended to permit a reasonable rate of return on investment. The Company's tariffs allow gas cost to be recovered in full (barring a finding of imprudence) in regular (as often as monthly) rate adjustments. This mechanism may result in some delay between the incurrence and recovery of increased gas costs. However, recent adjustments in the mechanism in Montana have substantially reduced that delay. In addition, an interim order for West Yellowstone's and Energy West Montana's general rate filings was approved for approximately $200,000 and approximately $800,000, respectively, on an annual basis, for services rendered on and after November 1, 2004.
SEASONALITY
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.
ENVIRONMENTAL MATTERS
The Company owns property on which it operated a manufactured gas plant from 1909 to 1928. The site is currently used as an office facility for Company field personnel and storage location for certain equipment and materials. The coal gasification process utilized in the plant resulted in the production of certain by-products which have been classified by the federal government and the State of Montana as hazardous to the environment.
The Company has completed its remediation of soil contaminants at the plant site and in April of 2002 received a closure letter from Montana Department of Environmental Quality ("MDEQ") approving the completion of such remediation program.
The Company and its consultants continue to work with the MDEQ relating to the remediation plan for water contaminants. The MDEQ has established regulations that allow water contaminants at a site to exceed standards if it is technically impracticable to achieve those standards. Although the MDEQ has not established guidance respecting the attainment of a technical waiver, the U.S. Environmental Protection Agency ("EPA") has developed such guidance. The EPA guidance lists factors which render mediations technically impracticable. The Company has filed a request for a waiver from complying with certain standards with the MDEQ.
At June 30, 2004, the Company had incurred cumulative costs of approximately $1,925,000 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, 2004, the Company had recovered approximately $1,440,000 through such surcharges. As of June 30, 2004, the cost remaining to be recovered is $485,000.
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the Environmental Surcharge. The MPSC determined that the initial order allowing the collection of the surcharge was intended by the MPSC to cover only a two year collection period, after which it would contemplate additional filings by the Company, if necessary. The Company responded to the Show Cause Order and the MPSC subsequently ordered the termination of the Environmental Surcharge on August 20, 2003. The Company filed a request with the commission to continue the collection of the surcharge until all expenses have been recovered. This request was approved by the MPSC and the surcharge was reinstated in September 2004. The Company is required, under the Commission's most recent order, to file with the MPSC every two years for approval to continue the recovery of the surcharge.
EMPLOYEES
The Company and its subsidiaries had a total of 115 employees as of June 30, 2004. Three of these employees were employed by EWR, 24 by the Company's Propane Operations, 76 by the Company's Natural Gas Operations and 12 at the corporate office. The Company's Natural Gas Operations include 17 employees represented by two labor unions. Contracts with each of these unions expire on June 30, 2006. However, both unions have requested to reopen wage negotiations in the current agreement pursuant to wage opener provisions. The Company is involved in negotiations with the two labor unions on this issue.
EXECUTIVE OFFICERS
The following table sets forth the names, ages, and the positions and offices presently held by the executive officers of the Company:
DAVID A. CEROTZKE was appointed President and Chief Executive Officer on July 1, 2004. He has been a member of the Board of Directors of the Company since December 2003. Prior to joining the Company he was a consultant in the energy industry from January 2003 to December 2003. From 1990 to 2003, he served in various executive capacities, including Vice-President of Engineering, Vice-President of Operations, Vice-President of Marketing and Treasurer of Nicor Inc., a diversified energy holding company.
JOHN C. ALLEN was appointed Senior Vice-President, General Counsel and Secretary on July 1, 2004. He served as Interim President and Chief Executive Officer from September 22, 2003 to June 30, 2004. He joined the Company in 1986 as Corporate Counsel and Secretary and was appointed General Counsel, Vice-President and Secretary of the Company in 1992. Prior to joining Energy West he was a Staff Attorney for the Montana Consumer Counsel from 1979 to 1986.
TIM A. GOOD has been the 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 Natural Gas - Wyoming Division from 1988 to July 1, 2000.
DOUGLAS R. MANN has been the Vice-President and Manager of the Company's Propane Operations 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. He joined Energy West in 1983, after a 14 year career in computer engineering and technical sales.
JAMES E. MORIN has been President of EWR since February 2003. From July 2001 to February 2003 he served as Vice-President of Electricity Marketing and from August 1997 to July 2001 he served as Manager of Industrial and Commercial Marketing for EWR.
M. SHAWN SHAW was appointed Principal Financial Officer effective September 10, 2004. He has served the Company as a Senior Accountant in various financial and regulatory capacities since 1991.
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, as well as two large propane storage tanks.
EWR and EWD combined own 163 natural gas production wells and three gathering systems in north central Montana.
At June 30, 2003, EWD owned approximately 30 acres of real property in Great Falls, Montana. The property was sold on September 8, 2003, and EWD realized a pre-tax gain of approximately $121,000. During fiscal year 2003, EWD purchased a 40% ownership interest in natural gas production properties in north central Montana that provide approximately 350 MCF of natural gas daily for resale.
WYOMING: In Cody, Wyoming, the Company leases office and service buildings for the Natural Gas - Wyoming division under long-term lease agreements. The Company owns approximately 500 miles of transmission and distribution mains and related metering and regulating equipment, all of which are located in or around Cody, Meeteetse and Ralston.
EWD owns two pipelines in Wyoming and Montana. One is currently being operated as a gathering system. The other pipeline began operating as a natural gas interstate transmission pipeline on July 3, 2003. The pipelines extend from north of Cody, Wyoming to Warren, Montana.
ARIZONA: The Company owns approximately 170 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. 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 year periods. EWP owns several large bulk propane tanks and numerous customer tanks located in Pine, Strawberry, Payson and Star Valley, which are used to serve customers in those communities and 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 involved in the following described litigation.
On June 17, 2003, EWR and PPL Montana, LLC ("PPLM") reached agreement on a settlement of a lawsuit involving a wholesale electricity supply contract. Under the terms of the settlement, EWR paid PPLM a total of $3,200,000, consisting of an initial payment of $1,000,000 on June 17, 2003, and a second payment of $2,200,000 on September 30, 2003, terminating all proceedings in the case. EWR had established reserves and accruals in fiscal year 2001 of
approximately $3,032,000 to pay a potential settlement with PPLM and the remaining $168,000 was charged to operating expenses in fiscal year 2003.
On August 8, 2003, the Company reached agreement with the Montana Department of Revenue ("DOR") to settle a claim that the Company had under-reported its personal property for the years 1997 - 2002 and that additional property taxes and penalties should be assessed. The settlement amount is being paid in ten annual installments of $243,000 each, beginning November 30, 2003.
The Company initially determined that it was entitled to recover the amounts paid in connection with the DOR settlement through future rate adjustments as a result of legislation permitting "automatic adjustments" to rates to recover such property tax increases. The MPSC, however, interpreted the new legislation as allowing recovery of only a portion of the higher property taxes. Rates recovering the portion of the higher taxes permitted under the MPSC's interpretation of the legislation went into effect on January 1, 2004. The Company has since obtained interim rate relief which includes full recovery of the property tax associated with the DOR settlement.
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, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock Prices and Dividend Comparison - Fiscal Years 2004 and 2003
Prior to October 19, 2004, shares of the Company's Common Stock were traded on the Nasdaq National Market under the symbol "EWST." Effective as of the opening of business on October 19, 2004, shares of the Company's Common Stock are being traded on the Nasdaq National Market under the symbol "EWSTE." 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, mark-down or commission, and may not necessarily represent the actual transactions.
As of June 30, 2004, there were approximately 1,700 holders of record of the Company's common stock.
DIVIDEND POLICY
The Board of Directors historically considered approving common stock dividends for payments in March, June, September and January. On June 17, 2003, the Company's Board of Directors suspended the payment of quarterly cash dividends. The LaSalle Facility contains restrictions respecting the payment of dividends. (See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources"). Quarterly dividend payments per common share for fiscal years 2004 and 2003 were:
ITEM 6.
ITEM 6.- SELECTED FINANCIAL DATA
The following table contains certain selected historical consolidated financial information and is qualified by the more detailed Consolidated Financial Statements and Notes thereto included elsewhere in this Annual Report on Form 10-K. The information below should be read in conjunction with the Consolidated Financial Statements and Notes thereto and "Management's Discussion and Analysis of Financial Conditions and Results of Operations" included elsewhere in this Annual Report on Form 10-K. (Dollar amounts are in thousands, except per share and number of shares.)
(1) First three quarters as restated, See "Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF CONSOLIDATED OPERATIONS
RECENT DEVELOPMENTS
RESTATEMENT OF FINANCIAL RESULTS
On September 29, 2004, the Company announced that it was delaying the filing of its Annual Report on Form 10-K in order to complete a review of the accounting for certain contracts. Based on the results of its review, the Company has corrected its accounting and previous valuation of certain of EWR's contracts for fiscal years 2002 and 2003, and the first three quarters of fiscal year 2004, and has restated its earnings for those periods.
The Company's review of EWR's contracts included an evaluation of a gas purchase agreement and a gas sales agreement entered into during fiscal year 2002 involving counterparties who are affiliated with each other. The gas purchase agreement has previously been reflected in the Company's financial statements as a derivative asset. The gas sales agreement was previously classified by the Company as a normal sales contract, and therefore was not reflected on the Company's financial statements as a derivative liability. The Company determined that a shorter period similar to that of the gas sales agreement should have been used in the determination of the fair value of the gas purchase agreement and that the gas sales agreement does not qualify for the "normal purchase and sale" exception. As a result the consolidated financial statements have been restated to reflect a significant reduced fair value for the gas purchase agreement and the gas sales agreement as a derivative liability at its estimated fair value.
In the course of its review, the Company also determined that the fair value of a small gas purchase contract and a small gas sales contract entered into by EWR during the fiscal quarter ended December 31, 2003, had not been properly reflected in the Company's unaudited quarterly financial statements. The Company has reflected the fair value of these contracts in its restated quarterly financial information.
None of the adjustments affects the Company's cash flows or cash balances. The Company's cumulative gain (loss) in the portfolio of contracts valued on a mark-to-market basis will be realized in later periods as contracts settle or are performed and/or as natural gas prices change. See Note 15 of the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
AMENDMENTS TO LOAN AGREEMENT
The Company has recently entered into a number of amendments and waivers with respect to its credit facility. See Liquidity and Capital Resources.
CRITICAL ACCOUNTING POLICIES
Critical accounting policies are those that are most significant to the portrayal of the Company's condition and results of operations and require difficult, subjective and complex judgments by management in order to make estimates about the effect of matters that are inherently uncertain. In applying such policies management must record income and expense amounts that are based upon informed judgments and best estimates. Because of the uncertainty inherent in these estimates, actual results could differ from estimates used in applying critical accounting policies. Changes in estimates, based on more accurate future information, may affect amounts reported in future periods. Management is not aware of any reasonably likely events or circumstances which would result in different amounts being reported that would materially affect the Company's financial condition or results of operation
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 rate-making 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 utility for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). Costs recovered through rates include income taxes, property taxes, environmental remediation and costs of gas.
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 SFAS No. 133.
Contracts that are required to be valued as derivatives under SFAS No. 133 are reflected at "fair value" under the mark-to-market method of accounting. The market prices or fair values used in determining the value of the Company's portfolio are management's best estimates utilizing information such as closing exchange rates, over-the-counter quotes, historical volatility and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable amount of time under current market conditions. As additional information becomes available, or actual amounts are determinable, the recorded estimates may be revised. As a result, operating results can be affected by revisions to prior accounting estimates. Operating results can also be affected by changes in underlying factors used in the determination of fair value of portfolio such as the following:
- There is variability in mark-to-market earnings due to changes in the market price for gas. The Company's portfolio is valued based on current and expected future gas prices. Changes in these prices can cause fluctuations in earnings.
- The Company discounts derivative assets and liabilities using risk-free interest rates adjusted for credit standing in accordance with SFAS No. 133, which is more fully described in Statement of Financial Accounting Concepts No. 7, "Using Cash Flow Information and Present Value in Accounting Measurement" (SFAS Concept 7).
Other activities consist of the purchasing of gas for utility operations, which fall under the normal purchases and sales exception, and entering into transactions to hedge risk associated with these purchases. These activities require that management make certain judgments regarding election of the normal purchases and sales exceptions and qualification of hedge accounting by identifying hedge relationships and assessing hedge effectiveness.
RESULTS OF CONSOLIDATED OPERATIONS
The following discussion of the Company's financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this Report. The following gives effect to the restatement of the Company's consolidated financial statements as discussed in Note 15 to the consolidated financial statements.
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003
NET LOSS
The Company's net loss for fiscal year 2004 was $556,000 compared to a net loss of $857,000 for fiscal year 2003, an improvement of $301,000. The improvement in the Company's net loss from fiscal year 2003 to fiscal year 2004 was primarily the result of a reduction in distribution, general and administrative expenses, costs of gas and electricity-wholesale and cost of goods sold, and an increase in other income from fiscal year 2003 to fiscal year 2004, which were partially offset by an increase in interest expense, taxes and gas purchased and a decrease in income tax benefits from fiscal year 2003 to fiscal year 2004. The
principal changes that contributed to the improvement of $301,000 in net loss from fiscal year 2003 to fiscal year 2004 are explained below.
REVENUES
The Company's revenues for fiscal year 2004 were $73,291,000 compared to $77,898,000 in fiscal year 2003, a decrease of $4,607,000. The decrease was primarily attributable to: (1) a $6,944,000 decrease in EWR marketing revenue primarily due to the loss of revenues of $11,682,000 and $238,000 after the exit from its electricity and appliance businesses, respectively, partially offset by a $4,049,000 increase in volumes and prices of gas sales and the $932,000 increase in revenues as a result of mark-to-market accounting, and (2) a reduction of $5,050,000 in revenue from Propane Operations primarily as a result of the sale of wholesale propane assets in Superior, Montana. Revenues were relatively flat in Pipeline Operations. The lower consolidated revenues were partially offset by a $7,436,000 increase in revenue from Natural Gas Operations resulting primarily from $6,136,000 of surcharges on higher gas costs and $1,100,000 of increased revenue from higher rates approved by the respective commissions in Montana and Wyoming as well as the approval of $200,000 for property tax recovery in Montana.
GROSS MARGIN
Gross margins (revenues less cost of gas and electricity and costs of goods sold) were nearly the same in fiscal years 2004 and 2003. Significant changes in gross margins for the Company's segments from fiscal year 2003 to fiscal year 2004 were: (1) decreased gross margins in EWR of $1,255,000, primarily due to decreases in marketing activities, increases in prices related to gas purchases necessary to satisfy fixed price contract agreements, and the $932,000 adjustment under mark-to-market accounting, (2) decreased gross margins in the Propane Operations of $288,000, due to the sale of the wholesale propane assets in Superior, Montana, offset by gross margin increases in (1) Natural Gas Operations of $1,307,000 due to the rate increases in Montana and Wyoming, and (2) Pipeline Operations of $239,000 due to the placement in service of the Shoshone interstate pipeline.
EXPENSES OTHER THAN COSTS OF GAS AND ELECTRICITY AND COSTS OF GOODS SOLD
Expenses other than costs of gas and electricity and costs of goods sold decreased by $1,255,000 from fiscal year 2003 to fiscal year 2004 due to a decrease in distribution, general and administrative expenses, and maintenance and depreciation expenses, partially offset by an increase in taxes other than taxes on income.
Distribution, general and administrative expenses decreased by $1,499,000. This reduction resulted from the settlement of the PPLM litigation in fiscal year 2003, and the resulting elimination for fiscal year 2004 of any costs and expenses relating to the PPLM litigation, in fiscal year 2004. Such costs were $1,552,000 in fiscal year 2003. Debt issuance expenses of $100,000 were included in distribution, general and administrative expenses in fiscal year 2004 compared with $420,000 included in fiscal year 2003, a reduction of $561,000 in operating expenses due to the sale of wholesale propane assets in fiscal year 2004, and cost savings of $376,000 related to a reduction in payroll and other associated costs in fiscal year 2004. The reductions were partially offset by proxy contest expenses of $570,000 incurred in fiscal year 2004, shareholder rights plan expenses of $227,000 incurred in fiscal year 2004, an increase of $337,000 in general liability insurance premiums in fiscal year 2004, and a $175,000 increase in director expenses. (Additional debt issuance costs incurred in fiscal year 2004 were amortized as interest expense. See table below.)
Maintenance and depreciation expenses decreased $77,000 for fiscal year 2004 as compared to fiscal year 2003.
Taxes other than taxes on income increased by $322,000 due to a Montana DOR audit of assessed personal property values. The Company recovered approximately $200,000 of this expense through higher rates in fiscal year 2004.
CERTAIN EXPENSES INCURRED DURING FISCAL YEARS 2002, 2003, AND 2004
The Company's consolidated results of operations were negatively affected by certain costs and expenses that occurred during fiscal years 2002, 2003, and 2004. These expenses, summarized in the table below, include litigation expenses in connection with the PPLM lawsuit during fiscal years 2002 and 2003, expenses associated with the proxy contest during fiscal year 2004, and expenses associated with the shareholder rights plan during fiscal year 2004.
In addition, the Company incurred significant expenses associated with restructuring the Company's credit facilities during fiscal years 2003 and 2004. These expenses are also summarized in the table. Although future expenses associated with credit facilities and other capital-related expenses can be expected in the normal course, the credit facility restructuring expenses incurred during fiscal years 2003 and 2004 were substantially higher than similar expenses incurred in previous periods. No assurance can be given with respect to future levels of expenses related to capital needs.
*In fiscal year 2004, $696,000 of short-term debt issuance costs were capitalized. Beginning October 31, 2003 these costs started amortizing at $58,000 per month. At June 30, 2004, $522,000 of amortization had been included as interest expense. In addition, $41,000 was included as interest expense at June 30, 2004 for amortization of costs totaling $830,000 associated with obtaining long-term debt. In fiscal year 2004, $100,000 related to obtaining short-term financing was recorded in general and administrative expenses compared to $420,000 in fiscal year 2003.
OTHER INCOME
Other income increased by $83,000 from $302,000 in fiscal year 2003 to $385,000 in fiscal year 2004 primarily due to sale of non-operating real estate assets located in Montana.
INTEREST EXPENSE
Interest expense increased by $866,000 or 53% from $1,633,000 in fiscal year 2003 to $2,499,000 in fiscal year 2004 due to higher overall corporate borrowings and amortization of $563,000 in costs associated with debt refinanced in fiscal year 2004.
INCOME TAX BENEFITS
Income tax benefits decreased by $174,000 from a tax benefit of $543,000 in fiscal year 2003 to a tax benefit of $369,000 in fiscal year 2004 due to decreased net loss.
FISCAL YEAR ENDED JUNE 30, 2003 (AS RESTATED) COMPARED TO FISCAL YEAR ENDED JUNE 30, 2002 (AS RESTATED).
NET INCOME (LOSS)
The Company's net loss for fiscal year 2003 was $857,000 compared to net income of $827,000 in fiscal year 2002, a decrease of $1,684,000. The reduction in net income is primarily a result of the following: Natural Gas Operations reduction of $755,000 in net income due to reduced volumes and additional operating expenses related to overhead and interest costs, and Propane Operations had reduced net income of approximately $465,000 due to lower margins resulting from higher costs of propane and additional overhead expense. The Company's EWR segment experienced an increase in net loss of $324,000 due primarily to additional legal fees of $987,000 related to the PPLM litigation, and Pipeline Operations had reduced net income of $140,000 primarily due to expenses incurred to obtain Federal Energy Regulatory Commission ("FERC") regulatory approval of the Shoshone pipeline.
REVENUES
Operating revenues of the Company decreased $11,342,000 from $89,240,000 in fiscal year 2002 to $77,898,000 in fiscal year 2003. The Natural Gas Operations' revenues decreased
$7,888,000 due to elimination of the surcharge approved by the MPSC in March 2001 for the recovery of increased gas costs that had been incurred prior to March 2001. The increased gas costs were fully recovered by June 2002, and the surcharge was eliminated. Also, warmer than normal weather experienced during fiscal year 2003 resulted in lower volumes. EWR experienced lower revenues of $5,880,000 due to decreased marketing activity and a $3,892,000 decrease in revenue under mark-to-market accounting. Propane Operations experienced $2,130,000 higher revenues due to both higher prices and sales volumes and the Pipeline Operations experienced an increase in revenues of approximately $295,000.
GROSS MARGIN
Gross margins (operating revenues less cost of gas and electricity and cost of goods sold) increased $727,000 in fiscal year 2003. This increase was attributable mainly to increased gross margins in the Company's EWR segment of $1,120,000 offset by the $3,892,000 adjustment under mark-to-market accounting and gross margin decreases in both the Propane Operations and Natural Gas Operations resulting from higher than normal propane and gas costs.
EXPENSES OTHER THAN COSTS OF GAS AND ELECTRICITY AND COSTS OF GOODS SOLD
Expenses other than costs of gas and electricity and costs of goods sold increased by $3,185,000 from fiscal year 2002 to fiscal year 2003.
Distribution, general and administrative expenses increased from $8,790,000 in fiscal year 2002 to $11,669,000 in fiscal year 2003. This increase of $2,879,000 was due in part to costs and expenses of the PPLM litigation of $1,552,000 in fiscal year 2003 compared with $565,000 in fiscal year 2002. Additional increases in these expenses included: $700,000 related to payroll and employee benefit costs, $140,000 in general liability insurance expenses, $462,000 in outside professional services, $80,000 in bad debt expense, $90,000 in director and shareholder expenses, and $420,000 related to restructuring the Company's credit facilities.
Maintenance and depreciation increased $31,000 and $333,000, respectively, with a decrease of $58,000 in taxes other than income.
OTHER INCOME
Other income decreased by $356,000 from $658,000 in fiscal year 2002 to $302,000 in fiscal year 2003 primarily due to a $300,000 settlement received by EWR in fiscal year 2002 as part of a transaction to purchase a group of producing natural gas reserves.
INTEREST EXPENSE
Interest expense decreased by $71,000 from $1,704,000 in fiscal year 2002 to $1,633,000 in fiscal year 2003 due to lower overall corporate borrowings in fiscal year 2003.
INCOME TAX BENEFIT (EXPENSE)
Income taxes benefits increased by $1,058,000 from a $515,000 tax expense in fiscal year 2002 to a $543,000 tax benefit in fiscal year 2003 due to a loss in fiscal 2003.
OPERATING RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003
NATURAL GAS REVENUES AND GROSS MARGINS
The Natural Gas Operations' operating revenues in fiscal year 2004 increased to $39,063,000 from $31,627,000 in fiscal year 2003. This was primarily due to surcharges related to higher gas costs and increased rates related to property tax recovery in Montana and higher rates from approved rate cases in Montana and Wyoming.
Gross margin, which is defined as operating revenues less gas purchased, was approximately $11,180,000 for fiscal year 2004 compared to approximately $9,873,000 in fiscal year 2003. The increase of $1,307,000 is primarily due to general rate increases placed in effect on December 15, 2002 of $600,000 and June 1, 2003 for an additional $80,000 in Montana and $722,000 on June 1, 2003 in Wyoming. On January 1, 2004 an additional rate increase of approximately $500,000 per year went into effect to recover property taxes in Montana.
Gas purchases in Natural Gas Operations increased by $6,129,000 from $21,754,000 in fiscal year 2003 to $27,883,000 in fiscal year 2004. The increase in gas costs reflect higher gas prices during the fiscal year.
NATURAL GAS OPERATING EXPENSES
Natural Gas Operations' operating expenses were approximately $9,843,000 for fiscal year 2004, as compared to $8,542,000 for fiscal year 2003. The increase of $1,301,000 is due mainly to $672,000 increase in overhead costs, $274,000 in personal property tax, $100,000 in bad debt expense, and $184,000 in insurance expenses and $52,000 in depreciation expense.
NATURAL GAS OTHER INCOME
Other income increased by $3,000 from $94,000 in fiscal year 2003 to $97,000 in fiscal year 2004. The increase was due primarily to miscellaneous fixed assets sales during fiscal year 2004.
FISCAL YEAR ENDED JUNE 30, 2003 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2002
NATURAL GAS REVENUES AND GROSS MARGINS
Natural Gas Operations' operating revenues decreased from approximately $39,515,000 in fiscal year 2002 to approximately $31,627,000 in fiscal year 2003. This decrease of $7,888,000 was due primarily to the elimination of the surcharge approved by the MPSC in March 2001 for the recovery of increased gas costs that had been incurred prior to March 2001. The increased gas costs were fully recovered by June 2002, and the surcharge was eliminated. Also, warmer than normal weather experienced during fiscal year 2003 and reduced volumes sold to a large industrial customer by Natural Gas - Wyoming resulted in lower total volumes of natural gas sold of approximately 369,000 MCF, a 6% reduction from fiscal year 2002.
Gross margin, defined as operating revenues less cost of natural gas, declined from approximately $10,050,000 in fiscal year 2002 to approximately $9,873,000 in fiscal year 2003, primarily due to the reduction in sales volumes experienced during fiscal year 2003.
Natural gas purchases decreased from $29,465,000 in fiscal year 2002 to $21,754,000 in fiscal year 2003. The decrease in gas costs of $7,711,000 is due to lower volumes being sold and the lower cost of natural gas during fiscal year 2003.
NATURAL GAS OPERATING EXPENSES
Natural Gas Operations' operating expenses were $8,542,000 for fiscal year 2003 compared to $7,497,000 for fiscal year 2002. The increase in operating expenses of $1,045,000 was due primarily to an increase in property taxes, an increase in general liability insurance premiums, increases in employee benefit costs and increases in overhead costs.
NATURAL GAS OTHER INCOME
Other income decreased by $59,000 from $153,000 in fiscal year 2002 to $94,000 in fiscal year 2003. The decrease was primarily due to a reduction in service sales related to home and industrial installations.
OPERATING RESULTS OF THE COMPANY'S PROPANE OPERATIONS
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003
PROPANE REVENUE AND GROSS MARGINS
Propane Operations' revenues decreased $5,050,000 from $12,786,000 in fiscal year 2003 to $7,736,000 in fiscal year 2004 as a result of the sale of the wholesale propane assets located at Superior, Montana. Cost of propane sold decreased from $8,762,000 to $4,000,000 for the same period due to the decrease in volumes sold by the Company's wholesale operations, partially offset by increases in the cost of propane for both the regulated utility and the wholesale propane operations. These decreases in revenues and corresponding decrease in cost of propane resulted in a $288,000 decrease in gross margin, from $4,024,000 in fiscal year 2003 to $3,736,000 in fiscal year 2004.
Crude oil prices play a significant role in wholesale pricing for propane. Wholesale propane prices move up as the cost of crude oil increases and play a significant role in the Company's ability to stay competitive. While propane normally enjoys a significant cost performance advantage over electricity, crude oil price increases over the past year have eroded that advantage. Designers and home builders are beginning to view propane and electricity as equal in cost performance. Because electric generation uses crude oil as well as natural gas, in time the Company expects electric rates to increase due to fuel price increases. However, currently in the Company's markets, electric rates have not been significantly impacted by the crude oil price increases.
PROPANE OPERATING EXPENSES
Operating expenses were $3,039,000 for fiscal year 2004 compared to $3,600,000 for fiscal year 2003. This decrease of $561,000 is related to the gain on the sale of wholesale propane assets of $252,000, decreases in operating costs of $474,000, which includes savings from exiting the wholesale propane market in Superior, Montana, and a decrease in depreciation and maintenance expense of $76,000. Offsetting these expense reductions was an increase in overhead costs (much of which the Company believes are nonrecurring) of approximately $198,000 and an increase in taxes other than income of $43,000, primarily related to increased property tax expense.
PROPANE OTHER INCOME
Other income decreased by $6,000 from $187,000 in fiscal year 2003 to $181,000 in fiscal year 2004. Increases in interest income from the note receivable from the buyer of the RMF
wholesale propane assets, and an increase in the revenue from contracted services related to the sale, were offset by a decrease in other miscellaneous income.
FISCAL YEAR ENDED JUNE 30, 2003 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2002
PROPANE REVENUES AND GROSS MARGINS
The Propane Operations segment's revenues rose from $10,656,000 in fiscal year 2002 to $12,786,000 in fiscal year 2003, an increase of $2,130,000 or 20%. This increase in revenues was due to increased sales prices in the second half of fiscal year 2003 in the Company's wholesale propane operations, coupled with an overall increase in volume in the Propane Operations segment. Total volume for the Propane Operations segment increased from 12,816,000 gallons in fiscal year 2002 to 16,033,000 gallons in fiscal year 2003, an increase of 25%. Cost of propane increased from $6,407,000 to $8,762,000 for the same period, a 37% increase, due to the increase in volumes sold and increases in the cost of propane for both the regulated utility and the wholesale propane operations. The increase in revenues and the increase in cost of propane resulted in a decrease of $225,000 in gross margin, or 5%, from $4,249,000 in fiscal year 2002 to $4,024,000 in fiscal year 2003.
PROPANE OPERATING EXPENSES
Operating expenses were $3,600,000 for fiscal year 2003 compared to $3,065,000 for fiscal year 2002. The increase of $535,000 was primarily related to increases in depreciation, overhead costs, and increased sales expenses in the wholesale propane operation.
PROPANE OTHER INCOME
Other income decreased by $12,000 from $199,000 in fiscal year 2002 to $187,000 in fiscal year 2003. This decrease was due primarily to the collection of a previously written off account in fiscal year 2002.
OPERATING RESULTS OF THE COMPANY'S EWR OPERATIONS
Note: Revenues are declining over the last three years due to decreased sales market and impact of net derivative values.
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003 (AS RESTATED)
EWR REVENUES AND GROSS MARGINS
Revenues were negatively impacted by declines in derivative values of $1,244,000 at the end of fiscal year 2004 from the end of fiscal year 2003, under mark-to-market accounting. Fiscal year 2003 included revenues of $245,000 from electricity marketing and $27,000, from appliance sales which decreased in fiscal year 2004 as the Company elected to not sell any new electricity contracts or gas appliances. EWR's fiscal year 2004 gross margin of $63,000 represents a decrease of $1,255,000 from gross margins earned in fiscal 2003. This decrease was due primarily to $2,091,000 more in fiscal year 2004 to purchase natural gas to satisfy fixed price contract agreements. The decrease in natural gas margins was partially offset by an increase in production margins of $175,000.
EWR OPERATING EXPENSES
Operating expenses of EWR decreased approximately $1,944,000, from $3,040,000 for fiscal year 2003 to $1,096,000 for fiscal year 2004. This decrease is due primarily to the decreased legal expenses related to the settlement of the PPLM litigation in fiscal 2003. Legal expenses related to the PPLM litigation in 2003 were approximately $1,552,000. The remainder of the decrease is due to a reduction in general and administrative expenses related to payroll and associated costs, travel and training and other cost savings measures.
EWR OTHER INCOME (EXPENSE)
Other expense was approximately $13,000 in fiscal year 2004 compared to other income of approximately $19,000 for fiscal year 2003. The reduction is primarily due to EWR devaluing an investment in a distributorship for $17,000. The decrease was partially offset by the gain on the sale of two vehicles and a gathering system compressor.
FISCAL YEAR ENDED JUNE 30, 2003 (AS RESTATED) COMPARED TO FISCAL YEAR ENDED JUNE 30, 2002 (AS RESTATED)
EWR REVENUES AND GROSS MARGINS
Revenues were negatively impacted by declines in derivative values of $2,177,000 at the end of fiscal year 2003 from the end of fiscal year 2002, under mark-to-market accounting. EWR's gross margin was approximately $1,318,000 for fiscal year 2003 compared to $197,000 for fiscal year 2002, an increase of $1,121,000. This increase was primarily due to a $1,509,000 increase in natural gas margins (primarily from the sale of storage inventories during the third quarter) and an increase in margins of $338,000 from production properties purchased in fiscal year 2002, offset by a decline of approximately $411,000 in gross margins from the sale of electricity.
EWR OPERATING EXPENSES
Operating expenses for EWR were approximately $3,040,000 for fiscal year 2003 compared to $1,628,000 for the previous fiscal year. The most significant factor causing the increase of $1,412,000 was legal expenses related to the PPLM litigation. The costs of the PPLM litigation were approximately $1,552,000 for fiscal year 2003 compared to approximately $535,000 for fiscal year 2002. The remainder of the increase in operating expenses of $395,000 was due primarily to increases in liability insurance, employee benefits, increased uncollectible expenses and an increase in the amount of allocated corporate overhead.
EWR OTHER INCOME
Other income was approximately $19,000 in fiscal year 2003 compared to approximately $304,000 for fiscal year 2002. The reduction is primarily due to a $300,000 settlement on the purchase of production properties during fiscal year 2002 that was not repeated during fiscal year 2003.
OPERATING RESULTS OF THE COMPANY'S PIPELINE OPERATIONS
FISCAL YEAR ENDED JUNE 30, 2004 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2003
PIPELINE REVENUES AND GROSS MARGINS
Pipeline Operations added the Shoshone pipelines as of July 2003, which produced revenue of $337,000 in fiscal year 2004. For fiscal year 2004 reporting, Pipeline Operations revenue consists only of gathering revenues related to the pipelines located in Wyoming and Montana. Revenues and expenses associated with the interests in natural gas production acquired in fiscal years 2002 and 2003 have been transferred to EWR.
Pipeline Operations' margin increased from $162,000 in fiscal year 2003 to $401,000 in fiscal year 2004. The increase of $239,000 was due primarily to the addition of $337,000 in revenues from the addition of the Shoshone pipeline in July 2003. This increase was partially offset by a reduction in margins of $98,000 due to the transfer of operation of natural gas production interests to EWR effective as of fiscal year 2004.
PIPELINE OPERATING EXPENSES
Operating expenses decreased from $265,000 in fiscal year 2003 to $214,000 in fiscal year 2004. The decrease of $51,000 was due to a reduction in payroll and related expenses.
PIPELINE OTHER INCOME
Other income for fiscal year 2004 included the sale of certain non-operating real estate assets located in Montana, which resulted in a gain of $121,000.
FISCAL YEAR ENDED JUNE 30, 2003 COMPARED TO FISCAL YEAR ENDED JUNE 30, 2002
PIPELINE REVENUES AND GROSS MARGINS
Pipeline Operations' revenues increased from $154,000 in fiscal year 2002 to approximately $449,000 in fiscal year 2003. The increase of $295,000 was due primarily to revenues generated from natural gas production properties purchased in fiscal year 2003. The cost of gas purchased increased $287,000 from fiscal year 2003 compared to fiscal year 2002 due to the increased cost of production.
PIPELINE OPERATING EXPENSES
Operating expenses increased from $71,000 in fiscal year 2002 to $265,000 in fiscal year 2003. The increase of $194,000 was due to additional expenses associated with production properties and additional expenses incurred in obtaining FERC regulatory approval to operate the Shoshone pipeline.
CONSOLIDATED CASH FLOW ANALYSIS
CASH FLOWS USED IN OPERATING ACTIVITIES
Cash flows used in operations in fiscal 2004 were unfavorable as a result of the net loss incurred in fiscal 2004. The Company's fiscal 2004 operating cash flows were driven by the following events and factors:
- Higher prices of natural gas and propane inventories.
- A significant pay down of trade accounts payable and other liabilities.
The amount of debt has substantially increased resulting in higher interest costs, which will continue to negatively impact operating cash flows. The Company is currently required to retire debt through the use of proceeds generated from the sale of equity securities under the terms of the LaSalle Facility.
The Company is attempting to improve operating cash flows by improving the efficiency of the core businesses, increasing revenues through utility rates, retiring debt and restructuring existing debt obligations.
CASH FLOWS USED IN INVESTING ACTIVITIES
Cash flows used in investing activities decreased in fiscal 2004 compared to fiscal 2003. This decrease mainly stemmed from reduced capital expenditures in 2004, a result of a management decision to limit fiscal 2004 expenditures. In addition, RMF propane assets were sold in August 2003.
Cash used in investing activities in fiscal 2003 decreased from fiscal 2002. This decrease primarily stemmed from a $1,445,000 reduction in capital expenditures for system extensions as well as the replacement and improvement of existing transmission, distribution, gathering and general facilities. In addition, $957,000 was expended for the acquisition of producing natural gas properties in May 2002.
CASH FLOWS FROM FINANCING ACTIVITIES
Cash flows from financing activities increased in fiscal 2004 compared to fiscal 2003. Fiscal 2004 net cash provided from financing activities stems from the $8,000,000 proceeds from additional long-term debt, net of $1,526,000 in debt issuance costs.
Cash flows from financing activities increased in fiscal 2003 compared to fiscal 2002. Net cash provided from financing activities in fiscal 2003 is the net effect of lower repayments on lines of credit.
GOVERNMENTAL REGULATION
The Company's utility operations are subject to regulation by the MPSC, the WPSC, and the ACC. Such regulation plays a significant role in determining the Company's return on equity. The commissions approve rates that are intended to permit a reasonable rate of return on investment. The Company's tariffs allow the cost of gas to pass through to the customers. There is some delay, however, between the time that the gas costs are incurred by the Company and the time that the Company recovers such costs from customers as part of its gas cost recovery mechanism. The interim rate increase became effective November 1, 2004 and is estimated to provide additional gross margin of approximately $800,000 annually. In addition, an interim order for the West
Yellowstone general rate filing was approved for approximately $200,000 annually and became effective on November 1, 2004.
SEASONALITY
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.
LIQUIDITY AND CAPITAL RESOURCES
The Company's operating capital needs, as well as dividend payments and capital expenditures, are generally funded through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund capital expenditures, the Company has borrowed short-term funds. When the short-term debt balance significantly exceeds working capital requirements, the Company has issued long-term debt or equity securities to pay down short-term debt. The Company has greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, the Company's short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and the Company's short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.
The Company substantially restructured its credit facilities during fiscal year 2004. On September 30, 2003, the Company established a $23.0 million short-term revolving credit facility with LaSalle Bank National Association, as Agent for certain banks (collectively, the "Lender"), replacing a previous short-term line of credit. The MPSC order granting approval of the $23.0 million credit facility imposes restrictions on the use of the proceeds to utility purposes, and requires the Company to provide monthly reports to the MPSC with respect to the financial condition of the Company. The Company continues to be subject to these MPSC requirements.
On March 31, 2004, the Company entered into a restated credit agreement with the Lender. Pursuant to the restated credit agreement, the previous $23.0 million revolving credit facility was replaced with a $15.0 million short-term revolving credit facility, a $6.0 million term loan maturing on March 31, 2009, and a $2.0 million term loan maturing on September 30, 2004 (collectively referred to as the "LaSalle Facility").
As of August 30, 2004, the Company and its lender under its credit facility (the "LaSalle Facility") amended certain covenants as follows: (1) increased the total debt to capital ratio from .65 to .70, (2) allowed the inclusion of extraordinary expenses incurred by the Company for legal fees and costs of the PPLM litigation, expenses and costs associated with the credit facilities, proxy contest costs, and the costs of adoption of the shareholder rights plan, in determining the interest coverage ratio, and (3) waived compliance with the ratios referred to in (1) and (2) above as of June
30, 2004 in addition to a shareholder's acquisition of more than 15% of the outstanding common stock of the Company.
As of September 10, 2004, the LaSalle Facility was amended to extend from September 30, 2004 until October 31, 2004, the deadline for the Company to repay the $2,000,000 term loan under the LaSalle Facility, with an infusion of new equity.
On October 20, 2004, but effective as of September 28, 2004, the LaSalle Facility was amended to extend until October 29, 2004, the deadline for the Company to deliver its audited financial statements for the fiscal year ended June 30, 2004.
On November 2, 2004, the Company executed a letter agreement effective as of September 28, 2004 amending the LaSalle Facility. The letter agreement provides for the extension of the deadline to deliver audited financial statements for fiscal year 2004 from October 29, 2004 to November 12, 2004.
As of November 2, 2004, the Company executed an amendment to the LaSalle Facility, which provides for an extension from October 31, 2004 to November 30, 2004 of the deadlines under the LaSalle Facility in connection with: (i) the termination date of the revolving facility and (ii) the date to consummate infusions of new equity of at least $2.0 million to repay the $2.0 million term loan under the LaSalle Facility.
As of November 30, 2004, the Company executed an agreement with its lender providing for (i) an extension of the revolving facility until November 28, 2005; (ii) an extension of the date to consummate infusions of new equity of at least $2.0 million and to repay the $2.0 million term loan to October 1, 2005; (iii) a conditional waiver of the deadline to deliver audited financial statements for fiscal year 2004 and the deadline to deliver financial statements for the fiscal quarter ended September 30, 2004; (iv) a waiver of the technical default that otherwise would have been caused by the restatement of financial results of prior periods; (v) modification of interest rates applicable to the $2.0 million term loan; (vi) a limitation of $1.0 million on total loans and additional capital investment from the Company to EWR; and (vii) waivers of certain financial covenant default as of September 30, 2004.
Borrowings under the LaSalle Facility are secured by liens on substantially all of the assets of the Company and its subsidiaries. The Company's obligations under certain other notes and industrial development revenue obligations are secured on an equal and ratable basis with the Lender in the collateral granted to secure the borrowings under the LaSalle Facility with the exception of the first $1.0 million of debt under the LaSalle Facility.
Under the LaSalle Facility the Company may elect to pay interest on portions of the amounts outstanding under the $15.0 million revolving line of credit at the London interbank offered rate (LIBOR), plus 250 basis points, for interest periods selected by the Company. For all other balances outstanding under the $15.0 million revolving line of credit, the Company pays interest at the rate publicly announced from time to time by LaSalle Bank as its "prime rate" (the "Prime Rate"). For the $6.0 million term loan under the LaSalle Facility, the Company may elect to pay interest at either the applicable LIBOR rate plus 350 basis points or at the Prime Rate plus 200 basis points. Pursuant to the November 30, 2004 amendment to the LaSalle Facility, the interest rate on the $2.0 million term loan will be: the Prime Rate plus 200 basis points through March 31, 2005; the Prime Rate plus 300 basis points from April 1, 2005 through June 30, 2005; and the Prime Rate plus 400 basis points from and after July 1, 2005. The Company also pays a commitment fee of 35 basis points for the daily unutilized portion of the $15.0 million revolving credit facility.
The LaSalle Facility requires the Company to maintain compliance with a number of financial covenants, including meeting limitations on annual capital expenditures, maintaining a total debt to total capital ratio of not more than ..70 to 1.00 and an interest coverage ratio of no less than
2.00 to 1.00. At June 30, 2004, the Company would not have been in compliance with the financial covenants under the LaSalle Facility had the Lender not waived or modified certain financial covenants. The LaSalle Facility also restricts the Company's ability to pay dividends during any period to a certain percentage of cumulative earnings of the Company over that period, and restricts open positions and Value at Risk (VaR) in the Company's wholesale operations.
In June 2003, the Company's Board of Directors suspended the Company's fourth quarter dividend to allow for strengthening of the Company's balance sheet. No determination has been made with respect to resumption of cash dividend payments.
At June 30, 2004, the Company had approximately $1.3 million of cash on hand. In addition, at June 30, 2004, the Company had borrowed approximately $6.7 million under the LaSalle Facility revolving line of credit. The Company's short-term borrowings under its lines of credit during fiscal year 2004 had a daily weighted average interest rate of 4.48% per annum. At June 30, 2004, the Company had outstanding letters of credit totaling $1,700,000 related to electricity and gas purchase contracts. These letters of credit are netted against the Company's bank line of credit, which resulted in net availability at June 30, 2004, of approximately $6.6 million under the LaSalle Facility revolving line of credit. At December 1, 2004, the Company had borrowed approximately $14.6 million under the LaSalle Facility revolving line of credit. Accordingly, the Company had net availability at December 1, 2004, of approximately $371,000 under the LaSalle Facility revolving line of credit. As discussed above, the Company's short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months. The Company's availability normally increases in January as monthly heating bills are paid and gas purchases are no longer necessary.
In addition to the LaSalle Facility, the Company has outstanding certain notes and industrial development revenue obligations (collectively "Long Term Notes and Bonds"). The Company's Long Term Notes and Bonds are made up of three separate debt issues: $8.0 million of Series 1997 notes bearing interest at an annual rate of 7.5%; $7.8 million of Series 1993 notes bearing interest at annual 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 bearing interest at annual rates ranging from 6.0% to 6.5%. The Company's obligations under the Long Term Notes and Bonds are secured on an equal and ratable basis with the Lender in the collateral granted to secure the LaSalle Facility with the exception of the first $1.0 million of debt under the LaSalle Facility.
Under the terms of the Long Term Notes and Bonds, the Company is subject to certain restrictions, including restrictions on total dividends and distributions, liens and secured indebtedness, and asset sales, and is restricted from incurring additional long-term indebtedness if it does not meet certain debt to interest and debt to capital ratios.
In the event that the Company's obligations under the LaSalle Facility were declared immediately due and payable as a result of an event of default, such acceleration also could result in events of default under the Company's Series 1993 Notes and Series 1997 Notes. In such circumstances, an event of default under either series of notes would occur if (a) the Company were given notice to that effect either by the trustee under the indenture governing such series of notes, or the holders of at least 25% in principal amount of the notes of such series then outstanding, and (b) within 10 days after such notice from the trustee or the note holders to the Company, the acceleration of the Company's obligations under the LaSalle Facility has not been rescinded or annulled and the obligations under the LaSalle Facility have not been discharged. There is no similar cross-default provision with respect to the Cascade County, Montana Series 1992B Industrial Development Revenue Bonds and the related Loan Agreement between the Company and Cascade County, Montana. If the Company's obligations were accelerated under the terms of any of the LaSalle Facility, the Series 1993 Notes or the Series 1997 Notes, such acceleration (unless rescinded or cured)
could result in a loss of liquidity and cause a material adverse effect on the Company and its financial condition.
The total amount outstanding under all of the Company's long term debt obligations was approximately $21.7 million and $15.4 million, at June 30, 2004 and June 30, 2003, respectively. The portion of such obligations due within one year was approximately $973,000 and $530,000 at June 30, 2004, and June 30, 2003, respectively.
The Company would not have been in compliance with certain covenants under the LaSalle Facility had the lender not waived or modified the covenants. The Company is currently evaluating its options with respect to raising equity capital to fund the repayment of the $2.0 million term loan, which matures on October 1, 2005.
CONTRACTUAL OBLIGATIONS
A table of the Company's long-term debt obligations, as well as other long-term commitments and contingencies, and the corresponding maturity dates are listed below.
PAYMENTS DUE BY PERIOD
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. In fiscal years 2004, 2003 and 2002, total capital expenditures for the Company were approximately $2,317,000, $4,130,000 and $6,442,000, respectively, including purchases of natural gas production properties. Expenditures for fiscal year 2002 were higher than usual due to the renovation of a transmission pipeline between Wyoming and Montana and a by-pass pipeline loop around Cody, Wyoming. Expenditures for fiscal year 2004 were limited to essential needs only. Expenditures in fiscal year 2005 are expected to be limited to essential needs only.
The Company estimates future cash requirements for capital expenditures will be as follows:
NEW ACCOUNTING PRONOUNCEMENTS
In April 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No. 149, Amendments of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. The Statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. Management adopted this standard on July 1, 2003 and determined that there is no current impact from SFAS No. 149 on the consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which provides standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement is effective for financial instruments entered into or modified after May 31, 2003 and for pre-existing instruments as of the beginning of the first interim period beginning after June 15, 2003. Management has determined that there is no current impact from SFAS No. 150 on the consolidated financial statements.
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 in which the Company operates is in transition. Legislative and regulatory initiatives, at both the federal and state levels, are designed to promote competition. The changes in the gas industry have allowed certain customers to negotiate gas purchases directly with producers or brokers. To date, open access in the gas industry has 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 (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation," and 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 No. 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 No. 71.
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 such default has occurred.
Among the risks involved in natural gas marketing is the risk of nonperformance by counterparties to contracts for purchase and sale of natural gas. EWR is party to certain contracts for purchase or sale of natural gas at fixed prices for fixed time periods. Some of these contracts are recorded as derivatives, valued on a mark-to-market basis. At June 30, 2004, the net fair value of the contracts was a derivative liability of approximately $1,485,000.
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, 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 of legal and administrative claims and proceedings against the Company or its subsidiaries;
- - 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 ability to meet the financial covenants imposed by lenders to be able to draw down on revolving lines of credit;
- - 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.
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, these businesses will be allowed to recover and earn on the actual cost of their investment in the replacement or upgrade of plant. Although prices for natural gas and propane vapor may fluctuate, earnings are not impacted because gas and propane vapor cost tracking procedures annually, and more often with approval of 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 MATTERS
The Company owns property on which it operated a manufactured gas plant from 1909 to 1928. The site is currently used as an office facility for Company field personnel and storage location for certain equipment and materials. The coal gasification process utilized in the plant resulted in the production of certain by-products, which have been classified by the federal government and the State of Montana as hazardous to the environment.
The Company has completed its remediation of soil contaminants at the plant site and in April of 2002 received a closure letter from Montana Department of Environmental Quality ("MDEQ") approving the completion of such remediation program.
The Company and its consultants continue to work with the MDEQ relating to the remediation plan for water contaminants. The MDEQ has established regulations that allow water contaminants at a site to exceed standards if it is technically impracticable to achieve those standards. Although the MDEQ has not established guidance respecting the attainment of a technical waiver, the U.S. Environmental Protection Agency ("EPA") has developed such guidance.
The EPA guidance lists factors which render mediations technically impracticable. The Company has filed a request for a waiver respecting compliance with certain standards with the MDEQ.
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. At June 30, 2004, the Company had incurred cumulative costs of approximately $1,925,000 in connection with its evaluation and remediation of the site. As of June 30, 2004, the Company had recovered approximately $1,440,000 through such surcharges.
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the Environmental Surcharge. The MPSC determined that the initial order allowing the collection of the surcharge was intended by the MPSC to cover only a two year collection period, after which it contemplated additional filings by the Company, if necessary. The Company responded to the Show Cause Order and the MPSC subsequently ordered the termination of the Environmental Surcharge on August 20, 2003. The Company filed a request with the commission to continue the collection of the surcharge until all expenses have been recovered. This request was approved by the MPSC and the surcharge was reinstated in September 2004. The Company is required to file with the MPSC every two years for approval to continue the recovery of the surcharge.
DERIVATIVES 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 counterparty performance. The Company has established policies and procedures to manage such risks. The Company has a Risk Management Committee (RMC), comprised of Company officers and management 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, counterparty credit risks, and other risks related to the energy commodity business.
In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas or electricity, from time to time the Company and its subsidiaries have entered into hedging arrangements. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.
The Company accounts for certain of such purchases or sale agreements in accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected in the Company's financial statements as derivative assets or derivative liabilities and valued at "fair value," determined as of the date of the balance sheet. Fair value accounting treatment is also referred to as "mark-to-market" accounting. Mark-to-market accounting results in disparities between reported earnings and realized cash flow, because changes in the derivative values are reported in the Company's Consolidated Statement of Operations as an increase or (decrease) in "Revenues - Gas and Electric - Wholesale" without regard to whether any cash payments 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. SFAS No. 133 requires that contracts for purchase or sale at fixed
prices and volumes must be valued at fair value (under mark-to-market accounting) unless the contracts qualify for treatment as a "normal purchase or sale."
Quoted market prices for natural gas derivative contracts of the Company and its subsidiaries are generally not available. Therefore, to determine the fair value of natural gas derivative contracts, the Company uses internally developed valuation models that incorporate independently available current and forecasted pricing information.
As of June 30, 2004, these agreements were reflected on the Company's consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:
Regulated Operations -- In the case of the Company's regulated divisions, gains or losses resulting from derivative contracts are subject to deferral under regulatory procedures approved by the public service regulatory commissions of the States of Montana and Wyoming. 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, Accounting for the Effects of Certain Types of Regulation.
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 include, but are not limited to risks associated with contracts accounted for as derivatives, statements regarding competition, weather conditions, changes in the utility regulatory environment, the effects of the PPLM settlement and the DOR settlement, the outcome of regulatory proceedings, capital expenditure needs, the Company's liquidity position, the effects of inflation, the ability of the Company to meet the financial covenants under the LaSalle Facility, and the availability of financing on acceptable terms. 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 include, but are not limited to the risk factors set forth under the heading "Risk Factors."
Any such forward-looking statement is qualified by reference to these risk 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 is subject to certain market risks, including commodity price risk (i.e., natural gas 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 seeks to protect itself against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. Open positions are to be managed with policies designed to limit the exposure to market risk, with regular reporting to management of potential financial exposure. The Company's risk management committee has limited the types of contracts the Company will consider to those related to physical natural gas deliveries. Therefore, management believes that the Company's results of operations are not significantly exposed to changes in natural gas prices.
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, however, are subject to variable interest rates. A hypothetical 100 basis point change in market rates applied to the balance of the notes payable would change interest expense by $150,000 annually.
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 such default has occurred.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements of the Company are filed under this Item, beginning on page of this Annual Report on Form 10-K.
Selected quarterly financial data required under this Item is included in Note 16 to the Company's Consolidated Financial Statements.
ITEM 9.
ITEM 9. - CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9 (A) - CONTROLS AND PROCEDURES
Company's management has evaluated, with the participation of the Chief Executive Officer and the Principal Financial Officer, the effectiveness of the disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K. Based on this evaluation, although the Company had a deficiency that gave rise to a restatement of the consolidated financial statements (see Note 15 of the Consolidated financial statements); the Chief Executive Officer and the Principal Financial Officer have concluded that the disclosure controls and procedures that are now in place at the Company are effective to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.
The Company corrected its accounting with regard to certain natural gas agreements following a review which identified accounting treatment issues with the agreements. The Company's independent auditors have advised the Company that they have identified a material weakness in the Company's internal control over financial reporting in connection with energy contracts. During fiscal year 2004 and the first part of fiscal year 2005, the Company has implemented changes in the internal control over financial reporting to address the material weakness. Those changes involved implementation of procedures respecting the contracting for gas under natural gas purchase and sale agreements, including establishing a separation between the deal-making function and the accounting and contract administration functions, establishment of record systems and procedures that require reconciliation of actual performance by the contracting parties against the prices, quantities and other material terms specified in the agreements, and redundant documentation for every agreement regarding its classification pursuant to SFAS 133. The procedures are designed to make sure that all material obligations entered into on behalf of the Company or its subsidiaries receive proper review and that those agreements are enforced and performed according to their terms and conditions. The procedures are also designed to make sure that the Company complies with applicable accounting requirements.
PART III
ITEM 10.
ITEM 10. - DIRECTORS AND EXECUTIVE OFFICER OF THE REGISTRANT
The information set forth in response to Item 401 of Regulation S-K under the heading "Executive Officers" located in Item 1, Part I of this Form 10-K is incorporated herein by reference in partial response to this Item 10.
DIRECTORS OF THE COMPANY
W. E. `GENE' ARGO, (62), has been a Director of the Company since 2002. He recently retired as the President and General Manager of Midwest Energy, Inc., a gas and electric cooperative in Hays, Kansas, in which capacity he had served since 1992. Mr. Argo serves as the Chairman of the Company's Compensation Committee.
DAVID A. CEROTZKE, (54), has been a Director of the Company since December 2003. He was appointed President and Chief Executive Officer of the Company on July 1, 2004. Prior to joining the Company he was a consultant in the energy industry from January 2003 to December 2003. From 1990 to 2003, he served in various executive capacities, including Vice-President of Engineering, Vice-President of Operations, Vice-President of Marketing and Treasurer of Nicor Inc., a diversified energy holding company.
ANDREW I. DAVIDSON, (36), has been a Director of the Company since 1999. He has been Senior Vice President and Director of Client Service and Marketing for Davidson Investment Advisors and a Financial Consultant for D.A. Davidson & Company since 1993.
DAVID A. FLITNER, (71), has been a Director of the Company since 1988. He has been the owner of the Flitner Ranch and Hideout Adventures, Inc., a recreational enterprise, since 1994. Mr. Flitner serves as the Chairman of the Company's Management and Business Development Committee.
G. MONTGOMERY MITCHELL, (76), has been a Director of the Company since 1984 and has served as the Chairman of the Board since 2001. Mr. Mitchell was Senior Vice President and Director of Stone and Webster Management Consultants, Inc. from August 1980 until his retirement in 1993. Mr. Mitchell is also a director of Energy South, Inc.
RICHARD M. OSBORNE, (59), has been a Director of the Company since December 2003. He is the President and Chief Executive Officer of OsAir, Inc., a company he founded in 1963, which operates as a property developer and manufacturer of industrial gases for pipeline delivery. Since September 1998, Mr. Osborne has also been Chairman of the Board and Chief Executive Officer of Liberty Self-Stor, Inc., a self-managed real estate investment trust that manages, acquires, develops, expands, and operates self-storage facilities.
TERRY M. PALMER, (60), has been a Director of the Company since 2002. Mr. Palmer was a partner in the accounting firm Ernst & Young LLP from 1979 until his retirement in October 2002. Since January 2003, Mr. Palmer has been employed on a part-time basis with the accounting firm of Marrs, Sevier & Company. Mr. Palmer is also a director of Apex Silver Mines Limited.
RICHARD J. SCHULTE, (64), has been a Director of the Company since 1997. Mr. Schulte is a principal in Schulte Associates LLC, a consulting firm providing management, marketing, e-commerce and organizational services to energy related businesses since 1998. He was formerly an officer of the American Gas Association and Stone & Webster Management Consultants, Inc. He was 2002 Chairman of the Board of Directors for the American Society for Testing and Materials (ASTM International). Mr. Schulte serves as Chairman of the Company's Audit Committee.
THOMAS J. SMITH, (60), has been a Director of the Company since December 2003. Since 1996 Mr. Smith has been the President of Liberty Self-Stor, Inc., a self-managed real estate investment trust that manages, acquires, develops, expands, and operates self-storage facilities. Mr. Smith is also a director of Liberty Self-Stor, Inc.
The Board of Directors has determined that all the directors other than Mr. Cerotzke are independent, as defined in Rule 4200(a)(15) of the National Association of Securities Dealers' listing standards.
AUDIT COMMITTEE
The Company's Board of Directors has an Audit Committee consisting of Messrs. Palmer, Schulte and Smith. The Committee met eight times during the fiscal year and has responsibility for retaining the independent auditors, reviewing the annual audit and making recommendations to the full Board regarding accounting matters that come to its attention. Each member of the Audit Committee is independent, both as defined in Rule 4200(a)(15) of the National Association of Securities Dealers' listing standards, and as defined in Rule 10A-3(b)(1)(ii) under the Securities Exchange Act of 1934, as amended. The Board of Directors has determined that Mr. Palmer and Mr. Smith are "audit committee financial experts" as defined in Item 401(h) of Regulation S-K.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires the Company's directors, executive officers and persons who own more than ten percent of the Company's common stock to file reports of ownership and changes in ownership with the Securities and Exchange Commission and the National Association of Securities Dealers (NASD). Such persons are also required to furnish the Company with copies of all such reports. Based solely on its review of the copies of such reports received by the Company, the Company believes that its directors and executive officers filed all required reports during or with respect to the fiscal year ending June 30, 2004 on a timely basis except for the following: Mr. Morin filed a late Form 3 on August 11, 2003, reporting his initial statement of beneficial ownership of securities of the Company as of January 23, 2003;
Mr. Argo filed a late Form 4 on October 17, 2003, reporting the acquisition of 600 shares of Company common stock at a purchase price of $6.75 per share on October 7, 2003, and 250 shares at $6.75 per share on October 8, 2003; Mr. Osborne filed a late amended Form 4 on February 17, 2004, amending a Form 4 filed on December 29, 2003, restating the amount of securities beneficially owned following the reported transaction to account for the 166,358 shares owned by Turkey Vulture Fund XIII, Ltd., an Ohio limited liability company of which Mr. Osborne is sole manager; Mr. Osborne filed a late Form 4 on March 15, 2004 reporting the acquisition of 1,000 shares of Company common stock at a purchase price of $6.25 per share on March 8, 2004, in addition to other acquisitions that were reported timely; Mr. Davidson filed a late Form 4 on April 1, 2004 reporting the acquisition of 237 deferred stock equivalents on February 19, 2004; and Mr. Davidson filed a late Form 4 on May 17, 2004 reporting the acquisition of 98 deferred stock equivalents on April 28, 2004.
CODE OF ETHICS
Our Board of Directors has adopted a written Code of Business Conduct for all directors, officers, and employees. A copy of this document is available on our website at www.ewst.com, free of charge under the Our Company section. We will satisfy any disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, any provision of the Code of Business Conduct with respect to our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions by disclosing the nature of such amendment or waiver on our website or in a report on Form 8-K.
NOMINATION OF DIRECTORS
On February 20, 2004, the Board of Directors of the Company adopted an amendment to the Company's By-Laws to amend the procedures to be followed for stockholder nominations of directors. In order for a stockholder to propose director nominations at the Company's annual meeting of stockholders, the By-Laws, as amended, require a stockholder to provide the Company with a written notice, which must be received by the Company at its principal executive offices, not less than sixty (60) days prior to the date of the annual meeting. The notice must set forth (a) as to each person whom the stockholder proposes to nominate for election as a director (i) the name, age, business address and residence address of the person, (ii) the principal occupation or employment of the person, (iii) the class or series and number of shares of capital stock of the Company which are owned beneficially or of record by the person and (iv) any other information relating to the person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder (the "Exchange Act"); and (b) as to the stockholder giving the notice (i) the name and record address of such stockholder, (ii) the class or series and number of shares of capital stock of the Company which are owned beneficially or of record by such stockholder, (iii) a description of all arrangements or understandings between such stockholder and each proposed nominee and any other person or persons (including their names) pursuant to which the nomination(s) are to be made by such stockholder, (iv) a representation that such stockholder intends to appear in person or by proxy at the annual meeting to nominate the persons named in its notice and (v) any other information relating to such stockholder that would be required to be disclosed in a proxy statement or other filings required
to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act. Such notice must be accompanied by a written consent of each proposed nominee to be named as a nominee and to serve as a director if elected.
ITEM 11.
ITEM 11. - EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
The following table sets forth the annual and long-term compensation of the Chief Executive Officer and other named executive officers of the Company earning compensation in excess of $100,000 in the fiscal year.
SUMMARY COMPENSATION TABLE
(a) Represents $4,665 of Company contributions to the Company's defined contribution retirement pension plan.
(b) Represents $13,647 of Company contributions to the Company's defined contribution retirement pension plan.
(c) Represents $12,165 of Company contributions to the Company's defined contribution retirement pension plan.
(d) Mr. Bernica resigned as President and Chief Executive Officer of the Company on September 22, 2003. Mr. Allen served as Interim President and Chief Executive Officer from September 22, 2003 until June 30, 2004.
(e) On October 24, 2003 the Company entered into a separation agreement with Mr. Bernica, providing for 30 semi-monthly payments of $6,187.50. On an annualized basis, this rate is equal to the rate of Mr. Bernica's cash compensation for fiscal year 2003. The agreement also provides that Mr. Bernica at his own cost may continue health coverage under the Company's health plan as required under Federal law.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION VALUES
DIRECTOR COMPENSATION
The Company paid its outside directors an annual retainer of $6,000 per year, $1,500 per Board meeting and $750 per Committee meeting. For Board or Committee meetings held by telephone conference, the rate is one half the regular rate indicated.
In addition, the Chairman of the Compensation Committee and the Chairman of the Management and Business Development Committee each receives an additional $3,000 annual retainer. The Chairman of the Audit Committee receives an additional $5,000 annual retainer. The Chairman of the Board receives an additional $8,000 annual retainer.
The directors have the option under the Deferred Compensation Plan for Directors to receive their compensation in the form of stock, cash, or in the form of deferred stock equivalents or deferred rights to receive cash. A deferred stock equivalent is a hypothetical share of common stock valued at the fair market value of a share of the common stock on the date of receipt. A director will be paid any deferred stock equivalents in stock at the time of his or her retirement from the Board of Directors.
EMPLOYMENT CONTRACTS
After Mr. Bernica's resignation, Mr. Allen served as Interim President and Chief Executive Officer during fiscal 2004 until Mr. Cerotzke was appointed President and Chief Executive Officer on July 1, 2004.
On June 23, 2004, the Company entered into written employment agreements with Mr. Cerotzke and Mr. Allen. Mr. Cerotzke's employment agreement provides for an initial base salary of $160,000, and Mr. Allen's employment agreement provides for an initial base salary of $135,000. Each of the employment agreements provides for periodic salary adjustments as determined by the Board. Mr. Cerotzke's employment agreement provides for annual incentive compensation under a program to be developed by the Board and under the Company's existing annual incentive program and for a grant of 10,000 options, with additional grants of 10,000 options on each of the first and second anniversaries of the effective date of the employment agreement. Mr. Allen's employment agreement provides for an initial grant of 20,000 options, with an additional grant of 10,000 options on the first anniversary of the effective date of the employment agreement. Twenty-five percent of each option grant vests immediately and the remainder of each option grant vests ratably over three years.
Mr. Cerotzke's agreement was effective July 1, 2004, and continues until terminated as provided in the agreement. The agreement provides a continuation of salary and medical benefits for 12 months, outplacement assistance, full vesting of stock options and payment of a pro-rated annual bonus following termination by the Company without cause or termination by Mr. Cerotzke if the
Company changes his title, materially reduces his duties or authority, requires him to report internally other than to the Board, or requires a relocation from the Great Falls area, or if his Board membership terminates other than by his voluntary resignation. In the event that Mr. Cerotzke's employment is terminated by the Company without cause or by Mr. Cerotzke for any of the reasons listed above following a change in control of the Company, Mr. Cerotzke is entitled to continuation of base salary and medical benefits for up to two years, payment of a prorated annual bonus, and up to two times' his target annual bonus, together with full vesting of his stock options. Under the employment agreement, Mr. Cerotzke is subject to confidentiality, conflict of interest and nonsolicitation provisions.
Mr. Allen's agreement was effective July 1, 2004, and continues for one year. The agreement provides for a continuation of salary and medical benefits for 12 months, outplacement assistance, full vesting of stock options and payment of a pro-rated annual bonus following termination by the Company without cause or termination by Mr. Allen if the Company materially reduces his duties or authority, changes his title or requires him to relocate. In the event that Mr. Allen's employment is terminated under circumstances entitling him to benefits under the Company's existing change in control severance plan, any benefits that Mr. Allen would receive under his employment agreement will be offset by any benefits he receives under the plan. Under the employment agreement, Mr. Allen is subject to confidentiality, conflict of interest and nonsolicitation provisions.
On October 24, 2003, the Company entered into a Separation Agreement, Release and Waiver of Claims with Edward J. Bernica, the Company's former President and Chief Executive Officer. Pursuant to the agreement, Mr. Bernica and the Company agreed to terminate Mr. Bernica's employment as President and Chief Executive Officer and Mr. Bernica also resigned as a Director of Energy West. As consideration for the agreement, the Company agreed to pay Mr. Bernica 30 semi-monthly payments of $6,187.50. On an annualized basis, this rate is equal to the rate of Mr. Bernica's cash compensation for fiscal year 2003. The agreement also provides that Mr. Bernica at his own cost may continue health coverage under the Company's health plan as required under Federal law. The agreement included a general release of all potential claims and contains standard confidentiality and non-solicitation language for the benefit of the Company.
ITEM 12.
ITEM 12. - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
CERTAIN BENEFICIAL OWNERSHIP OF THE COMPANY'S COMMON STOCK
The following table sets forth certain information regarding the beneficial ownership of the Common Stock of the Company on or about September 30, 2004 (i) by each shareholder who is known by the Company to own beneficially more than 5% of the outstanding Common Stock, (ii) by each director, and nominee for director, (iii) by each executive officer named in the Summary Compensation Table above, and (iv) by all executive officers and directors as a group. Each beneficial owner has sole voting and investment power unless otherwise indicated.
(a) Based solely on a Schedule 13D Amendment No. 11 filed with the Securities and Exchange Commission on October 4, 2004.
(b) Includes 14,356 shares subject to deferred stock equivalents under the Deferred Compensation Plan for Directors. Such deferred stock equivalents are convertible to common stock upon the termination of a director's service with the Company.
(c) Includes 7,185 shares subject to deferred stock equivalents under the Deferred Compensation Plan for Directors.
(d) Includes 8,515 shares subject to deferred stock equivalents under the Deferred Compensation Plan for Directors.
(e) Includes 11,250 shares subject to exercisable options, 862 shares pursuant to the Company's 401(K) Plan and 8,174 shares pursuant to the company's Employee Stock Ownership Plan.
(f) Includes 2,500 shares subject to exercisable options.
(g) Includes 6,250 shares subject to exercisable options, 485 shares pursuant to the Company's 401(K) Plan and 7,436 shares pursuant to the Company's Employee Stock Ownership Plan.
(h) Includes 30,056 shares subject to deferred stock equivalents, 26,400 shares subject to exercisable options, 1,347 shares pursuant to the Company's 401(K) Plan and 15,610 shares pursuant to the Company's Employee Stock Ownership Plan.
EQUITY COMPENSATION PLAN INFORMATION
(1) Includes 100,000 shares available for future issuance under the Company's Deferred Compensation Plan for Directors, 49,817 shares of which have been issued or allocated for issuance under terms of the plan.
ITEM 13.
ITEM 13. - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There are no transactions with management or business relationships with others that require disclosure under Item 404 of Regulation S-K.
ITEM 14.
ITEM 14. - PRINCIPAL ACCOUNTANT FEES AND SERVICES
Aggregate fees billed to the Company during fiscal years 2004 and 2003 by the Company's principal accounting firm, Deloitte & Touche LLP, and their affiliates, were as follows:
(a) Advisory services related to preparation of income tax returns.
(b) Advisory services related to 404 Sarbanes - Oxley readiness.
The Audit Committee pre-approves all audit and non-audit services performed by the independent auditors.
PART IV
ITEM 15.
ITEM 15. - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
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) EXHIBITS. The Exhibits required to be filed by Item 601 of Regulation S-K are listed under the heading "Exhibit Index," below.
(c) SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
ENERGY WEST, INCORPORATED
JUNE 30, 2004
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
Date: December 17, 2004 /s/ David A. Cerotzke ----------------------------------------- By: David A. Cerotzke President and Chief Executive Officer (principal executive 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.
EXHIBIT INDEX
3.1 Restated Articles of Incorporation of the Company, as amended to date (incorporated by reference to Exhibit 3.1 on Form 10-K/A for the fiscal year ended June 30, 1996, filed with the Commission on July 9, 1997).
3.2 Amended and Restated Bylaws of the Company, as amended to date (incorporated by reference to Exhibit 3.2 on Form 8-K filed with the Commission on March 5, 2004).
4.1 Form of Indenture (including form of Note) relating to the Company's Series 1997 Notes (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-2, File No. 333-31907).
4.2 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).
4.3 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).
4.4 Preferred Stock Rights Agreement, dated as of June 3, 2004, between Energy West, Incorporated and Computershare Trust Company, Inc., including the Terms of Series A Participating Preferred Stock, the form of Rights Certificate and the Summary of Rights attached thereto as Exhibits A, B and C, respectively (incorporated by reference to Exhibit 4.1 to the Form 8-A filed with the Commission on June 3, 2004).
10.1(a) Amended and Restated Credit Agreement, dated March 31, 2004 ("Credit Agreement"), by and among Energy West, Incorporated, its subsidiaries and LaSalle Bank National Association ("LaSalle") (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on April 1, 2004).
10.1(b) Waiver and First Amendment to Credit Agreement dated as of August 30, 2004 by and among the Company, its subsidiaries and LaSalle (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on September 3, 2004).
10.1(c) Second Amendment to Credit Agreement dated as of September 10, 2004 by and among the Company, its subsidiaries and LaSalle (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on September 16, 2004).
10.1(d) Letter Agreement to Credit Agreement entered into on October 20, 2004, by and among the Company, its subsidiaries and LaSalle (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on October 21, 2004).
10.1(e) Letter Agreement to Credit Agreement entered into on November 2, 2004, by and among the Company, its subsidiaries and LaSalle (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on November 5, 2004).
10.1(f) Third Amendment to Credit Agreement dated as of November 2, 2004, by and among the Company, its subsidiaries and LaSalle (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Commission on November 5, 2004).
10.1(g) Fourth Amendment to Credit Agreement dated as of November 30, 2004, by and among the Company, its subsidiaries and LaSalle (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Commission on December 6, 2004).
10.2 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 (incorporated by reference to Exhibit 10.6 on Form 10-K/A for the fiscal year ended June 30, 1996, filed with the Commission on July 9, 1997).
10.3 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 (incorporated by reference to Exhibit 10.7 on Form 10-K/A for the fiscal year ended June 30, 1996, filed with the Commission on July 9, 1997).
10.4 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 part of That Natural Gas Sale and Purchase Agreement, effective as of November 1, 1996 (incorporated by reference to Exhibit 10.8 on Form 10-K/A for the fiscal year ended June 30, 1996, filed with the Commission on July 9, 1997).
10.5 Employee Stock Ownership Plan Trust Agreement (incorporated by reference to Exhibit 10.2 to Registration Statement on Form S-1, File No. 33-1672).*
10.6 1992 Stock Option Plan (incorporated by reference to Exhibit 10.10 on Form 10-K/A for the fiscal year ended June 30, 1996, filed with the Commission on July 9, 1997).*
10.7 Form of Incentive Stock Option under the 1992 Stock Option Plan (incorporated by reference to Exhibit 10.11 on Form 10-K/A for the fiscal year ended June 30, 1996, filed with the Commission on July 9, 1997).*
10.8 Management Incentive Plan (incorporated by reference to Exhibit 10.12 on Form 10-K/A for the fiscal year ended June 30, 1996, filed with the Commission on July 9, 1997).*
10.9 Energy West Senior Management Incentive Plan (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2002, filed with the Commission on September 30, 2002).*
10.10 Energy West Incorporated Deferred Compensation Plan for Directors (incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2002, filed with the Commission on September 30, 2002).*
10.11 Amended and Restated Advisory Agreement, dated October 3, 2003, by and among Energy West, Incorporated, D.A. Davidson & Co. and DAMG Capital LLC (incorporated by reference to Exhibit 10.11 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, ,2003, filed with the Commission on October 9, 2003).
10.12 Letter Agreement dated June 5, 2003 between DAMG Capital LLC and the Company (incorporated by reference to Exhibit 10.12 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2003, filed with the Commission on October 9, 2003).
10.13 Letter Agreement dated June 5, 2003 between D.A. Davidson & Co. and the Company (incorporated by reference to Exhibit 10.13 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2003, filed with the Commission on October 9, 2003).
10.14 Agreement dated November 20, 2003 between and among J. Michael Gorman, Lawrence P. Haren, Richard M. Osborne, Thomas J. Smith, Turkey Vulture Fund XIII, Ltd., an Ohio limited liability company and, Energy West, Incorporated (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on November 21, 2003).
10.15 Separation Agreement, Release and Waiver of Claims between Energy West, Incorporated and Edward J. Bernica dated October 24, 2003 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on October 27, 2003).
10.16 Employment Agreement entered into as of June 23, 2004, between the Company and David Cerotzke (filed herewith).*
10.17 Employment Agreement entered into as of June 23, 2004, between the Company and John Allen (filed herewith). *
10.18 Option Agreement dated July 1, 2004, between the Company and David Cerotzke (filed herewith).*
10.19 Option Agreement dated July 1, 2004, between the Company and John Allen (filed herewith).*
10.20 Energy West, Incorporated 2002 Stock Option Plan (incorporated by reference to Appendix A to the Company's Proxy Statement filed with the Commission on October 30, 2002).
21.1 Subsidiaries of the Company (incorporated by reference to Exhibit 21.1 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2000, filed with the Commission on September 28, 2000).
23.1 Consent of Independent Registered Public Accounting Firm - DELOITTE & TOUCHE LLP (filed herewith).
31.1 Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2 Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.1 Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.2 Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
* Represents a management contract or a compensatory plan or arrangement
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Energy West, Incorporated Great Falls, Montana
We have audited the accompanying consolidated balance sheets of Energy West, Incorporated and subsidiaries as of June 30, 2004 and 2003, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended June 30, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. 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 audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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, such consolidated financial statements present fairly, in all material respects, the financial position of Energy West, Incorporated and subsidiaries at June 30, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 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.
As discussed in Note 15 to the consolidated financial statements, the accompanying consolidated financial statements for fiscal years 2003 and 2002 have been restated.
DELOITTE AND TOUCHE LLP
Salt Lake City, Utah December 16, 2004
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, JUNE 30, 2004 AND 2003
See notes to consolidated financial statements
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
See notes to consolidated financial statements.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
See notes to consolidated financial statements (Continued)
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
See notes to consolidated financial statements (concluded)
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
1. SUMMARY OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
NATURE OF BUSINESS -- Energy West, Incorporated (the "Company") is a regulated public entity with certain non-regulated 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.
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").
BASIS OF PRESENTATION -- The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.
As of June 30, 2004, the Company would not have been in compliance with certain covenants under the LaSalle Facility had the lender not waived or modified the covenants. See note 14.
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 fiscal year 2003 and 2002. All intercompany transactions and accounts have been eliminated.
SEGMENTS -- The Company reports financial results for four business segments: Natural Gas Operations, Propane Operations, EWR, and Pipeline Operations. Summarized financial information for these four segments is set forth in Note 10.
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, asset retirement obligations, 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 ("WPSC"), and the Arizona Corporation Commission. Purchased gas and propane costs that are different from those provided for in present rates, and approved by the applicable commissions, are accumulated and recovered or credited through future rate changes. As of June 30, 2004 and June 30, 2003, the Company has unrecovered purchase gas costs of $788,407 and $1,067,109 respectively.
PROPERTY, PLANT, AND EQUIPMENT -- 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%, 3.69% and 3.40% during the years ended June 30, 2004, 2003 and 2002, respectively.
CONSTRUCTION IN AID AND ADVANCES RECEIVED FOR CONSTRUCTION -- Contributions in aid of construction are contributions received from customers for construction which are not refundable. Customer advances for construction includes advances received from customers for construction which are to be refunded wholly or in part.
NATURAL GAS RESERVES -- EWR owns an undivided interest in certain producing natural gas reserves on properties located in northern Montana. EWD also owns an undivided interest in certain natural gas producing properties located in northern Montana. The Company is depleting these reserves using the units-of-production method. The gas reserves are included in the Property, Plant and Equipment, net in the accompanying consolidated financial statements. The production of the gas reserves is not considered to be significant to the operations of the Company as defined by Statement of Financial Accounting Standard ("SFAS") No. 69, Disclosures About Oil and Gas Producing Properties.
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. As of June 30, 2004 and 2003, management does not consider the value of any of its long-lived assets to be impaired.
STOCK-BASED COMPENSATION -- The Company has elected to use the intrinsic value method of accounting under 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 SFAS No. 123, Accounting for Stock-Based Compensation.
The following table illustrates the effect on net loss and loss per share for the years ended June 30, 2004 and 2003 if the fair value based method had been applied to all outstanding and unvested awards in the period:
In the fiscal years ended June 30, 2004 and 2002, no options were granted. In the fiscal year ended June 30, 2003, 114,500 options were granted. Additionally, the carryover effect of options granted prior to fiscal year 2002 was not significant.
The fair value of the options issued in fiscal year ended June 30, 2003 was estimated at the date of grant using the Black-Scholes option pricing model with the following assumptions:
1) risk-free interest rate of 3.2 percent;
2) dividend yield of 6.6 percent prior to third quarter of fiscal year 2003;
3) no discount for lack of marketability;
4) expected life of 5 years; and
5) a volatility factor of the expected market price of the Company's common stock of 37 percent.
COMPREHENSIVE INCOME -- During the years ended June 30, 2004, 2003, and 2002, the Company had no components of comprehensive income (loss) other than net income (loss).
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 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 and SFAS No. 149, Amendment of Statement 133 on Derivatives and Hedging Activities, which the Company adopted July 1, 2003. Derivatives are recorded at estimated fair value and gains and losses from derivative instruments are included as a component of gas and electric -- wholesale revenues in the accompanying
consolidated statements of operations. For the years ended June 30, 2004, 2003, and 2002, the Company recognized a reduction in revenues "gas and electric - wholesale" from derivative instruments of approximately $1,244,000, $2,177,000, and $4,240,000 respectively. Pursuant to SFAS No. 133, as amended, contracts for the purchase or sale of natural gas at fixed prices and notional volumes must be valued at fair value unless the contracts qualify for treatment as a "normal" purchase or sale and the appropriate election has been made. As of June 30, 2004 and 2003, the Company had elected the normal treatment for the majority of its contracts.
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 maturities of three months or less at the date of acquisition are considered to be cash equivalents.
EARNINGS PER SHARE -- Net income (loss) 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 11. Options to purchase 77,000 and 130,420 shares of common stock were outstanding at June 30, 2004 and June 30, 2003, respectively, but were not included in the computation of diluted earnings (loss) per share as the exercise price on the options is greater than the market price of the stock. The dilutive effect of stock options for the year ended June 30, 2002 was an increase to basic weighted average common shares outstanding of 9,537.
CREDIT RISK -- The Company's primary market areas are 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.
ASSET RETIREMENT OBLIGATIONS ("ARO") -- The Company adopted SFAS No. 143, Accounting for Asset Retirement Obligation effective July 1, 2002, and has recorded an asset
and an asset retirement obligation in the accompanying consolidated balance sheet in "Property, plant and equipment, net," and in "Other long-term liabilities." The asset retirement obligation of $586,229 and $555,665 represents the Company's estimated future liability as of June 30, 2004 and June 30, 2003 respectively, to plug and abandon existing oil and gas wells owned by EWR and EWD. EWR and EWD will depreciate the asset amount and increase the liability over the estimated useful life of these assets. In the future, the Company may have other asset retirement obligations arising from its business operations.
The Company has identified but not recognized ARO liabilities related to gas transmission and distribution assets resulting from easements over property not owned by the Company. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.
Changes in the asset retirement obligation can be reconciled as follows:
NEW ACCOUNTING PRONOUNCEMENTS -- In April 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No. 149, Amendments of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. The Statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. Management adopted this standard on July 1, 2003 and determined that there is no current impact from SFAS No. 149 on the consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which provides standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement is effective for financial instruments entered into or modified after May 31, 2003 and for pre-existing instruments as of the beginning of the first interim period beginning after June 15, 2003. Management has determined that there is no current impact from SFAS No. 150 on the consolidated financial statements.
RECLASSIFICATIONS - Certain prior year amounts have been reclassified to conform to the current year presentation.
2. NATURAL GAS WELLS
In order to provide a stable source of natural gas for a portion of its requirements, effective December 2001, EWR purchased a 70% working interest (59% net revenue interest) in a group of producing natural gas properties consisting of 116 wells and a 75% ownership interest in two gathering systems located in northern Montana.
The wells are depleting based upon production at approximately 10% per year as of June 30, 2004. For the period ended June 30, 2004, EWR's portion of the daily gas production was approximately 640 MCF per day, or approximately 3% of EWR's present volume requirements.
In March 2003, EWD acquired a 47% working interest (40% net revenue interest) in a group of producing natural gas properties consisting of 47 wells and a 75% ownership interest in a gathering system located in northern Montana.
For the period ended June 30, 2004, EWD's portion of the daily gas production was approximately 280 MCF per day, or approximately 1.5% of EWR's present volume requirements.
EWR and EWD's combined portion of the estimated daily gas production from the reserves is approximately 920 MCF, or approximately 4.5% of the Company's present volume requirements. This production gives the Company a natural hedge, due to fixed production expenses when market prices of natural gas are above the costs of production. The wells are operated by an independent third party operator who also has an ownership interest in the reserves. In 2002 and 2003 the Company entered into agreements with the operator of the wells to purchase a portion of the operator's share of production.
3. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following as of June 30, 2004 and 2003:
4. DEFERRED CHARGES
Deferred charges consist of the following as of June 30, 2004 and 2003:
Regulatory assets will be recovered over a period of approximately seven to twenty years.
5. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consist of the following as of June 30, 2004 and 2003:
6. OTHER LONG-TERM LIABILITIES
Other long-term liabilities consist of the following as of June 30, 2004 and 2003:
7. LINES OF CREDIT AND LONG-TERM DEBT
LINES OF CREDIT -- On March 31, 2004, the Company entered into a modification of its existing credit facility (as amended, the "LaSalle Facility") with LaSalle Bank National Association ("LaSalle"). The LaSalle Facility converted $8,000,000 of existing revolving loans into a $6,000,000, five-year term loan and a $2,000,000 term loan due on November 30, 2004, (collectively the "Term Loan") and reduces the maximum amount of the line of credit, which expires on November 30, 2004 (recently extended to November 28, 2005), from $23,000,000 to $15,000,000. The $2,000,000 term loan must be repaid with the proceeds of a placement of equity securities by the Company by November 30, 2004 (recently extended to October 1, 2005). See DEBT COVENANTS below. The credit facilities with LaSalle are secured, on an equal and ratable basis with the Company's other long-term debt, by substantially all of the Company's assets.
LONG-TERM DEBT -- Long-term debt at June 30, 2004 and 2003 consists of the following:
Borrowings under the LaSalle Facility are secured by liens on substantially all of the assets of the Company and its subsidiaries. The Company's obligations under the 1997 Notes, 1993 Notes and 1992B Notes, described below, are secured on an equal and ratable basis with the Lender in the collateral granted to secure the borrowings under the LaSalle Facility with the exception of the first $1.0 million of debt under the LaSalle Facility.
SERIES 1997 NOTES PAYABLE - On August 1, 1997, the Company issued $8,000,000 of Series 1997 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, the notes may be redeemed at any time prior to maturity, in whole or part, at 101% of face value if redeemed before June 1, 2005, and at 100% of face value if redeemed thereafter, plus accrued interest. As of June 30, 2004, the Company had not redeemed any of the notes under this issue, except for $139,016 in redemptions as a result of redemption rights exercisable upon the deaths of holders of the notes.
SERIES 1993 NOTES PAYABLE - On June 24, 1993, the Company issued $7,800,000 of Series 1993 notes bearing interest at rates ranging from 6.20% to 7.60%, payable semiannually on June 1 and December 1 of each year. The 1993 notes mature serially in increasing amounts on June 1 of each year beginning in 1999 and extending to June 1, 2013. At the Company's option, the notes may be redeemed at any time prior to maturity, in whole or part, at redemption prices declining from 103% to 100% of face value, plus accrued interest. As of June 30, 2004, the Company had not redeemed prior to their scheduled maturity any of the notes under this issue.
SERIES 1992B INDUSTRIAL DEVELOPMENT REVENUE OBLIGATIONS - On September 15, 1992, Cascade County, Montana issued $1,800,000 of Series 1992B Industrial Development Revenue Bonds (the "1992B Bonds") bearing interest at rates ranging from 3.35% to 6.50%, and loaned the proceeds to the Company. The Company is required to pay the loan, with interest, in amounts and on a schedule to repay the 1992B Bonds. Interest is payable semiannually on April 1 and October 1 of each year. The 1992B Bonds began maturing serially in increasing amounts on October 1, 1993, and continuing on each October 1 thereafter until October 1, 2012. At the Company's option, 1992B Bonds may be redeemed in whole or in part on any interest payment date at redemption prices declining from 101% to 100% of face value, plus accrued interest. As of June 30, 2004, the Company had not redeemed prior to their scheduled maturity any of the 1992B Bonds.
TERM LOAN -- On March 31, 2004, the Company entered into a modification of its LaSalle Facility. The modification converted $8,000,000 of existing revolving loans into a $6,000,000, five-year term loan with principal payments of $33,333 each month and a $2,000,000 term loan due on November 30, 2004 (recently extended to October 1, 2005). Under the LaSalle Facility, the Company pays interest (i) on its line of credit borrowings at either (a) the London Interbank Offered Rate (LIBOR) plus 250 basis points (bps) or, if the Company elects, (b) the rate publicly announced from time to time by the Lender as its "prime rate" ("Prime"), (ii) on its $6,000,000 term loan at either (a) LIBOR plus 350 bps or, if the Company elects, (b) Prime plus 150 bps and (iii) on its $2,000,000 term loan at Prime plus 200 bps through March 31, 2005; the Prime Rate plus 300 bps from April 1, 2005 through June 30, 2005; and the Prime Rate plus 400 bps from and after July 1, 2005. The LaSalle Facility also has a commitment fee of 35 bps due on the daily unutilized portion of the facility.
AGGREGATE ANNUAL MATURITIES -- The scheduled maturities of long-term debt at June 30, 2004 are as follows:
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 $24,796,889 and $16,580,495 as of June 30, 2004 and 2003, respectively.
DEBT COVENANTS -- 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, maintaining certain financial debt and interest ratios and others.
On April 16, 2004, a stockholder acquired certain shares of common stock which together with other shares owned by that stockholder total approximately 20.8% of all outstanding shares, which violated a covenant of the LaSalle Facility. Subsequently, the LaSalle Facility was amended to approve this concentration of equity ownership (see Note 14).
As of August 30, 2004, the Company and its lender under its credit facility (the "LaSalle Facility") amended certain covenants as follows: (1) increased the total debt to capital ratio from .65 to .70, (2) allowed the inclusion of certain expenses incurred by the Company for legal fees and costs of the PPLM litigation, expenses and costs associated with the credit facilities, proxy contest costs, and the costs of adoption of the shareholder rights plan, in determining the interest coverage ratio, and (3) waived compliance with the ratios referred to in (1) and (2) above as of June 30, 2004. In addition, LaSalle waived compliance to a shareholder's acquisition of more than 15% of the outstanding common stock of the Company.
On November 2, 2004, the Company executed a letter agreement effective as of September 28, 2004 amending the LaSalle Facility. The letter agreement provides for the extension of the deadline to deliver audited financial statements for fiscal year 2004 to November 12, 2004.
As of November 2, 2004, the Company executed an amendment to the LaSalle Facility, which provides for an extension to November 30, 2004 of the deadlines under the LaSalle Facility in connection with: (i) the termination date of the revolving facility and (ii) the date to consummate infusions of new equity of at least $2.0 million to repay the $2.0 million term loan under the LaSalle Facility.
As of November 30, 2004, the Company executed an agreement with its lender providing for (i) an extension of the revolving facility until November 28, 2005; (ii) an extension of the date to consummate infusions of new equity of at least $2.0 million and to repay the $2.0 million term loan to October 1, 2005; (iii) a conditional waiver of the deadline to deliver audited financial statements for fiscal year 2004 and the deadline to deliver financial statements for the fiscal quarter ended September 30, 2004; (iv) a waiver of the technical default that otherwise would have been caused by the restatement of financial results of prior periods; (v) modification of interest rates applicable to the $2.0 million term loan; (vi) a limitation of $1.0 million on total loans and additional capital investment from the Company to EWR; and (vii) waivers of certain financial covenant defaults as of September 30, 2004.
8. EMPLOYEE BENEFIT PLANS
The Company has a defined contribution plan (the "401k Plan") which covers substantially all of the Company's employees. Under the 401k Plan, the Company contributes 10% of each participant's eligible compensation. Total contributions to the 401k Plan for the years ended June 30, 2004, 2003, and 2002 were $512,220, $568,133, and $617,275, respectively. The Company also sponsors a defined postretirement health benefit plan (the "Retiree Health 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 Retiree Health 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.
A portion of the Company's 401k Plan consists of 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 made no contributions for the fiscal years ended June 30, 2004 and 2003, and recognized as expense $129,802 for the year ended June 30, 2002, related to the common stock contributions. In addition, the Company makes matching contributions in the form of Company stock equal to 10% of each participant's elective deferrals. The Company contributed shares of the Company's stock valued at $21,750, $24,686, and $26,142 in fiscal year 2004, 2003, and 2002, respectively.
The following table sets forth the funded status of the Retiree Health Plan and amounts recognized in the consolidated financial statements as of June 30, 2004 and 2003 and for the years ended June 30, 2004, 2003, and 2002:
A one-percentage-point increase in the assumed health care cost trend rate would increase interest and service cost by $4,600 and the accumulated postretirement benefit obligation by $33,200. A one-percentage-point decrease in the assumed health care cost trend rate would decrease interest and service cost by $3,900 and the accumulated postretirement benefit obligation by $28,600.
Included in the postretirement benefit expense amounts were $55,100 in 2004, $40,260 in 2003 and $26,100 in 2002 related to regulated operations. The MPSC allows for 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.
9. INCOME TAXES
Significant components of the Company's deferred tax assets and liabilities as of June 30, 2004 and 2003 are as follows:
As of June 30, 2004, the Company has a federal net operating loss of approximately $930,000 which will be carried back to fiscal year ended June 30, 2002.
Income tax expense (benefit) for the years ended June 30, 2004, 2003, and 2002 consists of the following:
Income tax expense (benefit) differs from the amount computed by applying the federal statutory rate to pre-tax income (loss) for the following reasons:
10. SEGMENTS OF OPERATIONS
Effective July 1, 2002, the Company changed the structure of its internal organization such that the Pipeline Operations was established as a new segment. The results of this segment reflect operations of oil and gas gathering systems placed into service in fiscal 2002, and transferred from EWR to EWD. For fiscal year 2002 and prior years, EWD consisted primarily of real estate holdings and incurred minimal expenses. The financial operations of EWD's pipeline assets and real estate holdings are now being reported as Pipeline Operations.
Summarized financial information for the Company's Natural Gas Operations, Propane Operations, EWR and Pipeline Operations (inter-company eliminations between segments primarily consist of gas sales from EWR to Natural Gas Operations, inter-company accounts receivable, accounts payable, equity, and subsidiary investment) is as follows:
11. STOCK OPTION AND SHAREHOLDER RIGHTS PLANS
STOCK OPTIONS -- The Energy West Incorporated 2002 Stock Option Plan is a stock option plan (the "Option Plan") that provides for the issuance of up to 200,000 shares of the Company's common stock to be issued to certain key employees. As of June 30, 2004, 156,037 shares were available for grant under the option plan. Additionally, the Company's 1992 Stock Option Plan (the "1992 Option Plan"), which expired in September 2002, provided for the issuance of up to 100,000 shares of the Company's common stock pursuant to options issuable to certain key employees. Under the 2002 Option Plan and the 1992 Option Plan (collectively, "the Option Plans"), the option price may not be less than 100% of the common stock fair market value on the date of grant (in the event of incentive stock options, 110% of the fair market value if the employee
owns more than 10% of the Company's outstanding common stock). Pursuant to the Option Plans, the options vest over four years and are exercisable over a five-year period from date of issuance. When the 1992 Option Plan expired in September 2002, 12,600 shares remained unissued and were no longer available for issuance.
A summary of activity under the Option Plan for the years ended June 30, 2004, 2003, and 2002 is as follows:
At June 30, 2004, the weighted average exercise price for the remaining outstanding shares was $8.491 per share. The weighted-average remaining contractual life of the remaining outstanding shares was three years. At June 30, 2004, there were approximately 85,500 shares available for grant.
SHAREHOLDER RIGHTS -- On June 3, 2004, the Company's Board of Directors declared a dividend of one Right to purchase one one-thousandth share of the Company's Series A Participating Preferred Stock for each outstanding share of Common Stock of the Company. Each Right entitles the registered holder to purchase from the Company one one-thousandth of a share of Series A Participating Preferred Stock at an exercise price of $24.00, subject to adjustment (the "Purchase Price"). The Rights generally will be exercisable only if a person or group acquires beneficial ownership of 15% or more of the Company's common stock or commences a tender or exchange offer upon consummation of which such person or group would beneficially own 15% or more of the Company's common stock. Any person or group owning 15% or more of the Company's common stock on June 3, 2004 will not cause the Rights to become exercisable unless such person or group acquires additional common stock. Once exercisable, then each holder of a Right that has not theretofore been exercised will thereafter have the right to receive, upon exercise, Common Shares having a value equal to two times the Purchase Price.
12. COMMITMENTS AND CONTINGENCIES
COMMITMENTS -- In 2000, the Company entered into a ten year transportation agreement with Northwestern Energy that fixed the cost of pipeline and storage capacity. Based on original contract prices, the minimum obligation under this agreement at June 30, 2004 is as follows:
ENVIRONMENTAL CONTINGENCY -- The Company owns property on which it operated a manufactured gas plant from 1909 to 1928. The site is currently used as an office facility for Company field personnel and storage location for certain equipment and materials. The coal gasification process utilized in the plant resulted in the production of certain by-products, which have been classified by the federal government and the State of Montana as hazardous to the environment.
In the summer of 1999, the Company received approval from the Montana Department of Environmental Quality ("MDEQ") for its plan for remediation of soil contaminants. The Company has completed its remediation of soil contaminants and in April of 2002 received a closure letter from MDEQ approving the completion of such remediation program.
The Company and its consultants continue to work with the MDEQ relating to the remediation plan for water contaminants. The MDEQ has established regulations that allow water contaminants at a site to exceed standards if it is technically impracticable to achieve them. Although the MDEQ has not established guidance to attain a technical waiver, the U.S. Environmental Protection Agency ("EPA") has developed such guidance. The EPA guidance lists factors which render mediations technically impracticable. The Company has filed a request for a waiver respecting compliance with certain standards with the MDEQ.
At June 30, 2004, the Company had incurred cumulative costs of approximately $1,925,000 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, 2004, the Company had recovered approximately $1,440,000 through such surcharges. As of June 30, 2004, the cost remaining to be recovered is $485,000.
On April 15, 2003, the MPSC issued an Order to Show Cause Regarding the Environmental Surcharge. The MPSC determined that the initial order allowing the collection of the surcharge was intended by the MPSC to cover only a two year collection period, after which it would contemplate additional filings by the Company, if necessary. The Company responded to the Show Cause Order and the MPSC subsequently ordered the termination of the Environmental Surcharge on August 20, 2003. The Company filed a request with the commission to continue the collection of the surcharge until all expenses have been recovered. This request was approved by the MPSC and the surcharge was reinstated in September 2004. The Company is required, under the Commission's most recent order, to file with the MPSC every two years for approval to continue the recovery of the surcharge.
DERIVATIVE CONTINGENCIES -- Among the risks involved in natural gas marketing is the risk of nonperformance by counterparties to contracts for purchase and sale of natural gas. EWR is party to certain contracts for purchase or sale of natural gas at fixed prices for fixed time periods. Some of these contracts are recorded as derivatives, valued on a mark-to-market basis.
LITIGATION -- 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 involved in the following described litigation.
On June 17, 2003, EWR and PPL Montana, LLC ("PPLM") reached agreement on a settlement of a lawsuit involving a wholesale electricity supply contract. Under the terms of the settlement, EWR paid PPLM a total of $3,200,000, consisting of an initial payment of $1,000,000 on June 17, 2003, and a second payment of $2,200,000 on September 30, 2003, terminating all proceedings in the case. EWR had established reserves and accruals in fiscal year 2001 of approximately $3,032,000 to pay a potential settlement with PPLM and the remaining $168,000 was charged to operating expenses in fiscal year 2003.
On August 8, 2003, the Company reached agreement with the Montana Department of Revenue ("DOR") to settle a claim that the Company had under-reported its personal property for the years 1997 - 2002 and that additional property taxes and penalties should be assessed. The settlement amount is being paid in ten annual installments of $243,000 each, beginning November 30, 2003.
The Company initially determined that it was entitled to recover the amounts paid in connection with the DOR settlement through future rate adjustments as a result of legislation permitting "automatic adjustments" to rates to recover such property tax increases. The MPSC, however, interpreted the new legislation as allowing recovery of only a portion of the higher property taxes. Rates recovering the portion of the higher taxes permitted under the MPSC's interpretation of the legislation went into effect on January 1, 2004. The Company has since obtained interim rate relief which includes full recovery of the property tax associated with the DOR settlement.
OPERATING LEASES -- The Company leases certain properties including land, office buildings, and other equipment under non-cancelable operating leases through fiscal year 2009. The future minimum lease payments on these leases are as follows:
Lease expense resulting from operating leases for the years ended June 30, 2004, 2003, and 2002 totaled $171,765, $189,906, and $189,906, respectively.
LETTERS OF CREDIT -- Outstanding letters of credit totaled $1,700,000 and $4,400,000 at June 30, 2004 and 2003, respectively. The letters of credit guarantee the Company's performance to third parties for gas and electric purchases and gas transportation services.
13. FINANCIAL 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 counterparty performance. The Company has established policies and procedures to manage such risks. The Company has a Risk Management Committee (RMC), comprised of Company officers and management 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, counterparty credit risks, and other risks related to the energy commodity business.
In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas or electricity, from time to time the Company and its subsidiaries have entered into hedging arrangements. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.
The Company accounts for certain of such purchases or sale agreements in accordance with SFAS No. 133. Under SFAS 133, such contracts are reflected in the Company's financial statements as derivative assets or derivative liabilities and valued at "fair value," determined as of the date of the balance sheet. Fair value accounting treatment is also referred to as "mark-to-market" accounting. Mark-to-market accounting results in disparities between reported earnings and realized cash flow, because changes in the derivative values are reported in the Company's Consolidated Statement of Operations as an increase or (decrease) in "Revenues - Gas and Electric - Wholesale" without regard to whether any cash payments 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. SFAS No. 133 requires that contracts for purchase or sale at fixed prices and volumes must be valued at fair value (under mark-to-market accounting) unless the contracts qualify for treatment as a "normal purchase or sale."
Quoted market prices for natural gas derivative contracts of the Company and its subsidiaries are generally not available. Therefore, to determine the fair value of natural gas derivative contracts, the Company uses internally developed valuation models that incorporate independently available current and forecasted pricing information.
As of June 30, 2004, these agreements were reflected on the Company's consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:
14. SUBSEQUENT EVENTS
As of August 30, 2004, the Company and its lender under its credit facility (the "LaSalle Facility") amended certain covenants as follows: (1) increased the total debt to capital ratio from .65 to .70, (2) allowed the inclusion of extraordinary expenses incurred by the Company for legal fees and costs of the PPLM litigation, expenses and costs associated with the credit facilities, proxy contest costs, and the costs of adoption of the shareholder rights plan, in determining the interest coverage ratio, and (3) waived compliance with the ratios referred to in (1) and (2) above as of June 30, 2004 in addition to a shareholder's acquisition of more than 15% of the outstanding common stock of the Company.
As of September 10, 2004, the LaSalle Facility was amended to extend from September 30, 2004 until October 31, 2004, the deadline for the Company to repay the $2,000,000 term loan under the LaSalle Facility, with an infusion of new equity.
On October 20, 2004, but effective as of September 28, 2004, the LaSalle Facility was amended to extend until October 29, 2004, the deadline for the Company to deliver its audited financial statements for the fiscal year ended June 30, 2004.
On November 2, 2004, the Company executed a letter agreement effective as of September 28, 2004 amending the LaSalle Facility. The letter agreement provides for the extension of the deadline to deliver audited financial statements for fiscal year 2004 from October 29, 2004 to November 12, 2004.
As of November 2, 2004, the Company executed an amendment to the LaSalle Facility, which provides for an extension from October 31, 2004 to November 30, 2004 of the deadlines under the LaSalle Facility in connection with: (i) the termination date of the revolving facility and (ii) the date to consummate infusions of new equity of at least $2.0 million to repay the $2.0 million term loan under the LaSalle Facility.
As of November 30, 2004, the Company executed an agreement with its lender providing for (i) an extension of the revolving facility until November 28, 2005; (ii) an extension of the date to consummate infusions of new equity of at least $2.0 million and to repay the $2.0 million term loan to October 1, 2005; (iii) a conditional waiver of the deadline to deliver audited financial statements for fiscal year 2004 and the deadline to deliver financial statements for the fiscal quarter ended September 30, 2004; (iv) a waiver of the technical default that otherwise would have been caused by the restatement of financial results of prior periods; (v) modification of interest rates applicable to the $2.0 million term loan; (vi) a limitation of $1.0 million on total loans and additional capital investment from the Company to EWR; and (vii) waivers of certain financial covenant defaults as of September 30, 2004.
15. RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS
On September 29, 2004, the Company announced that it was delaying the filing of its Annual Report on Form 10-K in order to complete a review of the accounting for certain contracts. Based on the results of its review, the Company has corrected its accounting and previous valuation of certain of EWR's contracts for fiscal years 2002 and 2003, and the first three quarters of fiscal year 2004, and has restated its earnings for those periods.
The Company's review of EWR's contracts included an evaluation of a gas purchase agreement and a gas sales agreement entered into during fiscal year 2002 involving counterparties who are affiliated with each other. The gas purchase agreement has previously been reflected in the Company's financial statements as a derivative asset. The gas sales agreement was previously classified by the Company as a normal sales contract, and therefore was not reflected on the Company's financial statements as a derivative liability. The Company determined that a shorter period similar to that of the gas sales agreement should have been used in the determination of the fair value of the gas purchase agreement and that the gas sales agreement does not qualify for the "normal purchase and sale" exception. As a result the consolidated financial statements have been restated to reflect a significant reduced fair value for the gas purchase agreement and the gas sales agreement as a derivative liability at its estimated fair value.
In the course of its review, the Company also determined that the fair value of a small gas purchase contract and a small gas sales contract entered into by EWR during the fiscal quarter ended December 31, 2003, had not been properly reflected in the Company's financial statements. The Company has reflected the fair value of these contracts in its restated financial statements.
As discussed in the table that follows, the accompanying consolidated financial statements as of June 30, 2003 and for the fiscal years ended June 30, 2002 and June 30, 2003 have been restated from amounts previously reported to reflect the correction of the accounting and valuation of the gas purchase and gas sale contracts discussed above.
None of the adjustments affects the Company's cash flows or cash balances. The Company's cumulative gain (loss) in the portfolio of contracts valued on a mark-to-market basis will be realized in later periods as contracts settle or are performed and/or as natural gas prices change.
A summary of the significant effects of the restatement is as follows:
16. QUARTERLY INFORMATION (UNAUDITED)
As discussed in Note 15 above, the Company has determined to restate its consolidated financial statements for fiscal years 2003 and 2002. Quarterly results (unaudited) for the years ended June 30, 2004 and 2003 including the effect of the restatement are as follows (in thousands, except per share data):