ITEM 1.
BUSINESS.
Overview
Energy West, Incorporated (the “Company”) is a regulated public utility, with certain non-utility operations conducted through its subsidiaries. We were originally incorporated in Montana in 1909. We have four reporting segments:
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Natural Gas Operations
Distributes natural gas to approximately 33,000 customers through regulated utilities operating in and around Great Falls and West Yellowstone Montana, and Cody Wyoming. The approximate population of the service territories is 100,000.
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Propane Operations
Distributes propane to approximately 7,900 customers through utilities operating underground vapor systems in and around Payson, Pine and Strawberry, Arizona and retail distribution of bulk propane to approximately 2,200 customers in the same Arizona communities. The approximate population of the service territories is 40,000.
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Energy West Resources, Inc. (EWR)
Markets approximately 3 billion cubic feet of natural gas to commercial and industrial customers in Montana and Wyoming and manage midstream supply and production assets for transportation customers and utilities. EWR also has an ownership interest in production and gathering assets.
•
Pipeline Operations (formerly Energy West Development, Inc. (EWD))
Owns the Shoshone interstate and the Glacier gathering pipeline assets located in Montana and Wyoming. Certain natural gas producing wells owned by EWD are being managed and reported in EWR.
See Note 10 to our Consolidated Financial Statements in Item 8 for financial information for each of our segments.
Natural Gas Operations
Our 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, water heating and cooking; and industrial customers use natural gas as a fuel in industrial processing and space heating. Our revenues from natural gas operations are generated under tariffs regulated by the state utility commissions of Montana and Wyoming.
Natural Gas - Montana Division
The 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 Montana division has right of way privileges for its distribution systems either through franchise agreements or general franchise agreements within its respective service territories. The Great Falls distribution component of the Montana division also provides natural gas transportation service to certain customers who purchase natural gas from other suppliers.
The Montana division received orders during the 2005 fiscal year from the Montana Public Service Commission or “MPSC”, respecting base rates in both Great Falls and West Yellowstone, Montana. These orders were granted pursuant to general rate applications filed by the division in fiscal year 2004. The Great Falls order was effective on an interim basis on November 1, 2004 and made final in August of 2005. That rate order effectively granted full recovery of the increased property tax liability resulting from the settlement reached with the Montana Department of Revenue in fiscal year 2004. It also provided recovery of other operating expenses as requested by the Company. The West Yellowstone rate order granted relief related to its share of the Montana Department of Revenue settlement as well as other operating expenses.
The following table shows the Montana division’s revenues by customer class for the fiscal year ended June 30, 2005 and the two preceding fiscal years:
Gas Revenue
Note:
Revenue increased in fiscal year 2005 compared to fiscal year 2004 due to higher gas costs as well as reflecting a full year of rate increases related to recovering property taxes. Fiscal year 2004 is higher as compared to fiscal year 2003 from increases in gas pricing and rate relief from approved rate cases in Montana for part of fiscal 2004.
The following table shows the volumes of natural gas, expressed in millions of cubic feet, or “MMcf,” sold or transported by the Montana division for the fiscal year ended June 30, 2005 and the two preceding fiscal years:
Gas Volumes
The Montana division has 199 transportation customers. No customer of the Montana division accounted for more than 1% of our consolidated revenues in fiscal 2005.
The operations of the 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 Montana division, but the Montana division provides gas transportation to customers who purchase from other suppliers.
The Montana division uses the NorthWestern Energy, or “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, we entered into a ten-year transportation agreement with NWE that fixes the cost of pipeline and storage capacity for the Montana division.
The 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 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 Wyoming division has a certificate of public convenience and necessity granted by the Wyoming Public Service Commission, or “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, 2005, the Wyoming division provided service to 5,951 customers, including one industrial customer. The Wyoming 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 Wyoming division’s distribution and transmission system.
The following table shows the Wyoming division’s revenues by customer class for the fiscal year ended June 30, 2005 and the two preceding fiscal years:
Gas Revenue
Note:
Higher revenues were realized in fiscal years 2005 and 2004 compared to fiscal year 2003 due to higher gas costs and 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.
The following table shows volumes of natural gas, expressed in MMcf, sold by the Wyoming division for the fiscal year ended June 30, 2005 and the two preceding fiscal years:
Gas Volumes
The 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 2005 this customer accounted for approximately 30% of the revenues of the Natural Gas - Wyoming division and approximately 9% 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 2005 increased approximately 31% over revenues in fiscal year 2004 EWR is the Wyoming division’s supplier of natural gas, pursuant to a three year agreement entered into in May of 2003.
The 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 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 Wyoming division’s tariffs include a purchased gas adjustment clause, which allows the Wyoming division to adjust rates periodically to recover changes in gas costs from base gas costs.
Propane Operations
We are engaged in the regulated sale of propane under the business name Energy West Arizona or “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 40,000. The operations of EWA are subject to regulation by the Arizona Corporation Commission or “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 our unregulated subsidiary, Energy West Propane, Inc. or “EWP”, under terms reviewed periodically by the ACC. EWA has approximately 7,900 regulated customers. 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.
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 or “RMF” which has wholesale operations primarily in Arizona. EWP had 2,188 unregulated customers as of June 30, 2005.
EWP’s wholesale division, RMF, supplies propane for our 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.
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 our service areas.
The following tables show propane revenues and volumes by customer class for the fiscal year ended June 30, 2005 and the two preceding fiscal years:
Propane Revenue
Propane Volume
Note:
Decreases in revenues and volumes are a result of the sale of certain assets of RMF in August 2003.
EWR
Our wholly-owned subsidiary, EWR, conducts certain marketing activities involving the sale of natural gas in Montana and Wyoming. It also marketed electricity in Montana for approximately a three year period beginning in 1999. During this period, EWR did not own any electric generating or transmission assets, but served as a broker, purchasing electricity from third parties and reselling it to end use customers throughout Montana. During fiscal year 2003, EWR’s participation in the electric market as a broker of electricity was evaluated and the decision was made to exit the electricity marketing business. Therefore, contracts for such electricity were not renewed as they expired. During the fiscal years 2005 and 2004, we had only one remaining electric contract with a margin of $34,000 and $72,000 in each of those two years, respectively. The electricity operations are reported within continuing operations because we use the same employees with the same overhead as our natural gas marketing operation. EWR has only two
remaining contracts, one with a commercial customer and the other with the supplier to obtain the electricity for the commercial customer. The terms of these contracts extend through fiscal 2006.
In order to provide a stable source of natural gas for a portion of its requirements, EWR and EWD purchased ownership in two natural gas production properties and three gathering systems located in north central Montana. The purchases were made in May 2002 and March 2003. This production gives EWR a natural hedge when market prices of natural gas are above the cost of production. The gas production from the properties provided approximately 5% of EWR’s volume requirements for fiscal 2005.
Pipeline Operations
We added Pipeline Operations 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.
Competition
The traditional competition we face in our 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 our service territory, previously installed equipment is not an issue.
Households in recent years have generally preferred the installation of gas heat. For example, we estimate 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 our Great Falls, Montana service mains in recent years have selected natural gas as their energy source. We face more intense competition in West Yellowstone and Cascade, Montana and the Payson/ Strawberry area of Arizona due to the cost of competing fuels than we face in the Great Falls area of Montana and our service territory in Wyoming.
The 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 Wyoming division’s service mains in recent years have selected gas as their energy source.
The principal competition we face 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.
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.
Finally, EWR’s principal competition is from other gas marketing firms doing business in Montana.
Governmental Regulation
Our utility operations are subject to regulation by the MPSC, the WPSC, Federal Energy Regulatory Commission or “FERC” and the ACC. Such regulation plays a significant role in determining our return on equity. The commissions approve rates intended to permit a reasonable rate of return on investment. Our tariffs allow gas cost to be recovered in full (barring a finding of imprudence) in regular (as often as monthly) rate adjustments. This mechanism has substantially reduced any delay between the incurrence
and recovery of gas costs. In addition, final orders have been received in the Montana Division for the West Yellowstone and Great Falls service territories as a result of general rate filings made by us in fiscal year 2004. The rate increases approved approximately $200,000 in increased revenues for West Yellowstone and approximately $800,000 in increased revenues for Great Falls. Both rate orders were effective for service rendered on and after November 1, 2004.
Seasonality
Our business and that of our subsidiaries in all segments is temperature-sensitive. In any given period, sales volumes reflect the impact of weather, in addition to other factors. Colder temperatures generally result in increased sales. We anticipate that this sensitivity to seasonal and other weather conditions will continue to be reflected in our sales volumes in future periods.
Environmental Matters
We own property on which we operated a manufactured gas plant from 1909 to 1928. The site is currently used as an office facility for 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 that have been classified by the Federal government and the State of Montana as hazardous to the environment.
We have completed our remediation of soil contaminants at the plant site and in April of 2002 received a closure letter from Montana Department of Environmental Quality, or “MDEQ,” approving the completion of such remediation program.
We and our 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, or “EPA,” has developed such guidance. The EPA guidance lists factors that render mediations technically impracticable. We have filed a request for a waiver from complying with certain standards with the MDEQ.
At June 30, 2005, we had incurred cumulative costs of approximately $1,925,000 in connection with our evaluation and remediation of the site. On May 30, 1995, we 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, 2005, we had recovered approximately $1,512,000 through such surcharges. As of June 30, 2005, the cost remaining to be recovered is $413,000.
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. We responded to the Show Cause Order and the MPSC subsequently ordered the termination of the Environmental Surcharge on August 20, 2003. We 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. We are 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
We had a total of 111 employees as of June 30, 2005. One of these employees is employed by EWR, 22 by our Propane Operations, 77 by our Natural Gas Operations and 11 at the corporate office. Our Natural Gas Operations include 17 employees represented by two labor unions. Contracts with each of these unions expire on June 30, 2006.
ITEM 2.
ITEM 2.
PROPERTIES.
Montana - In Great Falls, Montana, we own a 9,000 square foot office building, which serves as our headquarters, and a 3,000 square foot service and operating center (with various outbuildings), which supports day-to-day maintenance and construction operations. We own approximately 400 miles of underground distribution lines, or “mains,” and related metering and regulating equipment in and around Great Falls, Montana. In West Yellowstone, Montana, we own 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.
Combined, EWR and EWD own 163 natural gas production wells and three gathering systems in north central Montana. The natural gas wells are operated by a third party and we are invoiced each month for our share of the “actual” operating and capital expenses incurred.
Wyoming - In Cody, Wyoming, we lease office and service buildings for the Natural Gas - Wyoming division under long-term lease agreements. We own 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 - We own approximately 170 miles of distribution mains located in and around the community of Payson. We own five acres of land in Payson, on which we maintain and operate a propane vapor system for our operations. We lease an office building in Payson under an agreement that expires in 2006. We have 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.
We are party to certain legal proceedings and other various claims and lawsuits in the normal course of our business, which, in the opinion of management, are not material to our business or financial condition.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES.
Our Common Stock
Our Common Stock is quoted for trading on the Nasdaq National Market under the symbol “EWST.” The following table sets forth for the quarters indicated, the range of high and low prices of our common stock as reported by the Nasdaq National Market.
Holders of Record
As of September 1, 2005, there were approximately 1,700 holders of record of our common stock.
Dividend Policy
Our Board of Directors historically made quarterly dividend payments. However, on June 17, 2003, our Board suspended the payment of these quarterly dividends. Accordingly, there were no dividend payments declared or made during the fiscal years 2005 and 2004. Our current credit agreement with LaSalle Bank and our 1997 and 1993 Promissory Notes contain 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” for more information.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA.
Selected Financial Data on a Consolidated Basis (2005-2001 dollar amounts in thousands, except per share and number of shares data).
(1)
These amounts were restated in the prior year. See “Item 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF CONSOLIDATED OPERATIONS.
For a description of our significant accounting policies and an understanding of the significant factors that influenced our performance during the fiscal year ended June 30, 2005, this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” should be read in conjunction with the Consolidated Financial Statements, including the related notes, appearing in Item 8 of this Annual Report.
Forward-Looking Statements
This portion of the Annual Report on Form 10-K contains various “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which represent our expectations or beliefs concerning future events. These forward-looking statements are often characterized by the terms “may,” “believes,” “projects,” “expects,” or “anticipates,” and do not reflect historical facts.
Forward-looking statements involve risks, uncertainties and other factors, which may cause our actual results, performance or achievements to be materially different from those expressed or implied by such forward-looking statements. Factors and risks that could affect our results and achievements and cause them to materially differ from those contained in the forward-looking statements include those identified in the section titled “Risk Factors” in Part II, as well as other factors that we are currently unable to identify or quantify, but may exist in the future.
In addition, the foregoing factors may affect generally our business, results of operations and financial position. Forward-looking statements speak only as of the date the statement was made. We do not undertake and specifically decline any obligation to update any forward-looking statements.
Executive Overview
In 2005, we sought to restore stability and sustainable growth to our business by focusing on our core strengths: our utility operations and related energy ventures. Our progress meeting this challenge is marked by the following examples:
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We added the following individuals to our senior management team:
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David Cerotzke, President/ CEO - 32 years of gas industry experience.
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Wade Brooksby, Vice President and CFO - 22 years of energy industry financial/operating and SEC reporting experience.
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New rates were put in place in our regulated utilities in Great Falls and West Yellowstone. These along with the new rates adopted in Cody the year before significantly improved our margin (total revenue less gas costs). A vigorous focus on cost management led to significant reductions in expenses which allowed more of our margin to drop to the bottom line as earnings. This was offset somewhat by the accounting and legal costs of our restatement but it generated good earnings in fiscal 2005 and set the stage for improvements in the future.
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We have narrowed the focus of our non-regulated operations significantly seeking to capitalize on opportunities where our location or expertise give us a unique advantage to add value, such as our production properties near Cut Bank, Montana and our Shoshone and Glacier pipelines near Cody, Wyoming.
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On May 26, 2005, we successfully completed a $2,300,000 sale of 287,500 common shares at a price of $8.00 per share (a premium to the market at that time). We were able to complete the transaction without engaging an investment banker or broker; therefore, the deal costs were
negligible. $2,000,000 of the proceeds from the offering were used to satisfy our short-term debt obligation to LaSalle Bank.
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During the third and fourth quarters, our operations provided sufficient positive cash flows to enable us to significantly pay down the working capital line of credit to its lowest level in several years while at the same time building gas storage inventories needed for the coming winter season. The increased positive cash flow has resulted in better payment terms from some of our major gas and propane suppliers.
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During the fourth quarter, we successfully negotiated a new supply agreement to secure our propane requirements for our Arizona operations.
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During the third quarter, we engaged new securities legal counsel and independent auditors whose expertise fit well with our size and business sector.
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At our March 2005 Annual Meeting of Shareholders, the shareholders approved changes in the Board of Directors to a smaller more efficient size and increased the authorized common shares to 5,000,000, both of which we believe will allow us to respond to opportunities more quickly.
One of the challenges that our new management team confronted was the need to restate some prior period financials to redress issues related to the way we were valuing and accounting for certain contracts. Specifically, on September 29, 2004, we announced that we were delaying the filing of our 2004 Annual Report on Form 10-K in order to complete a review of the accounting for certain contracts. Based on the results of that review, we corrected our accounting and previous valuation of certain of EWR’s contracts for fiscal years 2002 and 2003, as well as the first three quarters of fiscal year 2004. As a result, we restated our earnings for those periods to reflect a significant reduced fair value for a gas purchase agreement and gas sales agreement as a derivative liability at its estimated fair value.
Our 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 had previously been reflected in our financial statements as a derivative asset. The gas sales agreement was previously classified as a normal sales contract, and therefore was not reflected on our financial statements as a derivative liability. We 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.
In the course of our review, we 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 our unaudited quarterly financial statements. We reflected the fair value of these contracts in our prior year quarterly financial information.
None of the prior year adjustments affected our cash flows or cash balances. Our 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.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions, and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial statements. The following are the accountings estimates that we believe are the most critical in nature. See Note 1 of the Notes to Consolidated Financial Statements for a discussion of our significant accounting policies.
Regulatory Accounting
Our accounting policies historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. Our regulated segment continues to be cost-of-service rate regulated, and we believe the application of Statement No. 71 to that segment continues to be appropriate. We must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that the regulated segment no longer meets the criteria of regulatory accounting under Statement No. 71, that segment will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities. Such a write-off could have a material impact on our consolidated financial statements.
The application of Statement No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the Montana and Wyoming Public Service Commissions and the Arizona Corporation Commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base this conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by regulatory agencies and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or for probable future refunds to customers.
We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that we will recover the regulatory assets that have been recorded.
Accumulated Provisions for Doubtful Accounts
We encounter risks associated with the collection of our accounts receivable. As such, we record a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, we primarily utilize the historical accounts receivable write-off amounts. Quarterly, at a minimum, we review the reserve for reasonableness based on the level of revenue and the aging of the receivable balance. The underlying assumptions used for the allowance can change from period to period and the allowance could potentially cause a material impact to the income statement and working capital. The actual weather, commodity prices and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from our assumptions and may impact operating income.
Unbilled Revenues and Gas Costs
At each month-end, we estimate the gas service that has been rendered from the latest date of each cycle meter reading to the month-end. This estimate of unbilled usage is based on projected base load usage for each day unbilled plus projected weather sensitive usage for each degree day during the unbilled period. Unbilled revenues and gas costs are calculated from the estimate of unbilled usage multiplied by the rates in effect at month-end. Actual usage patterns may vary from these assumptions and may impact operating income.
Recoverable/ Refundable Costs of Gas and Propane Purchases - We account 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 - We account 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 our 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 the portfolio such as the following:
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There is variability in “mark-to-market” earnings due to changes in the market price for gas. Our portfolio is valued based on current and expected future gas prices. Changes in these prices can cause fluctuations in earnings.
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We discount 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 or selling of gas for utility operations, which fall under the normal purchases and sales exception, and, from time to time, 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. There were no hedged transactions at June 30, 2005 or June 30, 2004.
Results of Consolidated Operations
The following discussion of 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 Annual Report.
Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004
Net Income (Loss) - Our net income for fiscal year 2005 was $1,381,000 compared to a net loss of $556,000 for fiscal year 2004, an improvement of $1,937,000. The improvement in our net income from fiscal year 2004 to fiscal year 2005 was the result of increases in margin and other income, decreases in overhead, depreciation, and general and administrative expenses, partially offset by increases in maintenance, interest, and taxes, both income and other taxes. The principal changes that contributed to the improvement from a net loss in fiscal year 2004 to net income in fiscal year 2005 are explained below.
Revenues - Our revenues for fiscal year 2005 were $76,709,000 compared to $73,291,000 in fiscal year 2004, an increase of $3,418,000. This increase was primarily attributable to increases in both Natural Gas and Propane Operations totaling $6,813,000 due to increased rates related to higher commodity costs, property tax recovery and approved rate cases in Montana, as well as an increase of $23,000 in Pipeline operations due to an increase of gathering revenue on the Glacier gathering line. These increases were offset by a decrease of $3,418,000 in EWR Marketing Operations primarily due to the loss of trading revenues of $8,679,000 offset by increases of $5,261,000 primarily from increases in revenue from retail customers, and favorable changes in the valuation of derivative contracts.
Gross Margin - Gross margins (revenues less cost of gas and electricity and costs of goods sold) were $18,376,000 in fiscal year 2005 compared to $15,380,000 in fiscal year 2004, an increase of $2,997,000. Gross margins were up in all segments in fiscal year 2005 compared to fiscal year 2004. Significant increases in gross margins for our segments were: (1) $1,851,000 in EWR resulting primarily from the change in the valuation of derivative contracts of $1,760,000 and net increases in production, electric and gas margin of $91,000 (2) $307,000 in the Propane Operation. Although costs increased, revenues in all propane operations increased at a slightly greater rate, resulting in higher gross margin. (3) $817,000 in Natural Gas Operations due to rate increases in Montana and Wyoming, and (4) $23,000 in Pipeline Operations due to an increase of gathering revenue on the Glacier line.
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 $182,000 from fiscal year 2004 to fiscal year 2005 due to a decrease in distribution, general and administrative expenses, as well as depreciation expenses, partially offset by increases in maintenance and taxes other than taxes on income.
Distribution, general and administrative expenses decreased by $723,000 related to costs savings measures in payroll and other associated costs in fiscal year 2005, as well as the elimination of non-recurring costs that took place in fiscal year 2004. Some of these costs in fiscal year 2004 included proxy contest expenses of $570,000, and shareholder rights plan expenses of $227,000. (Debt issuance costs incurred in fiscal year 2004 were amortized as interest expense. See table below.)
Maintenance and depreciation expenses increased $98,000 for fiscal year 2005 as compared to fiscal year 2004, primarily in Natural Gas Operations.
Taxes other than taxes on income increased by $444,000 due to the Montana DOR audit of assessed personal property values in 2004. This resulted in recognition of additional property tax expense each year for the next 10 years. The MPSC has allowed rate recovery for the increased property tax expense. This allowance is reflected in higher revenue for fiscal year 2005.
Certain Expenses Incurred During Fiscal Years 2003, 2004, and 2005 - Our consolidated results of operations were negatively affected by certain costs and expenses that occurred during fiscal years 2003, 2004 and 2005. These expenses, summarized in the table below, include litigation expenses in connection with the PPLM lawsuit during fiscal year 2003, expenses associated with the proxy contest and shareholder rights plan, and the costs associated with the restatement of previous years’ earnings which were incurred during fiscal year 2005.
In addition, the Company incurred significant expenses associated with restructuring our 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 began 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. In fiscal year 2005, the remaining $174,000 short-term debt issuance costs were charged to expense. In addition, $161,000 was included as interest expense at June 30, 2005 for continuing amortization of debt issuance costs for the long-term debt.
Other Income - Other income increased by $60,000 from $385,000 in fiscal year 2004 to $445,000 in fiscal year 2005 due primarily to recognition of interest income from a tax refund of prior years.
Interest Expense - Interest expense increased by $178,000, or 7%, from $2,499,000 in fiscal year 2004 to $2,677,000 in fiscal year 2005 due to higher overall corporate borrowings and higher interest rates.
Income Tax Benefits (Expense) - Income tax expense increased by $1,122,000 from a tax benefit of $369,000 in fiscal year 2004 to a tax expense of $753,000 in fiscal year 2005 due to increased net income.
Fiscal Year Ended June 30, 2004 Compared to Fiscal Year Ended June 30, 2003
Net Loss - Our 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 our 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 - Our revenues for fiscal year 2004 were $73,291,000 compared to $77,898,000 in fiscal year 2004, 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 our 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 above.)
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. The Company has since received rate orders permitting the recovery of substantially all of the property tax expense resulting from the settlement with Montana DOR.
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.
Operating Results of our Natural Gas Operations
Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004
Natural Gas Revenues and Gross Margins - The Natural Gas Operations’ operating revenues in fiscal year 2005 increased to $44,792,000 from 39,063,000 in fiscal year 2004. This $5,729,000 increase was primarily due to higher gas costs and increased rates related to property tax recovery and approved rate cases in Montana.
Gas purchases in Natural Gas Operations increased by $4,913,000 from $27,883,000 in fiscal year 2004 to $32,796,000 in fiscal year 2005. The increase in gas cost reflects higher commodity prices during the current fiscal year.
Gross margin, which is defined as operating revenues less gas purchased, was approximately $11,996,000 for fiscal year 2005 compared to approximately $11,180,000 in fiscal year 2004. The increase of $816,000 is primarily due to higher revenues explained above.
Natural Gas Operating Expenses - Natural Gas Segment’s operating expenses were approximately $9,666,000 as compared to $9,843,000 for fiscal year 2004. The $177,000 decrease is due mainly to $499,000 lower overhead charges and $50,000 lower depreciation expense. Payroll and other general and administrative costs were $142,000 lower due to implementation of cost-saving measures. Increased costs include $493,000 in higher property tax expenses for Montana due to increased valuations and amortization
of a 2004 property tax settlement over ten years and $87,000 higher automotive and property insurance expenses.
Natural Gas Other Income - Other income increased by $69,000 from $97,000 in fiscal year 2004 to $166,000 in fiscal year 2005. This was due primarily to cost savings associated with service sales in Great Falls as well as tax refund interest.
Natural Gas Interest Expense - Interest expense is $152,000 higher in fiscal year 2005 primarily due to higher short and long-term interest rates.
Natural Gas Income Tax Benefit (Expense) - Tax expenses are $242,000 higher in fiscal year 2005 due to higher income before taxes.
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 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 increased gas costs reflect higher commodity 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.
Natural Gas Interest Expense - Interest expense in FY2004 was $624,000 higher than fiscal year 2003 due to higher short term interest rates and loan balances.
Natural Gas Income Tax Benefit (Expense) - Tax expenses were $271,000 lower in fiscal year 2004 than fiscal year 2003 due to lower pretax income generated from increased interest expense.
Operating Results of our Propane Operations
Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004
Propane Revenue and Gross Margins - Propane Operations’ revenues increased $1,084,000 from $7,736,000 in fiscal year 2004 to $8,820,000 in fiscal year 2005 as a result of higher propane prices in fiscal year 2005. Cost of propane sold increased from $4,000,000 to $4,777,000 for the same period due also to increases in the cost of propane for both the regulated utility and the wholesale propane operations. Gross margin increased by $307,000 from $3,736,000 in fiscal year 2004 to $4,043,000 in fiscal year 2005. Although costs increased, revenues in all propane operations increased at a slightly greater rate, resulting in higher gross margin.
Propane Operating Expenses - Operating expenses were $2,969,000 for fiscal year 2005 compared to $3,039,000 for fiscal year 2004. This decrease of $70,000 is due to decreases in operating costs of $132,000, offset by the gain on the sale of assets of $252,000 in fiscal year 2004, a decrease in depreciation and maintenance expense of $4,000, a decrease in overhead costs of approximately $133,000 and a decrease in taxes other than income of $53,000 primarily related to the property tax settlement with the Montana Department of Revenue in fiscal year 2004. The settlement amount was expensed in fiscal year 2004 in the unregulated companies.
Propane Other Income - Other income increased by $29,000 from $181,000 in fiscal year 2004 to $210,000 in fiscal year 2005. Increases in interest income were coupled with increases in other miscellaneous income.
Propane Interest Expense - Interest expense decreased by $2,000 from $573,000 in fiscal year 2004 to $571,000 in fiscal year 2005.
Propane Income Tax Benefit (Expense) - Income tax expense increased by $269,000 from $2,000 in fiscal year 2004 to $271,000 in fiscal year 2005 due to higher pretax income generated from increased margins coupled with lower operating costs. In fiscal year 2004, permanent differences in tax assets and liabilities was generated from the sale of assets, resulting in lower taxes.
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 our 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.
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 as well as an increase in the revenue from contracted services related to the sale were offset by a decrease in other miscellaneous income.
Propane Interest Expense - Interest expense increased by $170,000 from $403,000 in fiscal year 2003 to $573,000 in fiscal year 2004 due to higher borrowings and amortization of costs associated with debt refinanced in fiscal year 2004.
Propane Income Tax Benefit (Expense) - Income tax expense decreased by $67,000 from $69,000 in fiscal year 2003 to $2,000 in fiscal year 2004 due to permanent differences in tax assets and liabilities generated from the sale of assets in fiscal year 2004, offset partially by increases in income before taxes.
Operating Results of our EWR Operations
Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004
EWR Revenues and Gross Margins - Revenues in EWR decreased $3,417,000 from $26,091,000 in fiscal year 2004 to $22,674,000 in fiscal year 2005. Decreased fiscal 2005 revenues due to $8,679,000 lower trading revenue were offset by 1) a $3,472,000 increase in retail gas and electric margins, 2) a favorable change in valuation of derivative contracts for $1,546,000, 3) a deferred gain of $214,000, and 4) a $30,000 increase in gathering revenue in fiscal 2005.
EWR’s fiscal year 2005 gross margin of $1,914,000 represents an increase of $1,851,000 from gross margin earned in fiscal 2004. This represents a $1,760,000 increase in the valuation of derivative contracts and a net increase in margin of $91,000 between production, electricity and gas marketing activities. The amount of the $1,760,000 change in the derivative contract valuation that was attributable to fiscal year 2005 is $516,000. The amount of the change in the derivative contract valuation that was attributable to fiscal year 2004 was ($1,244,000).
EWR Operating Expenses - Operating expenses of EWR increased approximately $77,000, from $1,096,000 for fiscal year 2004 to $1,173,000 for fiscal year 2005. This increase is due primarily to a reduction in overhead charges partially offset by an increase in general and administrative charges.
EWR Other Income (Expense) - Other income increased by $80,000 due to income of $58,000 from the settlement of a contract dispute, $9,000 of interest earned on an income tax refund and $13,000 savings in other expenses not incurred in 2005.
EWR Interest Expense - Interest expense increased by $22,000 due to an increase in borrowings.
EWR Income Tax Benefit (Expense) - Tax expense increased in 2005 from a tax benefit of $444,000 in 2004 to an expense of $211,000 due to changes in income before taxes.
Fiscal Year Ended June 30, 2004 (as restated) 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 $6,944,000 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 for EWR decreased approximately $1,944,000, from $3,040,000 for fiscal year 2003 to $1,096,000 for fiscal year 2004. The 2004 decrease is due primarily to non-recurring legal expenses of $1,552,000 related to the settlement of the PPLM litigation in fiscal 2003. The remainder of the decrease is due to lower general and administrative expenses for payroll and related expenses, less travel and training and other cost savings measures.
EWR Other Income (Expense) - Other income decreased in fiscal year 2004 compared to fiscal year 2003 primarily due to EWR devaluing an investment in a distributorship by $17,000. The decrease was partially offset by the gain on the sale of two vehicles and a gathering system compressor.
EWR Interest Expense - Interest expense increased by $29,000 in fiscal 2004 as compared to fiscal 2003 due to an increase in borrowings.
EWR Income Tax Benefit (Expense) - Fiscal 2004 tax benefit decreased compared to fiscal 2003 due to higher income before taxes.
Operating Results of our Pipeline Operations
Fiscal Year Ended June 30, 2005 Compared to Fiscal Year Ended June 30, 2004
Pipeline Revenues and Gross Margins - Pipeline Operations revenue consists only of gathering and transmission revenues related to the pipelines located in Wyoming and Montana.
Pipeline Operations’ margin increased from $401,000 in fiscal year 2004 to $424,000 in fiscal year 2005. The increase of $23,000 was due an increase in gathering volumes on the Glacier gathering line.
Pipeline Operating Expenses - Operating expenses decreased from $214,000 in fiscal year 2004 to $202,000 in fiscal year 2004. The $12,000 decrease was due to a reduction in payroll and related expenses.
Pipeline Other Income - Other income decreased from $121,000 in fiscal year 2004 to $2,000 in fiscal year 2005. Fiscal year 2004 included the sale of non-operating real estate assets located in Montana which resulted in a gain of $121,000.
Pipeline Interest Expense - Interest expense increased from $50,000 in fiscal year 2004 to $56,000 in fiscal year 2005 due to higher interest rates.
Pipeline Income Tax Benefit (Expense) - Tax expense decreased from an expense of $99,000 in fiscal year 2004 to $55,000 in fiscal year 2005. The decrease is due to lower net income in 2005 compared to 2004.
Fiscal Year Ended June 30, 2004 Compared to Fiscal Year Ended June 30, 2003
Pipeline Revenues and Gross Margins - 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 $51,000 decrease 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.
Pipeline Interest Expense - Interest expense increased from $7,000 in fiscal year 2003 to $50,000 in fiscal year 2004 due to an increase in corporate borrowing.
Pipeline Income Tax Benefit (Expense) - Tax expense increased from a benefit of $17,000 in fiscal year 2003 to $99,000 expense in fiscal year 2005. The increase is due to higher income before taxes in 2004.
Consolidated Cash Flow Analysis
Sources and Uses of Cash
Operating activities provide our primary source of cash. Cash provided by operating activities consists of net income (loss) adjusted for non-cash items, including depreciation, depletion, amortization, deferred income taxes and changes in working capital.
Our ability to maintain liquidity depends upon our $15,000,000 credit facility at LaSalle Bank, shown as line of credit on the accompanying balance sheet. Our use of the LaSalle credit facility decreased to $3,900,000 at June 30, 2005, compared with $6,729,000 at June 30, 2004. This $2,829,000 improvement reflects the fact that we generated a $1,381,000 net income in fiscal year 2005 as compared to a $556,000 net loss in fiscal year 2004, a $1,200,000 refund of income taxes collected from a carry back of net operating losses in prior years, a $1,472,000 decrease in natural gas and propane inventories, offset by a $796,000 increase in accounts receivable and a $960,000 decrease in accounts payable. We made capital expenditures of $2,796,000, $2,317,000 and $4,040,000 during the fiscal years ended 2005, 2004 and 2003, respectively. We finance our capital expenditures on an interim basis through this LaSalle credit facility. We periodically repay our short-term borrowings under our LaSalle credit facility by using the net proceeds from the sale of long-term debt and equity securities.
Long-term debt decreased to $18,677,000 at June 30, 2005, compared with $21,697,000 at June 30, 2004. This $3,020,000 decrease resulted primarily from using $2,000,000 of the proceeds from the May 26, 2005, sale of common shares to pay off a portion of the LaSalle term note and the scheduled principal payments of $480,000 on the Series 1993 notes, $90,000 on the Series 1992B notes and $400,000 on the term loan as provided for in the debt agreements.
Cash decreased to $94,000 at June 30, 2005, compared with $1,323,000 at June 30, 2004. This $1,229,000 decrease in cash for the year ended June 30, 2005 is compared with the $616,000 decrease and $1,571,000 increase in cash for the years ended June 30, 2004 and June 30, 2003, respectively, as shown in the following table:
For the year ended June 30, 2005, cash provided by operating activities increased $7,216,000 as compared to 2004 due to favorable working capital fluctuations. For the year ended June 30, 2004, cash provided by operating activities decreased $10,421,000 as compared to 2003 primarily due to a $1,090,000 decrease in accounts receivable, an increase of $4,144,000 for natural gas and propane stored in inventories and a $5,231,000 decrease in accounts payable.
For the year ended June 30, 2005, cash used in investing activities increased $1,320,000 as compared to 2004 due primarily from a $479,000 increase in capital expenditures and no significant proceeds from the sale of assets in fiscal year 2005. For the year ended June 30, 2004, cash used in investing activities decreased $2,931,000 as compared to 2003 due primarily to a $1,723,000 decrease in capital expenditures and $946,000 proceeds received from the sale of assets and $159,000 cash received from contributions in aid of construction in the year 2004.
For the year ended June 30, 2005, cash used in financing activities decreased by $6,509,000 as compared to 2004, primarily due to $8,000,000 borrowings of long-term notes net of $1,526,000 debt issuance expenses during fiscal year 2004. Cash provided by financing activities increased $5,303,000 for the year ended June 30, 2004, primarily due to increased net borrowings in fiscal year 2004 compared to no such borrowings in fiscal year 2003 and the payment of $1,082,000 of dividends in 2003.
Governmental Regulation
Our utility operations are subject to regulation by the MPSC, the WPSC, and the ACC. Such regulation plays a significant role in determining our return on equity. The commissions approve rates that are intended to permit a reasonable rate of return on investment. Our 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 MPSC final order approved in August of 2005 is estimated to provide additional gross margin of approximately $800,000 annually. In addition, a final order for the West Yellowstone general rate filing was approved for approximately $200,000 annually and became effective on November 1, 2004.
Liquidity and Capital Resources
Our operating capital needs, as well as 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, we have borrowed short-term funds. When the short-term debt balance significantly exceeds working capital requirements, we have issued long-term debt or equity securities to pay down short-term debt. We have 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, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.
We maintain a $15 million revolving credit facility with LaSalle Bank National Association, as Agent for certain banks. The LaSalle credit facility is accompanied by a $6.0 million term loan maturing on March 31, 2009. The term loan at June 30, 2005 had an outstanding balance of $5.5 million. Borrowings under the LaSalle credit facility are secured by liens on substantially all of our assets. Our obligations under certain other notes and industrial development revenue obligations are secured on an equal and ratable basis with LaSalle in the collateral granted to secure the borrowings under the LaSalle credit facility with the exception of the first $1.0 million of debt under the LaSalle credit facility.
The following table represents borrowings under the LaSalle credit facility for each of the periods presented.
Under the LaSalle credit facility, we may elect to pay interest on portions of the amounts outstanding at the London Interbank Offered Rate (LIBOR), plus 250 basis points, for interest periods we select. For all other balances outstanding under the LaSalle credit facility, we pay interest at the rate publicly announced from time to time by LaSalle as its “Prime Rate.” For the term loan with LaSalle, we may elect to pay interest at either the applicable LIBOR rate, plus 350 basis points or at the Prime Rate, plus 200 basis points.
The LaSalle credit facility requires us 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. The LaSalle credit facility also restricts our ability to pay dividends during any period to a certain percentage of our cumulative earnings over that period, and restricts open positions and Value at Risk (VaR) in our wholesale operations. At June 30, 2005, we were in compliance with the financial covenants under the LaSalle credit facility; however, at June 30, 2004, we would not have been in compliance with the financial covenants under the LaSalle credit facility had LaSalle not waived or modified certain financial covenants.
At June 30, 2005, we had approximately $93,000 of cash on hand. In addition, at June 30, 2005, we had borrowed approximately $3.9 million under the LaSalle credit facility. Our short-term borrowings under our lines of credit during fiscal year 2005 had a daily weighted average interest rate of 5.49% per annum. At June 30, 2005, we had no outstanding letters of credit related to electricity and gas purchase contracts. We had net availability at June 30, 2005, of approximately $11,100,000 under the LaSalle credit facility revolving line of credit. As discussed above, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months. Our availability normally increases in January as monthly heating bills are paid and gas purchases are no longer necessary.
In addition to the LaSalle credit facility, we have outstanding certain notes and industrial development revenue obligations (collectively “Long Term Notes and Bonds”). Our 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%. Our 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 credit facility with the exception of the first $1.0 million of debt under the LaSalle credit facility.
Under the terms of the Long Term Notes and Bonds, we are subject to certain restrictions, including restrictions on total dividends and distributions, liens and secured indebtedness, and asset sales, and are restricted from incurring additional long-term indebtedness if we do not meet certain debt to interest and debt to capital ratios.
In the event that our obligations under the LaSalle credit 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 our Series 1993 Notes and Series 1997 Notes. In such circumstances, an event of default under either series of notes would occur if (a) we 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, the acceleration of our obligations under the LaSalle credit facility has not been rescinded or annulled and the obligations under the LaSalle credit 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 our obligations were accelerated under the terms of any of the LaSalle credit 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 our financial condition.
The total amount outstanding under all of our long term debt obligations was approximately $18.7 million and $21.7 million, at June 30, 2005 and June 30, 2004, respectively. The portion of such obligations due within one year was approximately $1,013,000 and $973,000 at June 30, 2005, and June 30, 2004, respectively.
Contractual Obligations
Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. On August 9, 2004, we entered into a fixed-for-floating interest rate swap transaction on our five-year floating interest rate term note. If we were to designate it as a hedge this transaction would qualify as a fair value hedge under SFAS No. 133; we have elected not to designate it as a hedge and have not recorded it as a fair value hedge.
The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on June 30, 2005. The interest rates presented below represent the weighted-average interest rates for the year ended June 30, 2005. The fair value of the interest rate swap was $5,184 and is recorded as an asset on the accompanying financial statements.
Payments Due by Period
(a)
Our long-term debt, notes payable and customers’ deposits all require interest payments. Interest payments are projected based on actual interest payments incurred in fiscal 2005 until the underlying debts mature.
(b)
See Note 7 of the Notes to Consolidated Financial Statements for a description of this debt. The cash obligations represent the maximum annual amount of redemptions to be made to certain holders or their beneficiaries through the debt maturity date.
(c)
For the purpose of this calculation, we have assumed that our obligation is limited to a maximum of $125 per month for each of our 14 retired persons for the remainder of their expected life.
(d)
Transportation and Storage Obligations represent annual commitments with suppliers for periods extending up to four years. These costs are recoverable in customer rates.
See Note 12 of the Notes to Consolidated Financial Statements for other commitments and contingencies.
Capital Expenditures
We conduct ongoing construction activities in all of our utility service areas in order to support expansion, maintenance and enhancement of its gas and propane pipeline systems. In fiscal years 2005, 2004 and 2003, our total capital expenditures were approximately $2,796,000, $2,317,000 and $4,040,000, respectively, including purchases of natural gas production properties. Expenditures for fiscal year 2003 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 2005 and 2004 were limited to essential needs only. Expenditures in fiscal year 2006 are expected to be limited to essential needs only.
We estimate future cash requirements for capital expenditures will be as follows:
New Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board (the “FASB”) issued a revision of Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Accounting for Stock-Based Compensation. The revised statement requires public entities to measure liabilities incurred to employees in share-based payment transactions at fair value. This Statement is effective for public entities as of the beginning of the first interim or annual reporting period that begins after December 15, 2005. Management is currently evaluating the impact that the adoption of this standard will have on the consolidated financial statements.
In May 2005, FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“SFAS No. 154”). SFAS No. 154 modifies the requirements for accounting and reporting changes to accounting principles. The provisions of SFAS No. 154 require, unless impracticable, retrospective application to prior periods’ financial statements of (1) all voluntary changes in principles and (2) changes required by a new accounting pronouncement, if a specific transition is not provided. SFAS No. 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate, which requires prospective application of the new method. SFAS No. 154 is effective for all accounting changes made in fiscal years beginning after
December 15, 2005. Management has determined that there is no current impact from SFAS No. 154 on the consolidated financial statements.
In March 2005, the FASB issued Interpretation No. 47 (“ FIN 47”), “Accounting for Conditional Asset Retirement Obligations,” an interpretation of FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application for interim financial information is permitted but is not required. Management is evaluating if adoption of this standard will have an impact on the consolidated financial statements.
Risk Factors
An investment in our common stock involves a substantial degree of risk. Before making an investment decision, you should give careful consideration to the following risk factors in addition to the other information contained in this report. The following risk factors, however, may not reflect all of the risks associated with our business or an investment in our common stock.
Our quarterly results of operations could fluctuate due to factors outside of our control.
Factors that could cause our results of operations to fluctuate in the future include the following:
•
Fluctuating energy commodity prices, including prices for fuel and purchased power;
•
The possibility that regulators may not permit us to pass through all 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 we conduct business;
•
Changes in federal or state laws and regulations to which we are subject, including tax, environmental and employment laws and regulations;
•
The impact of the Federal Energy Regulatory Commission (FERC) and state public service commission statutes, regulations, and actions, including allowed rates of return, and the resolution of other regulatory matters;
•
Our ability to obtain governmental and regulatory approval of various expansion or other projects;
•
The costs and effects of legal and administrative claims and proceedings against us or our subsidiaries;
•
Conditions of the capital markets we utilize to access capital to finance operations;
•
The ability to raise capital in a cost-effective way;
•
The ability to meet 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 our growth;
•
The ability to control costs;
•
The ability of each business unit to successfully implement key systems, such as service delivery systems;
•
Our ability to develop expanded markets and product offerings and our 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.
We are subject to complex government regulation, which may have a negative impact on our business and our results of operations.
We are subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influence our operating environment and may affect our ability to recover costs from utility customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. FERC, State and Federal environmental agencies, the MPSC, the WPSC and the ACC regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. We believe the necessary permits, approvals and certificates have been obtained for our existing operations. However, we are unable to predict the impact on our business and operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.
The regulatory structure in which we operate 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 our regulated segment. Our regulated natural gas and propane vapor operations follow Statement of Financial Accounting Standards (SFAS) No. 71 “Accounting for the Effects of Certain Types of Regulation,” and the 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 our 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 operations of the Company. However, we are unaware of any circumstances or events in the foreseeable future that would cause us to discontinue the application of SFAS No. 71.
Recent events in the energy markets that are beyond our control may have negative impacts on our business.
As a result of the energy crisis in California during the summer of 2001, the recent volatility of natural gas prices in North America, the filing of bankruptcy by the Enron Corporation, and investigations by governmental authorities into energy trading activities, companies generally in the regulated and unregulated utility businesses have been under an increased amount of public and regulatory scrutiny. The
capital markets and credit ratings agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws, but it is difficult or impossible to predict or control what effect these or related issues may have on our business or our access to the capital markets.
Our results of operations can be adversely affected by milder weather.
Our business 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. We anticipate that this sensitivity to seasonal and other weather conditions will continue to be reflected in our sales volumes in future periods. As a result, unusually mild weather could diminish our results of operations and harm our financial condition.
The use of derivative contracts in the normal course of our business and changing interest rates and market conditions could result in financial losses that negatively impact our results of operations.
Our operations include managing market risks related to commodity prices. We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas and propane. In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas, from time to time we 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.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material adverse impact on our earnings for a given period.
We are subject to numerous environmental laws and regulations which may increase our cost of operations, impact our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.
In addition, we may be a responsible party for environmental clean-up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.
We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.
We depend upon our executive officers and key personnel.
Our performance depends substantially on the performance of our executive officers and other key personnel. The success of our business in the future will depend on our ability to attract, train, retain and motivate high quality personnel, especially highly qualified managerial personnel. The loss of services of
any executive officers or key personnel could have a material adverse effect on our business, results of operations or financial condition.
Competition for talented personnel is intense, and there is no assurance that we will be able to continue to attract, train, retain or motivate other highly qualified technical and managerial personnel in the future. In addition, market conditions may require us to pay higher compensation to qualified personnel than we currently anticipate. Any inability to attract and retain qualified personnel in the future could have a material adverse effect on our business, prospects, financial condition, and results of operations.
Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and stock price.
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, beginning with our Annual Report on Form 10-K for the fiscal year ending June 30, 2007, we will be required to furnish a report by our management on our internal control over financial reporting. The internal control report must contain (i) a statement of management’s responsibility for establishing and maintaining adequate internal control over financial reporting, (ii) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our internal control over financial reporting, (iii) management’s assessment of the effectiveness of our internal control over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not internal control over financial reporting is effective, and (iv) a statement that our independent auditors have issued an attestation report on management’s assessment of internal control over financial reporting.
In order to achieve compliance with Section 404 of the Act within the prescribed period, we have initiated a process to document and evaluate our internal control over financial reporting, which will be both costly and challenging. In this regard, management has dedicated internal resources and will engage outside consultants if necessary. The project team will adopt a detailed work plan to (i) assess and document the adequacy of internal control over financial reporting, (ii) take steps to improve control processes where appropriate, (iii) validate through testing that controls are functioning as documented and (iv) implement a continuous reporting and improvement process for internal control over financial reporting. There is a risk that neither we nor our independent auditors will be able to conclude at June 30, 2007 that our internal controls over financial reporting are effective as required by Section 404 of the Act.
During the course of our testing we may identify deficiencies which we may not be able to remediate in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to achieve and maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Moreover, effective internal controls, particularly those related to revenue recognition, are necessary for us to produce reliable financial reports and are important to helping prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could drop significantly.
Certain provisions in our charter, under applicable Montana law, as well as our Shareholder Rights Plan, may prevent or delay a change of control of our company.
We have adopted a Shareholder Rights Plan. This Plan serves as a strong deterrent to any unsolicited or hostile takeover attempts and, effectively, requires an interested acquirer to negotiate with our Board of Directors.
Additionally, our Articles of Incorporation authorize our Board of Directors to issue preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions granted to or imposed upon any unissued shares of preferred stock and to fix the number of shares constituting any series and the designations of such series, without further vote or action by the shareholders. Montana law, our charter
and our Shareholders Rights Plan, could prohibit or delay mergers or other takeover or change of control of our Company and may discourage attempts by other companies to acquire us, even if such a transaction would be beneficial to our stockholders.
Actual results could differ from estimates used to prepare our financial statements.
In preparing our financial statements in accordance with generally accepted accounting principles, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
•
Regulatory Accounting - Regulatory accounting allows for the actions of regulators, such as the MPSC, and FERC, to be reflected in the financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
•
Derivative Accounting - Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in common stock equity (as a component of other comprehensive income (loss)).
•
Mark-to-Market Accounting - The market value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.
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 our exposure to such changes. Actual results may differ. See the notes to the financial statements for a description of our 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. Our 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 our results of operations are not significantly exposed to changes in natural gas prices.
Interest Rate Risk
Our 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. Some of our notes payable, however, are subject to variable interest rates which we may mitigate by
entering into interest rate swaps. A hypothetical 100 basis point change in market rates applied to the balance of the notes payable would change interest expense by approximately $130,000 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 begin on page of this Annual Report on Form 10-K. Certain supplementary financial information is contained in Note 16 to our Consolidated Financial Statements.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
On March 4, 2005, we engaged Hein & Associates LLP as our new independent auditor to audit our consolidated financial statements. This was not the result of any disagreement with Deloitte & Touche LLP, our prior auditors. Management believed that the Hein & Associate’s size and level of expertise presented a more appropriate fit with our needs.
In connection with our audit for fiscal 2004, Deloitte & Touche LLP advised us that they had identified a material weakness in our internal control over financial reporting in connection with derivative contracts. This ultimately led to a restatement of our previously issued consolidated financial statements for the fiscal years ended June 30, 2002 and June 30, 2003 and the first three quarters of the fiscal year ended June 30, 2004.
Subsequently, we have implemented changes in our internal controls over financial reporting to address the material weakness. Specifically, we implemented procedures with respect to 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, and we established 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 No. 133. These procedures are designed to make sure that all material obligations entered into on our behalf or on behalf of our subsidiaries receive proper review and that those agreements are enforced and performed according to their terms and conditions. These procedures are also designed to make sure that we comply with applicable accounting requirements.
We have begun to provide our accounting staff with additional training on the identification and accounting for derivative instruments, contracts qualifying for the normal purchase and sales exception under SFAS No. 133, and unusual financing arrangements. In addition to these steps, we continue to evaluate how we can further strengthen our policies and procedures related to identifying and accounting for derivative instruments.
We believe that we have improved our financial reporting and disclosure controls and procedures and remedied the material weakness identified above.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES.
Disclosure controls and procedures are designed with an objective of ensuring that information required to be disclosed in our periodic reports filed with the Securities and Exchange Commission, such as this Annual Report on Form 10-K, is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission. Disclosure controls are also designed with an objective of ensuring that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, in order to allow timely consideration regarding required disclosures.
The evaluation of our disclosure controls by our principal executive officer and principal financial officer included a review of the controls’ objectives and design, the operation of the controls, and the effect of the controls on the information presented in this Annual Report. Our management, including our chief executive officer and chief financial officer, does not expect that disclosure controls can or will prevent or detect all errors and all fraud, if any. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Also, projections of any evaluation of the disclosure controls and procedures to future periods are subject to the risk that the disclosure controls and procedures may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on their review and evaluation, as of the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective at the reasonable assurance level. They are not aware of any significant changes in our disclosure controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. During the most recent fiscal period, there have not been any changes in our internal control over financial reporting that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
Certain information required by Part III is omitted from this Annual Report on Form 10-K because we will file our definitive Proxy Statement for our 2005 Annual Meeting of Shareholders to be held in November 2005 (the “2005 Proxy Statement”) not later than 120 days after the end of the fiscal year covered by this Annual Report. Certain information included in the 2005 Proxy Statement is incorporated herein by reference.
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding directors and executive officers of our company and the disclosure required by Item 405 of Regulation S-K concerning Section 16(a) Beneficial Ownership Reporting Compliance will be set forth under the captions “Election of Directors,” “Executive Officers and Compensation” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the 2005 Proxy Statement. Such information is incorporated by reference into this Annual Report on Form 10-K.
Code of Ethics
We have adopted a corporate code of ethics that applies to all of our employees and directors, including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. Our Code of Business Conduct fully complies with the requirements of Sarbanes-Oxley Act of 2002. Specifically, our Code of Business Conduct is reasonably designed to deter
wrongdoing and promote (i) honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships; (ii) full, fair, accurate, timely and understandable disclosure in public reports; (iii) compliance with applicable governmental laws rules and regulations; (iv) prompt internal reporting of code violations to an appropriate person identified in the code; and (v) accountability for adherence to the code. A copy of this document is available on our website at www.ewst.com, free of charge under the section titled “Our Company.” 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.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Information regarding director and executive compensation will be set forth under the captions “Election of Directors” and “Executive Officers and Compensation” in the 2005 Proxy Statement.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information regarding security ownership of certain beneficial owners and management will be set forth under the caption “Security Ownership of Principal Stockholders and Management” in the 2005 Proxy Statement.
Equity Compensation Plan
We maintain the 2002 Stock Option Plan pursuant to which we may grant equity awards to eligible persons. The following table sets forth certain information about equity awards under our 2002 Stock Option Plan.
(1)
Includes 100,000 shares available for future issuance under our Deferred Compensation Plan for Directors, 73,331 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 ACCOUNTING FEES AND SERVICES
Information regarding this item will be set forth under the caption “Principal Accountant Fees and Services” in the 2005 Proxy Statement.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements included in Part II, Item 8:
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
(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, 2005
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENERGY WEST, INCORPORATED
/s/ DAVID A. CEROTZKE
David A. Cerotzke
President and Chief Executive Officer
(principal executive officer)
Date: September 27, 2005
KNOW ALL THESE PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints, jointly and severally, David Cerotzke and John Allen, his true and lawful attorney-in-fact and agents, with full power of substitution, for him in any and all capacities, to sign any and all amendments to this Report on Form 10-K, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that said attorney-in-fact or his substitute, may do or cause to be done by virtue hereof.
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.
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 sheet of Energy West, Incorporated and subsidiaries as of June 30, 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended. Our audit also included the financial statement schedule as of, and for the year ended June 30, 2005 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 these financial statements and financial statement schedule based on our audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the June 30, 2005 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy West, Incorporated and subsidiaries as of June 30, 2005, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion the financial statement schedule as of, and for the year ended June 30, 2005, 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.
HEIN & ASSOCIATES LLP
Phoenix, Arizona
September 15, 2005
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 sheet of Energy West, Incorporated and subsidiaries as of June 30, 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended June 30, 2004. Our audits also included the financial statement schedule for the years ended June 30, 2004 and 2003, 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 the results of their operations and their cash flows for each of the two 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 for the years ended June 30, 2004 and 2003, 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 year 2003 were restated in the prior year.
DELOITTE AND TOUCHE LLP
Salt Lake City, Utah
December 16, 2004
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, JUNE 30, 2005 AND 2004
See notes to consolidated financial statements
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30, 2005, 2004, AND 2003
See notes to consolidated financial statements
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED JUNE 30, 2005, 2004, AND 2003
See notes to consolidated financial statements
ENERGY WEST INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2005, 2004, AND 2003
See notes to consolidated financial statements (concluded)
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended June 30, 2005, 2004, and 2003
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. Our 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. Our West Yellowstone, Montana operation is supplied by liquefied natural gas.
Our non-regulated operations include wholesale distribution of bulk propane in Arizona 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, 2005, the Company was in compliance with all of the covenants of the LaSalle credit facility, however, as of June 30, 2004, the Company would not have been in compliance with certain covenants under the LaSalle credit facility had the lender not waived or modified the covenants. See note 7.
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 our 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
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
commissions, are accumulated and recovered or credited through future rate changes. As of June 30, 2005 and June 30, 2004, the Company has unrecovered purchase gas costs of $1,863,475 and $788,407 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. These assets are depreciated and amortized over three to forty years.
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 production activities are being accounted for using the successful efforts method. The gas reserves are included in the Property, Plant and Equipment, net in the accompanying consolidated financial statements. The Company is not the operator of any of the natural gas producing wells on these properties. 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, 2005 and 2004, 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.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table illustrates the effect on net income per share for the year ended June 30, 2005 and loss per share for the year 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 year ended June 30, 2005, 70,000 options were granted. In the fiscal year ended June 30, 2004 no options were granted At June 30, 2005, a total of 126,000 options were outstanding.
The fair value of the options issued in Fiscal Year Ended June 30, 2005 was estimated at the date of grant using the Black-Scholes option pricing model with the following assumptions:
1) risk-free interest rate of 3.9 percent;
2) no dividends in the fiscal years 2005 and 2004 and a 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 to 10 years; and
5) a volatility factor of the expected market price of our common stock of 54 percent.
Comprehensive Income - During the years ended June 30, 2005, 2004, and 2003, 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 2004, and 2003, the Company recognized a reduction in revenues “gas and electric - wholesale” from derivative instruments of approximately $1,244,000, and $2,177,000 respectively. During
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
fiscal year 2005, the company had an increase in revenues of $1,546,000 due to the change in the fair value of the derivative instruments and $214,000 in amortization of the deferred gain established in January 2005 when EWR reclassified two derivative contracts as “normal sales and purchases”. 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. As of June 30, 2005 the Company has no derivative instruments designated and qualifying as SFAS No. 133 hedges.
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 our 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 potentially dilutive securities are the stock options described in Note 11. Options to purchase 126,000 and 77,000 shares of common stock were outstanding at June 30, 2005 and June 30, 2004, respectively, and were excluded in the computation of diluted earnings (loss) per share as the options were anti-dilutive.
Credit Risk - Our 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. See Note 7 for a discussion of the fair value of the fixed rate long-term debt.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 $618,473 and $586,229 represents the estimated future liability as of June 30, 2005 and June 30, 2004 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 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.
In December 2004, the Financial Accounting Standards Board (the “FASB”) issued a revision of Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Accounting for Stock-Based Compensation. The revised statement requires public entities to measure liabilities incurred to employees in share-based payment transactions at fair value. This Statement is effective for public entities as of the beginning of the first interim or annual reporting period that begins after December 15, 2005. Management is currently evaluating the impact that the adoption of this standard will have on the consolidated financial statements.
In May 2005, FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“SFAS No. 154”). SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle. The provisions of SFAS No. 154 require, unless impracticable, retrospective application to prior periods’ financial statements of (1) all voluntary changes in principles and (2) changes required by a new accounting pronouncement, if a specific transition is not provided. SFAS No. 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate, which requires prospective application of the new method. SFAS No. 154 is effective for all accounting changes made in fiscal years beginning after December 15, 2005. Management has determined that there is no current impact from SFAS No. 154 on the consolidated financial statements.
In March 2005, the FASB issued Interpretation No. 47 (“ FIN 47”), “Accounting for Conditional Asset Retirement Obligations,” an interpretation of FASB issued Statement No. 143 (“SFAS No. 143”),
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
“Accounting for Asset Retirement Obligations.” FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application for interim financial information is permitted but is not required. Management has determined that there is no current impact from FIN 47 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, EWR and EWD purchased ownership in two natural gas production properties and three gathering systems located in north central Montana. The purchases were made in May 2002 and March of 2003. The company is depleting the cost of the gas properties using the units-of-production method. As of June 30, 2005, an independent reservoir engineer estimated the net gas reserves at 5.2 Bcf (unaudited) and a $9,702,799 net present value after applying a 10% discount (unaudited). The net book value of the gas properties totals $1,580,665 and is included in the Property, Plant and Equipment, Net in the accompanying consolidated financial statements.
The wells are depleting based upon production at approximately 10% per year as of June 30, 2005. For the period ended June 30, 2005, 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 working interests 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, 2005, 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 our present volume requirements. 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. 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 the Oil and Gas Producing Properties.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
3.
Property, Plant and Equipment
Property, plant and equipment consist of the following as of June 30, 2005 and 2004:
4.
Deferred Charges
Deferred charges consist of the following as of June 30, 2005 and 2004:
Regulatory assets will be recovered over a period of approximately seven to twenty years.
The property tax asset does not earn a return in the rate base; however the property tax is recovered in rates over a ten-year period starting January 1, 2004. The income taxes and environmental remediation costs earn a return equal to that of the Company’s rate base. No other assets earn a return or are recovered in the rate structure. Other regulatory assets are amortized over fiscal year 2006.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
5.
Accrued and Other Current Liabilities
Accrued and other current liabilities consist of the following as of June 30, 2005 and 2004:
6.
Other Long-Term Liabilities
Other long-term liabilities consist of the following as of June 30, 2005 and 2004:
*
In January 2005, two long-term contracts were designated as “normal purchases and sales”. The derivative liability as of January 2005 will now be amortized over the remaining monthly volumes of the contract at a rate of $1.21 per MMBtu.
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 credit facility”) with LaSalle Bank National Association (“LaSalle”). Among other things, such modification converted $8,000,000 of 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 reduced the maximum amount of the line of credit, which expires on November 28, 2005, from $23,000,000 to $15,000,000. The $2,000,000 term loan was repaid May 26, 2005 with the proceeds of a sale of equity securities by the Company. The LaSalle credit facility is secured, on an equal and ratable basis with our other long-term debt, by substantially all of our assets.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Long-term Debt - Long-term debt at June 30, 2005 and 2004 consists of the following:
Borrowings under the LaSalle credit facility are secured by liens on substantially all of the assets of the Company and its subsidiaries. Our 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 credit facility with the exception of the first $1.0 million of debt under the LaSalle credit 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 our 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, 2005, 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 our 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, 2005, 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 our 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, 2005, 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 credit 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 October 1, 2005. The $2,000,000 term loan was repaid May 26, 2005 with proceeds of a placement of equity securities by the Company. Under the LaSalle credit facility, the Company pays interest (i) on its line of credit
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 200 bps and (iii) on its $2,000,000 term loan at Prime plus 200 bps through March 31, 2005 and; the Prime Rate plus 300 bps from April 1, 2005 through May 26, 2005. The LaSalle credit facility also has a commitment fee of 35 bps per annum due on the daily unutilized portion of the facility.
Aggregate Annual Maturities - The scheduled maturities of long-term debt at June 30, 2005 are as follows:
The estimated fair value of our fixed rate long-term debt, based on quoted market prices for the same or similar issues, is approximately $16,456,080 and $24,796,889 as of June 30, 2005 and 2004, respectively.
Debt Covenants - Our 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 credit facility. Subsequently, the LaSalle credit facility was amended to approve this concentration of equity ownership.
As of August 30, 2004, the Company and its lender under its credit facility (the “LaSalle credit 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 credit 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 credit facility, which provides for an extension to November 30, 2004 of the deadlines under the LaSalle credit facility in connection with: (i) the termination date of the revolving facility and (ii) the date to consummate
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
infusions of new equity of at least $2.0 million to repay the $2.0 million term loan under the LaSalle credit 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.
On May 26, 2005, the Company completed the sale of 287,500 common shares at a price of $8.00 per share for net proceeds of $2,202,956 after deducting $97,044 of issuance expenses. $2,000,000 of the equity proceeds were immediately used to pay off the short-term loan under the LaSalle credit facility.
8.
Employee Benefit Plans
The Company has a defined contribution plan (the “401k Plan”) which covers substantially all of its 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, 2005, 2004, and 2003 were $479,868, $512,220, and $568,133, 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. Our 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 our 401k Plan consists of an Employee Stock Ownership Plan (“ESOP”) that covers most of our employees. The ESOP receives contributions of our 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 our common stock. The Company made no contributions for the fiscal years ended June 30, 2005, 2004 and 2003. 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 our stock valued at $20,185, $21,750, and $24,686 in fiscal year 2005, 2004, and 2003, respectively.
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2005 and 2004 and for the years ended June 30, 2005, 2004, and 2003:
A one-percentage-point increase in the assumed health care cost trend rate would increase interest and service cost by $5,200 and the accumulated postretirement benefit obligation by $45,000. A
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
one-percentage-point decrease in the assumed health care cost trend rate would decrease interest and service cost by $4,200 and the accumulated postretirement benefit obligation by $38,400.
Included in the postretirement benefit expense amounts were $63,553 in 2005, $55,100 in 2004 and $40,260 in 2003 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 our contributions are made.
9.
Income Taxes
Significant components of our deferred tax assets and liabilities as of June 30, 2005 and 2004 are as follows:
As of June 30, 2004, the Company had a federal net operating loss of approximately $930,000 which was carried back to fiscal year ended June 30, 2002.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Income tax expense (benefit) for the years ended June 30, 2005, 2004, and 2003 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
The results of our regulated and unregulated propane business are analyzed by our chief operating decision maker together, and decisions on how to allocate resources and assess performance is done for the combined regulated and unregulated operations taken as a whole.
The unregulated and the regulated business use the same officers and employees, use essentially the same assets, are managed together at the same location and management does not believe that the unregulated business could be satisfactorily analyzed for performance without consideration of the regulated component. Therefore, the results of the two components are combined by management prior to assessing performance. By combining the regulated and unregulated components, we are providing the user of the financial statement the view of the business through management’s eyes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Summarized financial information for our 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:
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
11.
Stock Option and Shareholder Rights Plans
2002 Stock Option Plan - The Energy West Incorporated 2002 Stock Option Plan (the “Option Plan”) provides for the issuance of up to 200,000 shares of our common stock to be issued to certain key employees. As of June 30, 2005, there are 126,000 options outstanding and the maximum number of shares available for future grants under this plan is 74,000 shares. Additionally, our 1992 Stock Option Plan (the “1992 Option Plan”), which expired in September 2002, provided for the issuance of up to 100,000 shares of our common stock pursuant to options issuable to certain key employees. Under the
ENERGY WEST, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 100% of the fair market value if the employee owns more than 10% of our outstanding common stock) Pursuant to the Option Plans, the options vest over four to five years and are exercisable over a five to ten-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.
SFAS No. 123 Disclosures - We have adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock-Based Compensation. See Note 1 for the related pro forma disclosures, in accordance with SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. The following assumptions were applied for the SFAS No. 123 disclosure-only provision information included in Note 1.
For purposes of the pro forma disclosures, the fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions for the years ended June 30, 2005 and 2004, respectively; no expected dividends, volatility of 54%; risk-free interest rate of 3.9%; and expected lives of four to ten years. A summary of the status of our stock option plans as of June 30, 2005, 2004 and 2003, and changes during the years ended on these dates is presented below.
The weighted average fair value of options granted during the years ended June 30, 2005, 2004, and 2003 was $2.99, $0, $1.62. The fair value of the options granted was determined using the Black-Scholes model with the following weighted-average assumptions for fiscal 2005: expected life of 9.15 years, interest rate of 3.9%, volatility of 54% and no dividend yield.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following information applies to options outstanding at June 30, 2005:
Shareholder Rights - On June 3, 2004, our Board of Directors declared a dividend of one Right to purchase one one-thousandth share of our 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 our common stock or commences a tender or exchange offer upon consummation of which such person or group would beneficially own 15% or more of our common stock. Any person or group owning 15% or more of our 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, 2005 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2005, 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, 2005, the Company had recovered approximately $1,512,000 through such surcharges. As of June 30, 2005, the cost remaining to be recovered is $413,000.
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 have been 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
January 1, 2004. The Company has since obtained 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, 2005, 2004, and 2003 totaled $142,599, $171,765, and $189,906, respectively.
Letters of Credit - Outstanding letters of credit totaled $0 and $1,700,000 at June 30, 2005 and 2004, respectively. The letters of credit guarantee our 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 our 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 our 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 our 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.”
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2005, these agreements were reflected on our consolidated balance sheet as derivative assets and liabilities at an approximate fair value as follows:
14.
Subsequent Events
On September 15, 2005, LaSalle Bank proposed terms for an extension of our existing credit facilities. However the proposal is not a commitment by the Bank and should not be relied on as such. Final approval for the credit renewal is subject to approval by the Bank’s Loan Committee.
Energy West reached agreement on September 20, 2005 with Tenaska Marketing Ventures and Jefferson Energy Trading to supply its regulated natural gas customers in Montana for the period of November 2005 through October 2006. The full requirements contract is for both the commodity and services needed to supply approximately 3.2 Bcf of natural gas to Energy West’s regulated gas customers in Montana.
15.
Prior Year 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 our 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 consolidated financial statements as of June 30, 2003 and for the fiscal year ended then were restated in the prior year from amounts previously reported to reflect
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the correction of the accounting and valuation of the gas purchase and gas sale contracts discussed above. Although not present in the table that follows, the June 30, 2002 financial statements were also restated in the prior year.
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:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
16.
Quarterly Information (Unaudited)
Quarterly results (unaudited) for the years ended June 30, 2005 and 2004 including the effect of the restatement of the first three quarters of year 2004 are as follows (in thousands, except per share data):
EXHIBIT INDEX