Item 1. Business
THE UNITIL SYSTEM
Unitil Corporation (Unitil or the Company) was incorporated under the laws of the State of New Hampshire in 1984. Unitil is a registered public utility holding company under the Public Utility Holding Company Act of 1935 (the 1935 Act), and is the parent company of the Unitil System. The following companies are wholly owned subsidiaries of Unitil, which together make up the Unitil System:
Unitil Corporation
Subsidiaries
State and Year of Organization
Principal Type
of Business
Concord Electric Company (CECo)
NH - 1901
Retail Electric Distribution Utility
Exeter & Hampton Electric Company (E&H)
NH - 1908
Retail Electric Distribution Utility
Fitchburg Gas and Electric Light Company (FG&E)
MA - 1852
Retail Electric & Gas Distribution Utility
Unitil Power Corp. (Unitil Power)
NH - 1984
Wholesale Electric Power Utility
Unitil Realty Corp. (Unitil Realty)
NH - 1986
Real Estate Management
Unitil Service Corp. (Unitil Service)
NH - 1984
System Service Company
Unitil Resources, Inc. (Unitil Resources)
NH - 1993
Energy Brokering, Marketing and Services
Usource, Inc.
NH - 2000
Energy Brokering, Marketing and Services
Usource L.L.C. (Usource)
NH - 2000
Energy Brokering, Marketing and Services
The Unitil System's principal business is the retail sale and distribution of electricity and related services in several cities and towns in the seacoast and capital city areas of New Hampshire, and both electricity and gas and related services in north central Massachusetts, through Unitil's three wholly owned retail distribution utility subsidiaries (CECo, E&H and FG&E, collectively referred to as the Retail Distribution Utilities). The Company's wholesale electric power utility subsidiary, Unitil Power Corp., principally provides all the electric power supply requirements to CECo and E&H for resale at retail.
Unitil has three additional wholly owned subsidiaries: Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and Unitil Resources, Inc. (Unitil Resources). Unitil Realty owns and manages the Company's corporate office building and property located in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Service provides, at cost, centralized management, administrative, accounting, financial, engineering, information systems, regulatory, planning, procurement, and other services to the Unitil System companies. Unitil Resources is the Company's wholly owned non-utility subsidiary and has been authorized by the Securities and Exchange Commission, pursuant to the rules and regulations of the 1935 Act, to engage in business transactions as a competitive marketer of electricity, gas and other energy commodities in wholesale and retail markets, and to provide energy brokering, consulting and management related services within the United States. Usource, Inc. is a wholly owned subsidiary of Unitil Resources, Inc. Usource L.L.C. (Usource) is a wholly owned subsidiary of Usource, Inc. Usource provides an internet-based energy brokering service, as well as various energy consulting and marketing activities.
During 1999 and 2000, Unitil acquired an approximate 9% interest in Enermetrix (formerly known as North American Power Brokers, Inc.), a privately held company providing Internet technology solutions to the energy industry. Unitil, through Unitil Resources, has licensed and deployed the Enermetrix Internet-based technology for electricity and natural gas sales between consumers and suppliers. Under the name Usource, Unitil Resources offers retail energy consumers the market benefits of energy supply bidding with the efficiency and cost benefits of e-commerce.
UTILITY OPERATIONS
CECo is engaged principally in the distribution and sale of electricity at retail to approximately 27,400 customers in the City of Concord, which is the state capital, and twelve surrounding towns, all in New Hampshire. CECo's service area consists of approximately 240 square miles in the Merrimack River Valley of south central New Hampshire. The service area includes the City of Concord and major portions of the surrounding towns of Bow, Boscawen, Canterbury, Chichester, Epsom, Salisbury and Webster, and limited areas in the towns of Allenstown, Dunbarton, Hopkinton, Loudon and Pembroke.
The State of New Hampshire's government operations are located within CECo's service area, including the executive, legislative, judicial branches and offices and facilities for all major state government services. In addition, CECo's service area is a retail trading center for the north central part of the state and has diversified businesses relating to insurance, printing, electronics, granite, belting, plastic yarns, furniture, machinery, sportswear and lumber. Of CECo's 2000 retail electric revenues, approximately 34% were derived from residential sales, 40% from commercial, government and nonmanufacturing sales, 25% from industrial/manufacturing sales and 1% from other sales.
E&H is engaged principally in the distribution and sale of electricity at retail to approximately 40,500 customers in the towns of Exeter and Hampton and in all or part of sixteen surrounding towns, all in New Hampshire. E&H's service area consists of approximately 168 square miles in southeastern New Hampshire. The service area includes all of the towns of Atkinson, Danville, East Kingston, Exeter, Hampton, Hampton Falls, Kensington, Kingston, Newton, Plaistow, Seabrook, South Hampton and Stratham, and portions of the towns of Derry, Brentwood, Greenland, Hampstead and North Hampton.
Commercial and industrial customers served by E&H are quite diversified and include retail stores, shopping centers, motels, farms, restaurants, apple orchards and office buildings, as well as manufacturing firms engaged in the production of sportswear, automobile parts and electronic components. It is estimated that there are over 150,000 daily summer visitors to E&H's territory, which includes several popular resort areas and beaches along the Atlantic Ocean. Of E&H's 2000 retail electric revenues, approximately 47% were derived from residential sales, 29% from commercial, government and nonmanufacturing sales, 21% from industrial/manufacturing sales and 3% from other sales.
FG&E is engaged principally in the distribution and sale of both electricity and natural gas in the City of Fitchburg and several surrounding communities. FG&E's service area encompasses approximately 170 square miles in north central Massachusetts.
Electricity is supplied and distributed by FG&E to approximately 26,100 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. FG&E's industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and allied industries. Of FG&E's 2000 electric revenues, approximately 36% were derived from residential sales, 26% from commercial and nonmanufacturing sales, 30% from industrial/manufacturing sales and 8% from other sales.
Natural gas is supplied and distributed by FG&E to approximately 14,800 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Of FG&E's 2000 gas operating revenues, approximately 49% were derived from residential sales, 11% from small general customers, 19% from medium general customers, 6% from large general customers, 11% from interruptible sales (which are sales to customers that have agreed to discontinue use of the Company-supplied gas service temporarily upon notice by the Company, and which customers usually have an alternate fuel capability, e.g., fuel oil, that they can employ during the interruption periods) and 4% from other sales. FG&E's industrial gas revenue is primarily derived from firm sales to paper manufacturing and paper products companies, fabricated metal products manufacturers, rubber and plastics manufacturers, and primary iron.
Natural gas sales in New England are seasonal, and the Company's results of operations reflect this seasonal nature. Accordingly, results of operations are typically positively impacted by gas operations during the five heating season months from November through March of the following year. Electric sales in New England are far less seasonal than natural gas sales; however, the highest usage typically occurs in the summer and winter months due to air conditioning and heating requirements, respectively. The Unitil System is not dependent on a single customer or a few customers for its electric and gas sales.
(For details on the Unitil System's Results of Operations see Part II, Item 7 herein.)
(For segment information see Part II, Item 8, Footnote 11 herein.)
RATES AND REGULATION
The Company is registered with the Securities and Exchange Commission (SEC) as a holding company under the 1935 Act, and it and its subsidiaries are subject to the provisions of the 1935 Act. Accordingly, the Securities and Exchange Commission (SEC) has jurisdiction over Unitil and its subsidiaries with respect to, among other things, securities issues, sales and acquisitions of securities and utility assets, intercompany loans, services performed by and for affiliated companies, certain accounts and records, and involvement in non utility operations. The Company and its subsidiaries, where applicable, are subject to regulation by the Federal Energy Regulatory Commission (FERC), the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (MDTE) with respect to rates, adequacy of service, issuance of securities, accounting and other matters. Unitil Power, as a wholesale utility, is subject to rate regulation by the FERC. Both CECo and E&H, as retail electric utilities in New Hampshire, are subject to rate regulation by the NHPUC, and FG&E is subject to MDTE regulation with respect to gas and electric retail rates, and FERC regulation with respect to New England Power Pool (NEPOOL) interchanges and other wholesale sales of electricity.
Current Rate Regulation - The revenues of Unitil's Retail Distribution Utilities are collected pursuant to rates on file with the NHPUC, the MDTE and, to a minor extent, the FERC. In general, the Retail Distribution Companies current retail rates are comprised of a base rate component, established during comprehensive base rate cases, and various periodic rate adjustment mechanisms, which track and reconcile particular expense elements with associated collected revenues. The last comprehensive regulatory proceedings to increase base electric rates for Unitil's Retail Distribution Utilities were in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. FG&E was granted its first Gas Base Rate adjustment in 14 years effective December 1, 1998. The majority of the Unitil System's utility operating revenues are presently collected under various rate adjustment mechanisms, including revenues collected from customers for fuel, purchased power, cost of gas, transition costs and demand-side management program costs.
The Unitil System Agreement (System Agreement), as approved by the FERC, governs wholesale sales by Unitil Power to its New Hampshire retail distribution affiliates, CECo and E&H, and provides for recovery by Unitil Power of all costs incurred in the provision of service. Unitil Power has continued to adjust its wholesale rates every six months in accordance with the System Agreement, and CECo and E&H have continued to file corresponding semiannual changes in their retail fuel and purchased power adjustment clauses with the NHPUC which have been routinely approved.
The Massachusetts Electric Restructuring Law has changed the way FG&E provides service to its electric customers. Instead of supplying energy on demand to all its customers, FG&E delivers energy to its customers on behalf of competitive suppliers and will supply Standard Offer Service energy to customers who do not choose a competitive supplier and Default Service to new customers or those whose competitive supplier terminates. The result of these changes was the replacement of FG& E's quarterly filed electric fuel charge with: a) an annually determined Standard Offer Service charge and reconciliation adjustment mechanism; and b) a semi-annual determined Default Service charge and reconciliation adjustment mechanism, both of which are designed to allow FG&E to recover all its power supply costs. In addition FG&E has implemented a Transition Cost Charge and reconciliation adjustment mechanism enabling it to recover its stranded costs (See Massachusetts (Electric) in Regulatory Matters section).
FG&E's gas costs are recovered through a cost of gas adjustment (CGA) mechanism, through which firm gas customers pay the costs incurred for procuring and transporting gas to FG&E's local distribution system for delivery to customers.
SFAS No. 71 - The Company accounts for all its regulated operations in accordance with Statement of Financial Accounting Standard ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation," requiring the Company to record the financial statement effects of the rate regulation to which the Company is currently subject. If a separable portion of the Company's business no longer meets SFAS No. 71, the Company is required to eliminate the financial statement effects of regulation for that portion. (See "Power Supply Divestiture" in Note 8 of the financial statements contained herein.)
REGULATORY MATTERS
The Unitil System of Companies is regulated by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), and state regulatory authorities with jurisdiction over the utility industry, including the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In recent years, there has been significant legislative and regulatory activity to introduce greater competition in the supply and sale of electricity and gas, while continuing to regulate the delivery and distribution operations of our utility subsidiaries.
Massachusetts enacted comprehensive electric utility industry restructuring in November 1997. Since March 1, 1998, all electric consumers in Massachusetts served by investor-owned utilities have had the ability to choose their electric energy supplier. FG&E, the Company's Massachusetts utility operating subsidiary, continues to implement its comprehensive electric restructuring plan and divestiture of its entire regulated power supply business, including its nuclear investment.
Since 1997, FG&E has worked in collaboration with the other Massachusetts gas distribution utilities and various other stakeholders to develop and implement the infrastructure to offer gas customers choice of their competitive gas energy supplier and to complete the restructuring of gas service provided by gas utilities. FG&E filed with the MDTE new gas tariffs to implement natural gas unbundling in accordance with Model Terms and Conditions resulting from these collaborative efforts. The MDTE issued an Order approving these tariffs and final regulations effective November 1, 2000.
In New Hampshire, CECo and E&H, our electric utility operating subsidiaries, and Unitil Power Corp., our wholesale power company, continue to prepare for the transition that will move them into this new market structure, pending resolution of certain key restructuring policies and issues. The utility operating companies have also been active participants in the restructuring of the wholesale power market and transmission system in New England. Though retail competition in the sale of electricity has stalled throughout the region, new wholesale markets have been implemented in the New England Power Pool (NEPOOL) under the general supervision of an Independent System Operator (ISO).
Massachusetts Electric Restructuring - On January 15, 1999, the MDTE approved FG&E's restructuring plan with certain modifications. The Plan provides customers with: a) the ability to choose an energy supplier; b) an option to purchase Standard Offer Service provided by FG&E at regulated rates for up to seven years; and c) a cumulative 15% rate reduction adjusted for inflation. The Order also approved FG&E's power supply divestiture plan for its interest in three generating units and four long-term power supply contracts.
Pursuant to the Plan, on October 30, 1998, FG&E filed a proposed contract with Constellation Power Services Inc. for provision of Standard Offer Service. Constellation began to supply power under that contract on March 1, 1999, and is scheduled to continue through February 28, 2005. The award of this contract was the first successful Standard Offer auction conducted in Massachusetts.
A contract for the sale of FG&E's interest in the New Haven Harbor plant was approved by the MDTE on March 31, 1999, and the sale of the unit closed on April 14, 1999. A contract for the sale of the entire output from FG&E's remaining generating assets and purchased power contracts to Select Energy, Inc. was approved by the MDTE on December 28, 1999, and went into effect February 1, 2000.
On December 22, 1999, FG&E filed with the MDTE new rates for effect January 1, 2000. The revised rates maintain the required inflation-adjusted 15% rate discount. The MDTE approved the rates on January 5, 2000, subject to an examination of the Company's filing in which it reconciles its estimated and actual transition costs (the "reconciliation filing").
On February 2, 2000, the MDTE initiated a proceeding to examine FG&E's reconciliation filing and the consistency of the proposed charges and adjustments with the methods approved in FG&E's restructuring plan. The MDTE held four days of hearings in May 2000, and the Company presented testimony in support of its filing. As part of his review of FG&E's filing, the Massachusetts Attorney General has challenged FG&E's recovery of certain transition costs and other cost reconciliation calculations. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there could be an adverse impact on the Company's consolidated financial position.
As a result of restructuring and divestiture of FG&E's generation and purchased power portfolio, FG&E has accelerated the write-off of its electric generation assets and its abandoned investment in Seabrook Station. The MDTE established the return to be earned on the unamortized balance of FG&E's generation plant, reducing FG&E's earnings on those assets. In 2000, Unitil's earnings from this business segment represented approximately 16% of the earnings from utility operations. As this portfolio is amortized over the next 9 years, earnings from this segment of FG&E's utility business will continue to decline and ultimately cease.
On August 2, 2000, FG&E was the first electric company in Massachusetts to file for an increase in its Standard Offer Service rates pursuant to the Fuel Adjustment provision of its Standard Offer Service (SOS) tariff. This adjustment allows an increase in the SOS rate due to increases in the fuel prices of oil and natural gas. Any revenues received as a result of this adjustment are passed on to the Company's wholesale SOS provider. The MDTE suspended the filing for further review. Subsequently, other electric utility companies operating in Massachusetts made similar filings, and the MDTE instituted proceedings in each of those cases. On December 4, 2000, the MDTE issued an order for the utilities authorizing a "fixed" fuel adjustment, calculated based on the most recent 12 months of data. These adjustments took effect on January 1, 2001. FG&E's SOS rate increased from 3.8 cents/kWh to 5.121 cents/kWh. Unrecovered amounts to date will be recovered, subject to the rate reduction requirements of the Act.
In approving the new SOS rates, the MDTE also directed all electric distribution companies to file a report with the MDTE on their efforts to mitigate transition costs. On January 19, 2001, FG&E filed an extensive report detailing its mitigation activities, including contract restructurings, divestiture of its generating assets, and a variety of initiatives intended to reduce the burden of increasing energy prices on customers. While FG&E has substantially completed the divestiture of its generation assets, the Company continues to seek ways to reduce its transition costs and lower prices for customers.
On December 1, 2000, FG&E filed new electric rates for effect January 1, 2001. The revised rates maintain the required inflation-adjusted 15% rate discount. The MDTE approved final rates on December 29, 2000, subject to reconciliation pursuant to an investigation of actual and estimated transition costs, resulting in an upward inflation adjustment of 3.5% relative to 2000 rates.
New customers, and customers who previously opted to take electric supply service from a competitive provider, may purchase power through FG&E under Default Service. FG&E provides the Default Service through a third party supplier at market-based rates. The Company issued a Request for Proposals for Default Service in September 2000. FG&E awarded a contract and filed resulting rates which were approved effective for the period January through May 2001.
In June 2000, the MDTE opened an investigation into whether (1) metering, meter maintenance and testing, and customer billing and information services (MBIS) should be unbundled; and (2) the service territories of distribution companies should remain exclusive. On December 29, 2000, the MDTE issued its report recommending that the Legislature not take action to allow for the competitive provision of MBIS in the electric industry. The MDTE also concluded that exclusive service territories should remain intact.
Massachusetts Gas Restructuring - In mid-1997, the MDTE directed all Massachusetts natural gas Local Distribution Companies (LDCs) to form a collaborative with other stakeholders to develop common principles and appropriate regulations for the unbundling of gas service, and directed FG&E and four other LDCs to file unbundled gas rates for its review. FG&E's unbundled gas rates were filed with, and approved by, the MDTE and implemented in November 1998.
On February 1, 1999, the MDTE issued an order in which it determined that the LDCs would continue to have an obligation to provide gas supply and delivery services for another five years, with a review after three years. This order also set forth the MDTE's decision requiring mandatory assignment by LDCs of their pipeline capacity contracts to competitive marketers. In March 1999, the LDCs and other stakeholders filed a settlement with the MDTE, which set forth rules for implementing an interim firm transportation service through October 31, 2000. The MDTE approved the settlement on April 2, 1999. FG&E has made separate compliance filings that were approved by the MDTE to implement its interim firm gas transportation service for its largest general service customers and to complement this service with a firm gas peaking service. This interim service is now superseded by the permanent transportation service, which was approved for implementation on November 1, 2000.
On November 3, 1999, the Massachusetts LDCs filed Model Terms and Conditions for Gas Service, including provisions for capacity assignment, peaking service, and Default Service. In accordance with the MDTE's approval of these Model Terms and Conditions in January 2000, FG&E filed Company-specific tariffs that implement natural gas unbundling. The MDTE also opened a rulemaking proceeding on proposed regulations that would govern the unbundling of services related to the provision of natural gas. The MDTE has issued an order approving the tariffs and final regulations effective November 1, 2000.
New Hampshire Electric Restructuring - On February 28, 1997, the NHPUC issued its Final Plan for New Hampshire electric utilities to transition to a competitive electric market in the state (Final Plan). The Final Plan linked the interim recovery of stranded cost by the State's utilities to a comparison of their existing rates with the regional average utility rates. CECo's and E&H's rates are below the regional average; thus, the NHPUC found that CECo and E&H were entitled to full interim stranded cost recovery, as defined by the NHPUC. However, the NHPUC also made certain legal rulings which could affect CECo's and E&H's long-term ability to recover all of their stranded costs.
Northeast Utilities' affiliate Public Service Company of New Hampshire (PSNH) filed suit in U.S. District Court for protection from the Final Plan and related orders and was granted an indefinite stay. In June 1997, Unitil, and other utilities in New Hampshire, intervened as plaintiffs in the federal court proceeding. In June 1998, the federal court clarified that the injunctions issued by the court in 1997 had effectively frozen the NHPUC's efforts to implement restructuring. This amended injunction was challenged by the NHPUC, and affirmed by the First Circuit Court of Appeals. Unitil continues to be a plaintiff-intervenor in federal district court. Further court proceedings are pending final resolution of electric restructuring for PSNH.
Unitil has continued to work actively to explore settlement options and to seek a fair and reasonable resolution of key restructuring policies and issues in New Hampshire. The Company is also monitoring the regulatory and legislative proceedings dealing with electric restructuring in the state. In October 2000, the NHPUC approved a settlement for the restructuring of PSNH. Appeals of the PSNH restructuring orders were denied by the New Hampshire Supreme Court and are now being pursued with the U.S. Supreme Court.
Pending Rate Proceedings - The last formal regulatory filings to increase base electric rates for Unitil's three retail operating subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. A majority of the Company's operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas, energy efficiency, and restructuring-related cost recovery mechanisms. Industry restructuring will continue to change the methods of how certain costs are recovered through the Company's regulated rates and tariffs.
As discussed above, FG&E filed for and received approval of an increase to its electric Standard Offer Service rate reflecting extraordinary increases in the price of oil and natural gas. FG&E also received an increase to its Cost of Gas Adjustment resulting in bill increases of approximately 25%, effective November 1, 2000. FG&E subsequently received another increase of approximately 20% to its Cost of Gas Adjustment for effect February 1, 2001. Wholesale natural gas prices reached record levels in New England and across the United States in response to cold weather and tight supplies. In New Hampshire, CECo and E&H filed and received approval of increases to their Fuel and Purchased Power Adjustments, resulting in bill increases of 25% to 34%, depending upon usage patterns, effective January 1, 2001. These higher fuel costs are a pass-through without markup or profit. Retail electricity prices for most New England utilities are increasing this winter.
On May 15, 1998, FG&E filed a gas base rate case with the MDTE. The last base rate case had been in 1984. After evidentiary hearings, the MDTE issued an Order allowing FG&E to establish new rates, effective November 30, 1998, which would produce an annual increase of approximately $1.0 million in gas revenues. As part of the proceeding, the Massachusetts Attorney General alleged that FG&E had double-collected fuel inventory finance charges, and requested that the MDTE require FG&E to refund approximately $1.6 million in double collections since 1987. The Company believes that the Attorney General's claim is without merit and that a refund was not justified or warranted. The MDTE rejected the Attorney General's request and stated its intent to open a separate proceeding to investigate the Attorney General's claim. On November 1, 1999, the MDTE issued an Order of Notice initiating an investigation of this matter. Hearings were held in early 2000 and were reopened in November 2000 to hear new evidence. Supplemental testimony has been filed and additional hearings were held in February 2001.
On October 29, 1999, the MDTE initiated a proceeding to implement Performance Based Rate making (PBR) for all electric and gas distribution utilities in Massachusetts. PBR is a method of setting regulated distribution rates that provide incentives for utilities to control costs while maintaining a high level of service quality. Under PBR, a company's earnings are tied to performance targets, and penalties can be imposed for deterioration of service quality. On December 29, 1999, FG&E filed a petition with the MDTE for authority to defer for later recovery costs associated with its preparation of a PBR filing for its gas division and its participation in the MDTE-initiated generic gas and electric PBR proceedings. This petition and the MDTE's generic proceeding are pending. The Company is currently evaluating the impact, if any, that PBR would have on the Company's ability to continue applying the standards of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation."
On December 31, 1999, the Massachusetts Attorney General filed a complaint against FG&E requesting that the MDTE investigate the distribution rates, rate of return, and depreciation accrual rates for FG&E's electric operations in calendar year 1999. The MDTE opened a proceeding in November 2000, held a public hearing and procedural conference in December 2000, and subsequently issued a procedural schedule covering the period January through April 2001. Any order received from the MDTE would apply to the Company's rates prospectively and would not be retroactive. Management is unable to predict the outcome of this proceeding but an unfavorable result could have an adverse impact on the Company's consolidated financial position.
Millstone Unit No. 3 - FG&E has a 0.217% nonoperating ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which calls for increased NRC inspection attention. In March 1996, as a result of engineering evaluations, Millstone 3 was taken out of service. The NRC authorized the restart of Millstone 3 in June 1998.
During the period that Millstone 3 was out of service, FG&E continued to incur its proportionate share of the unit's ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E also incurred costs to replace the power that was expected to be generated by the unit. During the outage, FG&E incurred approximately $1.2 million in replacement power costs, and recovered those costs through its electric fuel charge, which is subject to review and reconciliation by the MDTE. Under existing MDTE precedent, FG&E's replacement power costs of $1.2 million could be subject to disallowance in rates.
In August 1997, FG&E, in concert with other non-operating joint owners, filed a demand for arbitration in Connecticut and a lawsuit in Massachusetts, in an effort to recover costs associated with the extended unplanned shutdown. Several preliminary rulings have been issued in the arbitration and legal cases, and both cases are continuing. On March 22, 2000, FG&E entered into a settlement agreement with the defendants under which FG&E will dismiss its lawsuit and arbitration claims. The settlement is generally similar to earlier settlements with the defendants, and three joint owners that own, in the aggregate, approximately 19% of the unit. The settlement provides for FG&E to receive an initial payment of $600,000 and other amounts contingent upon future events and would result in FG&E's entire interest in the unit being included in the auction of the majority interest, and certain of the minority interests, in Millstone 3, which is expected to be completed by 2001. Upon completion of the sale of Millstone 3, FG&E will be relieved of all residual liabilities, including decommissioning liabilities, associated with Millstone 3. FG&E expects to flow through the net proceeds of the settlement to its customers .
On September 8, 2000, Western Massachusetts Electric Company, New England Power Company, and FG&E together filed a Joint Petition requesting approval by the MDTE of the sale of their respective interests in Millstone Units 1, 2, and 3. The Companies also requested MDTE findings that the divested assets qualify as "eligible facilities" pursuant to Section 32 (c) of the Public Utility Holding Company Act of 1935. The MDTE approved the sale and certified the unit as an "eligible facility" on December 22, 2000. The parties to the sale transaction are currently awaiting other state and federal regulatory approvals for the final sale of the Millstone units.
ELECTRIC POWER SUPPLY
New England Power Pool - FG&E, UPC, CECo, and E&H are members of the New England Power Pool (NEPOOL). NEPOOL was formed to assure reliable operation of the bulk power system in the most economic manner for the region. Under the NEPOOL Agreement and the Open Access Transmission Tariff ("OATT"), to which virtually all New England electric utilities are parties, substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is performed on a regional basis. NEPOOL is governed by an agreement that is filed with the FERC and its provisions are subject to continuing FERC jurisdiction. The NEPOOL Agreement and the OATT imposes generating capacity and reserve obligations, provides for the use of major transmission facilities and payments associated therewith. The most notable benefits of NEPOOL are coordinated power system operation in a reliable manner and providing a supportive business environment for the development of a competitive electric marketplace.
There are ongoing legislative and regulatory initiatives that are primarily focused on the deregulation of the generation and supply of electricity and the corresponding development of a competitive market place from which customers could choose their electric energy supplier. As a result, the NEPOOL Agreement continues to be restructured. NEPOOL's membership provisions have been broadened to cover all entities engaged in the electricity business in New England, including power marketers and brokers, independent power producers, load aggregators and retail customers in states that have enacted retail access statutes. The regional bulk power system is operated by an independent corporate entity, ISO New England (ISO-NE), so that there is no opportunity for conflicting financial interests between the system operator and the market-driven participants. Various energy and capacity products are traded in open, competitive markets, with transmission access and pricing subject to a regional tariff (the OATT) designed to promote competition among power suppliers. On May 1, 1999, ISO-NE began dispatching generating units using a bid-based system and implemented bid-based markets for reserve products and automatic generation control.
Energy Resources - Since April 1, 1998, each electric utility is required to carry an allocated share of the NEPOOL capability responsibility under the NEPOOL Agreement. These capacity requirements are determined each month based on regional reliability criteria. Unitil Power Corp., the full requirements supplier to CECo and E&H, had an annual peak capability responsibility in November 2000 of 274.64 MW and a corresponding monthly peak demand of 184.44 MW. FG&E's capability responsibility has decreased substantially from a year ago due to a contract with Constellation Power Source for the Standard Offer Service Load within its distribution territory. FG&E's capability responsibility for November 2000 was 12.36 MW, with a corresponding monthly peak demand of 8.30 MW. Effective December 1, 2000, FG&E began serving Default Service Load through a six month contract wherein the Default Service supplier has the load serving obligation, thus at the end of 2000 FG&E had no direct capability responsibility. Under MDTE regulations, FG&E will continue to procure Default Service through a bid process every six to twelve months.
To meet the needs of CECo and E&H, Unitil Power Corp. has contracted for generating capacity and energy and for associated transmission services as needed to meet NEPOOL requirements and to provide a diverse and economical energy supply. Unitil Power's purchases are from various utility and non-utility generating units using a variety of fuels and from several utility systems in the U.S. and Canada as well as purchases in the spot market. For the twelve months ended December 31,2000, Unitil Power's energy needs were provided by the following fuel sources: nuclear (29%), oil (10%), gas (10%), coal (7%), refuse (4%), hydro (6%) and system (34%).
In 2000, FG&E met its capacity requirements through an all requirements Standard Offer contract with Constellation Power Source, a Default Service contract with Consolidated Edison Energy, Inc. in December, 2000, spot purchases, purchase power contracts and ownership interests in two generating units in which FG&E participates on a tenancy-in-common basis as a non-operating owner. FG&E's contract and jointly owned asset purchases are from various utility and non-utility generating units using a variety of fuels and from several utility systems in the U.S. and Canada. The power supply portfolio, including the joint ownership generation output, was sold to Select Energy, Inc. beginning February 1, 2000 as part of the power supply restructuring plan approved by the MDTE. For the twelve months ended December 31, 2000, FG&E's energy needs were met with a combination of output originating from the Standard Offer, all requirements service contract, the FG&E power portfolio for January 2000, spot and short-term purchase to cover Default Service needs from February through November and the Default Service all requirements contract in December. As a result of these purchases, FG&E's needs were met primarily by system power.
FG&E is participating, on a tenancy-in-common basis with other New England utilities, in the ownership of two generating units, Wyman 4 and Millstone 3. Wyman Unit No. 4 is an oil-fired station in Yarmouth Maine, which is operated by FPL Energy Maine, LLC as the majority owner, that has been in commercial operation since December 1978. Millstone Unit No. 3, a nuclear generating unit operated by Northeast Utilities, has been in commercial operation since April 1986. FG&E's ownership interest in Millstone 3 is scheduled to be sold during the first half of 2001. FG&E completed the sale of its principal generating asset, a 4.5% interest in New Haven Harbor Station, in March 1999. In accordance with Massachusetts Electric Restructuring Law, and pursuant to the power supply divestiture discussed in Note 8 of the Financial Statements, FG&E began selling the output from its generation units on February 1, 2000.
Fuel - Oil: Approximately 10% of UPC's electric power in 2000 was provided by oil-fired units. Most fuel oil used by New England electric utilities is acquired from foreign sources and is subject to interruption and price increases by foreign governments.
Coal: Approximately 7% of UPC's 2000 requirements were from coal-burning facilities. The facilities generally purchase their coal under long term supply agreements with prices tied to economic indices. Although coal is stored both on-site and by fuel suppliers, long term interruptions of coal supply may result in limitations in the production of power or fuel switching to oil and thus result in higher energy prices.
Nuclear: FG&E has a 0.217% ownership interest in Millstone Unit No. 3 (the Unit). The Unit has contracted for certain segments of the nuclear fuel production cycle through various dates. This cycle includes, among other things, mining, enrichment and disposal of used fuel.
Pursuant to the Nuclear Waste Policy Act of 1982, the participants in Millstone 3 were required to enter into contracts with the United States Department of Energy, prior to the operation of that Unit, for the transport and disposal of spent fuel at a nuclear waste repository. FG&E cannot predict whether the Federal government will be able to provide storage or permanent disposal repositories for spent fuel. FG&E's ownership interest is expected to be sold during the first half of 2001. The sales agreement and a separate settlement agreement with Northeast Utilities indemnifies FG&E from continuing liability associated with environmental, decommissioning and waste disposal associated with its Millstone 3 ownership.
GAS SUPPLY
FG&E distributes gas purchased from domestic and Canadian suppliers under long term contracts as well as gas purchased from producers and marketers on the spot market. The following tables summarize actual gas purchases by source of supply and the cost of gas sold for the years 1998 through 2000.
Sources of Gas Supply
(Expressed as percent of total MMBtu of gas purchased)
Cost of Gas Sold
Cost of gas purchased and sold per MMBtu
$5.19
$3.42
$3.36
Percent Increase (Decrease) from prior year
52.01%
1.74%
(14.08%)
As a supplement to pipeline natural gas, FG&E owns a propane air gas plant and a liquefied natural gas (LNG) storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.
ENVIRONMENTAL MATTERS
The Company continues to work with federal and state environmental agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E has proceeded with site remediation work as specified on the Tier 1B permit, which allows FG&E to work towards temporary remediation of the site.
In April 2000, FG&E applied for a Utility Related Abatement Measure (URAM) with the Massachusetts Department of Environmental Protection (DEP) to permit excavation work required to construct a new electric substation on FG&E's former MGP site at Sawyer Passway. The permit application was reviewed and approved by the Massachusetts DEP in May 2000. All work permitted under the provisions of the URAM was completed and a final report of closure was submitted to the DEP in December 2000.
Construction of the new highway bridge across Sawyer Passway began in October 2000. FG&E began fulfillment of obligations associated with the bridge construction as stipulated in a memorandum of understanding with the Massachusetts Highway Department and the Massachusetts DEP.
Upon completion of site remediation associated with the bridge construction, the last remaining portion of the Sawyer Passway MGP site is expected to be closed out and attain the status of temporary closure in late 2001. This temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed.
The costs of remedial action at this site are initially funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the MDTE. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site.
CAPITAL REQUIREMENTS
Cash Flows Used in Investing Activities increased approximately $7.1 million in 2000, primarily reflecting cash proceeds of $5.3 million received in 1999 from the sale of the Company's 4.5% interest in New Haven Harbor Station in 1999. Absent the effect of these 1999 sale proceeds, Cash Flows Used in Investing Activities increased $1.8 million in 2000 compared to 1999, reflecting higher expenditures of $2.8 million on distribution system additions and improvements and higher expenditures of $2.4 million for Usource software development and computer hardware. These higher expenditures were offset by a decrease in investment activity related to Enermetrix in 2000, compared to 1999.
Capital expenditures are projected to decrease in 2001 to approximately $18.5 million, primarily reflecting lower planned expenditures on the Company's non-regulated business activities.
FINANCING ACTIVITIES
Cash Flows from Financing Activities increased by $18.0 million in 2000 compared to 1999. This increase reflects a higher level of borrowing in 2000 versus 1999. During 2000, the Company used proceeds from short-term borrowings to fund a portion of its additions to Property, Plant, and Equipment; its non-regulated business activities; and a portion of its energy supply costs that exceeded amounts billed to customers via existing electricity and gas supply cost recovery mechanisms. This time lag between increases in energy costs and corresponding rate increases results in the Company incurring short-term debt to fund, on an interim basis, the Company's energy cost obligations.
At December 31, 2000, the Company had unsecured bank lines for short-term debt aggregating $35,000,000 with three banks for which it pays commitment fees. At December 31, 2000, the unused portion of the credit lines outstanding was $2,500,000. The average interest rates on all short-term borrowings were 6.57% and 5.72% during 2000 and 1999, respectively.
EMPLOYEES
As of December 31, 2000, the Company and its subsidiaries had 339 full-time and part-time employees. The Company considers its relationship with its employees to be good and has not experienced any major labor disruptions since the early 1960's.
There are approximately 100 employees represented by labor unions. In 2000, E&H reached a new five-year pact with its employees covered by a collective bargaining agreement, which will expire effective May 31, 2005. In 2000, CECo reached a new five-year pact with its employees covered by a collective bargaining agreement, which will expire effective May 31, 2005. In 2000, FG&E reached a five-year pact with its employees covered by collective bargaining agreements, which will expire effective May 31, 2005. The agreements provided for discreet salary adjustments, established work practices and provided uniform benefit packages. The Company expects to successfully negotiate new agreements prior to the expiration dates of these contracts.
The Company and its subsidiaries, where applicable, have in force funded Retirement Plans and related Trust Agreements providing retirement annuities for participating employees at age 65. The Company's policy is to fund the pension cost accrued (see Note 9 of Notes to Consolidated Financial Statements contained in Part II, Item 8). The Company maintains two stock option plans, which provide for the granting of options to key employees, as follows: (see Note 2 of Notes to Consolidated Financial Statements contained in Part II, Item 8).
Unitil Corporation Key Employee Stock Option Plan: The "Unitil Corporation Key Employee Stock Option Plan" was a 10-year plan which began in March 1989. The number of shares granted under this plan, as well as the terms and conditions of each grant, were determined by the Board of Directors, subject to plan limitations. All options granted under this plan vested upon grant. The 10-year period in which options could be granted under this plan expired in March 1999. The expiration date of the remaining outstanding options is November 3, 2007. The plan provides dividend equivalents on options granted, which are recorded at fair value as compensation expense.
Unitil Corporation 1998 Stock Option Plan: The "Unitil Corporation 1998 Stock Option Plan" became effective on December 11, 1998. The number of shares granted under this plan, as well as the terms and conditions of each grant, are determined by the Board of Directors, subject to plan limitations. All options granted under this plan vest over a three-year period from the date of the grant with 25% vesting on the first anniversary of the grant, 25% vesting on the second anniversary, and 50% vesting on the third anniversary. Under the terms of this plan, key employees may be granted options to purchase the Company's common stock at no less than 100% of the market price on the date the option is granted. All options must be exercised no later than 10 years after the date on which they were granted.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of the Company as of March 1, 2001 are listed below, along with a brief account of their business experience during the past five years. All officers are elected annually by the Board of Directors at the Directors' first meeting following the annual meeting, which is held on the third Thursday in April, or at a special meeting held in lieu thereof. There are no family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was selected. Officers of the Company also hold various Director and Officer positions with subsidiary companies.
Name, Age
and Position
Business Experience
During Past 5 years
Robert G. Schoenberger, 50,
Chairman of the Board of Directors
and Chief Executive Officer
Mr. Schoenberger has been Chairman of the Board and Chief Executive Officer of Unitil since 1997. Prior to his employment with Unitil, Mr. Schoenberger was President and Chief Operating Officer at New York Power Authority (NYPA) from 1993 until 1997.
Michael J. Dalton, 60,
President and
Chief Operating Officer
Mr. Dalton has been a Director, President and Chief Operating Officer of the Company since its incorporation in 1984.
Anthony J. Baratta, Jr., 57,
Senior Vice President
And
Chief Financial Officer
Mr. Baratta has been Senior Vice President and Chief Financial Officer of Unitil since 1998. Prior to his employment with Unitil, Mr. Baratta was Executive Vice President and Chief Financial Officer at New World Power Corporation.
Mark H. Collin, 42,
Treasurer and Secretary and
Vice President, Unitil Service
Mr. Collin was appointed Treasurer and Secretary in January 1998. Mr. Collin has been the System subsidiary Treasurer and Vice President of Unitil Service Corp. since 1992.
George R. Gantz, 49
Senior Vice President
Business Development Unitil Service
Mr. Gantz has been Senior Vice President of Unitil Service since 1994.
Item 2.
Item 2. Properties
CECo's distribution service center building and adjoining administration building, totaling 37,560 square feet of office, warehouse and garage area, are located on land in the City of Concord owned by CECo in fee. CECo's sixteen electric distribution substations constitute 114,290 kVA of capacity for the transformation of electric energy from the 34.5 kV transmission voltage to primary distribution voltage levels. The electric substations are, with one exception, located on land owned by CECo in fee. The sole exception is located on land occupied pursuant to a perpetual easement.
CECo has in excess of 34 pole miles of 34.5 kV electric transmission facilities located, with minor exceptions, either on land owned by CECo in fee or on land occupied pursuant to perpetual easements. CECo also has a total of approximately 649 pole miles of overhead electric distribution lines and a total of approximately 44 conduit bank miles (124 cable miles) of underground electric distribution lines. The electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by CECo without objection by the owners. In the case of certain distribution lines, CECo owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telephone and telegraph companies.
Additionally, CECo owns in fee 137.7 acres of land located on the east bank of the Merrimack River in the City of Concord. Of the total acreage, 81.2 acres are located within an industrial park zone, as specified in the zoning ordinances of the City of Concord.
The physical properties of CECo (with certain exceptions) and its franchises are subject to the lien of its Indenture of Mortgage and Deed of Trust, as supplemented, under which the respective series of First Mortgage Bonds of CECo are outstanding.
E&H's distribution and engineering service center building is located on land owned by E&H in fee. E&H's fourteen electric distribution substations, including a 5,000 kVA mobile substation, constitute 91,400 kVA of capacity for the transformation of electric energy from the 34.5 kV transmission voltage to primary distribution voltage levels. The electric substations are located on land owned by E&H in fee.
E&H has in excess of 68 pole miles of 34.5 kV electric transmission facilities located on land either owned or occupied pursuant to perpetual easements. E&H also has a total of approximately 744 pole miles of overhead electric distribution lines and a total of approximately 120 conduit bank miles of underground electric distribution lines. The electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by E&H without objection by the owners. In the case of certain distribution lines, E&H owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telephone and telegraph companies.
Certain physical properties of E&H and its franchises are subject to the lien of its Indenture of Mortgage and Deed of Trust, as supplemented, under which the respective series of First Mortgage Bonds of E&H are outstanding.
FG&E owns a liquid propane gas plant and a liquid natural gas plant, both of which are located on land owned in fee. FG&E is participating, on a tenancy-in-common basis with other New England utilities, in the ownership of two generating units. In accordance with Massachusetts Electric Restructuring Law, and pursuant to the power supply divestiture discussed in Note 8 of the Financial Statements, FG&E began selling the output from its generation units on February 1, 2000. At December 31, 2000, the electric properties of the Company consisted principally of 42 miles of transmission lines, 18 transmission and distribution substations, including two mobile substations of 18.75-kVA total capacity, constitute a total capacity of 475,650 kVA and 479.04 miles of distribution lines. Electric transmission facilities (including substations) and steel, cast iron and plastic gas mains owned by the Company are, with minor exceptions, located on land owned by the Company in fee or occupied pursuant to perpetual easements. The Company leases its service building. (See Business - Electric Power Supply and Gas Supply above for additional information regarding the Company's plants, facilities and gas mains and services.)
Unitil Realty owns the Company's corporate headquarters building and 12 acres of land in fee, which is located in the town of Hampton, New Hampshire. The Company believes that its facilities are currently adequate for its intended uses.
Item 3.
Item 3. Legal Proceedings
The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. In the opinion of the Company's management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company's financial position.
Item 4
Item 4 Submission of Matters to a Vote of Security Holders
None
PART II
Item 5
Item 5 Market for Registrant's Common Equity and Related Stockholder Matters
Common Stock Data
Item 6.
Item 6. Selected Financial Data
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
EARNINGS AND DIVIDENDS
Diluted Earnings per Share were $1.47 for the year ended December 31, 2000, compared to $1.74 and $1.72 for the years ended 1999 and 1998, respectively. As shown in the table below, in 2000, utility operations contributed $1.82 per share, while non-regulated operations lost $0.35 per share related to planned start-up costs of the Company's e-commerce business, Usource. Contributing positively to the Company's utility operations earnings is a slight increase in distribution revenues, offset by higher Depreciation and Amortization and Nonoperating Expenses. The Usource loss was the result of planned expenditures for sales, marketing, and product development. In 1999, utility operations contributed $1.84 per share, while Usource operations lost $0.10 per share.
Diluted Earnings per Share
Utility Operations
$1.82
$1.84
$1.72
Usource
($0.35)
($.10)
-
Total Company
$1.47
$1.74
$1.72
Net Income applicable to Common Stock for the year ended December 31, 2000, was $7.0 million, compared to $8.2 million and $8.0 million for years ended 1999 and 1998, respectively. The average return on common equity was 8.8%, 10.6%, and 10.9% in 2000, 1999, and 1998, respectively. The lower net income and average return on common equity in 2000 primarily reflects the impact on current income of the Company's expenditures on Usource.
Unitil's annual common stock dividend in 2000 was $1.38 per share. This annual dividend of $1.38 in 2000 resulted in a payout ratio of 94% for the year. Excluding the loss from non-regulated operations, the payout was 76% on earnings from utility operations. At its January 2001 meeting, the Unitil Board of Directors declared a regular quarterly dividend on the Company's common stock of $0.345 per share. This quarterly dividend reflects the current annual dividend rate of $1.38 per share.
THE YEAR IN REVIEW
In 2000, Unitil Corporation remained proactive in managing the challenges of industry restructuring and volatile energy markets, while pursuing opportunities in the e-commerce sector through our investment in Enermetrix and the companion start-up of Usource, our energy-related e-commerce marketplace. Our distribution companies continued to address the changing regulatory environment in Massachusetts and New Hampshire. At the same time, we have devoted significant resources to developing and implementing strategies to grow Usource and create future value for shareholders. The higher and more volatile energy prices experienced during 2000 resulted in higher commodity prices for our utility customers and lower-than-expected transaction volume for Usource.
Utility restructuring in Massachusetts continues to move forward. A significant development for our Massachusetts subsidiary, Fitchburg Gas & Electric Light Company (FG&E), was the settlement of its claims against Northeast Utilities (NU) for damages related to the shutdown of Millstone 3 Nuclear Unit (see Regulatory Matters, page 25). A major benefit of the settlement was the inclusion of FG&E's minority interest in the sale of Millstone 3 and the elimination of further decommissioning funding and liability for FG&E. The Millstone 3 sale, expected to be completed in 2001, is another step in the divestiture of FG&E's generation assets and marks the Company's exit from the nuclear power business. FG&E also filed with the Massachusetts Department of Telecommunications and Energy (MDTE) new gas tariffs to implement natural gas unbundling, which became effective November 1, 2000. The Company continues to monitor the regulatory and legislative proceedings dealing with electric restructuring in New Hampshire, and to develop plans for the transition to a competitive electric market.
The volatility of the wholesale energy markets for electric and natural gas energy commodities during 2000 resulted in increased electricity and gas supply costs to the Company and our customers. The energy costs incurred by the Company to procure electricity and natural gas on behalf of its customers are reconciled and recovered through regulated cost recovery adjustment mechanisms with no markup or profit margin. However, these increases in power and gas supply costs resulted in significantly higher working capital requirements and short-term borrowing in 2000, reflecting the inherent lag in the regulatory cost recovery process. By carefully tracking the energy markets, and obtaining timely decisions to adjust retail prices to match rising wholesale costs, Unitil has avoided the creation of a sustained gap between wholesale prices and retail rates. These rate adjustments have allowed the Company to begin recovering the higher energy supply costs from our customers, and to improve the Company's cash flow and credit position. At the same time, the Company has stepped up its efforts to reach out to its electric and gas customers with information about financial assistance, bill payment options, and energy conservation.
The volatile conditions in energy markets, particularly the significant increase in electricity and natural gas prices during the second half of the year, have also impacted Usource, resulting in evolving and expanded strategies. The Usource business model strategy calls for combining direct customer contact through its sales force and on-line e-commerce access (usourceonline.com)
to provide a "Total Energy Solutions" approach for prospective customers. Our efforts during the second half of 2000 were focused on refining this strategy and accelerating technology to launch an updated version of the new platform in January 2001.
USOURCE
In the fourth quarter of 1999, Unitil Corporation launched a new start-up business, Usource (usourceonline.com), with the mission to be "a national leader, through our Internet-based marketplace, in providing customers with choice and control over their energy procurement and with a portfolio of related products and services." The Usource business strategy is based on a very simple goal - to meet business customers' need of accessing and managing the increasingly tumultuous energy markets for electricity and natural gas procurement.
Through December 31, 2000, Usource recorded a net loss of $1.7 million compared to a net loss of $0.5 million for partial year 1999. The earnings per share impact of the Usource loss was $0.35 compared to a loss of $0.10 for the 1999 partial year of operations. Pursuant to brokerage activities in 2000, approximately 5.5 billion cubic feet of natural gas were delivered, which generated revenues of $0.1 million.
Capital Expenditures related to Usource development totaled $3.1 million in 2000, versus $0.7 million in 1999. The $3.1 million for 2000 includes $2.8 million for software development and computer equipment and $0.3 million for customer list acquisitions (see Note 11, Usource).
OPERATING REVENUES-ELECTRIC
Unit (kWh) Sales - Unitil's total electric kilowatt-hour (kWh) sales decreased by 1.3% in 2000 compared to 1999. This decrease reflects the loss of a major customer that ceased operations in the second quarter of 2000, and a cooler-than-normal summer in 2000. Absent the loss of this major customer, total kWh sales in 2000 were flat compared to 1999. This primarily reflects continued growth in the number of customers served by the Company, offset by a cooler-than-normal summer season in 2000.
Sales to residential customers increased by 0.8% in 2000 compared to 1999, and were 6.5% higher than 1998 sales. The slight increase in energy sales in 2000, as compared to 1999, was due to a 1.4% increase in the number of residential customers that the Company serves, offset by lower usage of electricity for cooling purposes during the summer. This summer was cooler than normal. The 6.5% increase in 2000 as compared to 1998 is the result of a 2.5% increase in residential customers, as well as a colder winter heating season in 2000.
Commercial and Industrial sales of electricity were down 2.5% in 2000 compared to 1999, primarily related to the shutdown in June 2000, of a major customer. Exclusive of this customer, Commercial and Industrial sales were flat compared to the prior year, reflecting the cooler summer weather in 2000. 2000 sales were higher by 1.2% compared to 1998, reflecting a healthy regional economy offset by a reduction in sales to the customer discussed above.
The following table details total kilowatt-hour sales for the last three years by major customer class:
kWh Sales (000's)
Residential
576,524
571,694
541,492
Commercial/Industrial
1,011,012
1,037,130
999,476
Total kWh Sales
1,587,536
1,608,824
1,540,968
Electric Operating Revenue increased by $5.9 million, or 3.9%, in 2000 compared to 1999. This increase in revenue is a result of increased fuel and energy supply prices, offset by decreased sales volume. The energy component of electric operating revenue represents the recovery of energy supply costs, which are collected from customers through periodic cost recovery adjustment mechanisms. Changes in energy supply prices do not affect net income, as they normally mirror corresponding changes in energy supply costs. In addition, an approximate $0.3 million decrease in revenue was recorded in the year 2000 related to an Order by the MDTE disallowing certain revenues associated with Conservation and Load Management programs subsequent to the March 1998 implementation of electric utility industry restructuring in Massachusetts.
The following table details total electric operating revenue for the last three years by major customer class:
Electric Operating Revenue (000's)
Residential
$61,506
$58,415
$57,242
Commercial/Industrial
98,517
95,662
92,397
Total Operating Revenue
$160,023
$154,077
$149,639
OPERATING REVENUES-GAS
Unit (Therm) Sales - Total firm therm gas sales increased 8.4% in 2000 when compared to 1999, due to a colder winter heating season compared to the prior year, coupled with higher sales volume, due to the Company's gas marketing initiatives. Total firm therm sales increased 8.9% in the two-year period from 1998 to 2000
The following table details total firm therm gas sales for the last three years, by major customer class:
Firm Therm Sales (000's)
Residential
11,730
10,980
11,656
Commercial/Industrial
12,262
11,156
10,371
Total Firm Therm Sales
23,992
22,136
22,027
Gas Operating Revenues, which represent approximately 12% of Unitil's total operating revenues, increased by $4.6 million, or 25.6%, in 2000 compared to 1999. This increase was attributable to higher unit sales, as well as increased gas supply prices.
The following table details total gas operating revenue for the last three years, by major customer class:
Gas Operating Revenue (000's)
Residential
$11,540
$8,635
$8,581
Commercial/Industrial
8,745
7,148
6,259
Total Firm Gas Revenue
20,285
15,783
14,840
Interruptible Gas Revenue
2,471
2,333
2,169
Total Gas Revenues
$22,756
$18,116
$17,009
OPERATING REVENUES-OTHER
Other Revenue was flat in 2000 compared to 1999. This was the result of a decrease in revenue generated from consulting activities, offset by an increase in revenues from the Company's e-commerce business, Usource.
OPERATING EXPENSES
Fuel and Purchased Power expense is the cost of power supply, including fuel used in electric generation and the price of wholesale energy and capacity, that meets Unitil's electric energy requirements. Fuel and purchased power expenses, normally recoverable from customers through periodic cost recovery adjustment mechanisms, increased $8.1 million, or 7.9%, in 2000 compared to 1999. The change was driven by an increase in wholesale power prices, as the nation experienced volatile markets and rising energy prices in 2000.
Gas Purchased for Resale reflects gas purchased and manufactured to supply the Company's total gas energy requirements. Gas supply costs are recoverable from customers through the Cost of Gas Adjustment mechanism. Purchased Gas costs increased by $3.6 million or 36.9% in 2000 compared to 1999, reflecting an increase in therms purchased and significantly higher wholesale gas prices in 2000.
Operation and Maintenance expense includes electric and gas utility operating costs, and the operating cost of the Company's non-regulated business activities. Total Operating and Maintenance expense was relatively flat in 2000 compared to 1999. Utility Operations accounted for a net decrease of $0.4 million, reflecting effective cost management and business process improvements. Usource Operating and Maintenance expense increased by $0.6 million in 2000 compared to 1999, reflecting planned sales, marketing, and product development expenditures.
DEPRECIATION, AMORTIZATION AND TAXES
Depreciation and Amortization expense increased $0.6 million, or 4.8%, in 2000 compared to 1999, due to a higher level of Plant in Service and accelerated write-off of electric generating assets, due to electric utility industry restructuring in Massachusetts. The electric generating assets will be fully amortized in approximately nine years. In addition, the Company has incurred higher depreciation and amortization expenses related to Usource in 2000 compared to 1999.
Federal and State Income Taxes decreased by $0.6 million, or 15.7%, in 2000 compared to 1999. This result reflects lower net income before taxes and a lower level of Investment Tax Credit amortization.
Local Property and Other Taxes decreased $0.1 million, or 2.2%, in 2000 compared to 1999. This decrease was related to local property tax changes.
INTEREST EXPENSE
Interest Expense, Net decreased $0.1 million, or 1.4%, in 2000 compared to the prior year. Higher short-term borrowing rates and a higher level of debt outstanding were offset by an increase in accrued interest income associated with deferred rate recovery mechanisms.
INVESTMENTS
During 1999 and 2000, Unitil acquired an approximate 9% equity interest in Enermetrix, formerly known as North American Power Brokers, Inc. The total investment is recorded "at cost" on the balance sheet as Other Property and Investments and is approximately $5.4 million. Enermetrix is a privately held company that has been financed by four rounds of private equity capital. Unitil has participated in three of these rounds of financing. Enermetrix, a software provider and technology enabler, developed an Internet-based energy procurement bid system, the Enermetrix Network, that matches buyers and sellers of energy in competitive markets. Unitil is represented on the Enermetrix board of directors. Although the market value of the investment in Enermetrix stock is not readily determinable, management believes the fair value of this investment currently exceeds its cost.
CAPITAL REQUIREMENTS AND LIQUIDITY
Unitil requires capital for the addition of property, plant, and equipment in order to improve, protect, maintain, and expand its electric and gas distribution systems, and to pursue its non-regulated business initiatives and opportunities. The capital necessary to meet these requirements has been derived primarily from the Company's retained earnings and sale of shares of common stock through the Company's Dividend Reinvestment and Stock Purchase plans. When internally generated funds are not available, it is the Company's policy to borrow funds on a short-term basis to meet the capital requirements of its subsidiaries and, when necessary, to repay short-term debt through the issuance of long-term debt financing.
Cash Flows from Operating Activities decreased by $9.4 million in 2000, after increasing by $5.1 million in 1999. The decrease in 2000 was primarily a result of higher levels of Accrued Revenues, due to higher energy costs not immediately collected from customers. Also contributing to the decrease were higher levels of Accounts Receivable and Deferred Taxes.
Cash Flows from Operating Activities have been negatively impacted by volatile energy markets. There is an inherent lag between the period when energy costs increase and the period when the Company is granted rate increases to offset those higher energy costs. This lag results in the Company having to pay its suppliers for the higher energy costs while collecting less than those costs from its customers. During the collection lag period, the Company's cash flow is negatively impacted and additional short-term borrowings are necessary.
Operating Activities
(000's)
Cash Provided by Operating Activities
$8,864
$18,308
$13,215
Cash Flows Used in Investing Activities increased approximately $7.1 million in 2000, primarily reflecting cash proceeds of $5.3 million received in 1999 from the sale of the Company's 4.5% interest in New Haven Harbor Station in 1999. Absent the effect of these 1999 sale proceeds, Cash Flows Used in Investing Activities increased $1.8 million in 2000 compared to 1999, reflecting higher expenditures of $2.8 million on distribution system additions and improvements and higher expenditures of $2.4 million for Usource software development and computer hardware. These higher expenditures were offset by a decrease in investment activity related to Enermetrix in 2000, compared to 1999.
Capital expenditures are projected to decrease in 2001 to approximately $18.5 million, primarily reflecting lower planned expenditures on the Company's non-regulated business activities.
Investing Activities
(000's)
Cash Used in Investing Activities
($22,249)
($15,131)
($14,463)
Cash Flows from Financing Activities increased by $18.0 million in 2000 compared to 1999. This increase reflects a higher level of borrowing in 2000 versus 1999. During 2000, the Company used proceeds from short-term borrowings to fund a portion of its additions to Property, Plant, and Equipment; its non-regulated business activities; and a portion of its energy supply costs that exceeded amounts billed to customers via existing electricity and gas supply cost recovery mechanisms. This time lag between increases in energy costs and corresponding rate increases, as discussed previously, results in the Company incurring short-term debt to fund, on an interim basis, the Company's energy cost obligations.
Concord Electric Company (CECo) and Exeter & Hampton Electric Company (E&H) received regulatory approval to increase fuel and purchased power rates as of January 1, 2001. FG&E received regulatory approval for an increase on November 1, 2000, in its Cost of Gas Adjustment Charge (CGAC), followed by a second increase on February 1, 2001. FG&E also received regulatory approval for an increase in its fuel index adjustment under its Standard Offer Service tariff to electric customers, effective on January 1, 2001. These rate increases are expected to ease the need for higher levels of short-term borrowings.
During 2000, the Company raised $0.6 million of additional common equity capital through the issuance of 22,916 shares of common stock in connection with the Dividend Reinvestment and Stock Purchase plans. No options were exercised in 2000 under the Company's Key Employee Stock Option Plan (KESOP).
Financing Activities
(000's)
Cash from Financing Activities
$13,598
($4,413)
$2,994
REGULATORY MATTERS
The Unitil System of Companies is regulated by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), and state regulatory authorities with jurisdiction over the utility industry, including the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In recent years, there has been significant legislative and regulatory activity to introduce greater competition in the supply and sale of electricity and gas, while continuing to regulate the delivery and distribution operations of our utility subsidiaries.
Massachusetts enacted comprehensive electric utility industry restructuring in November 1997. Since March 1, 1998, all electric consumers in Massachusetts served by investor-owned utilities have had the ability to choose their electric energy supplier. FG&E, the Company's Massachusetts utility operating subsidiary, continues to implement its comprehensive electric restructuring plan and divestiture of its entire regulated power supply business, including its nuclear investment.
Since 1997, FG&E has worked in collaboration with the other Massachusetts gas distribution utilities and various other stakeholders to develop and implement the infrastructure to offer gas customers choice of their competitive gas energy supplier and to complete the restructuring of gas service provided by gas utilities. FG&E filed with the MDTE new gas tariffs to implement natural gas unbundling in accordance with Model Terms and Conditions resulting from these collaborative efforts. The MDTE issued an Order approving these tariffs and final regulations effective November 1, 2000.
In New Hampshire, CECo and E&H, our electric utility operating subsidiaries, and Unitil Power Corp., our wholesale power company, continue to prepare for the transition that will move them into this new market structure, pending resolution of certain key restructuring policies and issues. The utility operating companies have also been active participants in the restructuring of the wholesale power market and transmission system in New England. Though retail competition in the sale of electricity has stalled throughout the region, new wholesale markets have been implemented in the New England Power Pool (NEPOOL) under the general supervision of an Independent System Operator (ISO).
Massachusetts Electric Restructuring - On January 15, 1999, the MDTE approved FG&E's restructuring plan with certain modifications. The Plan provides customers with: a) the ability to choose an energy supplier; b) an option to purchase Standard Offer Service provided by FG&E at regulated rates for up to seven years; and c) a cumulative 15% rate reduction adjusted for inflation. The Order also approved FG&E's power supply divestiture plan for its interest in three generating units and four long-term power supply contracts.
Pursuant to the Plan, on October 30, 1998, FG&E filed a proposed contract with Constellation Power Services Inc. for provision of Standard Offer Service. Constellation began to supply power under that contract on March 1, 1999, and is scheduled to continue through February 28, 2005. The award of this contract was the first successful Standard Offer auction conducted in Massachusetts.
A contract for the sale of FG&E's interest in the New Haven Harbor plant was approved by the MDTE on March 31, 1999, and the sale of the unit closed on April 14, 1999. A contract for the sale of the entire output from FG&E's remaining generating assets and purchased power contracts to Select Energy, Inc. was approved by the MDTE on December 28, 1999, and went into effect February 1, 2000.
On December 22, 1999, FG&E filed with the MDTE new rates for effect January 1, 2000. The revised rates maintain the required inflation-adjusted 15% rate discount. The MDTE approved the rates on January 5, 2000, subject to an examination of the Company's filing in which it reconciles its estimated and actual transition costs (the "reconciliation filing").
On February 2, 2000, the MDTE initiated a proceeding to examine FG&E's reconciliation filing and the consistency of the proposed charges and adjustments with the methods approved in FG&E's restructuring plan. The MDTE held four days of hearings in May 2000, and the Company presented testimony in support of its filing. As part of his review of FG&E's filing, the Massachusetts Attorney General has challenged FG&E's recovery of certain transition costs and other cost reconciliation calculations. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there could be an adverse impact on the Company's consolidated financial position.
As a result of restructuring and divestiture of FG&E's generation and purchased power portfolio, FG&E has accelerated the write-off of its electric generation assets and its abandoned investment in Seabrook Station. The MDTE established the return to be earned on the unamortized balance of FG&E's generation plant, reducing FG&E's earnings on those assets. In 2000, Unitil's earnings from this business segment represented approximately 16% of the earnings from utility operations. As this portfolio is amortized over the next 9 years, earnings from this segment of FG&E's utility business will continue to decline and ultimately cease.
On August 2, 2000, FG&E was the first electric company in Massachusetts to file for an increase in its Standard Offer Service rates pursuant to the Fuel Adjustment provision of its Standard Offer Service (SOS) tariff. This adjustment allows an increase in the SOS rate due to increases in the fuel prices of oil and natural gas. Any revenues received as a result of this adjustment are passed on to the Company's wholesale SOS provider. The MDTE suspended the filing for further review. Subsequently, other electric utility companies operating in Massachusetts made similar filings, and the MDTE instituted proceedings in each of those cases. On December 4, 2000, the MDTE issued an order for the utilities authorizing a "fixed" fuel adjustment, calculated based on the most recent 12 months of data. These adjustments took effect on January 1, 2001. FG&E's SOS rate increased from 3.8 cents/kWh to 5.121 cents/kWh. Unrecovered amounts to date will be recovered, subject to the rate reduction requirements of the Act.
In approving the new SOS rates, the MDTE also directed all electric distribution companies to file a report with the MDTE on their efforts to mitigate transition costs. On January 19, 2001, FG&E filed an extensive report detailing its mitigation activities, including contract restructurings, divestiture of its generating assets, and a variety of initiatives intended to reduce the burden of increasing energy prices on customers. While FG&E has substantially completed the divestiture of its generation assets, the Company continues to seek ways to reduce its transition costs and lower prices for customers.
On December 1, 2000, FG&E filed new electric rates for effect January 1, 2001. The revised rates maintain the required inflation-adjusted 15% rate discount. The MDTE approved final rates on December 29, 2000, subject to reconciliation pursuant to an investigation of actual and estimated transition costs, resulting in an upward inflation adjustment of 3.5% relative to 2000 rates.
New customers, and customers who previously opted to take electric supply service from a competitive provider, may purchase power through FG&E under Default Service. FG&E provides the Default Service through a third party supplier at market-based rates. The Company issued a Request for Proposals for Default Service in September 2000. FG&E awarded a contract and filed resulting rates which were approved effective for the period January through May 2001.
In June 2000, the MDTE opened an investigation into whether (1) metering, meter maintenance and testing, and customer billing and information services (MBIS) should be unbundled; and (2) the service territories of distribution companies should remain exclusive. On December 29, 2000, the MDTE issued its report recommending that the Legislature not take action to allow for the competitive provision of MBIS in the electric industry. The MDTE also concluded that exclusive service territories should remain intact.
Massachusetts Gas Restructuring - In mid-1997, the MDTE directed all Massachusetts natural gas Local Distribution Companies (LDCs) to form a collaborative with other stakeholders to develop common principles and appropriate regulations for the unbundling of gas service, and directed FG&E and four other LDCs to file unbundled gas rates for its review. FG&E's unbundled gas rates were filed with, and approved by, the MDTE and implemented in November 1998.
On February 1, 1999, the MDTE issued an order in which it determined that the LDCs would continue to have an obligation to provide gas supply and delivery services for another five years, with a review after three years. This order also set forth the MDTE's decision requiring mandatory assignment by LDCs of their pipeline capacity contracts to competitive marketers. In March 1999, the LDCs and other stakeholders filed a settlement with the MDTE, which set forth rules for implementing an interim firm transportation service through October 31, 2000. The MDTE approved the settlement on April 2, 1999. FG&E has made separate compliance filings that were approved by the MDTE to implement its interim firm gas transportation service for its largest general service customers and to complement this service with a firm gas peaking service. This interim service is now superseded by the permanent transportation service, which was approved for implementation on November 1, 2000.
On November 3, 1999, the Massachusetts LDCs filed Model Terms and Conditions for Gas Service, including provisions for capacity assignment, peaking service, and Default Service. In accordance with the MDTE's approval of these Model Terms and Conditions in January 2000, FG&E filed Company-specific tariffs that implement natural gas unbundling. The MDTE also opened a rulemaking proceeding on proposed regulations that would govern the unbundling of services related to the provision of natural gas. The MDTE has issued an order approving the tariffs and final regulations effective November 1, 2000.
New Hampshire Electric Restructuring - On February 28, 1997, the NHPUC issued its Final Plan for New Hampshire electric utilities to transition to a competitive electric market in the state (Final Plan). The Final Plan linked the interim recovery of stranded cost by the State's utilities to a comparison of their existing rates with the regional average utility rates. CECo's and E&H's rates are below the regional average; thus, the NHPUC found that CECo and E&H were entitled to full interim stranded cost recovery, as defined by the NHPUC. However, the NHPUC also made certain legal rulings which could affect CECo's and E&H's long-term ability to recover all of their stranded costs.
Northeast Utilities' affiliate Public Service Company of New Hampshire (PSNH) filed suit in U.S. District Court for protection from the Final Plan and related orders and was granted an indefinite stay. In June 1997, Unitil, and other utilities in New Hampshire, intervened as plaintiffs in the federal court proceeding. In June 1998, the federal court clarified that the injunctions issued by the court in 1997 had effectively frozen the NHPUC's efforts to implement restructuring. This amended injunction has been challenged by the NHPUC, and affirmed by the First Circuit Court of Appeals. Unitil continues to be a plaintiff-intervenor in federal district court. Further court proceedings are pending final resolution of electric restructuring for PSNH.
Unitil has continued to work actively to explore settlement options and to seek a fair and reasonable resolution of key restructuring policies and issues in New Hampshire. The Company is also monitoring the regulatory and legislative proceedings dealing with electric restructuring in the state. In October 2000, the NHPUC approved a settlement for the restructuring of PSNH. Appeals of the PSNH restructuring orders were denied by the New Hampshire Supreme Court and are now being pursued with the U.S. Supreme Court.
Pending Rate Proceedings - The last formal regulatory filings to increase base electric rates for Unitil's three retail operating subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. A majority of the Company's operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas, energy efficiency, and restructuring-related cost recovery mechanisms. Industry restructuring will continue to change the methods of how certain costs are recovered through the Company's regulated rates and tariffs.
As discussed above, FG&E filed for and received approval of an increase to its electric Standard Offer Service rate reflecting extraordinary increases in the price of oil and natural gas. FG&E also received an increase to its Cost of Gas Adjustment resulting in bill increases of approximately 25%, effective November 1, 2000. FG&E subsequently received another increase of approximately 20% to its Cost of Gas Adjustment for effect February 1, 2001. Wholesale natural gas prices reached record levels in New England and across the United States in response to cold weather and tight supplies. In New Hampshire, CECo and E&H filed and received approval of increases to their Fuel and Purchased Power Adjustments, resulting in bill increases of 25% to 34%, depending upon usage patterns, effective January 1, 2001. These higher fuel costs are a pass-through without markup or profit. Retail electricity prices for most New England utilities are increasing this winter.
On May 15, 1998, FG&E filed a gas base rate case with the MDTE. The last base rate case had been in 1984. After evidentiary hearings, the MDTE issued an Order allowing FG&E to establish new rates, effective November 30, 1998, that would produce an annual increase of approximately $1.0 million in gas revenues. As part of the proceeding, the Massachusetts Attorney General alleged that FG&E had double-collected fuel inventory finance charges, and requested that the MDTE require FG&E to refund approximately $1.6 million in double collections since 1987. The Company believes that the Attorney General's claim is without merit and that a refund was not justified or warranted. The MDTE rejected the Attorney General's request and stated its intent to open a separate proceeding to investigate the Attorney General's claim. On November 1, 1999, the MDTE issued an Order of Notice initiating an investigation of this matter. Hearings were held in early 2000 and were reopened in November 2000 to hear new evidence. Supplemental testimony has been filed and additional hearings were held in February 2001.
On October 29, 1999, the MDTE initiated a proceeding to implement Performance Based Rate making (PBR) for all electric and gas distribution utilities in Massachusetts. PBR is a method of setting regulated distribution rates that provide incentives for utilities to control costs while maintaining a high level of service quality. Under PBR, a company's earnings are tied to performance targets, and penalties can be imposed for deterioration of service quality. On December 29, 1999, FG&E filed a petition with the MDTE for authority to defer for later recovery costs associated with its preparation of a PBR filing for its gas division and its participation in the MDTE-initiated generic gas and electric PBR proceedings. This petition and the MDTE's generic proceeding are pending. The Company is currently evaluating the impact, if any, that PBR would have on the Company's ability to continue applying the standards of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation."
On December 31, 1999, the Massachusetts Attorney General filed a complaint against FG&E requesting that the MDTE investigate the distribution rates, rate of return, and depreciation accrual rates for FG&E's electric operations in calendar year 1999. The MDTE opened a proceeding in November 2000, held a public hearing and procedural conference in December 2000, and subsequently issued a procedural schedule covering the period January through April 2001. Any order received from the MDTE would apply to the Company's rates prospectively and would not be retroactive. Management is unable to predict the outcome of this proceeding but an unfavorable result could have an adverse impact on the Company's consolidated financial position.
Millstone Unit No. 3 - FG&E has a 0.217% nonoperating ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which calls for increased NRC inspection attention. In March 1996, as a result of engineering evaluations, Millstone 3 was taken out of service. The NRC authorized the restart of Millstone 3 in June 1998.
During the period that Millstone 3 was out of service, FG&E continued to incur its proportionate share of the unit's ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E also incurred costs to replace the power that was expected to be generated by the unit. During the outage, FG&E incurred approximately $1.2 million in replacement power costs, and recovered those costs through its electric fuel charge, which is subject to review and reconciliation by the MDTE. Under existing MDTE precedent, FG&E's replacement power costs of $1.2 million could be subject to disallowance in rates.
In August 1997, FG&E, in concert with other non-operating joint owners, filed a demand for arbitration in Connecticut and a lawsuit in Massachusetts, in an effort to recover costs associated with the extended unplanned shutdown. Several preliminary rulings have been issued in the arbitration and legal cases, and both cases are continuing. On March 22, 2000, FG&E entered into a settlement agreement with the defendants under which FG&E will dismiss its lawsuit and arbitration claims. The settlement is generally similar to earlier settlements with the defendants, and three joint owners that own, in the aggregate, approximately 19% of the unit. The settlement provides for FG&E to receive an initial payment of $600,000 and other amounts contingent upon future events and would result in FG&E's entire interest in the unit being included in the auction of the majority interest, and certain of the minority interests, in Millstone 3, which is expected to be completed by 2001. Upon completion of the sale of Millstone 3, FG&E will be relieved of all residual liabilities, including decommissioning liabilities, associated with Millstone 3. FG&E expects to flow through the net proceeds of the settlement to its customers .
On September 8, 2000, Western Massachusetts Electric Company, New England Power Company, and FG&E together filed a Joint Petition requesting approval by the MDTE of the sale of their respective interests in Millstone Units 1, 2, and 3. The Companies also requested MDTE findings that the divested assets qualify as "eligible facilities" pursuant to Section 32 (c) of the Public Utility Holding Company Act of 1935. The MDTE approved the sale and certified the unit as an "eligible facility" on December 22, 2000. The parties to the sale transaction are currently awaiting other state and federal regulatory approvals for the final sale of the Millstone units.
Environmental Matters -
The Company continues to work with federal and state environmental agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E has proceeded with site remediation work as specified on the Tier 1B permit, which allows FG&E to work towards temporary remediation of the site.
In April 2000, FG&E applied for a Utility Related Abatement Measure (URAM) with the Massachusetts Department of Environmental Protection (DEP) to permit excavation work required to construct a new electric substation on FG&E's former MGP site at Sawyer Passway. The permit application was reviewed and approved by the Massachusetts DEP in May 2000. All work permitted under the provisions of the URAM was completed and a final report of closure was submitted to the DEP in December 2000.
Construction of the new highway bridge across Sawyer Passway began in October 2000. FG&E began fulfillment of obligations associated with the bridge construction as stipulated in a memorandum of understanding with the Massachusetts Highway Department and the Massachusetts DEP.
Upon completion of site remediation associated with the bridge construction, the last remaining portion of the Sawyer Passway MGP site is expected to be closed out and attain the status of temporary closure in late 2001. This temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed.
The costs of remedial action at this site are initially funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the MDTE. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site.
Market Risk - Although Unitil's utility operating companies are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of fuel and gas costs in rates. Consequently, there is limited commodity price risk after consideration of the related rate-making. As the utility industry deregulates, the Company will be divesting its commodity-related energy businesses and therefore will be further reducing its exposure to commodity-related risk.
FORWARD-LOOKING INFORMATION
This report contains forward-looking statements which are subject to the inherent uncertainties in predicting future results and conditions. Certain factors that could cause the actual results to differ materially from those projected in these forward-looking statements include, but are not limited to; variations in weather, changes in the regulatory environment, customers' preferences on energy sources, general economic conditions, increased competition and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of the Company.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Reference is made to the "Market Risk" section of Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" on page 27 (above).
Item 8.
Item 8. Financial Statements and Supplemental Data
Report of Independent Certified Public Accountants
To the Shareholders of Unitil Corporation:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Unitil Corporation and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of earnings, cash flows and changes in common stock equity for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Unitil Corporation and subsidiaries as of December 31, 2000 and 1999, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
We have also audited Schedule II of Unitil Corporation and subsidiaries as of December 31, 2000 and for the three years then ended included in Part IV Item 14(a)(2). In our opinion, the schedule presents fairly, in all material respects, the information required to be set forth therein.
/s/ GRANT THORNTON LLP
Boston, Massachusetts
February 5, 2001
CONSOLIDATED STATEMENTS OF EARNINGS
(000's, except common shares and per share data)
Year Ended December 31,
Operating Revenues:
Electric
$160,023
$154,077
$149,639
Gas
22,756
18,116
17,009
Other
Total Operating Revenues
182,941
172,373
166,678
Operating Expenses:
Fuel and Purchased Power
110,280
102,171
98,589
Gas Purchased for Resale
13,492
9,854
9,874
Operation and Maintenance
24,545
24,404
23,652
Depreciation and Amortization
11,964
11,412
10,007
Provisions for Taxes:
Local Property and Other
4,967
5,077
5,540
Federal and State Income
3,413
4,047
3,710
Total Operating Expenses
168,661
156,965
151,372
Operating Income
14,280
15,408
15,306
Non-Operating Expenses
Income Before Interest Expense, Net
14,036
15,357
15,150
Interest Expense, Net
6,820
6,919
6,901
Net Income
7,216
8,438
8,249
Less Dividends on Preferred Stock
Net Income Applicable to Common Stock
$6,953
$8,170
$7,975
Average Common Shares Outstanding
4,723,171
4,682,273
4,505,784
Basic Earnings Per Share
$1.47
$1.74
$1.77
Diluted Earnings Per Share
$1.47
$1.74
$1.72
(The accompanying Notes are an integral part of these financial statements.)
CONSOLIDATED BALANCE SHEETS
(000'S) ASSETS
December 31,
Utility Plant:
Electric
$173,883
$161,767
Gas
36,996
34,031
Common
21,602
21,541
Construction Work in Progress
1,844
2,499
Utility Plant
234,325
219,838
Less: Accumulated Depreciation
71,036
66,429
Net Utility Plant
163,289
153,409
Other Property and Investments
8,740
5,051
Current Assets:
Cash
3,060
2,847
Accounts Receivable - Less Allowance for
Doubtful Accounts of $596 and $598
20,057
16,630
Refundable Taxes
1,980
1,419
Material and Supplies
2,854
2,503
Prepayments
1,317
Accrued Revenue
8,602
2,262
Total Current Assets
37,870
26,374
Noncurrent Assets:
Regulatory Assets
137,470
143,470
Prepaid Pension Costs
9,996
9,119
Debt Issuance Costs
1,479
1,351
Other Noncurrent Assets
24,123
24,753
Total Noncurrent Assets
173,068
178,693
TOTAL
$382,967
$363,527
(The accompanying Notes are an integral part of these financial statements.)
CONSOLIDATED BALANCE SHEETS (Cont.)
(000'S)
CAPITALIZATION AND LIABILITIES
December 31,
Capitalization:
Common Stock Equity
$79,935
$78,675
Preferred Stock, Non-Redeemable, Non-Cumulative
Preferred Stock, Redeemable, Cumulative
3,465
3,532
Long-Term Debt, Less Current Portion
81,695
84,966
Total Capitalization
165,320
167,398
Current Liabilities:
Long-Term Debt, Current Portion
3,207
1,191
Capitalized Leases, Current Portion
Accounts Payable
18,539
16,515
Short-Term Debt
32,500
10,500
Dividends Declared and Payable
Refundable Customer Deposits
1,252
1,302
Interest Payable
1,150
1,245
Other Current Liabilities
6,377
3,042
Total Current Liabilities
64,169
34,917
Deferred Income Taxes
45,859
42,634
Noncurrent Liabilities:
Power Supply Contract Obligations
97,342
106,184
Capitalized Leases, Less Current Portion
3,259
3,860
Other Noncurrent Liabilities
7,018
8,534
Total Noncurrent Liabilities
107,619
118,578
TOTAL
$382,967
$363,527
(The accompanying Notes are an integral part of these financial statements.)
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(000's except number of shares and par value)
December 31,
Common Stock Equity
Common Stock, No Par Value (Authorized - 8,000,000 shares;
$40,991
$40,352
Outstanding - 4,734,917 and 4,712,001 shares)
Stock Options
Retained Earnings
38,568
38,129
Total Common Stock Equity
79,935
78,675
Preferred Stock
CECo Preferred Stock, Non-Redeemable, Non-Cumulative:
6% Series, $100 Par Value
CECo Preferred Stock, Redeemable, Cumulative:
8.7% Series, $100 Par Value
E&H Preferred Stock, Redeemable, Cumulative:
5% Series, $100 Par Value
6% Series, $100 Par Value
8.75% Series, $100 Par Value
8.25% Series, $100 Par Value
FG&E Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value
8% Series, $100 Par Value
1,300
1,353
Total Preferred Stock
3,690
3,757
Long-Term Debt
CECo First Mortgage Bonds:
Series I, 8.49%, Due October 14, 2024
6,000
6,000
Series J, 6.96%, Due September 1, 2028
10,000
10,000
E&H First Mortgage Bonds:
Series K, 8.49%, Due October 14, 2024
9,000
9,000
Series L, 6.96%, Due September 1, 2028
10,000
10,000
FG&E Long-Term Notes:
8.55% Notes due March 31, 2004
12,000
13,000
6.75% Notes due November 30, 2023
19,000
19,000
7.37% Notes due January 15, 2029
12,000
12,000
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes Due August 1, 2017
6,902
7,157
Total Long-Term Debt
84,902
86,157
Less: Long-Term Debt, Current Portion
3,207
1,191
Total Long-Term Debt, Less Current Portion
81,695
84,966
Total Capitalization
$165,320
$167,398
(The accompanying Notes are an integral part of these financial statements.)
CONSOLIDATED STATEMENT OF CASH FLOWS
(000's)
Year Ended December 31,
Cash Flows from Operating Activities:
Net Income
$7,216
$8,438
$8,249
Adjustments to Reconcile Net Income to
Cash Provided by Operating Activities:
Depreciation and Amortization
11,964
11,412
10,007
Deferred Tax Provision
3,522
1,515
Amortization of Investment Tax Credit
(256)
(322)
(402)
Amortization of Debt Issuance Costs
Changes in Working Capital:
Accounts Receivable
(3,427)
(631)
Materials and Supplies
(351)
(299)
Prepayments
(1,481)
(94)
(713)
Accrued Revenue
(6,340)
(1,087)
5,621
Accounts Payable
2,024
5,133
(3,352)
Refundable Customer Deposits
(50)
(894)
Taxes and Interest Payable
(656)
(748)
Other, net
(3,362)
(5,182)
(6,721)
Cash Provided by Operating Activities
8,864
18,308
13,215
Cash Flows from Investing Activities:
Additions to Property, Plant and Equipment
(18,559)
(15,411)
(14,463)
Proceeds from the Sale of Electric Generation Assets
5,288
Additions to Other Property and Investments
(3,690)
(5,008)
Cash Used in Investing Activities
(22,249)
(15,131)
(14,463)
Cash Flows from Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net
22,000
(9,500)
2,000
Proceeds from Issuance of Long-Term Debt
12,000
20,000
Repayment of Long-Term Debt
(1,255)
(1,065)
(13,144)
Dividends Paid
(6,787)
(6,722)
(6,368)
Issuance of Common Stock
1,945
1,600
Retirement of Preferred Stock
(68)
(86)
(48)
Repayment of Capital Lease Obligations
(931)
(985)
(1,046)
Cash (Used In) Provided by Financing Activities
13,598
(4,413)
2,994
Net (Decrease) Increase in Cash
(1,236)
1,746
Cash at Beginning of Year
2,847
4,083
2,337
Cash at End of Year
$3,060
$2,847
$4,083
Supplemental Cash Flow Information:
Interest Paid
$8,640
$7,164
$7,445
Federal Income Taxes Paid
$350
$4,018
$2,490
Supplemental Schedule of Noncash Activities:
Capital Leases Incurred
$363
$553
$624
The Company recorded the estimated impact of the Order from the MDTE related to its electric Utility Restructuring Plan on December 31, 1998, and subsequently updated for actual amounts in 1999. The non-cash changes related to the Restructuring Plan are as follows:
(Decrease) Increase in Regulatory Assets
-
(23,504)
129,688
Decrease (Increase) in Power Supply Contract Obligations
-
23,504
(129,688)
(The accompanying Notes are an integral part of these financial statements.)
CONSOLIDATED STATEMENTS OF
CHANGES IN COMMON STOCK EQUITY
(000's except number of shares)
(The accompanying Notes are an integral part of these financial statements.)
Note 1: Summary of Significant Accounting Policies
Nature of Operations - Unitil Corporation (Unitil or the Company) is registered with the Securities and Exchange Commission (SEC) as a public utility holding company under the Public Utility Holding Company Act of 1935, and is the parent of the Unitil System (the System). The following companies are wholly owned subsidiaries of Unitil: Concord Electric Company (CECo), Exeter & Hampton Electric Company (E&H), Fitchburg Gas and Electric Light Company (FG&E), Unitil Power Corp. (UPC), Unitil Realty Corp. (URC), Unitil Service Corp. (USC), and its unregulated business unit Unitil Resources, Inc. (URI). Usource, Inc. and Usource L.L.C. (collectively Usource) are subsidiaries of Unitil Resources, Inc.
Unitil's principal business is the retail sale and distribution of electricity in New Hampshire and both electric and gas services in Massachusetts through its retail distribution subsidiaries CECo, E&H, and FG&E. The Company's wholesale electric power subsidiary, UPC, principally provides all the electric power supply requirements to CECo and E&H for resale at retail, and also engages in various other wholesale electric power services with affiliates and non-affiliates throughout the New England region. URI provides an Internet-based energy brokering business, Usource, as well as various energy consulting and marketing activities. Finally, URC and USC provide centralized facilities, operations and management services to support the Unitil System of Companies.
With respect to rates and accounting practices, CECo and E&H are subject to regulation by the New Hampshire Public Utilities Commission (NHPUC), FG&E is regulated by the Massachusetts Department of Telecommunications & Energy (MDTE), and CECo, E&H, UPC and FG&E are regulated by the Federal Energy Regulatory Commission (FERC).
The Company accounts for all its regulated operations in accordance with Statement of Financial Accounting Standard ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation," requiring the Company to record the financial statement effects of the rate regulation to which the Company is currently subject. If a separable portion of the Company's business no longer meets SFAS No. 71, the Company is required to eliminate the financial statement effects of regulation for that portion.
Basis of Presentation
Principles of Consolidation - Unitil Corporation is the parent company of the Unitil System. The consolidated financial statements include the accounts of the Company and all of its wholly-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and requires disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition - The Company's operating subsidiaries record electric and gas operating revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource L.L.C. records energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period.
Other Property and Investments - At December 31, 2000, Other Property and Investments includes the Company's investment in the stock of Enermetrix, which is recorded at its historical cost of $5,413,000, comprised of $5,117,000 of Enermetrix Convertible Preferred Stock and $296,000 of Enermetrix Common Stock Warrants. Although the market value of the investment in Enermetrix stock is not readily determinable, management believes the fair value of this investment currently exceeds its carrying cost.
Depreciation and Amortization - Depreciation provisions for the Company's utility operating subsidiaries are determined on a group straight-line basis. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2000 - 3.74 percent; 1999 - 3.72 percent; and 1998 - 3.21 percent.
Amortization provisions include the recovery of a portion of FG&E's former investment in the Seabrook Nuclear Power Plant in rates to its customers through a Seabrook Amortization Surcharge as ordered by the MDTE. In addition, FG&E is amortizing electric generating related assets, in accordance with its electric restructuring plan approved by the MDTE (See Note 12).
Federal Income Taxes - Deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and are measured by applying tax rates applicable to the taxable years in which those differences are expected to reverse. The Tax Reduction Act of 1986 eliminated investment tax credits. Investment tax credits generated prior to 1986 are being amortized, for financial reporting purposes, over the productive lives of the related assets.
Newly Issued Pronouncements - In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. In June 1999, FASB issued Statement of Accounting Standards No. 137 (SFAS 137), "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 - an amendment of FASB Statement No. 133". This statement has delayed the effective date of SFAS 133 until fiscal years beginning after June 15, 2000. In June 2000, SFAS No. 133 was amended by Statement of Financial Accounting Standards No. 138 (SFAS 138), "Accounting for Derivative Instruments and Hedging Activities - and amendment of FASB Statement No. 133. Management does not expect the adoption of these statements to have a material impact on its financial position or results of operations.
In December 1999, the SEC issued Staff Accounting Bulletin No. 101 ("SAB No. 101"), "Revenue Recognition in Financial Statements." SAB No. 101 provides guidance on applying generally accepted accounting principles to revenue recognition, presentation and disclosure in financial statements. Subsequently, the SEC has amended the implementation dates so that the Company is required to adopt the provision of SAB No. 101 in the fourth quarter of 2000. Unitil has adopted SAB No. 101 and there is no impact on the results of operations or financial position.
Reclassifications - Certain amounts previously reported have been reclassified to conform to current year presentation.
Note 2: Common Stock
New Shares Issued - During 2000, the Company raised $639,000 of additional common equity capital through the issuance of 22,916 shares of common stock in connection with the Dividend Reinvestment and Stock Purchase Plan. The Dividend Reinvestment and Stock Purchase Plan provides participants in the plan a method for investing cash dividends on the Company's Common Stock and cash payments in additional shares of the Company's Common Stock. In 1999, the Company raised $676,000 of additional common equity capital through the issuance of 27,619 shares of common stock in connection with the Dividend Reinvestment and Stock Purchase Plan and the Employee 401(k) Tax Deferred Savings and Investment Plan. The Employee 401(k) Tax Deferred Savings and Investment Plan is described in Note 9.
Stock-Based Compensation Plans - The Company maintains two stock option plans which provide for the granting of options to key employees, as follows:
Unitil Corporation Key Employee Stock Option Plan: The "Unitil Corporation Key Employee Stock Option Plan" was a ten year plan which began in March 1989. The number of shares granted under this plan, as well as the terms and conditions of each grant, were determined by the Board of Directors, subject to plan limitations. All options granted under this plan vested upon grant. The ten-year period in which options could be granted under this plan expired in March 1999. The expiration date of the remaining outstanding options is November 3, 2007. The plan provides dividend equivalents on options granted, which are recorded at fair value as compensation expense. The total compensation expenses recorded by the Company with respect to this plan were $39,000, $74,000 and $245,000 for the years ended December 31, 2000, 1999 and 1998, respectively.
Share Option Activity of the "Unitil Corporation Key Employee Stock Option Plan" is presented in the following table:
Beginning Options Outstanding and Exercisable
27,976
134,741
191,365
Dividend Equivalents Earned
1,382
2,988
10,327
Options Exercised
----
(109,753)
(66,951)
Ending Options Outstanding and Exercisable
29,358
27,976
134,741
Range of Option Exercise Price per Share
$12.11-$18.28
$12.11-$18.28
$12.11-$18.28
Weighted Average Remaining Contractual Life
6.9
7.9
8.9
Unitil Corporation 1998 Stock Option Plan: The "Unitil Corporation 1998 Stock Option Plan" became effective on December 11,1998. The number of shares granted under this plan, as well as the terms and conditions of each grant, are determined by the Board of Directors, subject to plan limitations. All options granted under this plan vest over a three-year period from the date of the grant with 25% vesting on the first anniversary of the grant, 25% vesting on the second anniversary and 50% vesting on the third anniversary. Under the terms of this plan, key employees may be granted options to purchase the Company's common stock at no less than 100% of the market price on the date the option is granted. All options must be exercised no later than ten years after the date on which they were granted. The total compensation expense recorded by the Company with respect to this plan was $144,000 for the year ended December 31, 2000 and $42,000 for the year ended December 31, 1999.
The Company has adopted Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock Based Compensation," and recognizes compensation costs at fair value at the date of grant.
The following summarizes certain data for options outstanding at December 31, 2000:
The weighted average fair value per share of options granted during 2000 and 1999 was $7.13 and $3.25, respectively. The fair value of options at the date of grant was estimated using the Black-Scholes model with the following weighted average assumptions:
Restrictions on Retained Earnings -Unitil Corporation has no restriction on the payment of common dividends from retained earnings. Its three retail distribution subsidiaries do have restrictions. Under the terms of the First Mortgage Bond Indentures, CECo and E&H had $4,778,000 and $4,400,000, respectively, available for the payment of cash dividends on their common stock at December 31, 2000. Under the terms of long-term debt Purchase Agreements, FG&E had $10,382,000 of retained earnings available for the payment of cash dividends on its common stock at December 31, 2000.
Note 3: Preferred Stock
Certain of the Unitil subsidiaries have redeemable Cumulative Preferred Stock outstanding and one subsidiary, CECo, has a Non-Redeemable, Non-Cumulative Preferred Stock issue outstanding. All such subsidiaries are required to offer to redeem annually a given number of shares of each series of Redeemable Cumulative Preferred Stock and to purchase such shares that shall have been tendered by holders of the respective stock. All such subsidiaries may redeem, at their option, the Redeemable Cumulative Preferred Stock at a given redemption price, plus accrued dividends.
The aggregate purchases of Redeemable Cumulative Preferred Stock during 2000, 1999 and 1998 were $67,500; $86,300; and $47,300, respectively. The aggregate amount of sinking fund requirements of the Redeemable Cumulative Preferred Stock for each of the five years following 2000 are $206,000 per year.
Note 4: Long-Term Debt
Certain of the Company's long-term debt agreements contain provisions which, among other things, limit the incursion of additional long-term debt.
Total aggregate amount of sinking fund payments relating to bond issues and normal scheduled long-term debt repayments amounted to $1,255,000, $1,065,000 and $4,394,000 in 2000, 1999 and 1998, respectively.
The aggregate amount of bond sinking fund requirements and normal scheduled long-term debt repayments for each of the five years following 2000 is: 2001 - $3,207,000; 2002 - $3,225,000; 2003 - $3,244,000; 2004 - $3,264,000 and 2005 - $286,000.
On January 26, 1999, FG&E sold $12,000,000 of long-term notes at par to institutional investors, bearing an interest rate of 7.37%. Proceeds were used to repay short-term indebtedness, incurred to fund FG&E's ongoing construction program.
The fair value of the Company's long-term debt is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. In management's opinion, the carrying value of the debt approximated its fair value at December 31, 2000 and 1999.
Note 5: Credit Arrangements
At December 31, 2000, the Company had unsecured committed bank lines for short-term debt aggregating $35,000,000 with three banks for which it pays commitment fees. At December 31, 2000, the unused portion of the committed credit lines outstanding was $2,500,000. The average interest rates on all short-term borrowings were 6.57% and 5.72% during 2000 and 1999, respectively.
Note 6: Leases
The Company's subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery and office equipment. FG&E has a facility lease for twenty-two years which began in February 1981. The lease allows five, five-year renewal periods at the option of FG&E. In addition, Unitil's subsidiaries lease some equipment under operating leases.
The following is a schedule of the leased property under capital leases by major classes:
The following is a schedule by years of future minimum lease payments and present value of net minimum lease payments under capital leases as of December 31, 2000:
Year Ending December 31, (000's)
1,452
1,357
2006 - 2010
1,362
Total Minimum Lease Payments
$5,817
Less: Amount Representing Interest
1,623
Present Value of Net Minimum Lease Payments
$4,194
Total rental expense charged to operations for the years ended December 31, 2000, 1999 and 1998 amounted to $21,000, $103,000, and $88,000, respectively. There are no material future operating lease payment obligations at December 31, 2000.
Note 7: Income Taxes
Federal Income Taxes were provided for the following items for the years ended December 31, 2000, 1999 and 1998, respectively:
The components of the Federal and State income tax provisions reflected in the accompanying consolidated statements of earnings for the years ended December 31, 2000, 1999 and 1998 were as follows:
Federal and State Tax Provisions (000's)
Federal
Current
($9)
$3,492
$2,221
Deferred
3,066
1,225
Amortization of Investment Tax Credits
(256)
(322)
(402)
Total Federal Tax Provision
2,801
3,235
3,044
State
Current
Deferred
Total State Tax Provision
Total Provision for Federal and State Income Taxes
$3,413
$4,047
$3,710
The differences between the Company's provisions for Federal Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below:
Statutory Federal Income Tax Rate
34%
34%
34%
Income Tax Effects of:
Investment Tax Credits
(2)
(2)
(3)
Abandoned Property
(6)
(7)
(6)
Other, Net
Effective Federal Income Tax Rate
28%
28%
27%
Temporary differences which gave rise to deferred tax assets and liabilities are shown below:
Deferred Income Taxes (000's)
Accelerated Depreciation
$24,519
$24,506
Abandoned Property
6,786
7,649
Contributions in Aid of Construction
(3,050)
(2,948)
Percentage Repair Allowance
1,956
1,923
Retirement Loss
2,820
2,640
Deferred Pensions
3,247
2,970
KESOP
(116)
(45)
Accumulated Deferred FAS 109 Tax Gross Up
3,129
3,170
Accrued Revenue
7,136
3,073
Investment Tax Credit
Gain on Sale of New Haven Harbor
(1,562)
(1,712)
Other
Total Deferred Income Tax
$45,859
$42,634
Note 8: Energy Supply
Massachusetts:
Joint Owned Units - FG&E is participating, on a tenancy-in-common basis with other New England utilities, in the ownership of two generating units. Wyman Unit No. 4 is an oil-fired station that has been in commercial operation since December 1978. Millstone Unit No. 3, a nuclear generating unit, has been in commercial operation since April 1986. FG&E completed the sale of its principal generating asset, a 4.5% interest in New Haven Harbor Station, in March 1999. Kilowatt-hour generation and operating expenses of the joint ownership units are divided on the same basis as ownership. FG&E's proportionate costs are reflected in the Consolidated Statements of Earnings. In accordance with Massachusetts Electric Restructuring Law, and pursuant to the power supply divestiture discussed below, FG&E began selling the output from their generation units on February 1, 2000. On December 22, 2000 the MDTE approved FG&E's request to sell its joint ownership share of Millstone Unit No. 3 to Dominion Resources, Inc. The sale is expected to be completed during the first half of 2001. Information with respect to FG&E's generation assets at December 31, 2000 is shown below:
Company's
Joint Ownership
Proportionate
Share of
Net Book
Units
State
Ownership %
Total MW
Value (000's)
Millstone Unit No. 3
CT
0.2170
2.50
$6,123
Wyman Unit No. 4
ME
0.1822
1.13
3.63
$6,230
Purchased Power and Gas Supply Contracts - FG&E has commitments under long-term contracts for the purchase of electricity and gas from various suppliers. Generally, these contracts are for fixed periods and require payment of demand and energy charges. Total costs under these contracts are included in Fuel and Purchased Power and Gas Purchased for Resale in the Consolidated Statements of Earnings. These costs are normally recoverable in revenues under various cost recovery mechanisms. In accordance with Massachusetts Electric Restructuring Law, and pursuant to the power supply divestiture discussed below, FG&E began selling the output from their power supply contracts on February 1, 2000. Information with respect to FG&E's electric purchased power contracts at December 31, 2000 is shown below:
Unit
Energy
Contract
Fuel Type
Entitlements
End Date
Hydro
8 MW
Hydro
3 MW
Wood
14MW
Power Supply Divestiture - In January 2000, the MDTE approved FG&E's agreement to sell the output from its remaining electric power generation portfolio to Select Energy, a subsidiary of Northeast Utilities. FG&E initiated its electric restructuring process, including the divestiture and sale of its power supply portfolio, in 1998, in response to the Massachusetts Electric Restructuring Law. Under the Select Energy contract, which went into effect February 1, 2000, FG&E began selling the output from its remaining power contracts and the output of its two minority interests in generation assets to Select Energy.
Under the Massachusetts Electric Restructuring Law, customers not purchasing electric power from competitive suppliers are eligible either for Standard Offer Service ("SOS") or for Default Service. Most of FG&E's customers are currently eligible for SOS service. On March 1, 1999, FG&E entered into a contract with Constellation Power Source to procure power needed to serve the SOS load. The contract will continue through February 28, 2005. The power required to meet Default Service is currently being procured through a six-month contract from Consolidated Edison Energy, Inc. In accordance with MDTE regulations, FG&E will conduct periodic Request for Proposals ("RFP") to procure Default Service at market prices. The next RFP will be used to procure Default Service effective June 1, 2001.
FG&E has been allowed recovery of its transition costs, including the above-market or stranded generation and power-supply related costs, via a non-bypassable uniform Transition Charge. The recoverable transition cost which have been recorded on FG&E's balance sheet as Regulatory Assets, include $97,342,000 of purchased power contracts and $6,020,000 of stranded generation assets and other adjustments related to the restructuring process.
As a result of the Order by the MDTE related to Electric Industry Restructuring in Massachusetts (See Note 12), the Company is required to discontinue the provisions of Statement of Financial Accounting Standards 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), to the generation and power supply portion of FG&E's business. FG&E's electric distribution business and gas supply and distribution business, as well as the power supply and distribution business of CECo, E&H and UPC will continue to apply SFAS No. 71.
New Hampshire:
Purchased Power Contracts - UPC has commitments under long-term contracts for the purchase of electricity from various suppliers. These wholesale contracts are generally for fixed periods and require payment of demand and energy charges. The total costs under these contracts are included in Fuel and Purchased Power in the Consolidated Statements of Earnings and are normally recoverable in revenues under various cost recovery mechanisms.
The status of UPC's electric purchased power contracts at December 31, 2000, is as shown below:
Notes:
(1) Total estimated 2000 annualized capacity payments.
(2) Total estimated 2000 annualized support charges.
Note 9: Benefit Plans
Pension Plans - Prior to May 1, 1998 four of the Company's subsidiaries had defined benefit Retirement and Pension plans and related Trust Agreements to provide retirement annuities for participating employees at age 65. On May 1, 1998, the plans of each employer were merged into one plan with uniform plan provisions to be known as the "Unitil Corporation Retirement Plan." The entire cost of the plan is borne by the respective subsidiaries.
The following table provides the components of net periodic expense (income) for the plans for years 2000, 1999 and 1998:
Net Periodic Expense (Income) (000's)
Service Cost
$850
$935
$827
Interest Cost
2,552
2,395
2,207
Expected Return on Plan Assets
(4,356)
(4,044)
(3,562)
Amortization of Transition Obligation
(16)
Amortization of Prior-Service Cost
Recognized net actuarial (gain)
(105)
---
---
Net Periodic Benefit Income
($876)
($528)
($470)
Reconciliation of Projected Benefit Obligations (000's):
Beginning of Year
$33,371
$36,621
$29,853
Service Cost
Interest Cost
2,552
2,395
2,207
Amendments
(80)
---
1,292
Actuarial (Gain) Loss
(4,601)
4,290
Benefit Payments
(2,094)
(1,979)
(1,848)
End of Year
$35,348
$33,371
$36,621
Reconciliation of Fair Value of Plan Assets (000's):
Beginning of Year
$45,783
$48,627
$42,304
Actual Return of Plan Assets
1,733
(865)
8,171
Benefit Payments
(2,094)
(1,979)
(1,848)
End of Year
$45,422
$45,783
$48,627
Funded Status (000's):
Funded Status at December 31
$10,074
$12,411
$12,006
Unrecognized Transition Obligation
Unrecognized Prior-Service Cost
1,038
1,216
1,317
Unrecognized (Gain) Loss
(1,200)
(4,677)
(4,986)
Prepaid Pension Cost
$9,996
$9,119
$8,591
Plan assets are invested in common stock, short-term investments and various other fixed income security funds. The weighted-average discount rates used in determining the projected benefit obligation in 2000, 1999 and 1998 were 7.75%, 7.75%, and 7.00%, respectively. The rate of increase in future compensation levels was 4.00% and the expected long-term rate of return on assets was 9.25% in 2000, 1999 and 1998.
Unitil Service Corp. has a Supplemental Executive Retirement Plan (SERP). The SERP is an unfunded retirement plan with participation limited to executives selected by the Board of Directors. The cost associated with the SERP amounted to approximately $112,000, $157,000; and $114,000 for the years ended December 31, 2000, 1999 and 1998, respectively.
Employee 401(k) Tax Deferred Savings Plan - The Company sponsors a defined contribution plan (under Section 401 (k) of the Internal Revenue Code) covering substantially all of the Company's employees. Participants may elect to defer from 1% to 15% of current compensation to the plan. The Company matches contributions, with a maximum matching contribution of 3% of current compensation. Employees may direct the investment of their savings plan balances into a variety of investment options, including a Company common stock fund. Participants are 100% vested in contributions made on their behalf, once they have completed three years of service. The Company's share of contributions to the plan were $425,000, $407,000 and $384,000 for the years ended December 31, 2000, 1999 and 1998, respectively.
Post-Retirement Benefits - The Company's subsidiaries provide health care benefits to retirees for a twelve-month period following their retirement. The Company's subsidiaries continue to provide life insurance coverage to retirees. Life insurance and limited health care post-retirement benefits require the Company to accrue post-retirement benefits during the employee's years of service with the Company and the recognition of the actuarially determined total post retirement benefit obligation earned by existing retirees. At December 31, 2000, 1999 and 1998, the accumulated post retirement benefit obligation (transition obligation) was approximately $257,000, $278,000 and $299,000, respectively, and the period cost associated with these benefits for 2000, 1999 and 1998 was approximately $90,000, $84,000 and $76,000, respectively. This obligation is being recognized on a delayed basis over the average remaining service period of active participants and such period will not exceed 20 years.
Note 10: Earnings Per Share
The following table reconciles basic and diluted earnings per share assuming all outstanding stock options were converted to common shares per SFAS 128.
(000's except share and per share data)
Basic Income Available to Common Stock
$6,953
$8,170
$7,975
Weighted Average Common Shares Outstanding - Basic
4,723,171
4,682,273
4,505,784
Plus: Diluted Effect of Incremental Shares
from Assumed Conversion
19,574
10,381
128,324
Weighted Average Common Shares
4,742,745
4,692,654
4,634,108
Outstanding - Diluted
Basic Earnings per Share
$1.47
$1.74
$1.77
Diluted Earnings per Share
$1.47
$1.74
$1.72
Note 11: Segment Information
The Company has reported four segments: utility electric, utility gas, Usource and other. Unitil is engaged principally in the retail sale and distribution of electricity in New Hampshire and both electric and gas service in Massachusetts through its retail distribution subsidiaries CECo, E&H, and FG&E. The Company's wholesale electric power subsidiary, UPC, provides all the electric power supply requirements to CECo and E&H for resale at retail, and also engages in various other wholesale electric power services with affiliates and non-affiliates throughout the New England Region. URI provides an Internet-based energy brokering service, through Usource, as well as various energy consulting and marketing activities. URC and USC provide centralized facilities and operations to support the Unitil System.
URC and USC are included in the "Other" column of the table below. USC provides centralized management and administrative services, including information systems management and financial record keeping. URC owns certain real estate, principally the Company's corporate headquarters. The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated in accordance with factors contained in cost of service studies, which were included in rate applications approved by the NHPUC and MDTE. Assets allocated to each segment are based upon specific identification of such assets provided by Company records.
The following table provides significant segment financial data for the years-ended December 31, 2000, 1999 and 1998:
Note 12: Commitments and Contingencies
Environmental Matters
The Company continues to work with federal and state environmental agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E has proceeded with site remediation work as specified on the Tier 1B permit, which allows FG&E to work towards temporary remediation of the site.
In April 2000, FG&E applied for a Utility Related Abatement Measure (URAM) with the Massachusetts Department of Environmental Protection (DEP) to permit excavation work required to construct a new electric substation on FG&E's former MGP site at Sawyer Passway. The permit application was reviewed and approved by the Massachusetts DEP in May 2000. All work permitted under the provisions of the URAM was completed and a final report of closure was submitted to the DEP in December 2000.
Construction of the new highway bridge across Sawyer Passway began in October 2000. FG&E began fulfillment of obligations associated with the bridge construction as stipulated in a memorandum of understanding with the Massachusetts Highway Department and the Massachusetts DEP.
Upon completion of site remediation associated with the bridge construction, the last remaining portion of the Sawyer Passway MGP site is expected to be closed out and attain the status of temporary closure in late 2001. This temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed.
The costs of remedial action at this site are initially funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the MDTE. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site.
Regulatory Matters
The Unitil System of Companies is regulated by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), and state regulatory authorities with jurisdiction over the utility industry, including the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In recent years, there has been significant legislative and regulatory activity to introduce greater competition in the supply and sale of electricity and gas, while continuing to regulate the delivery and distribution operations of our utility subsidiaries.
Massachusetts enacted comprehensive electric utility industry restructuring in November 1997. Since March 1, 1998, all electric consumers in Massachusetts served by investor-owned utilities have had the ability to choose their electric energy supplier. FG&E, the Company's Massachusetts utility operating subsidiary, continues to implement its comprehensive electric restructuring plan and divestiture of its entire regulated power supply business, including its nuclear investment.
Since 1997, FG&E has worked in collaboration with the other Massachusetts gas distribution utilities and various other stakeholders to develop and implement the infrastructure to offer gas customers choice of their competitive gas energy supplier and to complete the restructuring of gas service provided by gas utilities. FG&E filed with the MDTE new gas tariffs to implement natural gas unbundling in accordance with Model Terms and Conditions resulting from these collaborative efforts. The MDTE issued an Order approving these tariffs and final regulations effective November 1, 2000.
In New Hampshire, CECo and E&H, our electric utility operating subsidiaries, and Unitil Power Corp., our wholesale power company, continue to prepare for the transition that will move them into this new market structure, pending resolution of certain key restructuring policies and issues. The utility operating companies have also been active participants in the restructuring of the wholesale power market and transmission system in New England. Though retail competition in the sale of electricity has stalled throughout the region, new wholesale markets have been implemented in the New England Power Pool (NEPOOL) under the general supervision of an Independent System Operator (ISO).
Massachusetts Electric Restructuring - On January 15, 1999, the MDTE approved FG&E's restructuring plan with certain modifications. The Plan provides customers with: a) the ability to choose an energy supplier; b) an option to purchase Standard Offer Service provided by FG&E at regulated rates for up to seven years; and c) a cumulative 15% rate reduction adjusted for inflation. The Order also approved FG&E's power supply divestiture plan for its interest in three generating units and four long-term power supply contracts.
Pursuant to the Plan, on October 30, 1998, FG&E filed a proposed contract with Constellation Power Services Inc. for provision of Standard Offer Service. Constellation began to supply power under that contract on March 1, 1999, and is scheduled to continue through February 28, 2005. The award of this contract was the first successful Standard Offer auction conducted in Massachusetts.
A contract for the sale of FG&E's interest in the New Haven Harbor plant was approved by the MDTE on March 31, 1999, and the sale of the unit closed on April 14, 1999. A contract for the sale of the entire output from FG&E's remaining generating assets and purchased power contracts to Select Energy, Inc. was approved by the MDTE on December 28, 1999, and went into effect February 1, 2000.
On December 22, 1999, FG&E filed with the MDTE new rates for effect January 1, 2000. The revised rates maintain the required inflation-adjusted 15% rate discount. The MDTE approved the rates on January 5, 2000, subject to an examination of the Company's filing in which it reconciles its estimated and actual transition costs (the "reconciliation filing").
On February 2, 2000, the MDTE initiated a proceeding to examine FG&E's reconciliation filing and the consistency of the proposed charges and adjustments with the methods approved in FG&E's restructuring plan. The MDTE held four days of hearings in May 2000, and the Company presented testimony in support of its filing. As part of his review of FG&E's filing, the Massachusetts Attorney General has challenged FG&E's recovery of certain transition costs and other cost reconciliation calculations. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there could be an adverse impact on the Company's consolidated financial position.
As a result of restructuring and divestiture of FG&E's generation and purchased power portfolio, FG&E has accelerated the write-off of its electric generation assets and its abandoned investment in Seabrook Station. The MDTE established the return to be earned on the unamortized balance of FG&E's generation plant, reducing FG&E's earnings on those assets. In 2000, Unitil's earnings from this business segment represented approximately 16% of the earnings from utility operations. As this portfolio is amortized over the next 9 years, earnings from this segment of FG&E's utility business will continue to decline and ultimately cease.
On August 2, 2000, FG&E was the first electric company in Massachusetts to file for an increase in its Standard Offer Service rates pursuant to the Fuel Adjustment provision of its Standard Offer Service (SOS) tariff. This adjustment allows an increase in the SOS rate due to increases in the fuel prices of oil and natural gas. Any revenues received as a result of this adjustment are passed on to the Company's wholesale SOS provider. The MDTE suspended the filing for further review. Subsequently, other electric utility companies operating in Massachusetts made similar filings, and the MDTE instituted proceedings in each of those cases. On December 4, 2000, the MDTE issued an order for the utilities authorizing a "fixed" fuel adjustment, calculated based on the most recent 12 months of data. These adjustments took effect on January 1, 2001. FG&E's SOS rate increased from 3.8 cents/kWh to 5.121 cents/kWh. Unrecovered amounts to date will be recovered, subject to the rate reduction requirements of the Act.
In approving the new SOS rates, the MDTE also directed all electric distribution companies to file a report with the MDTE on their efforts to mitigate transition costs. On January 19, 2001, FG&E filed an extensive report detailing its mitigation activities, including contract restructurings, divestiture of its generating assets, and a variety of initiatives intended to reduce the burden of increasing energy prices on customers. While FG&E has substantially completed the divestiture of its generation assets, the Company continues to seek ways to reduce its transition costs and lower prices for customers.
On December 1, 2000, FG&E filed new electric rates for effect January 1, 2001. The revised rates maintain the required inflation-adjusted 15% rate discount. The MDTE approved final rates on December 29, 2000, subject to reconciliation pursuant to an investigation of actual and estimated transition costs, resulting in an upward inflation adjustment of 3.5% relative to 2000 rates.
New customers, and customers who previously opted to take electric supply service from a competitive provider, may purchase power through FG&E under Default Service. FG&E provides the Default Service through a third party supplier at market-based rates. The Company issued a Request for Proposals for Default Service in September 2000. FG&E awarded a contract and filed resulting rates which were approved effective for the period January through May 2001.
In June 2000, the MDTE opened an investigation into whether (1) metering, meter maintenance and testing, and customer billing and information services (MBIS) should be unbundled; and (2) the service territories of distribution companies should remain exclusive. On December 29, 2000, the MDTE issued its report recommending that the Legislature not take action to allow for the competitive provision of MBIS in the electric industry. The MDTE also concluded that exclusive service territories should remain intact.
Massachusetts Gas Restructuring - In mid-1997, the MDTE directed all Massachusetts natural gas Local Distribution Companies (LDCs) to form a collaborative with other stakeholders to develop common principles and appropriate regulations for the unbundling of gas service, and directed FG&E and four other LDCs to file unbundled gas rates for its review. FG&E's unbundled gas rates were filed with, and approved by, the MDTE and implemented in November 1998.
On February 1, 1999, the MDTE issued an order in which it determined that the LDCs would continue to have an obligation to provide gas supply and delivery services for another five years, with a review after three years. This order also set forth the MDTE's decision requiring mandatory assignment by LDCs of their pipeline capacity contracts to competitive marketers. In March 1999, the LDCs and other stakeholders filed a settlement with the MDTE, which set forth rules for implementing an interim firm transportation service through October 31, 2000. The MDTE approved the settlement on April 2, 1999. FG&E has made separate compliance filings that were approved by the MDTE to implement its interim firm gas transportation service for its largest general service customers and to complement this service with a firm gas peaking service. This interim service is now superseded by the permanent transportation service, which was approved for implementation on November 1, 2000.
On November 3, 1999, the Massachusetts LDCs filed Model Terms and Conditions for Gas Service, including provisions for capacity assignment, peaking service, and Default Service. In accordance with the MDTE's approval of these Model Terms and Conditions in January 2000, FG&E filed Company-specific tariffs that implement natural gas unbundling. The MDTE also opened a rulemaking proceeding on proposed regulations that would govern the unbundling of services related to the provision of natural gas. The MDTE has issued an order approving the tariffs and final regulations effective November 1, 2000.
New Hampshire Electric Restructuring - On February 28, 1997, the NHPUC issued its Final Plan for New Hampshire electric utilities to transition to a competitive electric market in the state (Final Plan). The Final Plan linked the interim recovery of stranded cost by the State's utilities to a comparison of their existing rates with the regional average utility rates. CECo's and E&H's rates are below the regional average; thus, the NHPUC found that CECo and E&H were entitled to full interim stranded cost recovery, as defined by the NHPUC. However, the NHPUC also made certain legal rulings which could affect CECo's and E&H's long-term ability to recover all of their stranded costs.
Northeast Utilities' affiliate Public Service Company of New Hampshire (PSNH) filed suit in U.S. District Court for protection from the Final Plan and related orders and was granted an indefinite stay. In June 1997, Unitil, and other utilities in New Hampshire, intervened as plaintiffs in the federal court proceeding. In June 1998, the federal court clarified that the injunctions issued by the court in 1997 had effectively frozen the NHPUC's efforts to implement restructuring. This amended injunction has been challenged by the NHPUC, and affirmed by the First Circuit Court of Appeals. Unitil continues to be a plaintiff-intervenor in federal district court. Further court proceedings are pending final resolution of electric restructuring for PSNH.
Unitil has continued to work actively to explore settlement options and to seek a fair and reasonable resolution of key restructuring policies and issues in New Hampshire. The Company is also monitoring the regulatory and legislative proceedings dealing with electric restructuring in the state. In October 2000, the NHPUC approved a settlement for the restructuring of PSNH. Appeals of the PSNH restructuring orders were denied by the New Hampshire Supreme Court and are now being pursued with the U.S. Supreme Court.
Pending Rate Proceedings - The last formal regulatory filings to increase base electric rates for Unitil's three retail operating subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. A majority of the Company's operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas, energy efficiency, and restructuring-related cost recovery mechanisms. Industry restructuring will continue to change the methods of how certain costs are recovered through the Company's regulated rates and tariffs.
As discussed above, FG&E filed for and received approval of an increase to its electric Standard Offer Service rate reflecting extraordinary increases in the price of oil and natural gas. FG&E also received an increase to its Cost of Gas Adjustment resulting in bill increases of approximately 25%, effective November 1, 2000. FG&E subsequently received another increase of approximately 20% to its Cost of Gas Adjustment for effect February 1, 2001. Wholesale natural gas prices reached record levels in New England and across the United States in response to cold weather and tight supplies. In New Hampshire, CECo and E&H filed and received approval of increases to their Fuel and Purchased Power Adjustments, resulting in bill increases of 25% to 34%, depending upon usage patterns, effective January 1, 2001. These higher fuel costs are a pass-through without markup or profit. Retail electricity prices for most New England utilities are increasing this winter.
On May 15, 1998, FG&E filed a gas base rate case with the MDTE. The last base rate case had been in 1984. After evidentiary hearings, the MDTE issued an Order allowing FG&E to establish new rates, effective November 30, 1998, which would produce an annual increase of approximately $1.0 million in gas revenues. As part of the proceeding, the Massachusetts Attorney General alleged that FG&E had double-collected fuel inventory finance charges, and requested that the MDTE require FG&E to refund approximately $1.6 million in double collections since 1987. The Company believes that the Attorney General's claim is without merit and that a refund was not justified or warranted. The MDTE rejected the Attorney General's request and stated its intent to open a separate proceeding to investigate the Attorney General's claim. On November 1, 1999, the MDTE issued an Order of Notice initiating an investigation of this matter. Hearings were held in early 2000 and were reopened in November 2000 to hear new evidence. Supplemental testimony has been filed and additional hearings were held in February 2001.
On October 29, 1999, the MDTE initiated a proceeding to implement Performance Based Rate making (PBR) for all electric and gas distribution utilities in Massachusetts. PBR is a method of setting regulated distribution rates that provide incentives for utilities to control costs while maintaining a high level of service quality. Under PBR, a company's earnings are tied to performance targets, and penalties can be imposed for deterioration of service quality. On December 29, 1999, FG&E filed a petition with the MDTE for authority to defer for later recovery costs associated with its preparation of a PBR filing for its gas division and its participation in the MDTE-initiated generic gas and electric PBR proceedings. This petition and the MDTE's generic proceeding are pending. The Company is currently evaluating the impact, if any, that PBR would have on the Company's ability to continue applying the standards of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation."
On December 31, 1999, the Massachusetts Attorney General filed a complaint against FG&E requesting that the MDTE investigate the distribution rates, rate of return, and depreciation accrual rates for FG&E's electric operations in calendar year 1999. The MDTE opened a proceeding in November 2000, held a public hearing and procedural conference in December 2000, and subsequently issued a procedural schedule covering the period January through April 2001. Any order received from the MDTE would apply to the Company's rates prospectively and would not be retroactive. Management is unable to predict the outcome of this proceeding but an unfavorable result could have an adverse impact on the Company's consolidated financial position.
Millstone Unit No. 3 - FG&E has a 0.217% nonoperating ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which calls for increased NRC inspection attention. In March 1996, as a result of engineering evaluations, Millstone 3 was taken out of service. The NRC authorized the restart of Millstone 3 in June 1998.
During the period that Millstone 3 was out of service, FG&E continued to incur its proportionate share of the unit's ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E also incurred costs to replace the power that was expected to be generated by the unit. During the outage, FG&E incurred approximately $1.2 million in replacement power costs, and recovered those costs through its electric fuel charge, which is subject to review and reconciliation by the MDTE. Under existing MDTE precedent, FG&E's replacement power costs of $1.2 million could be subject to disallowance in rates.
In August 1997, FG&E, in concert with other non-operating joint owners, filed a demand for arbitration in Connecticut and a lawsuit in Massachusetts, in an effort to recover costs associated with the extended unplanned shutdown. Several preliminary rulings have been issued in the arbitration and legal cases, and both cases are continuing. On March 22, 2000, FG&E entered into a settlement agreement with the defendants under which FG&E will dismiss its lawsuit and arbitration claims. The settlement is generally similar to earlier settlements with the defendants, and three joint owners that own, in the aggregate, approximately 19% of the unit. The settlement provides for FG&E to receive an initial payment of $600,000 and other amounts contingent upon future events and would result in FG&E's entire interest in the unit being included in the auction of the majority interest, and certain of the minority interests, in Millstone 3, which is expected to be completed by 2001. Upon completion of the sale of Millstone 3, FG&E will be relieved of all residual liabilities, including decommissioning liabilities, associated with Millstone 3. FG&E expects to flow through the net proceeds of the settlement to its customers .
On September 8, 2000, Western Massachusetts Electric Company, New England Power Company, and FG&E together filed a Joint Petition requesting approval by the MDTE of the sale of their respective interests in Millstone Units 1, 2, and 3. The Companies also requested MDTE findings that the divested assets qualify as "eligible facilities" pursuant to Section 32 (c) of the Public Utility Holding Company Act of 1935. The MDTE approved the sale and certified the unit as an "eligible facility" on December 22, 2000. The parties to the sale transaction are currently awaiting other state and federal regulatory approvals for the final sale of the Millstone units.
Market Risk - Although Unitil's utility operating companies are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of fuel and gas costs in rates. Consequently, there is limited commodity price risk after consideration of the related rate-making. As the utility industry deregulates, the Company will be divesting its commodity-related energy businesses and therefore will be further reducing its exposure to commodity-related risk.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Information required by this Item is set forth in Exhibit 99.1 on pages 2 through 8 of the 2000 Proxy Statement.
Item 11.
Item 11.
Executive Compensation
Information required by this Item is set forth in Exhibit 99.1 on pages 9 through 14 of the 2000 Proxy Statement.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by this Item is set forth in Exhibit 99.1 on pages 3 through 5 of the 2000 Proxy Statement and is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions
None
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) and (2) -
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
The following financial statements are included herein under Part II, Item 8, Financial Statements and Supplementary Data:
Report of Independent Certified Public Accountants
Consolidated Balance Sheets - December 31, 2000 and 1999
Consolidated Statements of Earnings for the years ended December 31, 2000, 1999, and 1998
Consolidated Statements of Capitalization - December 31, 2000 and 1999
Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999, and 1998
Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2000, 1999, and 1998
Notes to Consolidated Financial Statements
The following consolidated financial statement schedule of the Company and subsidiaries is included in Item 14(d):
Schedule II Valuation and Qualifying Accounts for December 31, 2000, 1999, and 1998
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions, are inappropriate, or information required is included in the financial statements or notes thereto and, therefore, have been omitted.
(3) - List of Exhibits
Exhibit Number
Description of Exhibit
Reference*
3.1
Articles of Incorporation
of the Company
Exhibit 3.1 to Form
S-14 Registration Statement 2-93769
3.2
Articles of Amendment to the Articles of Incorporation
Filed on March 4, 1992 and April 30, 1992
Exhibit 3.2 to Form 10-K for 1992
3.3
By-laws of the Company.
Exhibit 3.2 to Form
S-14 Registration Statement 2-93769
3.4
Articles of Exchange of Concord Electric Company (CECo),
Exeter & Hampton Electric Company (E&H) and the Company.
Exhibit 3.3 to
10-K for 1984
3.5
Articles of Exchange of CECo, E&H, and the Company - Stipulation of the Parties Relative to Recordation and Effective Date.
Exhibit 3.4 to
Form 10-K for 1984
3.6
The Agreement and Plan of Merger dated March 1, 1989 among the Company, Fitchburg Gas and Electric Light Company (FG&E) and UMC Electric Co., Inc. (UMC).
Exhibit 25(b) to
Form 8-K dated
March 1, 1989
3.7
Amendment No. 1 to The Agreement and Plan of Merger dated March 1, 1989 among the Company, FG&E and UMC
Exhibit 28(b) to
Form 8-K dated December 14, 1989
.
4.1
Indenture of Mortgage and Deed of Trust dated July 15, 1958 of CECo relating to First Mortgage Bonds, Series B, 4 3/8% due September 15, 1988 and all Series unless supplemented.
**
4.2
First Supplemental Indenture dated January 15, 1968 relating to CECo's First Mortgage Bonds, Series C, 6 3/4% due January 5, 1998 and all additional series unless supplemented.
**
4.3
Fourth Supplemental Indenture dated March 28, 1984 amending CECo's Original First Mortgage Bonds Indenture, and First, Second and Third Supplemental Indentures and all additional series unless supplemented.
**
4.4
Eight Supplemental Indenture dated October 14, 1994 relating to CECo's First Mortgage Bonds, Series I, 8.49% due October 14, 2024 and all additional series unless supplemented.
Exhibit 4.8 to
Form 10-K for 1994
4.5
Ninth Supplemental Indenture dated September 1, 1998 relating to CECo's. First Mortgage Bonds, Series J, 6.96% due September 1, 2028
Exhibit 4.24 to
Form 10-K for 1998
4.6
Indenture of Mortgage and Deed of Trust dated December 1, 1952 of E&H relating to all series unless supplemented.
Exhibit 4.5 to Registration Statement 2-49218
4.7
Eighth Supplemental Indenture dated October 29, 1987 relating to E&H's First Mortgage Bonds, Series I, 9.85% due October 15, 1997 and all additional series unless supplemented.
Exhibit 4.15 to
Form 10-K for 1987
4.8
Tenth Supplemental Indenture dated October 14, 1994 relating to E&H's First Mortgage Bonds, Series K, 8.49% due October 14, 2024 and all additional series unless supplemented.
Exhibit 4.17 to
Form 10-K for 1994
4.9
Eleventh Supplemental Indenture dated September 1, 1998 relating to E&H's First Mortgage Bonds, Series L, 6.96% due September 1, 2028
.
Exhibit 4.23 to
Form 10-K for 1998
4.10
FG&E Purchase Agreement dated March 20, 1992 for the 8.55% Senior Notes due March 31, 2004
Exhibit 4.18 to
Form 10-K for 1993
4.11
FG&E Note Agreement dated November 30, 1993 for the 6.75% Notes due November 23, 2023.
Exhibit 4.18 to
Form 10-K for 1993
4.12
Note Agreement dated January 26, 1999 for the 7.37% Notes due January 15, 2028.
Exhibit 4.25 to
Form 10-K for 1999
4.13
Unitil Realty Corp. Note Purchase Agreement dated July 1, 1997 for the 8.00% Senior Secured Notes due August 1, 2017.
Exhibit 4.22 to
Form 10-K for 1997
10.1
Unitil System Agreement dated June 19, 1986 providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H.
Exhibit 10.9 to
Form 10-K for 1986
10.2
Supplement No. 1 to Unitil System Agreement providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H.
Exhibit 10.8 to
Form 10-K for 1987
10.3
Transmission Agreement between Unitil Power Corp. and Public Service Company of New Hampshire, effective November 11, 1992.
Exhibit 10.6 to
Form 10-K for 1993
10.4
Form of Severance Agreement dated February 21, 1989, between the Company and the persons named in the schedule attached thereto.
Exhibit 10.55 to
Form 8 dated
April 12, 1989
10.5
Key Employee Stock Option Plan effective January 17, 1989.
Exhibit 10.56 to
Form 8 dated
April 12, 1989
10.6
Unitil Corporation Key Employee Stock Option Plan Award Agreement.
Exhibit 10.63 to
Form 10-K for 1989
10.7
Unitil Corporation Management Performance Compensation Plan.
Exhibit 10.94 to
Form 10-K/A for 1993
10.8
Unitil Corporation Supplemental Executive Retirement Plan effective as of January 1, 1987.
Exhibit 10.95 to
Form 10-K/A for 1993
10.9
Unitil Corporation 1998 Stock Option Plan.
Exhibit 10.12 to
Form 10-K for 1998
10.10
Unitil Corporation Management Incentive Plan.
Exhibit 10.13 to
Form 10-K for 1998
10.11
Entitlement Sale and Administrative Service Agreement with Select Energy.
Exhibit 10.14 to
Form 10-K for 1999
10.12
Purchase and Sale Agreement For New Haven Harbor.
Exhibit 10.15 to
Form 10-K for 1999
10.13
Labor Agreement effective June 1, 2000 between CECo and The International Brotherhood of Electrical Workers, Local Union No. 1837.
Filed herewith
10.14
Labor Agreement effective June 1, 2000 between E&H and The International Brotherhood of Electrical Workers, Local Union No. 1837.
Filed herewith
10.15
Labor Agreement effective June 1, 2000 between FG&E and The Utility Workers of America, AFL-CIO., Local Union No. B340, The Brotherhood of Utility Workers Council.
Filed herewith
11.1
Statement Re: Computation in Support of Earnings per Share For the Company.
Filed herewith
12.1
Statement Re: Computation in Support of Ratio of Earnings to Fixed Charges for the Company.
Filed herewith
21.1
Statement Re: Subsidiaries of Registrant.
Filed herewith
23.1
Consent of Independent Certified Public Accountants
Filed herewith
99.1
2000 Proxy Statement.
Filed herewith
* The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference.
** Copies of these debt instruments will be furnished to the Securities and Exchange Commission upon request.
(b) Report on Form 8-K
No reports on Form 8-K were filed during the fourth quarter of the year ended December 31, 2000.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Unitil Corporation
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Capacity
Date
/s/ Robert G. Schoenberger
Principal Executive
March 20, 2001
Robert G. Schoenberger
Officer; Director
/s/ Michael J. Dalton
Principal Operating
March 20, 2001
Michael J. Dalton
Officer; Director
/s/ Anthony J. Baratta, Jr.
Principal Financial
March 20, 2001
Anthony J. Baratta, Jr.
Officer
/s/ Albert H. Elfner, III
Director
March 20, 2001
Albert H. Elfner, III
/s/ Ross B. George
Director
March 20, 2001
Ross B. George
/s/ Bruce W. Keough
Director
March 20, 2001
Bruce W. Keough
/s/ M. Brian O'Shaughnessy
Director
March 20, 2001
M. Brian O'Shaughnessy
/s/ J. Parker Rice, Jr.
Director
March 20, 2001
J. Parker Rice, Jr.
/s/ Charles H. Tenney III
Director
March 20, 2001
Charles H. Tenney III
/s/ William E. Aubuchon, III
Director
March 20, 2001
William E. Aubuchon, III
/s/ Joan D. Wheeler
Director
March 20, 2001
Joan D. Wheeler
/s/.Eben S. Moulton
Director
March 20, 2001
Eben S. Moulton
SCHEDULE II
UNITIL CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES