Item 1. BUSINESS
The following are discussed under the general heading of "Business". Reference is made to the various other Items as applicable.
CORPORATE STRUCTURE
RGS Energy Group Inc. Incorporated in 1998 in the State of New York, RGS became the holding company for RG&E on August 2, 1999. RGS has no employees and no significant business operations other than through RG&E and RGS's other subsidiaries as described below.
Rochester Gas and Electric Corporation. Incorporated in 1904 in the State of New York, RG&E is engaged principally in the business of generating, purchasing, transmitting and distributing electricity, and purchasing, transporting and distributing natural gas. The business produces and distributes electricity and distributes gas in parts of nine counties centering about the City of Rochester. At December 31, 1999 the RG&E had 1,975 employees.
RG&E's service area for its regulated business has a population of approximately one million and is well diversified among residential, commercial and industrial consumers. In addition to the City of Rochester, which is the
third largest city and a major industrial center in New York State, it includes a substantial suburban area with commercial growth and a large and prosperous farming area. A majority of the industrial firms in RG&E's service area manufacture consumer goods. Many of RG&E's industrial customers are nationally known, such as Xerox Corporation, Eastman Kodak Company, Bausch & Lomb Incorporated and Delphi Automotive Systems, Inc.
Energetix, Inc. It is part of the Company's financial strategy to seek growth by entering into unregulated businesses. The Competitive Opportunities Settlement (discussed under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations) allows the Company to invest up to $100 million in unregulated businesses. The first step in this direction was the formation and operation of Energetix. Energetix is an unregulated subsidiary that brings energy products and services to the marketplace including the marketing of electricity, natural gas, gasoline, oil and propane fuel energy services in an area extending approximately in a 150-mile radius around Rochester. Energetix has over 15,000 customers for natural gas and electricity service.
Acquisitions under Energetix' control include Griffith Oil Co., Inc., the second largest oil and propane distribution company in New York State, and Stanbury Propane, Bobbett Gas Service and Clark Oil. The acquisitions give Energetix access to 70,000 customers, 65,000 of which are residing outside of the RG&E's regulated franchise territory. Including the acquisitions, Energetix has 379 employees and operates 18 customer service centers.
RGS Development Corporation. In 1998, the Company formed RGS Development to pursue unregulated business opportunities in the energy marketplace. RGS Development operations have not been material to RGS's results of operations or its financial condition.
Seasonal Nature of Business. The business of RGS and RG&E is seasonal. With respect to electricity, winter peak loads are attained due to spaceheating sales and shorter daylight hours and summer peak loads are reached due to the use of air-conditioning and other cooling equipment. With respect to natural gas, kerosene, propane and heating oil, the greatest sales occur in the winter months due to spaceheating usage. In addition, gasoline sales reflect seasonal fluctuations due to increased consumer driving during the warmer months. In each of the communities in which it renders regulated utility service, RG&E, with minor exceptions, holds the necessary municipal franchises, none of which contains burdensome restrictions. The franchises are non-exclusive, and are either unlimited as to time or run for terms of years.
Segment Information. Information concerning revenues, operating profits and identifiable assets for significant industry segments is set forth in Note 4 of the Notes to the Company's financial statements under Item 8. Information relating to the principal classes of service from which regulated electric and gas revenues are derived and other operating data are included herein under "Operating Statistics". A discussion of the causes of significant changes in revenues is presented in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations. Percentages of the Company's operating revenues derived from electric and gas service and unregulated businesses for each of the last three years are as follows:
RGS is operating in a rapidly changing competitive marketplace for electric and gas service. This competitive environment includes a federal and State trend toward deregulation and promotion of open-market choices for consumers.
See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Competition" for further information on the Competitive Opportunities Settlement, Energy Choice Program, FERC Open Access, PSC Proceeding on Nuclear Generation, Proposed Purchase of Nuclear Plants, PSC Gas Restructuring and the competitive challenges the Company faces in its electric and gas business and how it is responding to those challenges.
ELECTRIC OPERATIONS
Overview. In November 1997 the PSC approved a Settlement Agreement among RG&E, PSC staff and other parties which sets the framework for the introduction and development of open competition in the electric energy marketplace in New York State through July 1, 2002. Regarding RG&E's electric business, starting in 1996 the FERC issued new rules to facilitate the development of competitive wholesale markets. In 1998, FERC issued an order that conditionally authorizes the establishment of an independent system operator (NYISO) to administer a state-wide open access tariff. In 1999 the FERC issued an Order approving the NYISO Open Access tariff, the NYISO Services tariff and the related ISO Agreements of each of the Member Systems of the New York Power Pool. In November 1999 the NYISO implemented a competitive wholesale market for the sale, purchase and transmission of electricity in New York State. In December 1999 FERC issued Rule No. 2000 which calls for transmission owners to join regional transmission organizations to boost competition (see following discussion under "Regulatory Matters"). At the State level, the PSC endorsed a fundamental restructuring of the electric utility industry in the State in its "Competitive Opportunities Proceeding". RG&E's Competitive Opportunities Settlement in 1997, including its retail access program called "Energy Choice", allows for a phase- in to open electric markets while lowering customer prices and establishing an opportunity for competitive returns on shareholder investments. Through December 31, 1999, eight energy service companies have been qualified by the Company to serve retail customers under the Energy Choice Program.
In December 1999, RG&E exercised its right-of-first-refusal to acquire the interests of Niagara Mohawk Power Corporation (Niagara Mohawk) and New York State Electric and Gas Corporation (NYSEG)in the Nine Mile Two Plant and to buy Nine Mile One (see Item 7 under the heading "Proposed Purchase of Nuclear Plants" for further information). In a number of proceedings involving nuclear generation in New York State, including the proceedings related to the proposed sale of interests in Nine Mile, the PSC is expected to address issues related to the future of nuclear generation in the State. A final determination of these issues is not expected until later in 2000.
Electric System. The total net generating capacity of RG&E's electric system is 1,033,000 kilowatts (Kw). In addition RG&E purchases 120,000 Kw of
firm power under contract and 35,000 Kw of non-contractual peaking power from the New York Power Authority (NYPA), 150,000 Kw of a 1,000,000 Kw pumped storage plant owned by NYPA in Schoharie County, New York and 44,000 Kw of firm power from NYPA's 821,000 Kw FitzPatrick Nuclear Power Plant near Oswego, New York. RG&E's net peak load of 1,433,000 Kw occurred on July 6, 1999.
The percentages of electricity actually generated and purchased for the years 1995-1999 are as follows:
Generating Facilities. The RG&E's four major generating facilities are two nuclear units, the Ginna Nuclear Plant (Ginna Plant) and the Company's 14% share of Nine Mile Point Nuclear Plant Unit No. 2 (Nine Mile Two), and two fossil fuel generating stations, the Russell and Allegany Stations. In terms of capacity these comprise 46%, 15%, 25% and 6%, respectively, of the Company's current electric generating system. For information relating to the retirement of Beebee Station and the sale of Oswego Unit Six in 1999 see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - "Fossil Unit Status".
Nine Mile Two, a nuclear generating unit in Oswego County, New York with a designed capability of 1,143 Mw as estimated by Niagara Mohawk, was completed and entered commercial service in Spring 1988. Niagara Mohawk is operating the Unit on behalf of all owners pursuant to a full power operating license, which the NRC issued on July 2, 1987 for a 40-year term beginning October 31, 1986. Under arrangements dating from September 1975, ownership, output and cost of the project are shared by the Company (14%), Niagara Mohawk (41%) Long Island Power Authority (formerly Long Island Lighting Company) (18%), NYSEG (18%) and Central Hudson Gas & Electric Corporation (9%). Under the operating Agreement, Niagara Mohawk serves as operator of Nine Mile Two, but all five cotenant owners share certain policy, budget and managerial oversight functions. Niagara Mohawk and NYSEG have proposed to sell their interests in Nine Mile Two and Nine Mile One to AmerGen and to turn over operational control of the plants to AmerGen as well. RG&E has exercised its right to match the AmerGen offer and proposes to purchase the interests and enter into an operating agreement with Entergy Nine Mile, LLC (see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - "Proposed Purchase of Nuclear Plants"). The gross and net book cost of the RG&E's share of the Nine Mile Two facility including $374 million of disallowed costs previously written off, as of December 31, 1999 are $880 million and $376 million, respectively.
RG&E's Ginna Plant, which has been in commercial operation since July 1, 1970, provides 480 Mw of the RG&E's electric generating capacity. In August 1991 the NRC approved the RG&E's application for amendment to extend the Ginna Plant operating license expiration date from April 25, 2006 to September 18, 2009.
The gross and net book cost of the Ginna Plant facility as of December 31, 1999 are $579 million and $267 million, respectively. From time to time the NRC issues directives requiring all or a certain group of reactor licensees to perform analyses as to their ability to meet specified criteria, guidelines or operating objectives and where necessary to modify facilities, systems or procedures to conform thereto. Typically, these directives are premised on the NRC's obligation to protect the public health and safety. RG&E reviews such directives and implements a variety of modifications based on these directives and resulting analyses. Expenditures at the Ginna Plant, including the cost of these modifications, are estimated to be $5.2 million, $7.5 million and $8.0 million for the years 2000, 2001 and 2002, respectively, and are included in the capital expenditure amounts presented under Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations.
RG&E has three licensed hydroelectric generating stations (Stations 2,5 and 26) with an aggregate capability of 47 megawatts.
Insurance. The Price-Anderson Act establishes a federal program insuring against public liability in the event of a nuclear accident at a licensed U.S. reactor. Under the program, claims would first be met by insurance which licensees are required to carry in the maximum amount available (currently $200 million). If claims exceed that amount, licensees are subject to a retrospective assessment up to $88.1 million per licensed facility for each nuclear incident, payable at a rate not to exceed $10 million per incident per year. Those assessments are subject to periodic inflation indexing and a surcharge for New York State premium taxes. RG&E's interests in two nuclear units could expose it to a potential liability for each accident of $100.4 million through retrospective assessments of $11.4 million per incident per year in the event of a sufficiently serious nuclear accident at its own or another U.S. commercial nuclear reactor.
As a licensee of a commercial nuclear power plant in the United States, RG&E is required to have and maintain financial protection to cover radiation injury claims of certain nuclear workers. RG&E purchases primary insurance to meet this requirement. On January 1, 1998, a new insurance policy was issued that applies to claims first reported on or after January 1, 1998. This policy has a limit of $200 million (reinstated annually if certain conditions are met) for radiation injury claims against RG&E, or against other licensees who are insured by this policy. If these claims exceed the $200 million limit of primary coverage, the provisions of the Price-Anderson Act (discussed above) would apply. Since reserves for outstanding claims under former policies could be insufficient and certain claims may still be made under former policies due to a discovery period, RG&E could be assessed under these former policies along with the other policyholders. RG&E's share could be up to $3.1 million in any one year.
RG&E is a member of Nuclear Electric Insurance Limited, which provides insurance coverage for the cost of replacement power during certain prolonged accidental outages of nuclear generating units and coverage for property damage at nuclear generating units. If an insuring program's losses exceeded its other resources available to pay claims, RG&E could be subject to maximum assessments in any one policy year of approximately $1.8 million and $8.0 million in the event of losses under the replacement power and property damage coverages, respectively.
GAS OPERATIONS
With the unbundling of interstate gas pipeline services as directed by FERC Order 636, primary responsibility for reliable natural gas has shifted from interstate pipeline companies to local distribution companies, such as the Company. All gas customers have had a choice of suppliers since November 1996,
subject to certain phase-in limitations through 1998 for loss of gas commodity sales. Some of these customers are large, nationally known, publicly held companies. In 1998 the PSC issued a gas restructuring policy statement which concluded, among other things, that the most effective way to establish a competitive gas supply market is for gas distribution companies to cease selling gas. For further information concerning issues relating to RG&E under the PSC's Gas Policy Statement see Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Rates and Regulatory Matters".
As of December 31, 1999 RG&E's daily city gate resource capability is 3,700,000 therms and its daily contracted transportation capacity is 4,493,000 therms (where one Therm is equivalent to 100,000 British Thermal Units). RG&E optimizes its assets by contracting for gas resources that align with its system requirements. RG&E experienced on January 19, 1994, its maximum daily throughput of approximately 4,740,000 therms, (3,910,000 therms sold to retail customers and 830,000 therms delivered for transportation customers).
RG&E sells, distributes and transports natural gas to a geographic territory in a nine-county area centered around the City of Rochester, NY. RG&E purchases all of its required gas supply from numerous marketers and producers under contracts containing various terms and conditions. RG&E's natural gas supply mix includes long-term, short-term and spot natural gas purchases transported on both firm and interruptible transportation contracts. Approximately 30% of the gas delivered to customers by RG&E during 1999 was purchased directly by commercial, industrial and municipal customers from energy marketers. RG&E provided the transportation of gas on its system to these customers' premises. As RG&E customers continue to migrate to gas marketers, including Energetix, RG&E is terminating gas supply and transportation contracts upon expiration.
During 1999, approximately 80% of RG&E's natural gas supply was purchased from various suppliers under long-term and short-term contracts which includes baseload monthly purchases and 20% was purchased on the daily spot natural gas market to maximize natural gas cost savings. The company hedges its exposure to fluctuations in natural gas commodity prices through the use of futures contracts and storage assets.
UNREGULATED OPERATIONS
Energetix serves over 15,000 electric and gas customers and appliance service warranty customers and, through its acquisitions of Griffith Oil Company, Inc., Stanbury Propane, Clark Oil and Bobbett Gas Service approximately 70,000 customers for its other products including oil, diesel, kerosene, propane and gasoline. See Note 4 of the Notes to Financial Statements for additional operating information and Management's Discussion and Analysis of Financial Condition and Results of Operations under Unregulated Operating Revenues and Sales for information on products, revenues and sales.
REGULATORY MATTERS
RG&E is subject to PSC regulation of rates, service, and sale of securities, among other matters. RG&E is also regulated by the FERC on a limited basis, in the areas of interstate sales and exchanges of electricity, intrastate sales of electricity for resale, transmission wheeling service for other utilities, and licensing of hydroelectric facilities. As a licensee and operator of nuclear facilities, RG&E is also subject to regulation by the Nuclear
Regulatory Commission (NRC). The impact of regulation is discussed throughout this report.
FERC ORDER NO. 2000. On December 15, 1999, FERC adopted Order No. 2000 (the Rule), a significant action regarding electric industry restructuring which calls for transmission owners to join regional transmission organizations (RTOs) on a voluntary basis. The RTOs will serve as umbrella organizations, which will put all public utility transmission facilities in a region under common control. RTOs are expected to benefit consumers through lower electricity rates resulting from a wider choice of services and service providers. FERC is scheduling regional workshops in the first half of 2000 as part of a collaborative process to accommodate regional needs. The Rule requires all public utilities that own, operate or control interstate transmission facilities to file by October 15, 2000(or for public utilities like RG&E already participating in an ISO by January 15, 2001), a proposal for an RTO, or, alternatively, a description of any efforts made by the utility to participate in an RTO.
On November 18, 1999 the NYISO implemented a competitive wholesale market for the sale, purchase and transmission of electricity and ancillary services in New York State. Previously, FERC authorized the NYISO, approved tariffs and approved ISO agreements of the Member Systems. Whether the NYISO is considered an RTO under the Rule is expected to be determined as part of the collaborative process described above. For further information regarding "FERC Open Access Transmission Orders and Company Filings" see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Additional information regarding the Rule and the characteristics and functions of an RTO can be found at http://www.ferc.fed.us/news1/policy/pages/orders.htm.
FERC GAS MARKET PROPOSALS. On July 29, 1998, the FERC issued a Notice of Proposed Rulemaking (NOPR) (RM98-10) on short-term natural gas transportation services, which proposed an integrated package of revisions to its regulations governing interstate natural gas pipelines. Under the proposed approach regulatory policies are intended to maximize competition in the short-term transportation market, mitigate the ability of companies to exercise residual pipeline market power, and provide opportunities for greater flexibility providing pipeline services without disadvantaging customers that have limited access to gas supplies. The proposed changes include, among other things, initiatives to revise pipeline scheduling procedures and the policies that govern the flow of gas through the pipelines; require pipelines to auction short-term capacity; and permit pipelines to negotiate rates and terms of services.
In conjunction with the NOPR, the FERC also issued a Notice of Inquiry (NOI) (RM98-12) on its pricing policies in the existing long-term market and pricing policies for new capacity. No final orders have been issued in these proceedings. Thus, the Company is presently unable to estimate the effects of these matters on future operations.
See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Rates and Regulatory Matters" for information regarding a gas restructuring policy statement, a gas interim settlement and approved proposal, and a flexible pricing tariff for major industrial and commercial electric customers.
FUEL SUPPLY
Nuclear. Generally, the nuclear fuel cycle consists of the following: (1) the procurement of uranium concentrate (yellowcake), (2) the conversion of uranium concentrate to uranium hexafluoride, (3) the enrichment of the uranium hexafluoride, (4) the fabrication of fuel assemblies, (5) the utilization of the nuclear fuel in generating station reactors and (6) the appropriate storage or disposition of spent fuel and radioactive wastes. Arrangements for nuclear fuel
materials and services for the Ginna Plant and Nine Mile Two have been made to permit operation of the units through the years indicated:
(1) Information was supplied by Niagara Mohawk Power Corporation.
(2) Arrangements have been made for procuring the majority of the uranium and conversion requirements through 2002, leaving the remaining portion of the requirements uncommitted.
(3) RG&E has two contracts in place which will supply 100 percent of the annual Ginna Plant uranium requirements in 2000. A third contract is in place, which is supplying 500,000 pounds of uranium between 1999 and 2004 as scheduled by RG&E. This material may be scheduled for delivery against requirements in 2001, or may be scheduled for later delivery depending on the market price of uranium at the time. The remaining requirements are uncommitted.
(4) A contract is in place covering 100% of requirements in 2000. Remaining requirements will be filled from market purchases or a new long term contract.
(5) RG&E has a contract for nuclear fuel enrichment services which, assures provision of 100% of the Ginna Plant's requirements through the end of the current operating license.
(6) Nine Mile Two is covered for 75% of requirements through 2003 (with an option to increase to 100%).
With appropriate lead times, RG&E will pursue arrangements for the supply of uranium requirements and related services beyond those years for which arrangements have been made as shown above.
See Note 10 of the Notes to Financial Statements under Item 8 for additional information regarding nuclear fuel disposal costs, nuclear plant decommissioning and DOE uranium enrichment facility decontamination and decommissioning.
Coal. RG&E's 2000 coal requirements are expected to be approximately 500,000 tons. In 1999 92% of its requirements were purchased under contract and 8% were purchased on the spot market. RG&E maintains a reserve supply of coal ranging from 30-60 days supply at maximum burn rates.
The sulfur content of the coal utilized in RG&E's coal-fired facility ranges from 1.0 to 2.0 pounds per million BTU. Under existing New York State regulations, RG&E's coal-fired facility may not burn coal which exceeds a sulfur content of 2.5 pounds per million BTU, and must average no higher than 1.7 pounds per million BTU over a 12-month period or 1.9 pounds per million BTU over a three-month period. In 2000, Phase II Acid Rain Requirements will apply, requiring the surrender of SO2 allowances to match SO2 emissions.
FINANCING AND CAPITAL REQUIREMENTS PROGRAM
A discussion of RGS's capital requirements, financial objectives and the resources available to meet such requirements may be found in Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of Operations. RG&E expects to issue up to $200 million of long-term debt in connection with its proposed acquisition of the Nine Mile One facility and the Niagara Mohawk and NYSEG interests in Nine Mile Two. Through December 31, 1999 RGS has repurchased 2.9 million shares of Common Stock under a program which began in May 1998. Common Stock is the only security issued by RGS. Preferred Stock and Mortgage Bonds have been issued by RG&E. The sale of additional issues of these securities by RG&E depends on regulatory approval and RG&E's ability to meet certain requirements contained in its mortgage and Restated Certificate of Incorporation.
Under the New York State Public Service Law, RG&E is required to secure authorization from the PSC prior to issuance of any stock or any debt having a maturity of more than one year.
RG&E's First Mortgage Bonds are issued under a General Mortgage dated September 1, 1918, between the Company and Bankers Trust Company, as Trustee, which has been amended and supplemented by forty supplemental indentures. Before additional First Mortgage Bonds are issued, the following financial requirements must be satisfied:
(a) The First Mortgage prohibits the issuance of additional First Mortgage Bonds unless earnings (as defined) for a period of twelve months ending not earlier than sixty days prior to the issue date of the additional bonds are at least 2.00 times the annual interest charges on First Mortgage Bonds, both those outstanding and those proposed to be outstanding. The ratio under this test for the twelve months ended December 31, 1999 was 5.83.
(b) The First Mortgage also provides that, if additional First Mortgage Bonds are being issued on the basis of property additions (as defined), the principal amount of the bonds may not exceed 60% of available property additions. As of December 31, 1999 the amount of additional First Mortgage Bonds which could be issued on that basis was approximately $423,190,000. In addition to issuance on the basis of property additions, First Mortgage Bonds may be issued on the basis of 100% of the principal amount of other First Mortgage Bonds which have been redeemed, paid at maturity, or otherwise reacquired by the Company. As of December 31, 1999, RG&E could issue $227,169,000 of Bonds against Bonds that have matured or been redeemed.
RG&E's Restated Certificate of Incorporation (Charter) provides that, without consent by two-thirds of the votes entitled to be cast by the preferred stockholders, RG&E may not issue additional preferred stock unless in a 12-month period within the preceding 15 months: (a) net earnings applicable to payment of dividends on preferred stock, after taxes, have been at least 2.00 times the annual dividend requirements on preferred stock, including the shares both outstanding and proposed to be issued, and (b) net earnings available for interest on indebtedness, after taxes, have been at least 1.50 times the annual interest requirements on indebtedness and annual dividend requirements on preferred stock, including the shares both outstanding and proposed to be issued. For the twelve months ended December 31, 1999, the coverage ratio under (b) above (the more restrictive provision) was 2.10.
For other information with respect to long-term and short-term borrowing arrangements and limitations see Item 8, Note 6 - Long-Term Debt and Note 9 - Short-Term Debt.
The Charter of RGS does not contain any financial tests for the issuance of common or preferred stock. The Charter of RG&E does not contain any financial tests for the issuance of common or preference stock.
RGS has not issued any mortgage bonds or preferred stock. RG&E's securities ratings at December 31, 1999 were:
The securities ratings set forth in the table are subject to revision and/or withdrawal at any time by the respective rating organizations and should not be considered a recommendation to buy, sell or hold securities of the Company.
ENVIRONMENTAL QUALITY CONTROL
Operations at RGS's facilities are subject to various federal, state and local environmental standards. To assure compliance with these requirements, RGS expended approximately $2.5 million on a variety of projects and facility additions during 1999.
The federal Low Level Radioactive Waste Policy Act (Act), as amended in 1985, provides for states to join compacts or individually develop their own low level radioactive waste disposal sites. The Company can provide no assurance as to what disposal arrangements, if any, New York will have in place. The State has not passed legislation that would designate a site for the disposal of low level radioactive waste. RG&E has storage capacity at the Ginna Plant through the end of its license in 2009. A low level radioactive waste management and contingency plan is currently ongoing to provide assurance that Nine Mile Two will be properly prepared to handle interim storage of low level radioactive waste for the next ten years and beyond, if necessary.
RG&E has wastewater discharge permits from NYSDEC for each of its steam electric generating stations. The Ginna Station permit is dated February 1998; the Beebee station permit is dated February 1999; and the Russell Station permit is dated June 1999. These permits are each valid for a period of five years from their effective dates. Consistent with the Ginna permit, no significant changes to the wastewater discharge treatment systems are currently required, nor anticipated. At Beebee station, the plant went off line in June, 1999. Two of three discharge points have either been re-routed or have ceased operation. The wastewater treatment plant continues to operate in a batch mode at a significantly reduced frequency. At Russell Station an oil/water separator has been installed as a preventive measure against oil contamination within the station wastewaters. The cost of this separator is approximately $.6 million.
RG&E is developing strategies responsive to the Federal Clean Air Act amendments of 1990 (CAA) which will primarily affect air emissions from RG&E's fossil-fueled generating facilities. The strategy being developed is a combination of hardware solutions which have a capital and operation and maintenance (O&M) component and allowance trading solutions which have only an O&M impact. The most recent strategic developments still envision this combination of efforts as the most cost effective means of proceeding although there is some New York State legislative activity that could impact RG&E's ability to rely upon the emission allowance market to meet some of its environmental commitments. RG&E cannot predict the outcome of these matters in the Legislature and, as a result, RG&E's projections are based solely on the combination strategy. Capital expenditures due to CAA requirements are expected to be limited to $0.3 million in 2000. In 2000, it is estimated that additional
O&M costs for emissions control will range between $2.7 million and $3.4 million. O&M costs could increase further after this point depending on new Federal and state regulations. Any further capital expenditures for additional NOx control have been deferred until after 2000. These additional capital costs and any increases in annual operating costs that would be incurred as a result of these capital additions beyond the year 2000 cannot be predicted accurately until a final strategy is chosen which will await pending Federal and State regulatory decisions. (See Item 8, Note 10 under the heading "Environmental Matters" regarding initiatives of the New York Governor concerning the state's oxides of nitrogen (NOx) and sulfur dioxide (SO2) control programs and the New York Attorney General requesting historic information regarding certain upgrades, modifications and maintenance activities at coal fired power plants.)
RG&E believes that additional expenditures and costs made necessary by mandated environmental protection programs will be allowable for ratemaking purposes under cost of service rate regulation; but under the terms of RG&E's Competitive Opportunities Settlement Agreement, which sets a threshold of $2.5 million for recoverability of expenditures and costs resulting from mandates, the full amount of these items may not be recoverable. Capital expenditures for meeting various federal, State and local environmental standards are estimated to be $0.3 million for the year 2000, $1.5 million for the year 2001 and $.5 million for the year 2002. These estimates, which could change based on the impact of the initiatives described above, are included under Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, in the table entitled "Capital Requirements".
See Item 3 - Legal Proceedings and Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, with respect to other environmental matters.
RESEARCH AND DEVELOPMENT
RG&E's research activities are designed to improve existing energy technologies and to develop new technologies for the production, distribution, utilization and conservation of energy while preserving environmental quality. Research and development expenditures in 1999, 1998 and 1997 were $2.9 million, $3.4 million, and $4.5 million, respectively. These expenditures represent RG&E's contribution to research administered by Electric Power Research Institute, New York Gas Group, Empire State Electric Energy Research Corporation and an assessment for state government sponsored research by the New York State Energy Research and Development Authority, as well as internal research projects.
Electric Department Statistics
* Reclassified for comparative purposes.
* Reclassified for comparative purposes.
** Method for determining daily capacity, based on current network analysis, reflects the maximum demand which the transmission systems can accept without a deficiency.
Item 2.
Item 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of RG&E's electric generating plants in operation as of December 31, 1999 and the net generation of each plant for the year ended December 31, 1999, and the year each plant was placed in service are as set forth below:
(1) Shutdown on May 1, 1999 and Unit retired. (2) 24% share of jointly-owned facility was sold in October 1999. (3) Represents 14% share of jointly-owned facility. (4) Owned and operated by NYPA.
RG&E owns 148 distribution substations having an aggregate rated transformer capacity of 2,213,054 Kva, of which 139, having an aggregate rated capacity of 2,033,888 Kva, were located on lands owned in fee, and nine of which, having an aggregate rated capacity of 179,166 Kva, were located on land under easements, leases or license agreements. RG&E also has 69,528 line transformers with a capacity of 2,790,953 Kva. RG&E also owns 23 transmission substations having an aggregate rated transformer capacity of 3,335,617 Kva of which 22, having an aggregate rated capacity of 3,260,950 Kva, were located on land owned in fee and one, having a rated capacity of 74,667 Kva, was located on land under easements. RG&E's transmission system consists of approximately 716 circuit miles of overhead lines and approximately 405 circuit miles of underground lines. The distribution system consists of approximately 16,266 circuit miles of overhead lines, approximately 3,927 circuit miles of underground lines and 357,371 installed meters. The electric transmission and distribution system is entirely interconnected and, in the central portion of the City of Rochester, is underground. The electric system of RG&E is directly interconnected with other electric utility systems in New York and indirectly interconnected with most of the electric utility systems in the United States and Canada. (See Item 1 - Business, "Electric Operations".)
GAS PROPERTIES
The gas distribution systems consist of 4,280 miles of gas mains and 297,217 installed meters. (See Item 1 - Business, "Gas Operations" and "Gas Department Statistics".
UNREGULATED SUBSIDIARIES
Griffith, including its subsidiaries, owns or leases 50 properties for use in its business operations. These properties consist of:
- (3) Pipeline Terminal facilities: these major bulk petroleum storage facilities are primarily supplied by pipeline and have an aggregate storage capacity of approximately 475,000 barrels.
- (11) Bulk Plant Facilities: these bulk petroleum facilities are primarily supplied by truck and have an aggregate storage capacity of 105,000 barrels.
- (14) Service Stations: these retail sites are sublet to a dealer who provides various services at retail to the general public.
- (22) Other properties: there are a mixture of other properties including office buildings, warehouses and garage facilities used in the general operation of the business.
OTHER PROPERTIES
RG&E owns a ten-story office building centrally located in Rochester and other structures and property. RG&E also leases approximately 453,000 square feet of facilities for administrative offices and operating activities in the Rochester area.
RG&E has good title in fee, with minor exceptions, to its principal plants and important units, except rights of way and flowage rights, subject to restrictions, reservations, rights of way, leases, easements, covenants, contracts, similar encumbrances and minor defects of a character common to
properties of the size and nature of those of the Company. The electric and gas transmission and distribution lines and mains are located in part in or upon public streets and highways and in part on private property, either pursuant to easements granted by the apparent owner containing in some instances removal and relocation provisions and time limitations, or without easements but without objection of the owners. The First Mortgage securing RG&E's outstanding bonds is a first lien on substantially all the property owned by RG&E (except cash and accounts receivable). Mortgages securing RG&E's revolving credit agreement and a long term note are also liens on substantially all the property owned by RG&E (except cash and accounts receivable) subject and subordinate to the lien of the First Mortgage. RG&E has credit agreements with a domestic bank under which short-term borrowings are secured by RG&E's accounts receivable.
Item 3.
Item 3. LEGAL PROCEEDINGS
RG&E-OWNED WASTE SITE ACTIVITIES. As part of its commitment to environmental excellence, RG&E is conducting proactive Site Investigation and/or Remediation (SIR) efforts at seven Company-owned sites where past waste handling and disposal may have occurred. Remediation activities at five of these sites are in various stages of planning or completion and the Company is conducting a program to restore the other two sites. RG&E has recorded a total liability of approximately $21.9 million which it anticipates spending on SIR efforts at the seven Company-owned sites. Through December 31, 1999 the Company has incurred aggregate costs of $4.3 million for these sites.
In mid-1995, the New York State Department of Environmental Conservation (NYSDEC) developed a listing of sites called "The Hazardous Substance Site Inventory". Under current New York State law, unless a site, which is determined to pose a public health or environmental risk, contains hazardous wastes, State "Superfund" monies cannot be used to assist in the cleanup. The State wanted to have some sense of the scale of this problem before the legislature considered other avenues of legal and financial redress than those currently available. The NYSDEC's "Hazardous Substance Waste Disposal Site Study" was developed to assess the number of and cost to remediate sites where hazardous chemicals, but not hazardous wastes are present. Of the seven RG&E- owned sites three are listed in this inventory. These are East Station, Front Street and Brooks Avenue, all located in Rochester, NY. In addition to these three sites, the inventory includes Ambrose Yard and Lindberg Heat Treating. These two sites are owned by RG&E (and are in addition to the seven mentioned above) however, RG&E does not believe that additional SIR work for which it is responsible is required at either site. At this time, RG&E is unable to predict what action will be necessitated as a result of the listing.
In June, 1999, RG&E was named as a codefendant in a legal action brought by a party who purchased a portion of its Ambrose Yard property. The party has claimed that the RG&E's historic activities on the property resulted in the presence of residual contaminants that have adversely impacted the party's use of the property. RG&E is just beginning to investigate the claim and does not know whether the claim has any merit. There is insufficient information available at this time to predict the economic impact of the claim on RG&E.
Manufactured Gas Sites. RG&E and its predecessors formerly owned and operated five manufactured gas facilities for which SIR costs are estimated to be approximately $20 million. Three sites, located in the Rochester area are known as West Station, East Station and Front Street. Cleanup activities on a portion of the West Station site were concluded in July 1996 under a voluntary agreement with the NYSDEC. RG&E received release from future liability and a covenant not to sue from the NYSDEC for this work. There remain other portions of the property where additional remedial work is expected; however, only a preliminary scope and schedule have been determined.
At the second site known as East Station, an interim remedial action was undertaken in late 1993. Ground water monitoring wells were also installed to assess the quality of the ground water at this location. RG&E has informed the NYSDEC of the results of the samples taken. A supplemental remedial
investigation and feasibility study was undertaken and a draft report is in preparation at this time.
At the third site (Front Street), RG&E signed a consent order to perform limited remedial activities. That work was completed in late 1998. Additional investigative work and remedial action is expected to occur under separate agreement now under negotiation.
Another property owned by RG&E where gas manufacturing took place is located in Canandaigua, New York. Limited investigative work performed there during the summer of 1995 has shown evidence of both the former gas manufacturing operations and leakage from fuel tanks. The NYSDEC was informed; the fuel tanks removed; and additional investigative work continues. The NYSDEC is awaiting the Company's proposal for supplemental remedial investigation.
A preliminary phase 1 investigation was completed in 1998 on a 3/4 acre site located in Brockport, New York. Evidence of residuals from gas manufacturing operations suggest further investigation is necessary and may ultimately warrant remedial action. No estimates can be made based on available information at this time.
Other Sites. On another portion of RG&E's property in Rochester, NY (Brewer Street), the County of Monroe has installed and operates sewer lines. During sewer installation, the County constructed over Company property certain retention ponds which reportedly received from the sewer construction area certain waste materials (the materials) found there. In a November 1997 letter, the County claimed that RG&E was the original generator of the materials and asserted that the Company was liable to the County for 50% of all County costs incurred to date to excavate, treat and dispose of the materials placed in the ponds and to implement whatever further cleanup activities may be required by the NYSDEC. RG&E and the County have reached a settlement agreement. Pursuant to the settlement, RG&E will bear 20% of the remediation costs and has committed to be responsible for the construction management function. RG&E's overall costs are estimated to be approximately $1.3 million, excluding a 20% share of ongoing long-term operation and maintenance work which is judged to be insignificant at this time. There is a mutual waiver and release as to all past claims regarding this property.
Monitoring wells installed at another Company facility (Brooks Avenue) revealed that an undetermined amount of leaded gasoline had reached the ground water. The Company has continued to monitor free product levels in the wells, and has begun a modest free product recovery project. It is estimated that further investigative work into this problem may cost up to $100,000. While the cost of corrective actions cannot be determined until investigations are completed, preliminary estimates of additional costs are not expected to exceed $400,000.
SUPERFUND AND NON-OWNED OTHER SITES. RG&E has been or may be associated as a potentially responsible party at eight sites not owned by it and has recorded estimated liabilities of approximately $.5 million in connection with SIR efforts at these sites. RG&E has signed orders on consent for five of these sites.
In one site, known as the Quanta Resources Site, RG&E signed a consent order with the Environmental Protection Agency (EPA) and paid its $27,500 share of remedial cost. RG&E was again contacted by EPA in late August, 1996. The EPA informed RG&E that it believed certain additional work was required, including a study to determine the extent to which additional removal of waste materials was required. The EPA's list of PRPs had grown to about 80. RG&E, along with most of those PRPs, has agreed (through an Administrative Order on Consent) to conduct the required study. On May 12, 1997, RG&E signed an Administrative Order on Consent with the NYSDEC. This agreement served to obligate the respective parties to pay NYSDEC's past costs at the Site, RG&E's share of which was determined to be $1,500. There is as yet, no information on which to determine the cost to design and conduct at the site any remedial measures which federal or State authorities may require, but RG&E does not expect its additional costs to exceed $150,000.
On May 21, 1993, RG&E was notified by NYSDEC that it was considered a PRP for the Frontier Chemical Pendleton Superfund Site located in Pendleton, NY. RG&E has signed, along with other participating parties, an Administrative Order on Consent with NYSDEC. The Order on Consent obligates the parties to implement a work plan and remediate the site. The PRPs have negotiated a work plan for site remediation and have retained a consulting firm to implement the work plan. Preliminary estimates indicate RG&E's share of additional site remediation costs are not expected to exceed $500,000. RG&E is participating with the group to allocate costs among the PRPs. Subsequent work has indicated that the final cost is likely to be lower.
RG&E is involved in the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky and has signed various consent orders to that effect. RG&E has contributed to a study of the site and estimates that its share of the additional costs of investigation and remediation is not expected to exceed $211,000.
RG&E has been named as a PRP at three other sites and has been associated with two other sites for which RG&E's share of total additional projected costs is not expected to exceed $30,000. Actual expenditures for these sites are dependent upon the total cost of investigation and remediation and the ultimate determination of RG&E's share of responsibility for such costs as well as the financial viability of other identified responsible parties.
RG&E is negotiating with its past insurance carriers seeking to obtain coverage for environmental remediation costs at some locations.
GRIFFITH OWNED SITES. In connection with its Big Flats, New York terminal, Griffith has been complying with the Unilateral Administrative Order issued by the EPA. Pursuant to a cost sharing agreement with Sun Pipe Line Company, Griffith continues to undertake one-half of the costs necessary to comply with the order. To date Griffith has spent $1.8 million on this compliance. Griffith continues to disclaim that it is either the owner or operator of a failed spur where petroleum was discharged, and compliance is proceeding on this basis accordingly.
Since February 1996, Griffith has been involved in a legal proceeding in New York State Supreme Court for Steuben County, related to the environmental matter in the above paragraph. In Steuben Contracting v. Sun Pipe Line Company, Griffith Oil Co., Inc. and Chevron, USA, the plaintiff is seeking compensation for property damage associated with petroleum discharge at Big Flats. The parties have engaged in depositions and disclosure activities. Such disclosure has not revealed any facts that have altered Griffith's position that the other parties reimburse Griffith for costs, expenses and damages associated with site remediation at Big Flats.
In May 1998, the State of New York (State of New York v. Griffith Oil Co., Inc.) commenced an action against Griffith in New York State Supreme Court for Albany County, for statutory penalties in connection with the discharge of petroleum at Big Flats, New York. The complaint alleges Griffith failed to report the discharge within two hours of discovery, and further alleges a violation of Griffith's Major Oil Storage Facility License for failure to report such discharge. Griffith has answered the complaint and denied the allegations. Griffith's position is that it complied with practice established with DEC, and promptly reported the discharge upon confirmation of the presence of subsurface petroleum. Griffith has offered to settle this matter for $15,000 subject to a mutually acceptable agreement of settlement. Griffith continues to deny responsibility for this matter and unless otherwise settled will defend this matter in the usual course.
In April 1998, the State of New York commenced an action against Griffith and other parties (State of New York v. Griffith Oil Co., Inc., Sugar Creek Stores, Inc. and Mahl Bros. Oil Co., Inc. [Springville Bulk Plant]) in New York State Supreme Court for Erie County, for reimbursement of the sum of $180,962 to
the New York Environmental Protection and Spill Compensation Fund in connection with subsurface petroleum contamination in the vicinity of Springville, New York. Until December 1997, Griffith leased a petroleum bulk storage facility at the location. Cross-claims also exist among the defendants related to causes of action associated with the contamination and lease of the property. While the presence of subsurface contamination is evident, an analysis of the contamination is substantially associated with a parent product produced no later than 1985. This date precedes the interest of Griffith. Griffith will continue to vigorously defend this matter.
In connection with the acquisition of Griffith by Energetix, a stock purchase agreement obligates the Seller to pay for environmental claims or remedial action on Griffith property once the amount of environmental losses incurred by Energetix exceeds $3.5 million less any reserve reflected on the balance sheet at the time of acquisition. At December 31, 1999 approximately $700 thousand has been spent and $1.8 million is estimated to be spent.
See Item 8, Note 10 - Commitments and Other Matters.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of the fiscal year ended December 31, 1999.
Item 4 - A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information about the officers of RGS and RG&E as of January 1, 2000. Unless otherwise indicated all positions and offices listed are at RG&E.
Age Positions, Offices and Business Experience Name 1/1/00 1995 to date - ---- ------ --------------------------------------------------
Thomas S. Richards 56 Chairman, President and Chief Executive Officer of RGS - August 1999 to date.
Chairman, President and Chief Executive Officer - January 1998 to date.
President and Chief Operating Officer - March 1996 to December 1997.
Senior Vice President, Energy Services - August 1995 to March 1996.
Senior Vice President, Corporate Services and General Counsel - 1995 to August 1995.
Age Positions, Offices and Business Experience Name 1/1/00 1995 to date - ---- ------ ----------------------------------------------
Michael J. Bovalino 44 Senior Vice President of RGS - August 1999 to date.
President and Chief Executive Officer, Energetix, Inc (a wholly owned subsidiary of RGS) January 1998 to date.
Senior Vice President, Energy Services - January 1997 to December 1997.
Vice President, Retail Services for Plum Street Enterprises (a wholly owned subsidiary of Niagara Mohawk Power Corporation, 300 Erie Boulevard West, Syracuse, NY 13202) prior to joining the Company.
J. Burt Stokes 56 Senior Vice President and Chief Financial Officer of RGS - August 1999 to date.
Senior Vice President, Corporate Services and Chief Financial Officer - January 1, 1996 to date.
Chief Financial Officer and acting Chief Executive Officer for General Railway Signal Corporation, 150 Sawgrass Dr., Rochester, NY 14692 prior to joining the Company.
Michael T. Tomaino 62 Senior Vice President and General Counsel of RGS - August 1999 to Date.
Senior Vice President and General Counsel - October 1997 to Date.
Vice President, General Counsel and Secretary for Goulds Pumps, Inc., 300 Willowbrook Office Park, Fairport, NY 14450 prior to joining the Company.
Paul C. Wilkens 52 Senior Vice President of RGS - August 1999 to Date.
Senior Vice President, Generation - March 1998 to Date.
Director, Gas Services - January 1996 - March 1998.
Principal Consultant - May 1995 - January 1996.
Department Manager - Nuclear Engineering Services - 1995 - May 1995.
Age Positions, Offices and Business Experience Name 1/1/00 1995 to date - ---- ------- ----------------------------------------------
William J. Reddy 52 Controller of RGS - August 1999 to Date.
Vice President and Controller - August 1999 to Date.
Controller - April 1997 to August 1999.
Group Manager, Public Affairs Services - January 1995 to April 1997.
Division Manager, Public Affairs Services - January 1995.
The term of office of each officer extends to the meeting of the Board of Directors following the next election of Directors of their company and until his or her successor is elected and qualifies.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
RGS ENERGY GROUP, INC.
On August 2, 1999, Rochester Gas and Electric Corporation (RG&E) was reorganized into a holding company structure pursuant to an Agreement and Plan of Share Exchange (Exchange Agreement) between RG&E and RGS Energy Group, Inc. (RGS). As part of the reorganization, all of the outstanding shares of RG&E common stock were exchanged on a share-for-share basis for shares of RGS and RG&E became a subsidiary of RGS. Certificates for shares of RG&E common stock are automatically valid as certificates for RGS and do not have to be replaced. The transfer does not affect the value of the stock or RGS's dividend policy. RGS trades on the New York Stock Exchange under the symbol "RGS". RG&E shareholders approved the Exchange Agreement on April 29, 1999.
TAX STATUS OF CASH DIVIDENDS
Cash dividends paid in 1999, 1998 and 1997 were 100 percent taxable for federal income tax purposes.
DIVIDEND POLICY
RG&E has paid cash dividends quarterly on its Common Stock without interruption since it became publicly held in 1949. Since its formation in August 1999, RGS has continued this historic trend of dividend payments.
The ability of RGS to pay common stock dividends is governed by the ability of RGS's subsidiaries to pay dividends to RGS. Because RG&E is by far the largest of the subsidiaries, it is expected that for the foreseeable future the funds required by RGS to enable it to pay dividends will be derived predominantly from the dividends paid to RGS by RG&E. In the future, dividends from subsidiaries other than RG&E may also be a source of funds for dividend payments by RGS. RG&E's ability to make dividend payments to RGS will depend upon the availability of retained earnings and the needs of its utility business. RG&E's Certificate of Incorporation provides for the payment of dividends on Common Stock out of the surplus net profits (retained earnings) of the Company. In addition, pursuant to the PSC order approving the formation of RGS, RG&E may pay dividends to RGS of no more than 100% of RG&E's net income calculated on a two-year rolling basis. The calculation of net income for this purpose excludes non-cash charges to income resulting from accounting changes or certain PSC required charges as well as charges that may arise from significant unanticipated events. This condition does not apply to dividends that would be used to fund the
remaining portion of the $100 million authorized for RG&E's unregulated operations (about $42 million at December 31, 1999). The level of future cash dividend payments on Common Stock will be dependent upon RGS's future earnings, its financial requirements, and other factors.
Quarterly dividends on Common Stock are generally paid on the twenty-fifth day of January, April, July and October. In January 2000, RGS paid a cash dividend of $.45 per share on its Common Stock. The January 2000 dividend payment is equivalent to $1.80 on an annual basis.
Common Stock - Price Range 1999 1998 1997 - ---------------------------- ---- ---- ---- High 1st quarter 31 9/16 33 1/4 20 3/8 2nd quarter 28 7/16 32 3/4 21 7/16 3rd quarter 27 5/16 32 7/16 24 15/16 4th quarter 25 1/2 33 1/4 34 1/2
Low 1st quarter 25 7/16 29 1/2 18 7/8 2nd quarter 25 1/4 29 5/16 18 3rd quarter 24 1/16 28 3/8 20 5/8 4th quarter 20 28 9/16 23 3/4
At December 31 20 9/16 31 1/4 34
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA
CONSOLIDATED SUMMARY OF OPERATIONS
* Reclassified for comparative purposes.
CONDENSED CONSOLIDATED BALANCE SHEET
*Reclassified for comparative purposes.
(a) Includes Company's long-term liability to the Department of Energy (DOE) for nuclear waste disposal. Excludes DOE long-term liability for uranium enrichment decommissioning and amounts due or redeemable within one year.
(b) The return on average common equity for 1995 excluding effects of the 1995 Gas Settlement is 12.10%.
(c) Coverages in 1995 exclude the economic effect of the 1995 Gas Settlement ($44.2 million, pretax).
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following is Management's assessment of certain significant factors affecting the financial condition and operating results of RGS Energy Group, Inc. and its subsidiaries over the past three years. The Consolidated Financial Statements and the Notes thereto contain additional data. For the twelve months ended December 31, 1999, 58 percent of the Company's operating revenues were derived from electric service, 23 percent from natural gas service, and 19 percent from unregulated businesses.
SELECTED ABBREVIATIONS and GLOSSARY
Cooling degree days The extent to which the daily outdoor average temperature exceeds a base of 65 degrees Fahrenheit. One degree day is counted for each degree day falling above the assumed base for each calendar day.
Company or RGS RGS Energy Group Inc., a holding company formed August 2, 1999,which is the parent company of Rochester Gas and Electric Corporation, RGS Development Corporation, and Energetix, Inc.
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant wholly owned by the Company
Heating degree days The extent to which the daily outdoor average temperature falls below a base of 65 degrees Fahrenheit. One degree day is counted for each degree day falling below the assumed base for each calendar day.
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which the Company currently owns a 14% share
PSC New York State Public Service Commission
RG&E Rochester Gas and Electric Corporation, a wholly-owned subsidiary of the Company
Settlement Competitive Opportunities Case Settlement among the Company, PSC and other parties which provides the framework for the development of competition in the electric energy marketplace through June 30, 2002
SFAS Statement of Financial Accounting Standards
FORWARD LOOKING STATEMENTS - --------------------------
The discussion presented below contains statements which are not historic fact and which can be classified as forward looking. These statements can be identified by the use of certain words which suggest forward looking information, such as "believes," "will," "expects," "projects," "estimates" and "anticipates". They can also be identified by the use of words which relate to future goals or strategies. In addition to the assumptions and other factors referred to specifically in connection with the forward looking statements, some of the factors that could have a significant effect on whether the forward looking statements ultimately prove to be accurate include:
1. uncertainties related to the regulatory treatment of nuclear generation facilities including the proposed sale of the Nine Mile Point nuclear generating facilities by Niagara Mohawk Power Corporation (Niagara Mohawk) and New York State Electric and Gas Corporation and the exercise of RG&E's right of first refusal;
2. any state or federal legislative or regulatory initiatives (including the results of negotiations between RG&E and the PSC regarding certain gas restructurings) that affect the cost or recovery of investments necessary to provide utility service in the electric and natural gas industries. Such initiatives could include, for example, changes in the regulation of rate structures or changes in the speed or degree to which competition occurs in the electric and natural gas industries;
3. any changes in the ability of RG&E to recover environmental compliance costs through increased rates;
4. the determination in the nuclear generation proceeding initiated by the PSC, including any changes in the regulatory status of nuclear generating facilities and their related costs, including recovery of costs related to spent fuel and decommissioning;
5. any changes in the rate of industrial, commercial and residential growth in RG&E's and RGS's service territories;
6. the development of any new technologies which allow customers to generate their own energy or produce lower cost energy;
7. any unusual or extreme weather or other natural phenomena;
8. the ability of RGS to manage profitably new unregulated operations;
9. certain unknowable risks involved in operating unregulated businesses in new territories and new industries;
10. the timing and extent of changes in commodity prices and interest rates; and
11. any other considerations that may be disclosed from time to time in the publicly disseminated documents and filings of RGS and RG&E.
Shown below is a listing of the principal items discussed.
RGS ENERGY GROUP, INC. Page 29 Unregulated Subsidiaries
ROCHESTER GAS AND ELECTRIC CORPORATION Competition Page 30
PSC Competitive Opportunities Case Settlement Energy Choice Proposed Purchase of Nuclear Plants PSC Proceeding on Nuclear Generation Fossil Units Status FERC Open Access Transmission Orders and Company Filings Prospective Financial Position
Rates and Regulatory Matters Page 38 PSC Gas Restructuring Policy Statement Gas Proposal and Interim Settlement Flexible Pricing Tariff
LIQUIDITY AND CAPITAL RESOURCES Page 40 Capital and Other Requirements Financing Redemption of Securities Stock Repurchase Plan Environmental Issues Year 2000 Readiness Information
EARNINGS SUMMARY Page 43
RESULTS OF OPERATIONS Page 44 Operating Revenues and Sales Operating Expenses Other Statement of Income Items
DIVIDEND POLICY Page 49
RGS ENERGY GROUP, INC.
On August 2, 1999, RG&E was reorganized into a holding company structure pursuant to an Agreement and Plan of Share Exchange (Exchange Agreement) between RG&E and RGS. As part of the reorganization, all of the outstanding shares of RG&E common stock were exchanged on a share-for-share basis for shares of RGS and RG&E became a subsidiary of RGS. Certificates for shares of RG&E common stock are automatically valid as certificates for RGS and do not have to be replaced. The transfer does not affect the value of the stock or RGS's dividend policy. RGS trades on the New York Stock Exchange under the symbol "RGS". RG&E shareholders approved the Exchange Agreement on April 29, 1999.
The holding company structure was formed so that RGS could respond quickly to changes in the evolving competitive energy utility industry. The new structure permits the use of financing techniques that are better suited to the particular requirements, characteristics and risks of non-utility operations without affecting the capital structure or creditworthiness of RG&E. This
increases RGS's financial flexibility by allowing it to establish different debt-to-equity ratios for each of its individual lines of business.
RGS is not an operating entity. RGS's operations are being conducted through its subsidiaries which include RG&E, and two unregulated subsidiaries - RGS Development Corporation and Energetix, Inc.
RG&E will continue to offer regulated electric and natural gas utility service in its franchise territory. Energetix, Inc. provides energy products and services throughout upstate New York. RGS Development Corporation offers energy systems development and management services.
Unregulated Subsidiaries. It is part of RGS's financial strategy to seek growth by entering into unregulated businesses. The Settlement allowed RG&E to provide the funding for RGS to invest up to $100 million in unregulated businesses. The first step in this direction was the formation and operation of Energetix, Inc. (Energetix) effective January 1, 1998. Energetix is an unregulated subsidiary that brings energy products and services to the marketplace both within and outside of RG&E's regulated franchise territory. Energetix markets electricity, natural gas, oil, gasoline, and propane fuel energy services in an area extending in approximately a 150-mile radius around Rochester.
In August 1998, Energetix announced the acquisition of Griffith Oil Company, Inc. (Griffith), the second largest oil and propane distribution company in New York State. This $31.5 million acquisition was accounted for using purchase accounting and the results of Griffith's operations are reflected in the consolidated financial statements of RGS since its acquisition on August 2, 1998.
Griffith gives Energetix access to 70,000 new customers, 65,000 of which are outside of RG&E's regulated franchise territory. Griffith has approximately 350 employees and operates 18 customer service centers.
In September 1999, Griffith acquired Bobbett Gas Service, a provider of propane gas and service in the Central New York area. The acquisition adds 2,600 customers to the current Griffith customer base. The acquisition was accounted for using purchase accounting and their results of operations are reflected in the consolidated financial statements of RGS since acquisition.
In December 1999, Griffith acquired Clark Oil, a provider of fuel oil in the Central New York area. This acquisition adds 600 customers to the Griffith customer base. The acquisition was accounted for using purchase accounting and their results of operations are reflected in the consolidated financial statements of RGS since acquisition.
Additional information on Energetix operations (including Griffith) is presented under the headings Operating Revenues and Sales, Operating Expenses, and is contained in Note 4 of the Notes to Financial Statements.
During the second quarter of 1998, the Company formed RGS Development to pursue unregulated business opportunities in the energy marketplace. Through December 31, 1999, RGS Development operations have not been material to RGS's results of operations or its financial condition.
ROCHESTER GAS AND ELECTRIC CORPORATION
COMPETITION
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. During 1996 and 1997, RG&E, the staff of the PSC and several other parties negotiated an agreement which was
approved by the PSC in November 1997 (the "Settlement"). The Settlement sets the framework for the introduction and development of open competition in the electric energy marketplace and lasts through June 30, 2002. Over this time, the way electricity is provided to customers will fundamentally change. In phases, RG&E will allow customers to purchase electricity, and later capacity commitments, from sources other than RG&E through its retail access program, Energy Choice. These energy service companies will compete to package and sell energy and related services to customers. The competing energy service companies will purchase distribution services from RG&E who will remain the sole provider of distribution services, and will be responsible for maintaining the distribution system and for responding to emergencies.
The Settlement sets RG&E's electric rates for each year during its five- year term. Over the five-year term of the Settlement, the cumulative rate reductions for the bundled service will be as follows: Rate Year 1 (July 1, 1997 to June 30, 1998) $3.5 million; Rate Year 2 $12.8 million; Rate Year 3 $27.6 million; Rate Year 4 $39.5 million; and Rate Year 5 $64.6 million.
In the event that RG&E earns a return on common equity in its regulated electric business in excess of an effective rate of 11.50 percent over the entire five-year term of the Settlement, 50 percent of such excess will be used to write down deferred costs accumulated during the term. The other 50 percent of the excess will be used to write down accumulated deferrals or investment in electric plant or Regulatory Assets (which are deferred costs whose classification as an asset on the balance sheet is permitted by SFAS-71, Accounting for the Effects of Certain Types of Regulation). If certain extraordinary events occur, including a rate of return on common equity below 8.5 percent or above 14.5 percent, or a pretax interest coverage below 2.5 times, then either RG&E or any other party to the Settlement would have the right to petition the PSC for review of the Settlement and appropriate remedial action.
The Settlement requires unregulated energy retailing operations be structurally separate from the regulated utility functions. Although the Settlement provides incentives for the sale of generating assets, it does not require RG&E to divest generating or other assets or write-off stranded costs. Additionally, RG&E will be given a reasonable opportunity to recover substantially all of its prudently incurred costs, including those pertaining to generation and purchased power.
RG&E believes that the Settlement has not adversely affected its eligibility to continue to apply certain accounting rules applicable to regulated industries. In particular, RG&E believes it continues to be eligible for the treatment provided by SFAS-71 which allows RG&E to include assets on its balance sheet based on its regulated ability to recoup the cost of those assets. However, this may not be the case with respect to certain operational costs associated with non-nuclear generation (see Note 10 of the Notes to Financial Statements under the heading Other Matters, EITF Issue 97-4, Deregulation of the Pricing of Electricity).
RG&E's retail access program, Energy Choice, was approved by the PSC as part of the Settlement and went into effect on July 1, 1998. Details of the Energy Choice Program are discussed below.
One party to the Settlement negotiations has commenced an action for declaratory and injunctive relief as to certain provisions of the Settlement and the PSC's approval of it. RG&E is unable, at this time, to predict the outcome of this action.
ENERGY CHOICE. On July 1, 1998, RG&E officially began implementation of its full-scale electric retail access Energy Choice program. As of July 1, 1999, RG&E entered its second year of this program. There are five basic components of
the sale of energy: (1) the sale of electricity which is the amount of energy actually used by the consumer, (2) the sale of capacity which is the ability, through generating facilities or otherwise, to provide electricity when it is needed, (3) the sale of transmission services, which is the physical transportation of electricity to RG&E's distribution system, (4) the sale of distribution services, which is the physical delivery of electricity to the consumer, and (5) retail services such as billing and metering. Historically, RG&E has sold all five components bundled together for a fixed rate approved by the PSC. The implementation of the Energy Choice program included a four year phase-in process to allow RG&E and other parties to manage the transition to electric competition in an orderly fashion. During the first year of the program, participation in Energy Choice was limited to no more than 10 percent of RG&E's total annual retail electric kilowatt-hour sales (670,000 annualized megawatt-hours). Essentially, until this 10 percent limit was achieved, RG&E's electric retail customers could seek out or be approached by alternative energy service companies for electricity to be resold and then delivered over RG&E's distribution system. By February 1, 1999, only six months into the Energy Choice program, this 10 percent limit was achieved by qualified competitive energy service companies in RG&E's service territory. For the second year of the program, beginning July 1, 1999, this limit increased from 10 percent to approximately 20 percent. By December 31, 1999, approximately 14.8 percent of total RG&E sales had shifted to competitive energy service companies. On July 1, 2001, all retail customers will be eligible to purchase energy from alternative energy service companies. The phase-in of the Energy Choice program over the next few years eventually will give retail electric customers the opportunity to purchase energy, capacity and retailing services from competitive energy service companies. Existing RG&E customers may also continue to purchase fully bundled electric service from RG&E.
Energy Choice adopted the single-retailer model for the relationship between RG&E as the distribution provider, qualified energy service companies, and retail (end-use) customers. In this model, retail customers have the opportunity for choice in their energy service company and receive only one electric bill from the company that serves them. Except for providing emergency services, satisfying requests for distribution services, and scheduling outages, which remain RG&E's responsibility, the retail customer's primary point of contact for billing questions, technical advice and other energy-related needs, is with their chosen energy service company.
Under the single-retailer model, energy service companies are responsible for buying or otherwise providing the electricity their retail customers will use, paying regulated rates for transmission and distribution, and selling electricity to their retail customers (the price of which would include the cost of the electricity itself and the cost to transport electricity through RG&E's distribution system).
Throughout the term of the Settlement, RG&E will continue to provide regulated and fully bundled electric service under its retail service tariff to customers who choose to continue with such service.
During the initial "Energy-Only" stage of the Energy Choice program, energy service companies were able to choose their own sources of energy supply, while RG&E continued to provide to them, through its bundled distribution rates, the generating capacity (installed reserve) needed to serve their retail customers. In addition, during the "Energy-Only" stage, energy service companies had the option of purchasing "full-requirements" (i.e. delivery services plus energy) from RG&E.
The "Energy and Capacity" stage, the second stage of the phase-in, was scheduled to begin this past Fall. In this stage, energy service companies may purchase both energy and capacity in the open market. As a result of a delay in
establishing an Independent System Operator entity in New York State, RG&E, with the consent of the energy service companies participating in the Retail Access Program, reserved capacity for the 1999-2000 winter capability period and will provide energy and capacity for the energy service companies through that period. Essentially, energy service companies will purchase "full-requirements" (delivery services plus energy and capacity) from RG&E.
During the initial "Energy Only" stage of the retail access program, RG&E's distribution rate was set by deducting 2.305 cents per kilowatt-hour from its full service ("bundled") rates. The 2.305 cents per kilowatt-hour was comprised of 1.905 cents per kilowatt-hour (an estimate of the wholesale market price of electricity) plus 0.4 cents per kilowatt-hour for its avoided cost of retailing services. During the "Energy and Capacity" stage, RG&E's distribution rates will equal the bundled rate less RG&E's cost of the electric commodity and RG&E's non-nuclear generating capacity. During this stage of the program, RG&E's distribution rates will be set by deducting 3.0712 cents per kilowatt- hour from its full service ("bundled") rates. The 3.0712 cents per kilowatt- hour is comprised of 2.6712 cents per kilowatt-hour (an estimate of the wholesale market price of electric energy and capacity) plus 0.4 cents per kilowatt-hour for its avoided cost of retailing services.
As of December 31, 1999, eight energy service companies, including Energetix, the Company's unregulated subsidiary, are qualified by RG&E to serve retail customers under the Energy Choice program. In addition to Energetix, these companies are Columbia Energy Power Marketing Corporation, DukeSolutions, Inc., Northeast Energy Services, Inc.(NORESCO), North American Energy, NYSEG Solutions, Inc., Select Energy Inc., and TXU Energy Services, Inc. In addition, the County of Monroe has been qualified to act as its own energy service company to service its own facilities. As of December 31, 1999, all energy service companies had opted to purchase "full-requirements" from RG&E to serve their retail customers.
With the commencement of the "Energy and Capacity" stage and the implementation of the New York Independent System Operator on November 18, 1999 (see FERC Open Access Transmission Orders and Company Filings), the responsibility for purchasing not only energy, but also capacity, shifted to the energy service companies. However, these energy service companies, as "full- requirements" customers of RG&E during the winter capability period, will be purchasing energy and capacity from RG&E at 2.6712 cents per kilowatt-hour. The cost impact on RG&E of providing "full requirements" energy and capacity for this time period will be determined by prices in the New York State wholesale market. The PSC has approved a request by RG&E to extend "full-requirements" availability to November 1, 2000.
Once RG&E no longer provides "full requirements" to the energy service companies, they will assume responsibility for obtaining their own supplies. There will be a revenue decrease when RG&E no longer collects the $2.6712 cents per kilowatt-hour for energy and capacity. This will be offset to some extent by decreased costs resulting from no longer acquiring energy and capacity for the energy service companies. The extent of this offset will be determined by market prices.
On December 3, 1999, New York State Electric and Gas Corporation (NYSEG) petitioned the PSC to accelerate the implementation of retail access in RG&E's service territory. NYSEG filed the petition pursuant to the terms of its electric restructuring agreement, whereby NYSEG may petition the PSC to deny permission to a New York State utility-affiliated competitive energy service company to participate in NYSEG's retail access program if the service area of the energy service company's affiliated utility is not comparably open to retail access. However, NYSEG does not seek to deny RG&E's affiliate, Energetix, the ability to participate in NYSEG's retail access program, stating that such a
motion would be inconsistent with the PSC's efforts to create competitive opportunities in the electric industry. Instead, NYSEG requests the PSC to order RG&E to accelerate its retail access implementation schedule, claiming that RG&E's introduction of retail access is occurring at an extremely slow rate. RG&E's retail access program and implementation schedule was approved by the PSC in November 1997, as part of a comprehensive electric restructuring agreement. RG&E is in the process of preparing a response to NYSEG's petition, and cannot determine at this time what course of action the PSC may take.
On December 14, 1999, a group of marketers and energy service companies submitted a petition to the PSC to initiate an inquiry into the effectiveness of RG&E's retail access program. The petitioners are NYSEG Solutions, Inc., Advantage Energy, Leveraged Energy Purchasing Corporation, Empire Natural Gas Corporation, and Salerni & Boyd, Inc. The petitioners make the following claims concerning RG&E's retail access program: (1) RG&E's operating agreement creates significant obstacles to development of retail competition in RG&E's territory because of the obligations the energy service companies now have to serve the retail customers. The petitioners have asked the PSC to exercise its authority to investigate the effectiveness of the terms and conditions of RG&E's operating agreement, and order RG&E to either reduce the customer service obligations or offer a higher backout credit or other reasonable economic incentives to offset the costs of these obligations, and (2) the shopping credit (i.e., backout rate) offered by RG&E inhibits retail access and competition. The petitioners ask the PSC to order RG&E to provide additional credits, to at least 3.7 cents per kilowatt-hour, while maintaining the price of energy to the energy service companies at 2.8 cents per kilowatt-hour in order to provide a reasonable opportunity for the energy service companies to enter and compete in RG&E's territory, and (3) the phase-in approach to retail access in RG&E's relatively small service area discriminates against energy service companies and marketers and inhibits competition. The petitioners request the PSC to order RG&E to open its service territory to full retail access as soon as possible, but no later than July 1, 2000. RG&E is in the process of preparing a response to this petition, and cannot determine at this time what course of action the PSC may take.
The PSC is conducting proceedings that are intended to bring more administrative consistency among New York State utilities and potentially offer additional services for energy service companies to provide. These proceedings include uniform business practices, standardized billing and competitive metering. RG&E continues to assess the scope and impact of such changes on its operations.
PROPOSED PURCHASE OF NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and NYSEG announced their intention to sell their interests in the Nine Mile Two nuclear plant to AmerGen Energy Company, L.L.C.(AmerGen), a joint venture of PECO Energy of Philadelphia and British Energy. Niagara Mohawk owns 41 percent and NYSEG owns 18 percent of Nine Mile Two. The financial terms of the transaction include purchase prices to be paid to Niagara Mohawk of $63.6 million and to NYSEG of $27.9 million.
RG&E's 14 percent interest in Nine Mile Two was not included in the current proposal. As an original part owner, RG&E generally had three options: the first option was to retain its ownership interest on the same basis that it does now; the second option was to sell its 14 percent interest in Nine Mile Two to AmerGen on substantially the same terms as Niagara Mohawk and NYSEG; and the third option was to exercise its right-of-first-refusal and buy the Niagara Mohawk and/or NYSEG interests on terms at least as favorable as those offered by AmerGen. Niagara Mohawk took the position that an exercise of the right to buy its interest in Nine Mile Two must necessarily include matching the terms of the agreement between AmerGen and Niagara Mohawk ($72 million) to buy the Nine Mile
Point One Nuclear Plant (Nine Mile One), which is 100 percent owned by Niagara Mohawk.
On December 22, 1999, RG&E announced it had exercised its legal right-of- first-refusal to acquire a controlling interest in Nine Mile Two and to acquire the interests of Niagara Mohawk in Nine Mile One. As a result of the regulatory process discussed below, the status of RG&E's acquisition pursuant to its right- of-first-refusal is in question.
RG&E has contracted with Entergy Nuclear Nine Mile, L.L.C. (Entergy Nine Mile) to operate and maintain the plants upon RG&E's acquisition under its right-of-first-refusal. Under the terms of an operating agreement, Entergy Nine Mile will be responsible for operating the plants, for certain operating costs and risks during a transition period and most operating costs and risks thereafter. RG&E will be responsible for substantial operating costs and risks during the transition period and these costs and risks will be significantly reduced after the transition period. RG&E will pay Entergy Nine Mile a fixed price (periodically adjusted by certain appropriate price indices) per kilowatt- hour of power actually generated and delivered to RG&E. The contract with Entergy Nine Mile expires in September 2009.
RG&E intends to finance its acquisition through the issuance of long-term debt. Depending on when transfer of ownership takes place, RG&E currently expects to pay between $180 million and $210 million, including the cost of fuel at the plants. The transfer of ownership of the plants to RG&E and transfer of operation of the plants to Entergy Nine Mile will require State and federal regulatory approvals, including the PSC, the Nuclear Regulatory Commission (NRC) and the FERC.
In this transaction, RG&E will continue to own the rights to its original approximately 160 megawatts of electric generating capacity from Nine Mile Two and acquire the rights to approximately an additional 670 megawatts of capacity from that plant. At the conclusion of its purchase, RG&E would own 73% of Nine Mile Two. The Long Island Lighting Company, which is wholly-owned by the Long Island Power Authority, and Central Hudson Gas & Electric Corporation are the other non-operating owners of Nine Mile Two and will retain their interests in the plant. RG&E would also acquire the entire capacity from Nine Mile One, about 615 megawatts.
Niagara Mohawk and NYSEG will purchase the power produced by their previous ownership shares in the Nine Mile Point plants from RG&E under long-term contracts that run for a period of three to five years. These terms are the same as those agreed to by AmerGen. After that period of time, available power is expected to be sold into the wholesale energy market.
Under the terms of a decommissioning agreement, Entergy Nuclear, Inc. will be responsible for decommissioning the plants at a fixed price after they are both taken out of service. For Nine Mile One, Niagara Mohawk, as the former sole owner, will contribute the entire present cost of decommissioning to a fund. For Nine Mile Two, Niagara Mohawk and NYSEG will contribute payments proportionate to their former ownership interests.
At December 31, 1999 the net book value of RG&E's 14 percent interest in the Nine Mile Two generating facility was approximately $376 million.
On August 30, 1999 the PSC began a proceeding to review the proposed sale of the Nine Mile Point nuclear facilities by Niagara Mohawk and NYSEG to AmerGen to determine if the sale would be in the public interest. RG&E has intervened in that proceeding. In early January 2000, at the request of PSC Trial Staff, that proceeding was suspended to give the interested parties time for settlement
negotiations. In late January 2000, the PSC Trial Staff expressed its intention to move to dismiss the proceeding since it believes that the sale to AmerGen, as filed, is not consistent with the public interest standard in Public Service Law Section 70; Trial Staff said that it intends to immediately explore, in conjunction with the utilities and interested parties, other scenarios for future ownership and operation of the Nine Mile nuclear plants; and Trial Staff proposed that the parties dispense with formal evidentiary hearings in this proceeding. AmerGen has asked that the Judge reject Staff's request to dispense with formal evidentiary hearings and instead set a schedule for testimony and hearings in this proceeding.
A separate proceeding to consider RG&E's acquisition of the Nine Mile nuclear facilities has not yet been commenced. At this time, RG&E is uncertain what the outcome of the PSC regulatory process will be but expects that it will continue for some time. RG&E intends to continue to pursue all of its alternatives and evaluate any modifications to the current proposed transaction and any new proposed transaction.
PSC PROCEEDING ON NUCLEAR GENERATION. On March 20, 1998, the PSC initiated a proceeding to examine a number of issues raised by a Staff position paper on nuclear generation and the comments received in response to it. In reviewing the Staff paper and parties' comments, the PSC:
(1) adopted as a rebuttable presumption the premise that nuclear power should be priced on a market basis to the same degree as power from other sources, with parties challenging that premise having to bear a substantial burden of persuasion;
(2) characterized the proposals in the Staff paper as by and large consistent in concept with the PSC's goal of a competitive, market-based electricity industry;
(3) questioned Staff's position that would leave funding and other decommissioning responsibilities with the sellers of nuclear power interests and;
(4) indicated interest in the potential for a New York Nuclear Operating Company (NYNOC) proposal to benefit customers through efficiency gains and directed pursuit of that matter in this nuclear generating proceeding or separately upon the filing of a formal NYNOC proposal.
RG&E has worked with other New York nuclear generation operators on the development of a NYNOC but no substantial further work on its implementation is anticipated until completion of this proceeding and the outcome of any proposed sales by current New York nuclear plant owners is determined.
RG&E's potentially strandable assets in nuclear plant could be impacted by the outcome of this proceeding. The initial collaborative conference for this proceeding was held on January 20, 1999. The parties in this proceeding developed a collaborative, non-binding interim report entitled "Nuclear Generation and the Competitive Electric Market" which was issued in July 1999. RG&E is actively involved in this proceeding which is continuing. RG&E is unable to determine when this proceeding may conclude.
FOSSIL UNITS STATUS. In 1999, RG&E ceased operations at and retired its Beebee Station (80 Megawatt) generating facility. The retirement of Beebee Station did not have a material effect on the financial position or results of operations of RGS or RG&E. The Competitive Opportunities Settlement provides that all prudently incurred incremental costs associated with the retirement and
decommissioning of the plant are recoverable through RG&E's distribution access rates.
In early June 1999 the Allegany Station, a combined-cycle unit fueled by natural gas, began generating electricity. The 63 megawatt capacity unit is expected to generate electricity during the peak demand summer months and when the economics of producing electricity for sale are favorable. The plant is being operated and maintained for RG&E by Bell Harbert Energy L.L.C. Allegany Station, which was built as a co-generation facility in the early 1990s, was obtained by RG&E as part of a legal settlement in December 1998 with General Electric Capital Corporation, Kamine/Besicorp Allegany L.P. (Kamine) and other Kamine affiliates.
Oswego Unit Sale. On October 22, 1999, RG&E and Niagara Mohawk sold their respective 12% and 88% interests in the Oswego Generation Facility to Oswego Harbor Power L.L.C., a wholly-owned affiliate of NRG Energy, Inc. (collectively, the Buyer) for approximately $91 million. Additionally, the Buyer agreed to assume RG&E's obligations under a June 8, 1998 transmission services agreement (Exit Agreement) as it pertains to the Oswego Generation Facility. This assumption represents a net present value of approximately $25 million, which was deducted from RG&E's approximately $11 million share of the sale proceeds. Accordingly, upon closing, RG&E was required to make a net payment of approximately $14 million to Niagara Mohawk. Under the terms of the Competitive Opportunities Settlement, RG&E is permitted to recover any losses and related costs on a sale of generation through distribution rates. Pursuant to an October 21, 1999 PSC order, RG&E was required to file with the PSC a detailed calculation of its net book loss after tax impacts. RG&E made this filing with the PSC on December 21, 1999. Including the impact of the $25 million relating to the Exit Agreement, RG&E's net loss and associated costs are approximately $79 million. In the filing, RG&E indicated that $2.2 million of depreciation charges and $4.3 million of transmission contract payments, currently included in rates, will be used to amortize the net loss during the remaining term of the Competitive Opportunities Settlement.
FERC OPEN ACCESS TRANSMISSION ORDERS AND COMPANY FILINGS. On January 31, 1997, the New York electric utilities filed a "Comprehensive Proposal To Restructure the New York Wholesale Electric Market" with the FERC. As proposed, the New York Power Pool (NYPP) then in effect would be dissolved and an independent system operator (NYISO) would administer a Statewide open access tariff and provide for the reliable operation of the bulk power system in the State.
On June 30, 1998, the FERC issued an Order that conditionally authorized the establishment of the NYISO by the member systems of the NYPP (Member Systems). The order addressed areas of governance, standards of conduct and reliability. On April 30, 1999, the FERC issued an order which addressed several issues, including its rejection of the Member Systems' settlement on governance issues, and its acceptance of the Section 203 filing to transfer jurisdictional transmission facilities to the NYISO. On September 15, 1999, the FERC issued an Order approving the agreement on governance.
On January 27, 1999 the FERC issued an Order conditionally accepting the proposed NYISO tariff and the proposed market rules of the NYISO. The Order also granted the Member Systems' request for market-based rates for energy, ancillary services and installed capacity sold through the NYISO. On July 29, 1999, the FERC issued an Order, approving the NYISO Open Access Transmission Tariff, the NYISO Services Tariff, and each of the related ISO Agreements submitted by the Member Systems.
On November 18, 1999 the NYISO implemented a competitive wholesale market for the sale, purchase and transmission of electricity and ancillary services in New York State. After a two-week cutover period, the NYISO officially assumed control and operation of the New York State electric transmission system from the NYPP. With the implementation of day-ahead and real-time markets, RG&E is provided with additional flexibility, beyond bilateral contracts, in marketing its excess generation and in purchasing energy to supply retained retail load.
A settlement proceeding was established during 1999 to resolve an issue involving the disposition of certain pre-ISO transmission agreements. On June 17, 1999, the Member Systems and other intervenors filed a Settlement Agreement with FERC. On July 21, 1999, the presiding administrative law judge certified the uncontested settlement to the Commission. On November 26, 1999, the Commission approved the settlement. On January 5, 2000, the Commission certified a partial uncontested settlement that included changes to the revenue requirement as well as the divisor used to compute the transmission service charge, setting the rate that RG&E and the other New York State utilities will charge under the NYISO.
Currently, it is unclear what effect the above changes may have once other regulatory changes in New York State are implemented. At the present time, RG&E cannot predict what effects regulations ultimately adopted by FERC will have, if any, on future operations or the financial condition of RGS or RG&E.
COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. With PSC approval, RG&E has deferred certain costs rather than recognize them on its books when incurred. Such deferred costs are then recognized as expenses when they are included in rates and recovered from customers. Such deferral accounting is permitted by SFAS-71. These deferred costs are shown as Regulatory Assets on the Company's and RG&E's Balance Sheet and a discussion and summary of such Regulatory Assets is presented in Note 10 of the Notes to Financial Statements.
In a competitive electric market, strandable assets would arise when investments are made in facilities, or costs are incurred to service customers, and such costs are not fully recoverable in market-based rates. Estimates of strandable assets are highly sensitive to the competitive wholesale market price assumed in the estimation. In a competitive natural gas market, strandable assets would arise where customers migrate away from dependence on RG&E for full service, leaving RG&E with surplus pipeline and storage capacity, as well as natural gas supplies under contract. A discussion of strandable assets is presented in Note 10 of the Notes to Financial Statements.
At December 31, 1999 RG&E believes that its regulatory assets are probable of recovery. The Settlement in the Competitive Opportunities Proceeding does not impair the opportunity of RG&E to recover its investment in these assets. However, the PSC issued an Opinion and Order Instituting Further Inquiry on March 20, 1998 to address issues surrounding nuclear generation. The initial meeting in this Inquiry was held in January 1999 (see PSC Proceeding on Nuclear Generation). The ultimate determination in this proceeding or any proceeding to consider RG&E's proposed purchase of nuclear plants as discussed under Proposed Purchase of Nuclear Plants could have an impact on strandable assets and the recovery of nuclear costs.
RATES AND REGULATORY MATTERS
PSC GAS RESTRUCTURING POLICY STATEMENT. On November 3, 1998, the PSC issued a gas restructuring policy statement ("Gas Policy Statement") announcing its conclusion that, among other things, the most effective way to establish a competitive gas supply market is for gas distribution utilities to cease selling gas. The PSC established a transition process in which it plans to address three groups of issues: (1) individual gas utility plans to implement the PSC's vision of the market; (2) key generic issues to be dealt with through collaboration
among gas utilities, marketers, pipelines and other stakeholders, and (3) coordination of issues that are common to both the gas and the electric industries. The PSC has encouraged settlement negotiations with each gas utility pertaining to the transition to a fully competitive gas market. RG&E, the PSC Staff and other interested parties have been participating in settlement discussions in response to the specific requirements of the Policy Statement.
GAS PROPOSAL AND INTERIM SETTLEMENT. In August 1998, prior to issuance of the PSC's Gas Policy Statement (see PSC Gas Restructuring Policy Statement above), RG&E had commenced negotiations with the PSC staff and other parties to develop a comprehensive multi-year settlement of various issues, including rates and the structure of RG&E's gas business. Because the negotiation of a comprehensive settlement was not anticipated to conclude until mid-1999, the parties to the negotiations agreed to an Interim Settlement, effective November 1998 through June 1999, that dealt with such issues as rates, transportation and storage capacity costs, assignment of capacity, and retail access. Significant features of the Interim Settlement include a freeze on base rates at the current levels (which were fixed at July 1994 levels), the imputation of $11.9 million in revenues from the remarketing of capacity and a limit on RG&E's exposure to costs associated with the migration of customers from RG&E to marketers for sales and service.
Discussions following the expiration of the Interim Settlement resulted in a September 14, 1999 filing to address issues pertaining to the cost of upstream capacity and other matters pertaining to restructuring pursuant to the PSC's Policy Statement. The proposal calls for: (1) a continued reduction in capacity costs of $11.9 million, comprised of $10.2 million relating to upstream capacity release transactions for the period September 1, 1999 through August 31, 2000 and $1.7 million from the expiration of a Texas Eastern capacity contract; (2) a report to PSC staff, within 60 days of approval of the proposal, of the plans and progress RG&E has made to reduce its upstream capacity costs; (3) a resumption of the multi-year settlement discussions calling for RG&E to make a public filing addressing the rate and restructuring issues addressed in the PSC's Policy Statement within 120 days of approval of the proposal; and (4) RG&E continuing to work on retail access program improvements. The proposal was subsequently approved by the PSC and RG&E began implementation of its proposal in the fourth quarter of 1999. As required, the report on upstream capacity costs was submitted on November 29, 1999, under trade secret status. The public filing addressing the rate and restructuring issues was made on January 28, 2000. This filing is intended to provide the basis for negotiations with the PSC and other interested parties on RG&E's proposal to implement a fully competitive marketplace for natural gas. Settlement negotiations pertaining to RG&E's gas rate and restructuring proposal will begin as early as 30 days after filing pursuant to the Gas Policy Statement. RG&E is unable to predict the ultimate outcome from this proceeding, or when the PSC will issue a final order.
Under a March 1996 Order, the PSC permitted RG&E and other gas distribution companies to assign to marketers the pipeline and storage capacity held by RG&E to serve their customers. In its Gas Policy Statement issued in November 1998, the PSC ordered that the mandatory assignment of capacity, permitted by the March 1996 Order, be terminated effective April 1, 1999. According to the Gas Policy Statement, however, the utilities are to be afforded a reasonable opportunity to recover resulting strandable costs, if any. On March 24, 1999, the PSC issued an Order Concerning Assignment of Capacity for all gas utilities in the State of New York, generally requiring the removal of restrictions on customer migration from utility service to service from marketers. RG&E has complied with the PSC's directives.
FLEXIBLE PRICING TARIFF. Under its flexible pricing tariff for major industrial and commercial electric customers, RG&E may negotiate competitive electric rates at discount prices to compete with alternative power sources, such
as customer-owned generation facilities. Pursuant to the terms of the Settlement under the Competitive Opportunities Proceeding, RG&E will absorb, as it has done since the inception of these rates, the difference between the discounted rates paid under these individual contracts and the rates that would otherwise apply. Approximately 24 percent of all regulated electric sales to customers are made under long-term contracts, primarily to large industrial customers. These contracts represent approximately 49 percent of RG&E's revenues from its commercial and industrial customers.
LIQUIDITY AND CAPITAL RESOURCES
During 1999, RGS's and RG&E's cash flow from operations (see Statements of Cash Flows) provided the funds for construction expenditures and the payment of dividends and short-term debt. In addition, RG&E completed a long-term financing in October 1999 (see "Financing" below). Cash used for investing activities in 1999 was lower due to the acquisition of Griffith in August 1998 and there were no acquisitions of comparable size in 1999. Cash used in financing activities for 1999 was higher due mainly to the redemption of short-term debt. Capital requirements of the Company during 2000 are anticipated to be satisfied from the combination of internally generated funds and short-term credit arrangements. In addition, RG&E expects to issue long-term debt to finance its proposed acquisition of the Nine Mile Two facilities (see Proposed Purchase of Nuclear Plants). RG&E may also refinance long-term securities obligations during 2000 depending on prevailing financial market conditions.
CAPITAL AND OTHER REQUIREMENTS. RGS's and RG&E's capital requirements relate primarily to expenditures for energy delivery, including electric transmission and distribution facilities and gas mains and services as well as nuclear fuel, electric production, the repayment of existing debt and the repurchase of outstanding shares of Common Stock. Additional baseload generation is expected to be available once RG&E completes its acquisition of the Nine Mile Two facilities as discussed above. RG&E has no further plans to install additional baseload generation.
1998 Labor Day Storm. At approximately midnight, Monday morning, September 7, 1998, a severe lightning and windstorm struck RG&E's franchise area. The storm damaged RG&E's electrical system at several hundred different locations. Several counties within RG&E's franchise area were declared State and federal disaster areas.
RG&E has deferred approximately $8.5 million of costs and carrying charges associated with this storm. Under the Competitive Opportunities Settlement with the PSC, if incremental costs resulting from a "catastrophic event" exceed $2.5 million, such costs could be deferred. RG&E submitted a petition to the PSC for deferral of costs associated with this storm and this petition is currently pending.
Settlement with Co-generator. In May 1998 RG&E entered into a Global Settlement Agreement regarding the termination of a power purchase contract with Kamine/Besicorp Allegany L.P. (Kamine). In August 1998 the PSC approved the Global Settlement Agreement, and on December 1, 1998, the Agreement became effective. Under the terms of the Global Settlement Agreement, the Power Purchase Agreement was terminated in consideration of payment by RG&E of $168 million over 16 years, without interest, with an initial payment of $10 million. Also, under the terms of the Global Settlement Agreement, RG&E paid an additional $15 million for the purchase of the Kamine generation facility. In June 1999 the plant began generating electricity (see Fossil Units Status). RG&E does not expect the terms of the Global Settlement Agreement to have any material effect on its earnings or the earnings of RGS. Pursuant to a PSC order approving the terms of the Global Settlement Agreement, regulatory assets have been established by RG&E to account
for the initial payment, the facility purchase, and future payments. RG&E has no other long-term obligations to purchase energy from other cogeneration facilities.
Capital Requirements - Summary. Excluding the potential acquisition by RG&E of Nine Mile One and the additional investment in Nine Mile Two as discussed above, capital requirements for the Company over the three-year period 1997 to 1999 and the current estimate of capital requirements through 2002 are summarized in the Capital Requirements table. RG&E's portion of total construction requirements as presented in the Capital Requirements table for 2000, 2001, and 2002 are $151 million, $137 million, and $112 million, respectively.
The Company's capital expenditures program is under continuous review and could be revised for any number of issues. Also, RG&E may consider, as conditions warrant, the redemption or refinancing of certain outstanding long- term securities.
* Excludes prospective refinancings.
FINANCING. On October 27, 1999 RG&E issued $100 million of 7.60% First Mortgage Bonds, Designated Secured Medium-Term Notes, Series B. The net proceeds from this financing were used to repay short-term debt and pay for capital expenditures.
RG&E generally utilizes its credit agreements and unsecured lines of credit to meet any interim external financing needs prior to issuing any long-term securities. For information with respect to RGS's and RG&E's short-term borrowing arrangements and limitations, see Note 9 of the Notes to Financial Statements. As financial market conditions warrant, RG&E may also, from time to time, redeem higher-cost senior securities.
REDEMPTION OF SECURITIES. In addition to first mortgage bond maturities and mandatory sinking fund obligations over the past three years, discretionary redemption of securities totaled $152 million in 1997 and $25.5 million in 1998. Included in discretionary redemptions for 1997 and 1998 were over $127 million of
tax-exempt securities, which were refinanced with tax-exempt debt. There were no discretionary redemptions of securities in 1999.
STOCK REPURCHASE PLAN. In April 1998, the PSC approved a Stock Repurchase Plan for RG&E providing for the repurchase of Common Stock having an aggregate market value not to exceed $145 million. RG&E began the repurchase program in May 1998 and 2,942,600 shares of Common Stock have been repurchased for approximately $83.3 million through December 31, 1999. The average cost per share purchased during 1999 was $25.65.
ENVIRONMENTAL ISSUES. The production and delivery of energy are necessarily accompanied by the release of by-products subject to environmental controls. RGS and RG&E have taken a variety of measures (e.g., self-auditing, recycling and waste minimization, training of employees in hazardous waste management) to reduce the potential for adverse environmental effects from its energy operations.
RGS and RG&E have recorded liabilities to reflect specific issues where remediation activities are currently deemed to be probable and where the cost of remediation can be estimated. Estimates of the extent of the Company's degree of responsibility at a particular site and the method and ultimate cost of remediation require a number of assumptions for which the ultimate outcome may differ from current estimates. While RGS and RG&E do not anticipate that any adjustment would be material to its financial statements, it is reasonably possible that the result of ongoing and/or future environmental studies or other factors could alter this expectation and require the recording of additional liabilities. The extent or amount of such events, if any, cannot be estimated at this time.
Additional information concerning RGS's and RG&E's environmental matters can be found in Note 10 of the Notes to Financial Statements.
YEAR 2000 READINESS INFORMATION. As the year 2000 (Y2K) approached, RGS and RG&E, like most companies, faced potentially serious information and operational systems (computer and microprocessor-based devices) problems because many software applications and embedded systems programs created in the past would not properly recognize calendar dates beginning with the year 2000 or that the year 2000 is a "leap-year".
On and after January 1, 2000, the Company and RG&E have experienced normal operations of their computer and microprocessor-based devices with no loss or interruption of energy generation or delivery and no operating difficulties of its mission critical internally developed applications or critical devices. RG&E's two major electric power plants, Ginna and Russell Station, performed without any difficulties. Likewise, operations at the Nine Mile Two electric power plant proceeded normally and there has been no major impact on gas service. RG&E is not aware of any regional or statewide power systems that failed to perform as the result of Y2K-related problems. The Company has experienced no major problems related to applications and devices of critical external parties. The Company will continue to monitor the operation of its computers and microprocessor-based devices for any Y2K-related problems.
RG&E funded its Y2K Project internally and has incurred $9.3 million of incremental costs through December 31, 1999 associated with making the necessary modifications identified to applications and devices. Energetix, including Griffith Oil, incurred less than $100,000 of incremental costs. Neither RGS or RG&E have deferred any major corporate information technology projects due to this effort.
EARNINGS SUMMARY
The impact of developing competition in the energy marketplace may affect future earnings. The Competitive Opportunities Settlement allows for a phase-in to open electric markets while lowering customer prices and establishing an opportunity for competitive returns on shareholder investments. The nature and magnitude of the potential impact of the Settlement on the business of RG&E will depend on several factors, including the availability of qualified energy suppliers in RG&E's service territory, the degree of customer participation and ultimate selection of an alternative energy supplier, RG&E's ability to be competitive by controlling its operating expenses, and RGS's ultimate success in the development of its unregulated business opportunities as permitted under the Settlement.
Although RG&E does not earn a return on the gas commodity it acquires for distribution, under the current regulatory environment future earnings may be affected, in part, by the ultimate outcome of implementation of the November 1998 Gas Policy Statement (see Rates and Regulatory Matters). That policy statement concludes that the most effective way to establish a robust competitive gas supply in New York State is for local gas distribution companies (LDCs), such as RG&E, to exit the merchant function of acquiring gas, as well as transportation and storage capacity to serve retail customers. LDCs ceased assigning transportation capacity to customers migrating from sales to transportation service by April 1, 1999. The nature and magnitude of the potential impact of these policies will depend on individual negotiations that RG&E is undertaking with the PSC Staff and other interested parties on RG&E specific restructuring, as well as a number of Statewide collaborative efforts that will deal with such issues as provider of last resort, reliability, recovery of stranded costs, and market power as the transition is made to a more competitive gas business.
RGS. RGS reported consolidated earnings of $2.44 per share in 1999 compared to $2.32 in 1998. RGS's earnings per share in 1999 were positively affected by increased electric sales to a combination of marketers and retail customers during the summer months when the weather was 25% warmer than a year ago (cooling degree day basis) and by higher gas sales in the first quarter of 1999 driven by 19% colder weather (heating degree day basis)) as compared to 1998. Sales and revenues in 1999 also reflect a one-time adjustment during the second quarter of the year in the methodology of calculating unbilled sales and revenues which increased electric revenues by $7.1 million and gas revenues by $6.1 million. In addition, non-fuel operating expenses for RGS include a $4.8 million drop in RG&E welfare expense from 1998 as discussed below. RGS's share buy-back program also contributed to higher earnings per share in 1999 adding $.11 per share. Having a negative effect on earnings in 1999 was a 57-day scheduled refueling and ten-year in-service inspection outage at the Ginna plant (there was no outage in 1998) and a 30-day unscheduled outage at the Nine Mile Two plant. These outages contributed to increased purchased power expenses and decreased sales of electricity to other utilities during the year. A scheduled electric rate reduction effective July 1 and a one-time adjustment of approximately $7 million in the second quarter of 1999 to increase RG&E's allowance for uncollectible accounts also had an unfavorable effect on 1999 earnings.
RGS continues to grow its unregulated business through its subsidiary, Energetix, which provides electric, natural gas, and petroleum-based energy products and services throughout the upstate New York region. Energetix's unconsolidated operating revenues were $275 million in 1999, of which sales from Griffith's heating oil, gasoline and propane gas contributed approximately $220 million. These revenues from Griffith are included under "Other Revenues" on RGS's and RG&E's Income Statements. Energetix, including Griffith, on a consolidated basis, had a pre-tax loss of $0.1 million for 1999. These results reflect the development expenses related to building a successful unregulated
electric and natural gas business in an open and competitive market. Energetix's revenues for 2000 from electric and gas operations are expected to increase over 1999 levels as Energetix expands its customer base, although no assurance may be given that Energetix will achieve a net operating gain in 2000.
RG&E. Earnings for RG&E in 1999 reflect the same issues discussed above for RGS except that discussions relating to Energetix and Griffith are not applicable. The 1999 RG&E Income Statement reflects the consolidated operations of RG&E and its former subsidiaries, Energetix and RGS Development, through August 2, 1999 at which time the holding company RGS was formed and RG&E, Energetix and RGS Development then became subsidiaries of RGS. Subsequent to that date, the RG&E Income Statement reflects only the operating results of RG&E.
Basic earnings per share for RG&E were $2.32 in 1998, compared with $2.30 in 1997. For both 1998 and 1997, these results reflect the consolidated operations of RG&E and its subsidiaries at that time, Energetix and RGS Development Corporation. Operating performance of RG&E's generating plants, expense control, the sale of electric energy to wholesale customers, and the recognition of $17.4 million of non-recurring income during the year (see "1998 Compared to 1997", Other Statement of Income Items) allowed RG&E to keep 1998 earnings applicable to Common Stock at about the same level as 1997, despite rate decreases and warmer temperatures during the 1998 heating seasons. Earnings per share in 1998 were improved by approximately $.02 per share resulting from the buyback of Common Stock under the Company's Stock Repurchase Program.
For the twelve month period ending December 31, 1998, RG&E's unregulated subsidiary, Energetix, had a pretax operating loss of $4.1 million, which reduced consolidated earnings by approximately $0.06 per basic share. This loss is primarily due to initial start-up and marketing costs. Moreover, while Energetix was formed January 1, 1998, the first revenues were not received until April of 1998. In addition, revenues from Griffith Oil Co., Inc., a company acquired by Energetix, only reflect sales since acquisition in August 1998.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant changes in the amounts of revenues and expenses for RGS (regulated and unregulated business) and RG&E (regulated business), comparing 1999 to 1998 and 1998 to 1997. The operating results of the regulated business reflect RG&E's electric and gas sales and services and the operating results of the unregulated business reflect Energetix operations. In 1999, the majority of RGS's operating results reflect the operating results of RG&E and the factors that affect operating results for RG&E are the significant factors that affect comparable operating results for RGS, unless otherwise noted. The Notes to Financial Statements contain additional information.
1999 COMPARED TO 1998 - ---------------------
OPERATING REVENUES AND SALES. Increased electric revenues for RGS and RG&E reflect the warmer summer weather as discussed above to meet the demand for air conditioning usage partially offset by a base rate reduction and lower regulated electric sales due largely to RG&E's reduced capacity to sell power to other electric utilities because of the refueling and in-service inspection outage at the Ginna Plant and the unscheduled outage at Nine Mile Two as discussed above under "Earnings Summary". Regulated sales and revenues for this period compared to last year also reflect a one-time adjustment to reflect a change in the estimating process for unbilled sales and revenues. This adjustment increased regulated electric revenues by $7.1 million and increased
regulated gas revenues by $6.1 million. Regulated electric sales increased by 74,000 megawatt-hours and regulated gas sales were higher by 7,610,000 therms as a result of this one-time adjustment. A drop in commercial and industrial regulated electric sales reflects, in part, the opening of the electric market under the terms of the Competitive Opportunities Settlement. RG&E, however, sells electric energy, as well as distribution services, to qualified energy marketers in its franchise territory which has the effect of increasing wholesale sales to energy marketers. Included in RGS's electric operating revenues for 1999 are $65.2 million of revenues from electric sales to energy marketers and $ 25.3 million of revenues from wholesale sales to other utilities. Revenues in 1999 from energy marketers were up $50.2 million compared with 1998 reflecting the opening of the electric marketplace and increased sales of electricity and distribution services. Revenues from the sales of electric energy to other utilities dropped $3.7 million from 1998 due mainly to the availability of RG&E's generating plants as discussed above, partially offset by an increase in the average revenue per unit sold. Fluctuations in revenues from electric sales to other utilities are generally related to RG&E's customer energy requirements, the wholesale energy market, availability of transmission, and the availability of electric generation from RG&E's facilities.
Regulated gas margins (revenues less cost of purchased gas) were up over $12 million reflecting 11% cooler weather (based on heating degree days) for the year and the change in unbilled sales methodology discussed above. Therms of gas sold and transported for the regulated business were up 10.7 percent in 1999. The transportation of gas for customers who are able to purchase natural gas from sources other than RG&E is an important component of RG&E's marketing mix. In 1999, RG&E's small customer aggregate transportation market appeared as a significant addition to RG&E's marketing mix. Company facilities are used to distribute this gas, which in total amounted to 20.0 million dekatherms in 1999 and 16.4 million dekatherms in 1998. These purchases by eligible customers have caused decreases in RG&E's retail gas customer revenues, with offsetting decreases in purchased gas expenses and, in general, do not adversely affect earnings because transportation customers are billed at rates which, except for the cost of buying and transporting gas to RG&E's city gate, are the same as the rates charged RG&E's retail gas service customers. Moreover, under the current regulatory environment, RG&E does not earn a return on the gas commodity it acquires for distribution. Gas supplies transported in this manner are not included in RG&E's therm sales, depressing reported gas sales to non-residential customers.
Eighty percent of Energetix total operating revenues in 1999 were from the sale of heating oil, propane and gasoline by Griffith (see discussion under "Earnings Summary"). For heating oil and propane, Griffith experiences seasonal fluctuations due to the dependence on spaceheating sales during the heating season. In addition, gasoline sales reflect seasonal fluctuations due to increased consumer driving during the warmer months. Unregulated sales reflect Griffith's operations since its acquisition by Energetix on August 2, 1998 and the migration of electric and gas customers from the regulated to the unregulated business.
OPERATING EXPENSES. Higher regulated electric fuel expenses reflect increased purchased electricity costs driven by the effect from lower generation from the Ginna nuclear plant, hydro plants, and the closing of Beebee Station on April 30, 1999, in addition to an increase in the cost per unit purchased. The cost of purchased power may fluctuate depending on the availability of electric generation from RG&E's facilities, the wholesale energy market and the total availability of energy, and the availability of transmission facilities. Fuel expense for electric generation was down in 1999 reflecting lower generation from RG&E's facilities. Since July 1996, Common Stock shareholders have assumed the full benefits and detriments realized from actual electric fuel costs and generation mix compared with PSC-approved forecast amounts. RG&E normally
purchases electric power to supplement its own generation when needed to meet load or reserve requirements, and when such power is available at a cost lower than RG&E's production cost. Despite an increase in retail regulated gas therm sales, gas purchased for resale expense declined in 1999 reflecting a lower average cost per unit due, in part, to reduction in pipeline costs. Other fuel expense on both RGS's and RG&E's Income Statements reflect mainly the cost of purchased fuel for Griffith's operations since its acquisition by Energetix.
The decrease in non-fuel operating expenses for RGS and RG&E includes a $4.8 million drop in RG&E welfare expense from 1998 due mainly to the performance of pension assets and a change in the discount rate used to value the aggregate pension liability (see Note 3 of the Notes to Financial Statements), elimination in the first quarter of 1999 of property insurance and storm reserves no longer required totaling $2.1 million, lower non-fuel net expenses of $1.5 million associated with Ginna Station refueling outages, a decrease of $2.8 million due primarily to the completion in 1998 of the amortization of costs of RG&E's billing system, insurance dividends of $1.8 million, and lower employee performance incentive program costs of $1.1 million. Offsetting these declines was a June 1999 increase in the allowance for uncollectible accounts of approximately $7 million to better match RG&E's actual collection history, the establishment in the fourth quarter of 1999 of a $3.0 million liability for anticipated Nine Mile Two inventory losses due to a change in the expected ownership of that facility, and Y2K costs of $6.0 million.
The variance in unregulated non-fuel operating expenses reflects primarily an increase in payroll expenses ($5.6 million), other operating expenses for Griffith ($2.6 million), and general and administrative expenses ($2.1 million). The increase in these expenses reflects twelve months of Griffith's operations in 1999 compared with only five months of operations in 1998 following its acquisition in August 1998.
Depreciation expense for both RGS and RG&E in 1999 includes an incremental one-time charge in the second quarter of approximately $2.1 million associated with the closing of Beebee Station in April 1999. Depreciation and amortization expense for unregulated operations in 1999 was $3.2 million, up $2.1 million from 1998.
Local, State and other taxes for RGS and RG&E declined reflecting a New York State use tax audit refund, lower tax rates for State and local revenue taxes, and lower assessments for property taxes. These results were partially offset by higher unbilled revenue taxes resulting from an increase in unbilled revenues. For unregulated operations, local, State and other taxes increased $2.9 million to $4.0 million compared to 1998.
The difference in federal income tax expense for RGS and RG&E reflects pre- tax earnings and, regarding RG&E, the settlement of RG&E audits in the first quarter of 1998 and a tax reserve increase for potential disputed issues of $4.8 million in the fourth quarter of 1999.
OTHER STATEMENT OF INCOME ITEMS. The change in non-operating federal income taxes for both RGS and RG&E results from variances in non-operating earnings before federal income taxes.
The change in RGS's and RG&E's Other Income and Deductions, Other-net reflects mainly the recognition of income in 1998 due to the elimination of certain pension and other post-employment benefit deferred credits and Nine Mile Two operating and maintenance expenses in accordance with the Competitive Opportunities Settlement (see "1998 Compared to 1997", Other Statement of Income Items). This variance in Other Income and Deductions, Other-net was partially offset by non-cash carrying charges of $8.6 million related to deferral of Kamine (Allegany Station) facility costs in 1999 for the regulated business. These
carrying charges, which are primarily associated with the deferred recovery of costs associated with the Kamine settlement (see following paragraph), were allowed under the Competitive Opportunities and Kamine settlements. In addition, expenses associated with RG&E management performance awards were down $4.4 million in 1999 compared with 1998.
The increase in RGS's interest charges reflects mainly an increase in long- term debt outstanding, resulting mainly from the Kamine settlement, the acquisition of Griffith by Energetix, and the issuance of $50 million of long term debt by RG&E in December 1998. The increase in RG&E's interest charges reflects the same issues exclusive of the debt incurred for the Griffith acquisition. To a lesser extent, interest expense for both RGS and RG&E reflects the interest on $100 million of first mortgage bonds issued in October 1999 (see "Financing").
1998 COMPARED TO 1997 - ---------------------
OPERATING REVENUES AND SALES. Regulated electric revenues for 1998 were down compared to a year earlier resulting from a decrease in electric base rates effective July 1, 1998 and July 1, 1997 and the effect of the migration of approximately 10% of RG&E's electric load to competitive suppliers, including Energetix. Making a positive contribution to 1998 electric revenues was an increased demand for air conditioning load during the summer months when the weather was 70% warmer (on a cooling degree day basis) in contrast to the summer of 1997 which was 35% cooler than normal. Electric revenues from sales to other electric utilities was up largely due to the increased availability of the Ginna Plant. The Ginna Plant experienced a 31 day scheduled refueling outage in 1997 compared with no outage in 1998. The drop in commercial and industrial regulated electric sales reflects, in part, the opening of the electric market on July 1, 1998 under the terms of the Competitive Opportunities Settlement. RG&E, however, sells electric energy, as well as distribution services, to qualified energy marketers in its franchise territory which has the effect of increasing wholesale sales to energy marketers. Included in electric operating revenues for 1998 are $15.0 million of revenues from electric sales to energy marketers.
Regulated gas margins (revenues less cost of purchased gas) were down over $20 million reflecting 18% warmer weather (based on heating degree days). Therms of gas sold and transported for the regulated business were down 12.1 percent in 1998.
Included in total operating revenues for 1998 are $10.6 million of electric and gas operating revenues received by Energetix and $71.2 million of Griffith operating revenues. Griffith's operating revenues are reported under Other Revenues on both RGS's and RG&E's Income Statements. Prior year comparisons for the Company's unregulated subsidiary, Energetix, are not relevant because formal operations began in the first quarter of 1998 and Griffith was acquired in August 1998.
OPERATING EXPENSES. Higher fuel expenses in 1998 reflect higher fuel expenses for electric generation resulting from increased generation to support higher electric sales. For the 1998 comparison period, increased fuel expense also reflects relatively more generation from RG&E's costlier fossil-fueled units. Compared with 1997, purchased electric power expense declined in 1998 driven primarily by the effect of greater availability of RG&E's generating facilities. The cost per unit purchased for electric energy was up about 8% in 1998 compared with a year earlier. Gas purchased for resale expense declined in 1998 driven by a reduced volume of purchased gas resulting from a warmer heating season. Other fuel expense on both RGS's and RG&E's Income Statements reflects
mainly the cost of purchased fuel for Griffith operations since its acquisition in August 1998 by Energetix.
The decrease in non-fuel operating expenses for RGS and RG&E includes lower expense of $5.3 million associated with RG&E's uncollectible accounts and a $7.9 million drop in RG&E's welfare expenses due to a favorable adjustment in pension expense (see Note 3 to the Notes to Financial Statements). The decrease in uncollectible accounts expense was driven by the increased level of collection activity. Partially offsetting these lower costs were increased payroll costs of $2.2 million. Approximately $1.6 million of Year 2000 costs were charged to operating expenses in 1998, up $0.4 million from 1997.
The variance in unregulated non-fuel operating expenses reflects primarily a change in payroll expenses, other operating expenses for Griffith, and general and administrative expenses. Prior year comparisons for the Company's unregulated subsidiary, Energetix, are not relevant because formal operations began in the first quarter of 1998 and Griffith was acquired in August 1998.
Depreciation expense for both RGS and RG&E in 1998 remained relatively flat compared to 1997 due to the completion of depreciation expense on certain fully depreciated computer equipment. Depreciation and amortization expense in 1998 includes $1.1 million for unregulated operations.
Local, State and other taxes for RGS and RG&E declined reflecting mainly lower State revenue taxes due to decreased regulated revenues. This decline was partially offset by an additional $1.5 million of local and State taxes associated with unregulated operations.
The difference in federal income tax expense for RGS and RG&E reflects pre- tax earnings and, regarding RG&E, the settlement of RG&E audits in the first quarter of 1998.
OTHER STATEMENT OF INCOME ITEMS. The change in non-operating federal income taxes for both RGS and RG&E results from variances in non-operating earnings before federal income taxes, as well as a $1.7 million RG&E reserve for deferred taxes subsequent to a review of the historic balances.
The change in RGS's and RG&E's Other Income and Deductions, Other-net reflects the recognition of income due to the reversal of certain deferred credits in accordance with the Competitive Opportunities Settlement. In prior years, the PSC had required RG&E to establish deferred credits to account for certain pension and other post-employment benefit charges and Nine Mile Two operating and maintenance expenses. In 1998, these deferred credits totaling $17.4 million were eliminated consistent with the terms of the Settlement and discussions with the PSC. An amount of $8.8 million associated with certain pension charges was reflected on RG&E's books in the first quarter of 1998, after RG&E received the written order associated with the Competitive Opportunities Settlement. An amount of $6.0 million associated with certain Nine Mile Two operating and maintenance expenses was reflected ratably over each of the four quarters of 1998, consistent with Nine Mile Two accounting practices. The remainder associated with certain other post-employment benefits was reflected in the second quarter of 1998, after RG&E had concluded discussions with the PSC. This income was partially offset by expenses associated with the gas interim settlement agreement.
The decrease in RGS's and RG&E's interest charges reflects both mandatory and optional redemptions of long term debt undertaken by RG&E during 1998 and 1997. In addition, other interest decreased in 1998 due to lower miscellaneous interest charges on RG&E pension and other post-employment benefits. The decline in interest charges was partially offset by an additional
$1.0 million of interest expense associated mainly with the acquisition of Griffith by Energetix.
DIVIDEND POLICY
The ability of RGS to pay common stock dividends is governed by the ability of RGS's subsidiaries to pay dividends to RGS. Because RG&E is by far the largest of the subsidiaries, it is expected that for the foreseeable future the funds required by RGS to enable it to pay dividends will be derived predominantly from the dividends paid to RGS by RG&E. In the future, dividends from subsidiaries other than RG&E may also be a source of funds for dividend payments by RGS. RG&E's ability to make dividend payments to RGS will depend upon the availability of retained earnings and the needs of its utility business. In addition, pursuant to the PSC order approving the formation of RGS, RG&E may pay dividends to RGS of no more than 100% of RG&E's net income calculated on a two-year rolling basis. The calculation of net income for this purpose excludes non-cash charges to income resulting from accounting changes or certain PSC required charges as well as charges that may arise from significant unanticipated events. This condition does not apply to dividends that would be used to fund the remaining portion of the $100 million authorized for RG&E's unregulated operations (about $42 million at December 31, 1999). The level of future cash dividend payments on Common Stock will be dependent upon RGS's future earnings, its financial requirements, and other factors.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
RG&E is exposed to interest rate and commodity price risks.
The interest rate risk relates to new debt financing needed to fund capital requirements, including maturing debt securities, and to variable rate debt. RG&E manages its interest rate risk through the issuance of fixed -rate debt with varying maturities and through economic refundings of debt through optional redemptions. A portion of RG&E's long-term debt consists of long-term Promissory Notes, the interest component of which resets on a periodic basis reflecting current market conditions. See "Note 6 - Long Term Debt". RG&E was not participating in any derivative financial instruments for managing interest rate risks as of December 31, 1999 or December 31, 1998.
The commodity price risk relates to market fluctuations in the price of natural gas, electricity, and other petroleum-related products used for resale. Commodity purchases and electric generation are based on projected demand for power generation and customer delivery of electricity, natural gas and petroleum products. RG&E enters into forward contracts for natural gas to hedge the effect of price increases and reduce volatility on gas purchased for resale. Owned electric generation significantly reduces RG&E's exposure to market fluctuations in electric prices. RG&E does not hold open speculative positions in any commodity for trading purposes.
RG&E's exposure to market price fluctuations of the cost of natural gas is further limited as the result of the Gas Cost Adjustment (GCA), a regulatory mechanism that transfers substantially all gas commodity price risk to the customer. Nonetheless, RG&E does hedge approximately 70% of its gas supply price through the purchase of futures contracts and the use of storage assets. The balance of RG&E's natural gas requirements is procured through spot market purchases and is subject to market price fluctuations.
Under the Competitive Opportunities Settlement, RG&E's electric rates are capped at specified levels through June 30, 2002. As a result of owned generation and long-term fixed rate supply contracts, RG&E is largely insulated from market price fluctuations for procurement of its electric supply. In the event RG&E's generation assets fail to perform as planned, RG&E is exposed to market price fluctuations, and under the current rate agreement, fully absorbs this operating risk.
Energetix has entered into electric and natural gas purchase commitments with numerous suppliers. These commitments support fixed price offerings to retail electric and gas customers. Griffith is in the business of purchasing various petroleum-related commodities for resale to its customers. To manage the resulting market price risk, Griffith enters into various exchange-traded futures and option contracts and over-the-counter contracts with third parties. All hedge contracts are accounted for under the deferral method with gains and losses from the hedging activity included in the cost of sales as inventories are sold or as the hedge transaction occurs. Commodity instruments not designated as effective hedges are marked to market at the end of the reporting period, with the resulting gains or losses recognized in cost of sales. These contracts are closely monitored on a daily basis to manage the price risk associated with inventory and future sales commitments. At December 31, 1999 and 1998 Griffith's net deferred gains on open hedge contracts were immaterial.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. FINANCIAL STATEMENTS
The financial statements listed below are shown under Item 8 of this Report.
Report of Independent Accountants.
RGS Consolidated Statement of Income for each of the three years ended December 31, 1999. RGS Consolidated Statement of Retained Earnings for each of the three years ended December 31, 1999. RGS Consolidated Balance sheet at December 31, 1999 and 1998. RGS Consolidated Statement of Cash Flows for each of the three years ended December 31, 1999.
RG&E Statement of Income for each of the three years ended December 31, 1999. RG&E Statement of Retained Earnings for each of the three years ended December 31, 1999. RG&E Balance sheet at December 31, 1999 and 1998. RG&E Statement of Cash Flows for each of the three years ended December 31, 1999.
RGS and RG&E Notes to Consolidated Financial Statements.
Financial Statement Schedules:
The following Financial Statement Schedule is submitted as part of Item 14, Exhibits, Financial Statement Schedules and Reports on Form 8-K, of this Report. (All other Financial Statement Schedules are omitted because they are not applicable, or the required information appears in the Financial Statements or the Notes thereto.)
Schedule II - Valuation and Qualifying Accounts of RGS and RG&E.
B. SUPPLEMENTARY DATA
Interim Financial Data.
Report of Independent Accountants
To the Shareholders and Board of Directors of RGS Energy Group, Inc and the Shareholders and Board of Directors of Rochester Gas and Electric Corporation
In our opinion, the accompanying consolidated financial statements listed under Item 8A in the index appearing on the preceeding page present fairly, in all material respects, the financial position of RGS Energy Group, Inc. and its subsidiaries ("RGS") at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 and the accompanying financial statements listed under Item 8A in the index appearing on the preceding page present fairly, in all material respects, the financial position of Rochester Gas and Electric Corporation ("RG&E") at December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the RGS and RG&E management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
[PricewaterhouseCoopers LLP (signed)]
Rochester, New York February 1, 2000
RGS ENERGY GROUP, INC. CONSOLIDATED STATEMENT OF INCOME
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
The accompanying notes are an integral part of the financial statements. * Reclassified for comparative purposes.
RGS ENERGY GROUP, INC. CONSOLIDATED BALANCE SHEET
The accompanying notes are an integral part of the financial statements
RGS ENERGY GROUP, INC. CONSOLIDATED BALANCE SHEET
The accompanying notes are an integral part of the financial statements.
RGS ENERGY GROUP, INC. CONSOLIDATED STATEMENT OF CASH FLOWS
* Reclassified for comparative purposes
The accompanying notes are an integral part of the financial statements.
ROCHESTER GAS AND ELECTRIC CORPORATION STATEMENT OF INCOME
STATEMENT OF RETAINED EARNINGS
The accompanying notes are an integral part of the financial statements. * Reclassified for comparative purposes.
ROCHESTER GAS AND ELECTRIC CORPORATION BALANCE SHEET
The accompanying notes are an integral part of the financial statements.
ROCHESTER GAS AND ELECTRIC CORPORATION BALANCE SHEET
The accompanying notes are an integral part of the financial statements.
ROCHESTER GAS AND ELECTRIC CORPORATION STATEMENT OF CASH FLOWS
* Reclassified for comparative purposes The accompanying notes are an integral part of the financial statements.
NOTES TO FINANCIAL STATEMENTS
Note 1. SUMMARY OF ACCOUNTING PRINCIPLES
HOLDING COMPANY FORMATION. On August 2, 1999, RG&E was reorganized into a holding company structure in accordance with the Agreement and Plan of Exchange between RG&E and RGS Energy. RG&E's common stock was exchanged on a share-for- share basis for RGS Energy's common stock. RG&E's preferred stock was not exchanged as part of the share exchange and will continue as shares of RG&E.
GENERAL. The Company supplies regulated electric and gas services wholly within the State of New York. The unregulated portion of the Company provides products and services as discussed in Note 4. The Company is subject to regulation by the Public Service Commission of the State of New York (PSC) under New York statutes and by the Federal Energy Regulatory Commission (FERC) as a licensee and public utility under the Federal Power Act. The Company's accounting policies conform to generally accepted accounting principles as applied to New York State public utilities giving effect to the ratemaking and accounting practices and policies of the PSC.
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of 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.
A description of the Company's principal accounting policies follows.
BASIS OF PRESENTATION. This is a combined report of RGS Energy and RG&E, a regulated Electric and Gas subsidiary. The Notes to Financial Statements apply to both RGS Energy and RG&E. RGS Energy's Consolidated Financial Statements include the accounts of RGS Energy and its wholly owned subsidiaries, including RG&E, and two non-utility subsidiaries, RGS Development and Energetix. RGS Energy's prior period consolidated financial statements have been prepared from RG&E's prior period consolidated financial statements, except that accounts have been reclassified to reflect RGS Energy's structure. RG&E's financial statements reflect the operations of RG&E, Energetix and RGS Development prior to August 1, 1999. Subsequent to that date only RG&E operations are reflected.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries RG&E, Energetix, Energyline and RGS Development. All intercompany balances and transactions have been eliminated. Energetix's financial statements are consolidated with its wholly-owned subsidiary Griffith.
Energyline was dissolved in January 2000. It was formed as a gas pipeline corporation to fund the Company's investment in the Empire State Pipeline project. In late 1996, Energyline sold its investment in the Empire State Pipeline.
During the second quarter of 1998, the Company formed a new unregulated subsidiary, RGS Development Corporation ("RGS Development"). RGS Development was formed to pursue unregulated business opportunities in the energy marketplace. Through December 31, 1999, RGS Development operations have not been material to the Company's results of operation or its financial condition.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.
GOODWILL AND OTHER INTANGIBLE ASSETS. Goodwill presented on the consolidated balance sheet, represents the excess of cost over the net tangible and identifiable intangible assets of acquired businesses. It is stated at cost and is amortized, principally on a straight-line basis, over the estimated future periods to be benefited (20 years). On an annual basis the Company reviews the recoverability of goodwill based primarily upon an analysis of undiscounted cash flows from the acquired businesses. Other intangible assets include dealer improvements and are being amortized over varying periods. Accumulated amortization amounted to $1.7 million and $0.7 million at December 31, 1999 and December 31, 1998 respectively.
ACQUISITIONS. In August 1998, Energetix acquired Griffith Oil, Co., Inc. ("Griffith"), for $31.5 million. Griffith sells oil, propane, electricity, gasoline, natural gas and other services offered by Energetix to its existing customers. The acquisition was accounted for as a purchase resulting in goodwill as reflected on the consolidated financial statements. The principal tangible assets acquired were vehicles, tanks, pumps, buildings and commodity inventory.
RATES AND REVENUE. Revenue is recorded on the basis of meters read. In addition, the Company records an estimate of unbilled revenue for service rendered subsequent to the meter-read date through the end of the accounting period.
Through June 30, 1996, tariffs for electric service included fuel cost adjustment clauses which adjusted the rates monthly to reflect changes in the actual average cost of fuels. Beginning July 1, 1996, the electric fuel adjustment clause was eliminated in connection with a rate settlement agreement with the PSC.
The Company continues to use gas cost deferral accounting. A reconciliation of recoverable gas costs with gas revenues is done annually as of August 31, and the excess or deficiency is refunded to or recovered from the customers during a subsequent period.
UTILITY PLANT, DEPRECIATION AND AMORTIZATION. The cost of additions to utility plant and replacement of retirement units of property is capitalized. Cost includes labor, material, and similar items, as well as indirect charges such as engineering and supervision, and is recorded at original cost. The Company capitalizes an Allowance for Funds Used During Construction (AFUDC) approximately equivalent to the cost of capital devoted to plant under construction that is not included in its rate base. AFUDC is segregated into two components and classified in the Consolidated Statement of Income as Allowance for Borrowed Funds Used During Construction, an offset to Interest Charges, and Allowance for Other Funds Used During Construction, a part of Other Income. The rate approved by the PSC for purposes of computing AFUDC was 5.0% during the three-year period ended December 31, 1999. Replacement of minor items of property is included in maintenance expenses. Costs of depreciable units of plant retired are eliminated from utility plant accounts, and such costs, plus removal expenses, less salvage, are charged to the accumulated depreciation reserve.
Depreciation in the financial statements is provided on a straight-line basis at rates based on the estimated useful lives of property, which have resulted in an annual regulated depreciation provision of 3.2% in the three-year period ended December 31, 1999. The annual depreciation provision of Energetix is 7.6% and 8.0% for 1999 and 1998 respectively.
CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of cash and short-term commercial paper. These investments have original maturity not
exceeding three months. Such investments are stated at cost, which approximates fair value, and are considered cash equivalents for financial statement purposes.
INVESTMENTS IN DEBT AND EQUITY SECURITIES. The Company's accounting policy, as prescribed by the PSC, with respect to its nuclear decommissioning trusts is to reflect the trusts' assets at market value and reflect unrealized gains and losses as a change in the corresponding accrued decommissioning liability. The Company has no other debt or equity securities.
FINANCIAL/COMMODITY INSTRUMENTS. The Company periodically enters into agreements to minimize price risks for natural gas in storage. Gains or losses resulting from these agreements are deferred until the corresponding gas is withdrawn from storage and delivered to customers. The Company primarily enters into forward contracts for natural gas through its gas brokers.
Energetix has entered into electric and natural gas purchase commitments with numerous suppliers. These commitments support fixed price offerings to retail electric and gas customers. Griffith is in the business of purchasing various petroleum-related commodities for resale to its customers. In order to manage the risk associated with market price fluctuations Griffith enters into various exchange-traded futures and option contracts and over-the-counter contracts with third parties. The commodity instruments are designated at the inception as a hedge where there is a direct relationship to the price risk associated with Griffith's inventory or future purchases and sales of commodities used in Griffith's operation. These contracts are closely monitored on a daily basis to manage the price risk associated with the company's inventory and future product commitments. All hedge contracts are accounted for under the deferral method with gains and losses from the hedging activity included in the cost of sales as inventories are sold or as the hedge transaction occurs. Commodity instruments not designated as effective hedges are marked to market at the end of the reporting period, with the resulting gains or losses recognized in cost of sales. At December 31, 1999 and 1998 Griffith's net deferred gains on open hedge contracts were immaterial.
RESEARCH AND DEVELOPMENT COSTS. Research and Development costs were charged to expense as incurred. Expenditures for the years 1999, 1998, and 1997 were $2.9 million, $3.4 million and $4.5 million respectively.
ENVIRONMENTAL REMEDIATION COSTS. The Company accrues for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change.
MATERIALS, SUPPLIES AND FUELS. Materials and supplies inventories are valued at the lower of cost or market using the first-in, first-out method. Regulated fuel inventories are valued at average cost. Griffith fuel inventories are valued at the lower of cost or market, using the first-in, first-out method.
NUCLEAR OUTAGE COSTS. The Company levelizes estimated incremental non-fuel expenses due to planned refueling outages at its two nuclear power plants. Such costs are levelized between refueling outages.
STOCK-BASED COMPENSATION. The Company accounts for its stock-based compensation using the fair value method in accordance with SFAS-123. The aggregate amount charged to expense as a result of the Company's stock based compensation plans for the years 1999, 1998 and 1997 approximates $2.2 million, $5.9 million and $8.2 million respectively. Additional information on the PSOP is included in Note 8.
EARNINGS PER SHARE. SFAS-128, Earnings Per Share, was adopted by the Company in the fourth quarter of 1997. This statement replaces the presentation of primary earnings per share (EPS) with basic EPS, and also requires presentation of diluted EPS. Basic EPS is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the Company.
The following table illustrates the calculation of both basic and diluted EPS for the year ended December 31,:
At December 31, 1999 RGS had 177,322 of antidilutive stock options.
COMPREHENSIVE INCOME. There were no items of comprehensive income during the two-year period ended December 31, 1999; therefore, net income is equivalent to total comprehensive income.
RECLASSIFICATIONS. Certain amounts in the prior years' financial statements were reclassified to conform with current year presentation.
Note 2. FEDERAL INCOME TAXES
The provision for federal income taxes is distributed between operating expense and other income based upon the treatment of the various components of the provision in the rate-making process. The following is a summary of income tax expense for RGS Energy Group. Amounts for Rochester Gas and Electric are not materially different.
The following is a reconciliation of the difference between the amount of federal income tax expense reported in the Consolidated Statement of Income and the amount computed at the statutory tax rate of 35%.
A summary of the components of the net deferred tax liability is as follows:
SFAS-109 "Accounting for Income Taxes" requires that a deferred tax liability must be recognized on the balance sheet for tax differences previously flowed through to customers. Substantially all of these flow-through adjustments relate to property, plant and equipment and related investment tax credits of RG&E and will be amortized consistent with the depreciation of these accounts. The net amount of the additional liability at December 31, 1999 and 1998 was $129 million and $148 million, respectively. In conjunction with the recognition of this liability, a corresponding regulatory asset was also recognized.
Note 3: Pension and Other Postretirement Benefit Plans
The following table shows reconciliations of the domestic pension plan and other postretirement plan benefits as of December 31, 1999 and 1998:
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits on a defined dollar basis. In 1999, the health care benefit consists of a contribution of up to $220 per retiree per month towards the cost of a group health policy provided by the Company. The life insurance benefit consists of a Basic Group Life benefit, covering substantially all employees, providing a death benefit equal to one-half of the retiree's final pay.
In addition to the above plans, employees are eligible to contribute to a 401(k) plan. The Company matches a portion of these contributions. Contributions charged to income for this plan for 1999, 1998, and 1997 were $2.8 million, $2.5 million, and $2.3 million, respectively.
During 1999, a generation plant was shut down creating a staff reduction of 36 employees, resulting in a net curtailment charge of $4.9 million, including $8.4 million cost of special termination benefits provided to affected employees offset by a curtailment gain of $3.5 million. Pursuant to the Company's settlement agreement, this charge has been deferred.
Note 4. OPERATING SEGMENT FINANCIAL INFORMATION
Under SFAS-131, information pertaining to operating segments is required to be reported. Upon adoption of SFAS-131, the Company identified three operating segments, driven by the types of products and services offered and regulatory environment under which the Company primarily operates. The three segments are Regulated Electric, Regulated Gas, and Unregulated. The Regulated segments' financial records are maintained in accordance with generally accepted accounting principles (GAAP) and Public Service Commission (PSC) accounting policies. The Unregulated segment's financial records are maintained in accordance with GAAP.
During the reported periods, substantially all revenues are from United States sources, and all assets are located in the United States. No single customer represents more than 10% of the overall Company revenue.
The Regulated Electric segment supplies electric distribution services wholly within New York State. It produces electricity, and distributes and sells electricity to retail customers within a franchise area centering about the City of Rochester. It also sells electricity on a wholesale basis to other electric utilities throughout the Northeast and to energy marketers who resell that electricity to retail customers.
The Regulated Gas segment supplies gas services wholly within New York State. Gas is purchased and distributed to retail customers and distributed on behalf of other large or aggregated customers who purchase their own gas supply.
The Unregulated segment includes Energetix, RGS Development Corporation and Energyline. Energetix brings energy products and services to the marketplace both within and outside of the Company's regulated franchise area. These energy products and services include electricity, gasoline, natural gas, oil, propane, and appliance warranty and repair. RGS Development Corporation was formed to pursue unregulated business opportunities in the energy marketplace.
There are intersegment transactions which occur between the Regulated segments and the Unregulated segment. These transactions are governed by guidelines established in the Competitive Opportunities Settlement and other PSC proceedings. The Unregulated segment is charged for the provision of services and for an allocation of other corporate costs by the Regulated Segments on a fully loaded cost basis. The Unregulated segment buys electricity from the Regulated Electric segment at rates established through PSC proceedings. The Unregulated segment also pays the Regulated segments for electric and gas distribution services at rates established through PSC proceedings. The total amount of the revenues identified by operating segment do not equal the total Company consolidated amounts as shown in the Consolidated Statement of Income. This is due to the elimination of certain intersegment revenues during consolidation. Additionally, the operations of RGS Development Corporation and Energyline are included in Other (Income) and Deductions in the RGS Energy Group, Inc. Consolidated Statement of Income. The total assets identified by operating
segment do not equal the total Company consolidated amounts as shown in the Consolidated Balance Sheet. This is due to the elimination of certain intersegment transactions during consolidation, and certain common assets unidentifiable by segment. A reconciliation follows:
* Some items have been restated for comparative purposes.
Note 5. JOINTLY-OWNED FACILITIES
The following table sets forth the jointly-owned electric generating facility in which the Company is participating. Nine Mile Point Nuclear Plant Unit No. 2 has been constructed and is operated by Niagara Mohawk Power Corporation. Each participant must provide its own financing for any additions to the facility. The Company's share of direct expenses associated with this unit is included in the appropriate operating expenses in the Consolidated Statement of Income. Various modifications will be made throughout the life of this plant to increase operating efficiency or reliability, and to satisfy changing environmental and safety regulations.
The Plant in Service and Accumulated Provision for Depreciation balances for Nine Mile Point Nuclear Unit No. 2 shown above include disallowed costs of $374.3 million. Such costs, net of income tax effects, were previously written off in 1987 and 1989.
Note 6. LONG-TERM DEBT
FIRST MORTGAGE BONDS OF RG&E
/(a)/ The Series QQ First Mortgage Bonds and the 7%, 7.15%, 7.13%, 6.375%, 5.84% and 7.60% medium-term notes described below are generally not redeemable prior to maturity.
/(b)/ The Series RR and Series SS First Mortgage Bonds equal the principal amount of and provide for all payments of principal, premium and interest corresponding to the Pollution Control Refunding Revenue Bonds, Series 1992 A, Series 1992 B (Rochester Gas and Electric Corporation Projects), respectively, issued by the New York State Energy Research and Development Authority (NYSERDA) through a participation agreement with the Company. Payments of the principal of, and interest on the Series 1992 A and Series 1992 B Bonds are guaranteed under a Bond Insurance Policy by MBIA Insurance Corporation.
/(c)/ In 1993 RG&E issued $200 million under a medium-term note program entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series A" with maturities that range from seven years to thirty years.
/(d)/ RG&E issued $50 million in 1998 and $100 million in 1999 under a medium- term note program entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series B" with maturities that range from seven years to thirty years.
The First Mortgage provides security for the bonds through a first lien on substantially all the property owned by RG&E (except cash and accounts receivable).
Sinking and improvement fund requirements aggregate $333,540 per annum under the First Mortgage, excluding mandatory sinking funds of individual series. Such requirements may be met by certification of additional property or by depositing cash with the Trustee. The 1997 and 1996 requirements were met with funds deposited with the Trustee, and these funds were used for redemption of outstanding bonds of Series Y.
On December 1, 1998 RG&E redeemed all its outstanding First Mortgage 8 1/8% Bonds, due December 1, 2028, Series OO.
Sinking fund requirements and bond maturities for the next five years are:
PROMISSORY NOTES AND OTHER
/(e)/ The $25.5 million Promissory Note was issued in connection with NYSERDA's 5.95% Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), 1998 Series A. Payment of the principal of, and interest on the Series A Bonds is guaranteed under a Bond Insurance Policy by MBIA Insurance Corporation.
/(f)/ Multi-mode pollution control notes totaling the principal amount of $101.9 million were issued in connection with NYSERDA's Pollution Control Revenue Bonds (Rochester Gas and Electric Corporation Project), $34,000,000 1997 Series A, $34,000,000 1997 Series B and $33,900,000 1997 Series C. The Multi-mode Revenue Bonds have a structure that enables the Company to optimize the use of short-term rates by allowing for the interest rates to be based on a daily rate, a weekly rate, a commercial paper rate, an auction rate or a multi-year fixed rate. Payment of the principal of, and interest on the Multi-mode Revenue Bonds is guaranteed under Bond Insurance Policies by MBIA Insurance Corporation. At December 31, 1999 and December 31, 1998, the Multi-mode Revenue Bonds bore interest at the weekly rate and the average annual interest rate for all three series was 3.09% and 3.21%, respectively.
RG&E is obligated to make payments of principal, premium and interest on each Promissory Note which corresponds to the payments of principal, premium, if any, and interest on certain Pollution Control Revenue Bonds issued by NYSERDA as described above.
(g) The Promissory Note was issued in connection with the Kamine Global Settlement Agreement, which resolved all litigation, released all claims and terminated all electricity purchase obligations under a power purchase agreement. The Promissory Note is secured by a mortgage, the lien for which is subordinate to the lien of the First Mortgage. The liability represents the present value at December 31, 1999 and December 31, 1998 of future obligations under the Note assuming a discount rate of 7.5 percent. This balance will decrease as payments are made over the term of the Note. At December 31, 1999 and December 31, 1998 RG&E made payments totaling $9.6 million and $7.8 million, respectively. The Company expects to make future payments totaling $10.6 million per year.
(h) The $24.6 million Promissory Note was issued in connection with the acquisition of Griffith Oil, Inc. by Energetix and is secured by a pledge of the stock of Griffith Oil, Inc. RGS has made a financial guarantee on behalf of Energetix which obligates RGS in the event of a default by Energetix in payments under the Note. Beginning in 1998 payments of principal are made in seven annual installments and interest for the first three years accrues at the rate of 7% per year and thereafter at rates varying between 7%-8 1/2% per year.
Based on an estimated borrowing rate at year-end 1999 of 7.60% for long- term debt with similar terms and average maturities (11 years), the fair value of the Company's long-term debt outstanding (including Promissory Notes as described above) is approximately $829 million at December 31, 1999.
Based on an estimated borrowing rate at year-end 1998 of 5.84% for long- term debt with similar terms and average maturities (12 years), the fair value of the Company's long-term debt outstanding (including Promissory Notes as described above) is approximately $844 million at December 31, 1998.
Note 7. PREFERRED AND PREFERENCE STOCK OF RG&E
* See below for mandatory redemption requirements.
No shares of preferred or preference stock are reserved for employees, or for options, warrants, conversions, or other rights.
A. PREFERRED STOCK, NOT SUBJECT TO MANDATORY REDEMPTION:
# May be redeemed at any time at the option of the Company on 30 days minimum notice, plus accrued dividends in all cases.
B. PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:
+ Thereafter at $100.00
MANDATORY REDEMPTION PROVISIONS
In the event the Company should be in arrears in the sinking fund requirement, the Company may not redeem or pay dividends on any stock subordinate to the Preferred Stock.
Series V. The Series V is subject to a mandatory sinking fund sufficient to redeem on each March 1 beginning in 2004 to and including 2008, 12,500 shares at $100 per share and on March 1, 2009, the balance of the outstanding shares. The Company has the option to redeem up to an additional 12,500 shares on the same terms and dates as applicable to the mandatory sinking fund.
Based on an estimated dividend rate at year-end 1999 of 6.40% for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (8.25 years), the fair value of the Company's Preferred Stock, subject to mandatory redemption, is approximately $26 million at December 31, 1999.
Based on an estimated dividend rate at year-end 1998 of 4.75% for Preferred Stock, subject to mandatory redemption, with similar terms and average maturities (6.61 years), the fair value of the Company's Preferred Stock, subject to mandatory redemption, is approximately $39 million at December 31, 1998.
Note 8. COMMON STOCK AND STOCK OPTIONS
REPURCHASE PLAN
In December 1997, the Board of Directors of the Company authorized the repurchase of up to 4.5 million shares of the Company's Common Stock on the open market. A total of 1,435,600 and 1,507,000 of the shares were purchased in 1999 and 1998 respectively.
COMMON STOCK
At December 31, 1999, there were 50,000,000 shares of $5 par value Common Stock authorized, of which 35,943,213 were outstanding. No shares of Common Stock are reserved for warrants, conversions, or other rights. There were 1,954,767 shares of Common Stock reserved and unissued for employees under the 1996 Performance Stock Option Plan, as further described below.
PERFORMANCE STOCK OPTION PLAN
The Company has a Performance Stock Option Plan which provides for the granting of options to purchase up to 2,000,000 authorized but unissued shares or treasury shares of $5 par value Common Stock to executive officers and other key employees. No participant shall be granted options for more than 200,000 shares of Common Stock during any calendar year. The options would be exercisable for a period to be determined by the Committee on Management of the Board of Directors (the Committee). The Committee grants the right to receive a cash payment upon any exercise of an option equal to the quarterly dividend payment per share of Common Stock paid from the date the option was granted to the date of exercise.
In 1999, the Board of Directors granted 177,320 options at an exercise price of $29.689 per share. These options are exercisable for a period of 10 years, and vest three years after the options are granted. The average grant date option fair value and exercise prices are $3.17 and $29.689 respectively. None of these options were exercised during 1999, and are included in the summary of stock option activity presented on the following page.
In 1998, the Board of Directors granted 27,984 options at an exercise price of $33.9065 per share and 15,157 options at an exercise price of $31.0005 per share. These options are vested at 25% when the stock closes at $35 per share, 50% at $40 per share, 75% at $45 per share and 100% at $50 per share. These options are exercisable for a period of 10 years. The weighted average grant date option fair value is $5.56.
In 1997, the Board of Directors granted 504,700 options at an exercise price of $19.0625 per share. These options are vested at 50% when the stock closes at $25 per share, 75% at $30 per share and 100% at $35 per share. Also in 1997, the Board of Directors granted 50,159 options at an exercise price of $24.75 per share. These options are vested at 25% when the stock closes at $25 per share, 50% at $30 per share, 75% at $35 per share and 100% at $40 per share. These options are exercisable for a period of 10 years. The weighted average grant date option fair value is $4.60.
In order for the options to become vested, the closing prices must be sustained at or above the levels indicated above for a minimum of five consecutive trading days.
The weighted average contractual remaining life for all options issued is 7.02 years and exercise prices range from $19.063 to $33.907 at December 31, 1999.
Since the Company adopted SFAS-123, compensation expense associated with the options granted is reflected in 1999, 1998 and 1997 net income. The compensation expense recorded was $485,300 in 1999, $239,800 in 1998 and $2,399,000 in 1997. The compensation expense was calculated using the shorter of the anticipated or actual vesting period. In applying SFAS-123, the fair value of each option granted is estimated on the date of the grant using the Black-Scholes option pricing model with the following assumptions: risk-free rate of return ranging from 4.61% to 5.16% for 1999, 5.54% to 5.65% for 1998, and 6.39% to 6.56% for 1997, expected dividend yield of 0% for 1999, 1998 and 1997 and expected stock volatility of 19% for 1999 and 17% for 1998 and 1997.
A summary of the Company's stock option activity is presented below:
Note 9. SHORT-TERM DEBT
On December 31, 1999, RGS had total short-term debt outstanding of $10.5 million, comprised entirely of Energetix's short-term debt. At December 31, 1998, RG&E and Energetix had short-term debt outstanding of $50.5 million and $6.5 million, respectively. The weighted average interest rate on short-term debt outstanding at year-end 1999 for Energetix was 6.74%. The weighted average interest rates for borrowings during the year for RG&E and Energetix were 5.44% and 5.95%, respectively. The weighted average interest rates on short-term debt borrowed during 1998 were 5.51% and 6.31%, respectively.
RG&E's $90 million revolving credit agreement terminates on December 31, 2001. Griffith Oil Co., Inc., a subsidiary of Energetix, has a $15 million revolving credit agreement terminating July 31, 2002. Borrowings under this agreement are secured by personal property of Griffith. Energetix has made a financial guarantee on behalf of Griffith that obligates Energetix in the event of a Griffith default.
RG&E's Charter provides that it may not issue unsecured debt if immediately after such issuance the total amount of unsecured debt outstanding would exceed 15 percent of its total secured indebtedness, capital, and surplus without the approval of at least a majority of the holders of outstanding Preferred Stock. As of December 31, 1999, RG&E would be able to incur approximately $114.5 million of additional unsecured debt under this provision. RG&E has unsecured lines of credit totaling $27 million available from several banks, at their discretion.
In order to be able to use its $90 million revolving credit agreement, RG&E has created a subordinate mortgage which secures borrowings under its revolving credit agreement that might otherwise be restricted by this provision of its Charter. In addition, RG&E has a Loan and Security Agreement to provide for borrowings up to $30 million as needed from time to time for other working capital needs. Borrowings under this agreement, which can be renewed annually, are secured by a lien on RG&E's accounts receivable.
Note 10. COMMITMENTS AND OTHER MATTERS
REGULATORY ASSETS
With PSC approval RG&E has deferred certain costs rather than recognize them on its books when incurred. Such deferred costs are then recognized as expenses when they are included in rates and recovered from customers. Such deferral accounting is permitted by SFAS-71, Accounting for the Effects of Certain Types of Regulation. These deferred costs are shown as Regulatory Assets on the Company's and RG&E's Balance Sheets. Such cost deferral is appropriate under traditional regulated cost-of-service rate setting, where all prudently incurred costs are recovered through rates. In a purely competitive pricing environment, such costs might not have been incurred and could not have been deferred. Accordingly, if RG&E was no longer allowed to defer some or a portion of these costs under SFAS-71, these assets would be adjusted accordingly, up to and including the entire amount being written off.
Below is a summarization of the Regulatory Assets as of December 31, 1999 and 1998:
- - Kamine Settlement: This amount results from a settlement resolving all litigation, releasing all claims and terminating all electricity purchase obligations under a power purchase agreement. Recovery will be at the rate of approximately $10.5 million per year through June 30, 2002 and is subject to modification, thereafter.
- - Income Taxes: This amount represents the unrecovered portion of tax benefits from accelerated depreciation and other timing differences which were used to reduce tax expense in past years. The recovery of this deferral is anticipated over the remaining life of the related property, which varies from one to thirty years, when the effect of the past deductions reverses in future years.
- - Oswego Plant Sale: This amount results from the sale of RG&E's interest in the Oswego generation facility including closing costs and the Buyer's assumption of RG&E's obligations under a transmission services agreement. RG&E is currently amortizing this amount at the rate of approximately $6.5 million per year.
- - Deferred Environmental Site Investigation/Remediation Costs: These costs represent RG&E's share of the estimated costs to investigate and perform certain remediation activities at both RG&E-owned and non-owned sites with which it may be associated. RG&E has recorded a regulatory asset representing the remediation obligations to be recovered from ratepayers, subject to the terms of the Competitive Opportunities Settlement.
- - Uranium Enrichment Decommissioning Deferral: The Energy Policy Act of 1992 requires utilities to contribute such amounts based on the amount of uranium enriched by the United States Department of Energy (DOE) for each utility. This amount is mandated to be paid to DOE through the year 2007. The recovery of these costs is through base rates of fuel.
- - Gas Deferred Fuel: These costs result from a PSC-approved annual reconciliation of recoverable gas costs with gas revenues in which the excess or deficiency is refunded to or recovered from customers during a subsequent period.
- - Labor Day 1998 Storm Costs: These costs result from a 1998 Labor Day storm. Under the Competitive Opportunities Settlement, RG&E is entitled to defer, for later recovery in rates, certain costs, including those caused by "catastrophic events", when any single event results in costs exceeding $2.5 million. RG&E filed a petition with the PSC notifying them of the deferral of these storm costs.
In a competitive electric market, strandable assets would arise when investments are made in facilities, or costs are incurred to service customers, and such costs are not fully recoverable in market-based rates. An example includes high cost generating assets. Estimates of strandable assets are highly sensitive to the competitive wholesale market price assumed in the estimation. The amount of potentially strandable assets at December 31, 1999 depends on market prices and the competitive market in New York State which is still under development and subject to continuing changes which are not yet determinable, but the amount could be significant. Strandable assets, if any, could be written down for impairment of recovery based on SFAS-121, which requires write- down of long-lived assets whenever events or circumstances occur which indicate that the carrying amount of a long-lived asset may not be recoverable.
In a competitive natural gas market, strandable assets would arise where customers migrate away from dependence on RG&E for full service, leaving RG&E with surplus pipeline and storage capacity, as well as natural gas supplies under contract. RG&E has been restructuring its transportation, storage and supply portfolio to reduce its potential exposure to strandable assets. Regulatory developments referred to under "Gas Cost Recovery" below, may affect this exposure; but whether and to what extent there may be an impact on the level and recoverability of strandable assets cannot be determined at this time.
At December 31, 1999 RG&E believes that its regulatory assets are probable of recovery. The Settlement in the Competitive Opportunities Proceeding does not impair the opportunity of RG&E to recover its investment in these assets. However, the PSC issued an Opinion and Order Instituting Further Inquiry on March 20, 1998 to address issues surrounding nuclear generation. The initial meeting in this Inquiry was held in January 1999. RG&E is unable to determine when this proceeding may conclude (see PSC Proceeding on Nuclear Generation under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations). The ultimate determination in this proceeding or any proceeding to consider RG&E's proposed purchase of nuclear plants as discussed under "Nuclear-Related Matters" could have an impact on strandable assets and the recovery of nuclear costs.
CAPITAL EXPENDITURES
The Company's 2000 construction expenditures program is currently estimated at $154 million for RGS of which $151 million is for RG&E. These amounts exclude provision for the proposed purchase of the Nine Mile nuclear generating facilities (see below). The Company has entered into certain commitments for purchase of materials and equipment in connection with that program.
NUCLEAR-RELATED MATTERS
PROPOSED PURCHASE OF NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and New York State Electric and Gas (NYSEG) announced their intention to sell their interests in the Nine Mile Two nuclear plant to AmerGen Energy Company, L.L.C.(AmerGen), a joint venture of PECO Energy of Philadelphia and British Energy. Niagara Mohawk owns 41 percent and NYSEG owns 18 percent of Nine Mile Two. The financial terms of the transaction include purchase prices to be paid to Niagara Mohawk of $63.6 million and to NYSEG of $27.9 million.
RG&E's 14 percent interest in Nine Mile Two was not included in the current proposal. As an original part owner, RG&E generally had three options: the first option was to retain its ownership interest on the same basis that it does now; the second option was to sell its 14 percent interest in Nine Mile Two to AmerGen
on substantially the same terms as Niagara Mohawk and NYSEG; and the third option was to exercise its right-of-first-refusal and buy the Niagara Mohawk and/or NYSEG interests on terms at least as favorable as those offered by AmerGen. Niagara Mohawk took the position that an exercise of the right to buy its interest in Nine Mile Two must necessarily include matching the terms of the agreement between AmerGen and Niagara Mohawk ($72 million) to buy the Nine Mile Point One Nuclear Plant (Nine Mile One), which is 100 percent owned by Niagara Mohawk.
On December 22, 1999, RG&E announced it had exercised its legal right-of- first-refusal to acquire a controlling interest in Nine Mile Two and to acquire the interests of Niagara Mohawk in Nine Mile One. As a result of the regulatory process discussed below, the status of RG&E's acquisition pursuant to its right- of-first-refusal is in question.
RG&E has contracted with Entergy Nuclear Nine Mile, L.L.C. (Entergy Nine Mile) to operate and maintain the plants upon RG&E's acquisition under its right-of-first-refusal. Under the terms of an operating agreement, Entergy Nine Mile will be responsible for operating the plants, for certain operating costs and risks during a transition period and most operating costs and risks thereafter. RG&E will be responsible for substantial operating costs and risks during the transition period and these costs and risks will be significantly reduced after the transition period. RG&E will pay Entergy Nine Mile a fixed price (periodically adjusted by certain appropriate price indices) per kilowatt- hour of power actually generated and delivered to RG&E. The contract with Entergy Nine Mile expires in September 2009.
RG&E intends to finance its acquisition through the issuance of long-term debt. Depending on when transfer of ownership takes place, RG&E currently expects to pay between $180 million and $210 million, including the cost of fuel at the plants. The transfer of ownership of the plants to RG&E and transfer of operation of the plants to Entergy Nine Mile will require State and federal regulatory approvals, including the PSC, the Nuclear Regulatory Commission (NRC) and the FERC.
In this transaction, RG&E will continue to own the rights to its original approximately 160 megawatts of electric generating capacity from Nine Mile Two and acquire the rights to approximately an additional 670 megawatts of capacity from that plant. At the conclusion of its purchase, RG&E would own 73% of Nine Mile Two. The Long Island Lighting Company, which is wholly-owned by the Long Island Power Authority, and Central Hudson Gas & Electric Corporation are the other non-operating owners of Nine Mile Two and will retain their interests in the plant. RG&E would also acquire the entire capacity from Nine Mile One, about 615 megawatts.
Niagara Mohawk and NYSEG will purchase the power produced by their previous ownership shares in the Nine Mile Point plants from RG&E under long-term contracts that run for a period of three to five years. These terms are the same as those agreed to by AmerGen. After that period of time, available power is expected to be sold into the wholesale energy market.
Under the terms of a decommissioning agreement, Entergy Nuclear, Inc. will be responsible for decommissioning the plants at a fixed price after they are both taken out of service. For Nine Mile One, Niagara Mohawk, as the former sole owner, will contribute the entire present cost of decommissioning to a fund. For Nine Mile Two, Niagara Mohawk and NYSEG will contribute payments proportionate to their former ownership interests.
At December 31, 1999 the net book value of RG&E's 14 percent interest in the Nine Mile Two generating facility was approximately $376 million.
On August 30, 1999 the PSC began a proceeding to review the proposed sale of the Nine Mile Point nuclear facilities by Niagara Mohawk and NYSEG to AmerGen to determine if the sale would be in the public interest. RG&E has intervened in that proceeding. In early January 2000, at the request of PSC Trial Staff, that proceeding was suspended to give the interested parties time for settlement negotiations. In late January 2000, the PSC Trial Staff expressed its intention to move to dismiss the proceeding since it believes that the sale to AmerGen, as filed, is not consistent with the public interest standard in Public Service Law Section 70; Trial Staff said that it intends to immediately explore, in conjunction with the utilities and interested parties, other scenarios for future ownership and operation of the Nine Mile nuclear plants; and Trial Staff proposed that the parties dispense with formal evidentiary hearings in this proceeding. AmerGen has asked that the Judge reject Staff's request to dispense with formal evidentiary hearings and instead set a schedule for testimony and hearings in this proceeding.
A separate proceeding to consider RG&E's acquisition of the Nine Mile nuclear facilities has not yet been commenced. At this time, RG&E is uncertain what the outcome of the PSC regulatory process will be but expects that it will continue for some time. RG&E intends to continue to pursue all of its alternatives and evaluate any modifications to the current proposed transaction and any new proposed transaction.
DECOMMISSIONING TRUST. RG&E is collecting amounts in its electric rates for the eventual decommissioning of its Ginna Plant and for its 14% share of the decommissioning of Nine Mile Two. The operating licenses for these plants expire in 2009 and 2026, respectively.
Under accounting procedures approved by the PSC, RG&E has collected decommissioning costs of approximately $160.6 million through December 31, 1999 and is authorized to collect approximately $22 million annually through June 30, 2002 for decommissioning, covering both nuclear units. The amount allowed in rates is based on estimated ultimate decommissioning costs of $296.3 million for Ginna and $112.8 million for the RG&E's 14% share of Nine Mile Two (1995 dollars). These estimates are based on site specific cost studies for each plant completed in 1995. Site specific studies of the anticipated costs of actual decommissioning are required to be submitted to the NRC at least five years prior to the expiration of the license.
The NRC requires reactor licensees to submit funding plans that establish minimum NRC external funding levels for reactor decommissioning. RG&E's plan, filed in 1990, consists of an external decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two share. Since 1990, RG&E has contributed $128.0 million to this fund and, including realized and unrealized investment returns, the fund has a balance of $220.8 million as of December 31, 1999. The amount attributed to the allowance for removal of non-contaminated structures is being held in an internal reserve. The internal reserve balance as of December 31, 1999 is $32.6 million. NRC regulations require biennial reports on the status of Decommissioning Trust funds and RG&E reported to the NRC that both the Ginna and Nine Mile Two decommissioning trusts exceed the NRC minimum funding amounts required as of December 31, 1999.
The NRC has issued a policy statement relating to industry restructuring which addresses, in part, the prospects of joint and several liability of co-owners for nuclear decommissioning costs, such as co-owners of Nine Mile Two. The NRC recognizes that co-owners generally divide costs and output from their facilities by using a contractually-defined, pro rata share standard. The NRC has implicitly accepted this practice in the past and believes that it should continue to be the operative practice, but reserves the right, in highly unusual situations where adequate protection of public health and safety would be
compromised if such action were not taken, to consider imposing joint and several liability on co-owners when one or more co-owners have defaulted.
On March 20, 1998 the PSC issued an Opinion and Order Instituting Further Inquiry. In December 1998 the PSC issued a Notice of Collaborative Conference to further examine the future treatment of nuclear generation. The initial collaborative conference in this proceeding was held in January, 1999. RG&E's potentially strandable assets in nuclear plant could be impacted by the outcome of this proceeding. The parties in this proceeding developed a collaborative, non-binding interim report entitled "Nuclear Generation and the Competitive Electric Market" which was issued in July 1999. RG&E is actively involved in this proceeding which is continuing. RG&E is unable to determine when this proceeding may conclude.
The Staff of the Financial Accounting Standards Board is studying the recognition, measurement and classification of certain liabilities related to the closure or removal of long lived assets. This could affect the accounting for the decommissioning costs of RG&E's nuclear generating stations. If current accounting practices for such costs were changed, the annual provisions for decommissioning costs could increase, the estimated cost for decommissioning could be reclassified as a liability rather than as accumulated depreciation, the liability accounts and corresponding plant asset accounts could be increased and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense.
If annual decommissioning costs increased, the Company would expect to defer the effects of such costs pending disposition by the PSC.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. On June 12, 1998, 16 electric utilities from across the country, including RG&E, filed multi-count complaints against the United States government in the United States District Court for the Southern District of New York. The suits challenge the constitutionality of a $2.25 billion retroactive assessment imposed by the federal government on domestic nuclear power companies to pay for the clean up of the federal government's three uranium enrichment plants. Those plants are located at Oak Ridge, Tennessee, Paducah, Kentucky, and Portsmouth, Ohio. The Oak Ridge plant went into operation in 1945, and the other two plants began operation during the 1950s. The Government has moved to dismiss the utilities' complaints. A decision on the Government's motion is expected in early 2000.
The assessments for Ginna and RG&E's share of Nine Mile Two are estimated to total $22.1 million, excluding inflation and interest. Installments aggregating approximately $12.9 million have been paid through 1999. A liability has been recognized on the financial statements along with a corresponding regulatory asset. For the two facilities RG&E's liability at December 31, 1999 is $12.6 million ($10.9 million as a long-term liability and $1.7 million as a current liability). RG&E is recovering these costs in rates.
NUCLEAR FUEL DISPOSAL COSTS. The Nuclear Waste Policy Act (Nuclear Waste Act) of 1982, as amended, requires the DOE to establish a nuclear waste disposal site and to take title to nuclear waste. A permanent DOE high-level nuclear waste repository is not expected to be operational before the year 2010. In December 1996 the DOE notified RG&E that the DOE would not start accepting Ginna spent fuel in 1998. The Nuclear Waste Act provides for a determination of the fees collectible by the DOE for the disposal of nuclear fuel irradiated prior to April 7, 1983 and for three payment options. The option of a single payment to be made at any time prior to the first delivery of fuel to the DOE was selected by RG&E in June 1985. RG&E estimates the fees, including accrued interest, owed to the DOE to be $91.7 million at December 31, 1999. RG&E is allowed by the PSC to recover these costs in rates. The estimated fees are classified as a long- term liability and interest is accrued at the current three-month Treasury bill
rate, adjusted quarterly. The Nuclear Waste Act also requires the DOE to provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a charge of approximately one mill ($.001) per KWH of nuclear energy generated and sold. This charge (approximately $4.3 million per year) is currently being collected from customers and paid to the DOE pursuant to PSC authorization. RG&E expects to utilize on-site storage for all spent or retired nuclear fuel assemblies until an interim or permanent nuclear disposal facility is operational.
There are presently no facilities in operation in the United States available for the reprocessing of spent nuclear fuel from utility companies. In RG&E's determination of nuclear fuel costs it has taken into account that nuclear fuel would not be reprocessed and has provided for disposal costs in accordance with the Nuclear Waste Act. In November 1998 RG&E completed installation of seven high-capacity spent fuel racks in the Ginna spent fuel pool. This will allow interim storage capacity of all spent fuel discharged from the Ginna Plant through the end of its Operating License in the year 2009.
ENVIRONMENTAL MATTERS
The Company is subject to federal, state and local laws and regulations dealing with air and water quality and other environmental matters. Environmental matters may expose the Company to potential liabilities which, in certain instances, may be imposed without regard to fault or historical activities which were lawful at the time they occurred. The Company continually monitors its activities in order to determine the impact of its activities on the environment and to ensure compliance with various environmental requirements. RGS has recorded a total liability of approximately $23.7 million in connection with Site Investigation and/or Remediation (SIR) efforts where disposal of certain waste products may have occurred. Estimates of the SIR costs for each of these sites range from preliminary to highly refined. RG&E and Energetix expect to pay these SIR costs over the next ten years. These estimates could change materially, based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations. Liability may be joint and several for certain of these sites. There may be additional costs with respect to these and possibly other sites, the materiality of which is not presently determinable.
RG&E-OWNED ELECTRIC AND GAS WASTE SITE ACTIVITIES. RG&E is conducting proactive SIR efforts at seven RG&E-owned sites where past waste handling and disposal may have occurred. Remediation activities at five of these sites are in various stages of planning or completion and RG&E is conducting a program to restore the other two sites. RG&E has recorded a liability of approximately $21.9 million for SIR efforts at the seven Company-owned sites in the Rochester, NY area.
SUPERFUND AND NON-OWNED OTHER SITES. RG&E has been or may be associated as a potentially responsible party at eight sites not owned by it and has recorded estimated liabilities of approximately $.5 million in connection with SIR efforts at these sites. RG&E has signed orders on consent for five of these sites.
GRIFFITH FACILITIES. RGS's subsidiary, Energetix, acquired Griffith Oil, Inc. in 1998. A review and audit was conducted of all Griffith facilities by a nationally recognized engineering firm as part of the due diligence acquisition process by Energetix. As a result of this review 35 sites were identified which are currently undergoing evaluation and/or remediation. Using historical New York State Department of Environmental Conservation (NYSDEC) remedial actions as a guide, Energetix estimates the accrual of aggregate cleanup costs discounted at 6.8% over the future five-year period for all active sites approximates $1.3 million.
NEW YORK INITIATIVES. The New York Attorney General sent a letter to certain New York utilities in October, 1999 requesting historic information regarding certain upgrades, modifications and maintenance activities at coal fired power plants under their control. RG&E received such a letter requesting data covering a period back to 1977 for its Russell and (the now closed) Beebee Stations. The letter suggests that those upgrades, modifications and improvements may have required permission from the NYSDEC prior to their occurrence. RG&E and other letter recipients are involved in discussions with the Attorney General's office to clarify the scope and timing of the request and establish the role of the Attorney General and the DEC in the information gathering effort and any subsequent potential action. On January 13, 2000, RG&E received a formal request from the NYSDEC pursuant to its investigatory powers under the New York Environmental Conservation Law which seeks essentially the same documents covered by the Attorney General's letter. Commencing January 21, 2000, RG&E is providing responsive documents to the State through NYSDEC. RG&E cannot assess the potential impact of this initiative in these early stages of its development.
On October 14, 1999, the Governor of New York publicly proposed modifications of the state's oxides of nitrogen (NOx) and sulfur dioxide (SO2) control programs. The Governor's proposal suggests extending the existing NOx control program under which RG&E's Russell Station operates to a year-round program (it is currently in effect only for the five month ozone season). The proposal suggests such a change should take effect in October, 2003. In addition, the Governor is also proposing that there be a targeted reduction of some 50% in SO2 emissions below the existing Acid Rain Phase II limits that are required under the 1990 Clean Air Act Amendments. The proposal suggests a phase-in period from 2003 through 2007. Since this is only a proposed rule change and subject to review, comment and modification, no estimate of the future economic impact on RG&E of a change in the rules can be made at this time because the nature of the change is uncertain.
GAS COST RECOVERY
PSC GAS RESTRUCTURING POLICY STATEMENT. On November 3, 1998, the PSC issued a gas restructuring policy statement ("Gas Policy Statement") announcing its conclusion that, among other things, the most effective way to establish a competitive gas supply market is for gas distribution utilities to cease selling gas. The PSC established a transition process in which it plans to address three groups of issues: (1) individual gas utility plans to implement the PSC's vision of the market; (2) key generic issues to be dealt with through collaboration among gas utilities, marketers, pipelines and other stakeholders, and (3) coordination of issues that are common to both the gas and the electric industries. The PSC has encouraged settlement negotiations with each gas utility pertaining to the transition to a fully competitive gas market. RG&E, the PSC Staff and other interested parties have been participating in settlement discussions in response to the specific requirements of the Policy Statement.
GAS PROPOSAL AND INTERIM SETTLEMENT. In August 1998, prior to issuance of the PSC's Gas Policy Statement (see PSC Gas Restructuring Policy Statement above), RG&E had commenced negotiations with the PSC staff and other parties to develop a comprehensive multi-year settlement of various issues, including rates and the structure of RG&E's gas business. Because the negotiation of a comprehensive settlement was not anticipated to conclude until mid-1999, the parties to the negotiations agreed to an Interim Settlement, effective November 1998 through June 1999, that dealt with such issues as rates, transportation and storage capacity costs, assignment of capacity, and retail access. Significant features of the Interim Settlement include a freeze on base rates at the current levels (which were fixed at July 1994 levels), the imputation of $11.9 million in
revenues from the remarketing of capacity and a limit on RG&E's exposure to costs associated with the migration of customers from RG&E to marketers for sales service.
Discussions following the expiration of the Interim Settlement resulted in a September 14, 1999, filing to address issues pertaining to the cost of upstream capacity and other matters pertaining to restructuring pursuant to the PSC's Policy Statement. The proposal calls for: (1) a continued reduction in capacity costs of $11.9 million, comprised of $10.2 million relating to upstream capacity release transactions for the period September 1, 1999 through August 31, 2000 and $1.7 million from the expiration of a Texas Eastern capacity contract; (2) a report to PSC staff, within 60 days of approval of the proposal, of the progress RG&E has made to reduce its upstream capacity costs; (3) a resumption of the multi-year settlement discussions calling for RG&E to make a public filing addressing the rate and restructuring issues addressed in the PSC's Policy Statement within 120 days of approval of the proposal; and (4) RG&E continuing to work on retail access program improvements. The proposal was subsequently approved by the PSC and RG&E began implementation of its proposal in the fourth quarter of 1999. RG&E has proceeded to implement the proposal as approved. As required, the report on upstream capacity costs was submitted on November 29, 1999, under trade secret status. The public filing addressing the rate and restructuring issues was made on January 28, 2000. This filing is intended to provide the basis for negotiations with the PSC and other interested parties on RG&E's proposal to implement a fully competitive marketplace for natural gas. Settlement negotiations pertaining to RG&E's gas rate and restructuring proposal will begin as early as 30 days after the filing pursuant to the Policy Statement.
Under a March 1996 Order, the PSC permitted RG&E and other gas distribution companies to assign to marketers the pipeline and storage capacity held by RG&E to serve their customers. In its Gas Policy Statement issued in November 1998, the PSC ordered that the mandatory assignment of capacity, permitted by the March 1996 Order, be terminated effective April 1, 1999. According to the Gas Policy Statement, however, the utilities are to be afforded a reasonable opportunity to recover resulting strandable costs, if any. On March 24, 1999, the PSC issued an Order Concerning Assignment of Capacity for all gas utilities in the State of New York, generally requiring the removal of restrictions on customer migration from utility sales service to service from marketers. RG&E has complied with the PSC's directives.
LITIGATION
SPENT NUCLEAR FUEL LITIGATION. The federal Nuclear Waste Act obligated DOE to accept for disposal spent nuclear fuel (SNF) from utilities' powerplants by January 31, 1998 (statutory deadline). Since the mid-1980s RG&E and other nuclear plant owners and operators have paid substantial fees to DOE to fund that obligation (Nuclear Waste Fund). That the DOE would not meet its obligation was evident well prior to 1998; DOE admitted as much as the statutory deadline approached.
DOE's failure to meet its statutory deadline has given rise to numerous lawsuits in both the U.S. Court of Appeals for the District of Columbia and the U.S. Court of Federal Claims.
Although the DOE has been found to have breached its obligations, it is not possible to predict the outcome of these cases, the future course of the DOE obligation or the resolution of the spent nuclear fuel movement and storage concern that underlies it. Similarly, the ultimate outcome of nuclear waste legislation in Congress, that could address these and related concerns, is uncertain. The court rulings on the DOE's default in meeting its obligation to remove SNF by the statutory deadline, and on its contractual liability therefor, have been promising. The current court rulings appear to have prompted greater
DOE effort to complete site investigations at its Yucca Mountain, NV, site for SNF disposal and to focus greater Congressional attention on the inappropriateness of continuing to house SNF around the nation at short-term SNF facilities of nuclear powerplants. These developments have not yet led, however, either to a firm schedule for DOE's movement of SNF from plant facilities to a permanent repository or to the authorization of plant owners and operators to withhold their Nuclear Waste Fund payments to DOE until that schedule is established. RG&E and other nuclear utilities continue to work toward those objectives in judicial, legislative and administrative initiatives.
OTHER MATTERS
OTHER STATEMENT OF INCOME ITEMS. The change in RGS's and RG&E's Other Income and Deductions, Other-net reflects mainly the recognition of income in 1998 due to the elimination of certain pension and other post-employment benefit deferred credits and Nine Mile Two operating and maintenance expenses in accordance with the Competitive Opportunities Settlement. This variance in Other Income and Deductions, Other-net was partially offset by non-cash carrying charges of $8.6 million related to deferral of Kamine (Allegany Station) facility costs in 1999 for the regulated business. These carrying charges, which are primarily associated with the deferred recovery of costs associated with the Kamine settlement, were allowed under the Competitive Opportunities and Kamine settlements. In addition, expenses associated with RG&E management performance awards were down $4.4 million in 1999 compared with 1998.
EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY. In July 1997, the Financial Accounting Standards Board's EITF reached a consensus on accounting rules for utilities' transition plans for moving to more competitive environments and provided guidance on when utilities with transition plans will need to discontinue the application of SFAS-71.
The major EITF consensus was that the application of SFAS-71 to a segment (e.g. generation) which is subject to a deregulation transition plan should cease when the legislation or enabling rate order contains sufficient detail for the utility to reasonably determine what the transition plan will entail. The EITF also concluded that a decision to continue to carry some or all of the regulatory assets (including stranded costs) and liabilities of the separable portion of the business that is discontinuing the application of SFAS-71 should be determined on the basis of where the regulated cash flows to realize and settle them will be derived. If a transition plan provides for a non-bypassable fee for the recovery of stranded costs, there may not be any significant write- off if SFAS-71 is discontinued for a segment.
RG&E's application of the EITF 97-4 consensus has not affected its financial position or results of operations because any above-market generation costs, regulatory assets and regulatory liabilities associated with the generation portion of its business will be recovered by the regulated portion of RG&E through its distribution rates, given the Settlement provisions. The Settlement provides for recovery of all prudently incurred sunk costs (all investment in electric plant and electric regulatory assets) as of March 1, 1997 by inclusion in rates charged pursuant to RG&E's distribution access tariff. The Settlement also states that "the Parties intend that the provisions of this Settlement will allow RG&E to continue to recover such costs, during the term of the Settlement, under SFAS-71", and that "such treatment shall be consistent with the principle that RG&E shall have a reasonable opportunity beyond July 1, 2002 to recover all such costs". The fixed portion of the non-nuclear generation to-go costs sometime after July 1, 1999 and the variable portion of the non- nuclear generation to-go costs after July 1, 1998 are subject to market forces and would no longer be able to apply SFAS-71. These costs have been below prevailing market prices. RG&E's net investment at December 31, 1999 in nuclear generating assets is $634.3 million and in non-nuclear generating assets is $58.4 million. (See
"Proposed Purchase of Nuclear Plants" for information concerning RG&E's proposed acquisition of the interests in Nine Mile Two owned by two co-owners and Nine Mile One owned by Niagara Mohawk.)
LEASE AGREEMENTS. RG&E and Energetix lease a total of 15 properties for administrative offices, operating activities and vehicles. The total lease obligations charged to operations was $5.4 million, $4.8 million and $4.2 million in 1999, 1998 and 1997, respectively, including $1.5 million in 1999 and $.5 million in 1998 for Energetix. RG&E's estimated annual lease obligations for the years 2000-2004 will be $4.0 million, $2.5 million, $2.5 million, $2.7 million and $2.7 million, respectively. Energetix estimated annual lease obligations for the years 2000-2004 will be $1.3 million, $1.0 million, $.6 million, $.4 million and $.2 million, respectively. Commitments under capital leases after 2004 are not significant.
PURCHASE COMMITMENTS. The Company has entered into electric and natural gas purchase commitments with numerous suppliers. Certain of these commitments support fixed price offerings to retail electric and gas customers.
INTERIM FINANCIAL DATA
In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results of operations for such periods. The variations in operations reported on a quarterly basis are a result of the seasonal nature of the Company's business and the availability of surplus electricity. The sum of the quarterly earnings per share may not equal the fiscal year earnings per share due to rounding.
/1/ Reclassified for comparative purposes.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
Information required by Items 10-14 with respect to RG&E has been omitted pursuant to General Instruction J(2)(c). Information required by Items 10-14 with respect to RGS are described below.
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 of Form 10-K relating to directors who are nominees for election as directors at RGS's Annual Meeting of Shareholders to be held on April 26, 2000, will be set forth under the heading "Election of Directors" in the Company's Definitive Proxy Statement for such Annual Meeting of Shareholders.
The information required by Item 10 of Form 10-K with respect to RGS's executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Part I as Item 4 - A of this Form 10-K under the heading "Executive Officers of the Registrant".
Item 11.
Item 11. EXECUTIVE COMPENSATION
The information required for RGS by Item 11 of Form 10-K will be set forth under the headings "Report of the Committee on Management on Executive Compensation", "Executive Compensation" and "Pension Plan Table" in RGS's Definitive Proxy Statement for the Annual Meeting of Shareholders.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 of Form 10-K will be set forth under the heading "Security Ownership of Management" in RGS's Definitive Proxy Statement for the Annual Meeting of Shareholders.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 of Form 10-K will be set forth under the heading "Election of Directors" in RGS's Definitive Proxy Statement for the Annual Meeting of Shareholders.
Pursuant to General Instruction G(3) to Form 10-K, Items 10 through 13 have not been answered because, within 120 days after the close of its fiscal year, RGS will file with the Commission a definitive proxy statement pursuant to Regulation 14A which involves the election of directors. RGS's definitive proxy statement dated March 15, 2000 will be filed with the Securities and Exchange Commission prior to April 30, 1999. The information required in Items 10 through 13 under the headings set forth above is incorporated by reference herein by this reference thereto. Except as specifically referenced herein the proxy statement in connection with the annual meeting of shareholders to be held April 26, 2000 is not deemed to be filed as part of this Report.
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. The financial statements listed below are shown under Item 8 of this Report.
Report of Independent Accountants.
RGS Consolidated Statement of Income for each of the three years ended December 31, 1999.
RGS Consolidated Statement of Retained Earnings for each of the three years ended December 31, 1999.
RGS Consolidated Balance sheet at December 31, 1999 and 1998.
RGS Consolidated Statement of Cash Flows for each of the three years ended December 31, 1999.
RG&E Consolidated Statement of Income for each of the three years ended December 31, 1999.
RG&E Consolidated Statement of Retained Earnings for each of the three years ended December 31, 1999.
RG&E Consolidated Balance sheet at December 31, 1999 and 1998.
RG&E Consolidated Statement of Cash Flows for each of the three years ended December 31, 1999.
RGS and RG&E Notes to Consolidated Financial Statements.
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1999.
Schedule II - Valuation and Qualifying Accounts of RGS and RG&E.
(a) 3. Exhibits - See List of Exhibits.
(b) Reports on Form 8-K
RGS and RG&E:
A report was filed on December 22, 1999 in connection with RG&E exercising its right of first refusal to acquire a controlling interest in the Nine Mile Point 2 Nuclear Plant and to buy the Nine Mile Point 1 nuclear Plant.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Thousands of Dollars)
Beginning in 1992 the Company no longer charges uncollectible expenses through the uncollectible reserve. The 1998 reserves for uncollectibles includes Energetix. The total amount written off directly to expense in 1997 was $12,912, in 1998 was $11,838 and in 1999 was $11,852. In 1997, the amounts charged to other accounts represent a true-up of writeoff amounts during the implementation of a new customer information system ($3.0 million) and the forgiveness of late payment amounts which had previously been reflected as revenue ($1.3 million). In 1998, the amount charged to other accounts reflects consolidation of Energetix/Griffith reserve for uncollectibles ($0.3 million) and forgiveness of late payments ($0.2 million). The deductions in 1998 represent true-ups of the estimated reserve required for uncollectibles. In 1999, the amount charged to other accounts reflects consolidation of Energetix/Griffith reserve for uncollectibles.
LIST OF EXHIBITS
Exhibit 3-1* Restated Certificate of Incorporation of Rochester Gas and Electric Corporation under Section 807 of the Business Corporation Law filed with the Secretary of State of the State of New York on June 23, 1992. (Filed in Registration No. 33-49805 as Exhibit 4-5 in July 1993)
Exhibit 3-2* Certificate of Amendment of the Certificate of Incorporation of Rochester Gas and Electric Corporation Under Section 805 of the Business Corporation Law filed with the Secretary of State of the State of New York on March 18, 1994. (Filed as Exhibit 4 in May 1994 on Form 10-Q for the quarter ended March 31, 1994, SEC File No. 1-672)
Exhibit 3-3* By-Laws of RG&E, as amended to date. (Filed as Exhibit 3-3 in February 1999 on Form 10-K for the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 3-4* Certificate of Incorporation of RGS Energy Group, Inc. filed with the Secretary of State of the State of New York on November 5, 1998. (Filed as Exhibit 3-1 in Registration Statement No. 333- 67427)
Exhibit 3-5* By-Laws of RGS Energy Group, Inc. (Filed as Exhibit 3-2 in Registration Statement No. 333-67427)
Exhibit 4-1* Restated Certificate of Incorporation of Rochester Gas and Electric Corporation under Section 807 of the Business Corporation Law filed with the Secretary of State of the State of New York on June 23, 1992. (Filed in Registration No. 33-49805 as Exhibit 4-5 in July 1993)
Exhibit 4-2* Certificate of Amendment of the Certificate of Incorporation of Rochester Gas and Electric Corporation Under Section 805 of the Business Corporation Law filed with the Secretary of State of the State of New York on March 18, 1994. (Filed as Exhibit 4 in May 1994 on Form 10-Q for the quarter ended March 31, 1994, SEC File No. 1-672)
Exhibit 4-3* By-Laws of RG&E, as amended to date. (Filed as Exhibit 3-3 in February 1999 on Form 10-K for the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 4-4* Certificate of Incorporation of RGS Energy Group, Inc. filed with the Secretary of State of the State of New York on November 5, 1998. (Filed as Exhibit 3-1 in Registration Statement No. 333-67427)
Exhibit 4-5* By-Laws of RGS Energy Group, Inc. (Filed as Exhibit 3-2 in Registration Statement No. 333-67427)
Exhibit 4-6* General Mortgage to Bankers Trust Company, as Trustee, dated September 1, 1918, and supplements thereto, dated March 1, 1921, October 23, 1928, August 1, 1932 and May 1, 1940. (Filed as Exhibit 4-2 in February 1991 on Form 10-K for the year ended December 31, 1990, SEC File No. 1-672)
Exhibit 4-7* Supplemental Indenture, dated as of March 1, 1983 between the Company and Bankers Trust Company, as Trustee (Filed as Exhibit 4-1 on Form 8-K dated July 15, 1993, SEC File No. 1-672)
Exhibit 10-1* Basic Agreement dated as of September 22, 1975 among RG&E, Niagara Mohawk Power Corporation, Long Island Lighting Company, New York State Electric & Gas Corporation and Central Hudson Gas & Electric Corporation. (Filed in Registration No. 2-54547, as Exhibit 5-P in October 1975)
Exhibit 10-2* Letter amendment modifying Basic Agreement dated September 22, 1975 among RG&E, Central Hudson Gas & Electric Corporation, Orange and Rockland Utilities, Inc. and Niagara Mohawk Power Corporation. (Filed in Registration No. 2-56351, as Exhibit 5-R in June 1976)
Exhibit 10-3* Agreement dated February 5, 1980 between RG&E and the Power Authority of the State of New York. (Filed as Exhibit 10-10 in February 1990 on Form 10-K for the year ended December 31, 1989, SEC File No. 1-672)
Exhibit 10-4* Agreement dated March 9, 1990 between RG&E and Mellon Bank, N.A. (Filed as Exhibit 10-1 in May 1990 on Form 10-Q for the quarter ended March 31, 1990, SEC File No. 1-672)
Exhibit 10-5* Operating Agreement effective January 1, 1993 among the owners of the Nine Mile Point Nuclear Plant Unit No. 2. (Filed as Exhibit 10-12 in February 1993 on Form 10-K for the year ended December 31, 1992, SEC File No. 1-672)
Exhibit 10-6* (A) Rochester Gas and Electric Corporation Deferred Compensation Plan. (Filed as Exhibit 10-14 in February 1994 on Form 10-K for the year ended December 31, 1993, SEC File No. 1-672)
Exhibit 10-7* (A) Rochester Gas and Electric Corporation Long Term Incentive Plan, Restatement of January 1, 1994. (Filed as Exhibit 10-10 in February 1995 on Form 10-K for the year ended December 31, 1994, SEC File No. 1-672)
Exhibit 10-8* (A) Rochester Gas and Electric Corporation Deferred Stock Unit Plan for Non-Employee Directors, effective as of December 31, 1995. (Filed as Exhibit 10-1 in May 1996 on Form 10-Q for the quarter ended March 31, 1996, SEC File No. 1-672)
Exhibit 10-9* (A) RGS Energy Group, Inc. Executive Incentive Plan, Restatement of January 1, 1999. (Filed as Exhibit 10 in November 1999 on Form 10-Q for the quarter ended September 30, 1999, SEC File No. 0-30338)
Exhibit 10-10* (A) RG&E Unfunded Retirement Income Plan Restatement as of July 1, 1995. (Filed as Exhibit 10-12 in February 1996 on Form 10-K for the year ended December 31, 1995, SEC File No. 1-672)
Exhibit 10-11* (A) Agreement dated January 1, 1999 between RG&E and Thomas S. Richards, Chairman of the Board, President and Chief Executive Officer. (Filed as Exhibit 10-13 in February 1999 on Form 10-K for the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 10-12* (A) Agreement dated January 1, 1999 between RG&E and Paul C. Wilkens, Senior Vice President, Generation. (Filed as Exhibit 10-14 in February 1999 on Form 10-K for the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 10-13* (A) Agreement dated January 1, 1999 between RG&E and J. Burt Stokes, Senior Vice President, Corporate Services and Chief Financial Officer. (Filed as Exhibit 10-15 in February 1999 on Form 10-K for the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 10-14* (A) Agreement dated January 26, 1999 between RG&E and Michael J. Bovalino, President, Energetix, Inc. (Filed as Exhibit 10-16 in February 1999 on Form 10-K for the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 10-15* Amended and Restated Settlement Agreement dated October 23, 1997 between the Company the Staff of the New York Public Service Commission (PSC), and certain other parties (Filed as Exhibit 10-4 on Form 10-Q for the quarter ended September 30, 1997, SEC File No. 1-672) as amended pursuant to an order of the PSC issued January 14, 1998 (excluding Appendices). (Filed as Exhibit 10-18 in February 1998 on Form 10-K for the year ended December 31, 1997, SEC File No. 1-672)
Exhibit 10-16* (A) Form of Rochester Gas and Electric Corporation 1996 Performance Stock Option Plan Agreement. (Filed as Exhibit 10-1 in November 1997 on Form 10-Q for the quarter ended September 30, 1997, SEC File No. 1-672)
Exhibit 10-17* (A) Agreement, dated January 18, 1999, between RG&E and Michael T. Tomaino, Senior Vice President and General Counsel. (Filed as Exhibit 10-19 in February 1999 on Form 10-K for the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 10-18* Global Settlement Agreement as amended October 29, 1998 between RG&E, General Electric Capital Corporation and Kamine/Besicorp Allegany L.P. and other Kamine affiliates. (Filed as Exhibit 10-21 in February 1999 on Form 10-K for the year ended December 31, 1998, SEC File No. 1-672)
Exhibit 21 Subsidiaries of RGS
Exhibit 23 Consent of PricewaterhouseCoopers LLP, independent accountants
Exhibit 27-1 Financial Data Schedule of RGS, pursuant to Item 601(c) of Regulation S-K.
Exhibit 27-2 Financial Data Schedule of RG&E, pursuant to Item 601(c) of Regulation S-K.
* Incorporated by reference. (A) Denotes executive compensation plans and arrangements.
RG&E agrees to furnish to the Commission, upon request, a copy of all agreements or instruments defining the rights of holders of debt which do not exceed 10% of the total assets with respect to each issue, including the Supplemental Indentures under the General Mortgage and credit agreements in connection with promissory notes as set forth in Note 6 of the Notes to Financial Statements.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
RGS ENERGY GROUP, INC.
ROCHESTER GAS AND ELECTRIC CORPORATION
By: /S/ THOMAS S. RICHARDS ------------------------------ (Thomas S. Richards) Chairman, President and Chief Executive Officer
DATE: February 11, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each Registrant in the capacities and on the dates indicated.
SIGNATURE TITLE (RGS and RG&E DATE - --------- ------ ---- unless otherwise noted)
Principal Executive Officer:
/S/ THOMAS S. RICHARDS Chairman, President and February 11, 2000 - ---------------------------- Chief Executive Officer (Thomas S. Richards)
Principal Financial Officer:
/S/ J. B. STOKES Senior Vice President and February 11, 2000 - ---------------------------- Chief Financial Officer of (J. Burt Stokes) RGS; Senior Vice President, Corporate Services and Chief Financial Officer of RG&E
Principal Accounting Officer:
/S/ WILLIAM J. REDDY Controller of RGS; February 11, 2000 - ---------------------------- Vice President and (William J. Reddy) Controller of RG&E
SIGNATURE TITLE DATE - --------- ----- ----
Directors of RGS and RG&E:
/S/ ANGELO J. CHIARELLA Director February 11, 2000 - --------------------------- (Angelo J. Chiarella)
/S/ ALLAN E. DUGAN Director February 11, 2000 - --------------------------- (Allan E. Dugan)
/S/ MARK B. GRIER Director February 11, 2000 - ---------------------------- (Mark B. Grier)
/S/ SUSAN R. HOLLIDAY Director February 11, 2000 - --------------------------- (Susan R. Holliday)
/S/ JAY T. HOLMES Director February 11, 2000 - --------------------------- (Jay T. Holmes)
/S/ G. JEAN HOWARD Director February 11, 2000 - ---------------------------- (G. Jean Howard)
/S/ SAMUEL T. HUBBARD,JR Director February 11, 2000 - --------------------------- (Samuel T. Hubbard,Jr.)
/S/CLEVE L. KILLINGSWORTH,JR. Director February 11, 2000 - ---------------------------- (Cleve L. Killingsworth,Jr.)
/S/ ROGER W. KOBER Director February 11, 2000 - --------------------------- (Roger W. Kober)
/S/ CORNELIUS J. MURPHY Director February 11, 2000 - --------------------------- (Cornelius J. Murphy)
/S/ CHARLES I. PLOSSER Director February 11, 2000 - --------------------------- (Charles I. Plosser)
/S/ THOMAS S. RICHARDS Director February 11, 2000 - --------------------------- (Thomas S. Richards)