Committee Reports

Electric Utilities Restructuring in New York: A Status Report


A.The Traditional Structure Of The Industry2
B.Federal Legislation3
(a)Public Utility Holding Company Act of 1935 (“PUHCA”)3
(b)Part II of the Federal Power Act (“FPA”)4
(c)Public Utility Regulatory Policies Act of 1978 (“PURPA”)4
2.Public Power5
C.The Drivers Of Change6
1.Progress in Technology6
3.The Example of Other Regulated Industries8
4.The Special Case of Shoreham9
D.The Process Of Change In New York9
E.Consolidated Edison Company Of New York, Inc.12
1.Rate Plan12
(b)Scheduled reductions (to base rates)13
(c)Other significant rate provisions13
2.Retail Access Schedule14
3.Rate Design And Back-Out Rates15
(a)Rate design15
(b)Back-out rates16
4.Generation Divestiture/Market Power Issues16
5.Corporate Restructuring16
(a)Holding company structure16
(b)Functional realignment17
6.Affiliate Transactions And Competitive Conduct Standards; Royalty17
(a)Affiliate transactions17
(b)Competitive Conduct Standards18
7.Stranded Cost Recovery18
(a)Definition and magnitude18
(b)Recovery mechanisms19
8.Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities21
9.Social/Environmental Programs22
(a)Environmental Programs22
(b)Low-income assistance22
(c)Economic development22
10.System Benefits Charge22
11.Reliability Incentives/Penalties23
12.Nuclear Generation Issues23
F.Orange & Rockland Utilities, Inc.23
1.Rate Plan24
(b)Rate reductions (to base rates)24
2.Retail Access Schedule24
3.Rate Design and Back-out Rates24
4.Generation Divestiture/Market Power Issues25
5.Corporate Restructuring25
6.Competitive Conduct Standards and Affiliate Transactions26
7.Stranded Cost Recovery26
8.Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities27
9.Social/Environmental Programs27
(a)Environmental programs27
(b)Low-income assistance27
(c)Economic development27
10.System Benefits Change28
11.Reliability Incentives/Penalties28
12.Nuclear Generation Issues28
G.Central Hudson Gas & Electric Corporation28
1.Rate Plan28
(b)Scheduled Reductions (to Base Rates)29
2.Retail Access Schedule29
3.Rate Design29
(b)Industrial rate options30
4.Generation Divestiture/Market Power Issues31
5.Corporate Restructuring31
6.Competitive Conduct Standards and Affiliate Transactions31
7.Stranded Cost Recovery32
8.Supplier of Last Resort and Energy Service Company Responsibilities32
9.Social/Environmental Programs32
(a)Environmental programs32
(b)Low-income assistance33
(c)Economic development33
10.System Benefits Charge33
11.System Benefits Charge33
12.Reliability Incentives/Penalties33
13.Nuclear Generation Issues33
H.New York State Electric & Gas Corporation33
1.Rate Plan34
(b)Scheduled reductions (to base rates)34
2.Retail Access Schedule35
3.Rate Design and Back-Out Rates35
(a)Rate Design35
(b)Back-Out Rates36
4.Generation Divestiture/Market Power Issues36
5.Corporate Restructuring37
6.Competitive Conduct Standards and Affiliate Transactions37
7.Stranded Cost Recovery37
8.Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities38
9.Social/Environmental Programs38
(a)Environmental programs38
(b)Low-income assistance38
(c)Economic development39
10.System Benefits Charge39
11.Reliability Incentives/Penalties39
12.Nuclear Generation Issues39
I.Niagara Mohawk Power Corporation40
1.Rate Plan40
(b)Scheduled reductions (to base rates)41
2.Retail Access Schedule41
3.Rate Design and Back-Out Rates41
(a)Rate design41
(b)Back-out rates42
4.Generation Divestiture/Market Power Issues42
5.Corporate Restructuring43
6.Competitive Conduct Standards and Affiliate Transactions43
7.Stranded Cost Recovery44
8.Supplier of Last Resort and Energy Service Company Responsibilities44
9.Social/Environmental Programs44
(a)Environmental programs44
(b)Low-income assistance45
10.System Benefits Charge45
11.Reliability Incentives/Penalties45
12.Nuclear Generation Issues45
J.Rochester Gas And Electric Corporation46
1.Rate Plan46
(b)Scheduled reductions (to base rates)46
2.Retail Access Schedule47
3.Rate Design And Back-Out Rates48
(a)Rate design48
(b)Back-out rates48
4.Generation Divestiture/Market Power Issues49
5.Corporate Restructuring49
6.Competitive Conduct Standards and Affiliate Transactions49
7.Stranded Cost Recovery50
8.Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities50
9.Social/Environmental Programs51
10.System Benefits Charge51
11.Reliability Incentives/Penalties51
12.Nuclear Generation Issues51
K.Long Island Lighting Company/The Brooklyn Union Gas Company52
1.Rate Plan52
(a)LILCO/Brooklyn Union’s Rate Plan52
(b)LIPA’s rate plan53
2.Retail Access Schedule53
3.Rate Design and Back-Out Rates53
(a)Residential rates53
(b)Non-residential rates54
(c)Buy-back rates54
(d)Shoreham property tax settlement54
4.Generation Divestiture/Market Power Issues54
5.Corporate Restructuring54
6.Competitive Conduct Standards and Affiliate Transactions55
(a)Allocation of common costs and accounting for transactions between and among the new holding company and its subsidiaries55
(b)Provision of services56
(c)Other restrictions on affiliate transactions56
7.Stranded Cost Recovery57
8.Supplier of Last Resort and Energy Service (ESCO) Responsibilities57
9.Social/Environmental Programs57
10.System Benefits Charge57
11.Reliability Incentives/Penalties58
12.Nuclear Generation Issues58
13.Mergers and Acquisitions58
(a)Energy-related business59
(b)Water, environmental and technical services59
(c)Telecommunication business59
(d)Area development business59
(e)Financial services businesses59
L.Winners And Losers60
1.Will Competition Lower All-In Rates and, If So, by How Much?60
2.How Will the Benefits and Burdens of Competition Be Shared?61
(a)Residential customers61
(b)Commercial and industrial customers61
(c)Utility, IPP and ESCO investors61
(d)Utility, IPP and ESCO investors61
(e)State and local government (tax revenues and tax base)63
3.The Customer Experience under Competition63
(a)New products and services63
(c)Environmental issues64
4.Economic and Political Effects at State and Local Levels64
M.Utility Restructuring Programs65
1.Organizational Restructuring65
3.Merger Activity66
5.Generation Divestiture67
N.Transmission System Issues68
1.The Independent System Operator68
2.Transmission System Planning68
P.Statement of Financial Accounting Standards No. 7169



New York State has initiated an historic restructuring of the way New Yorkers will purchase electricity. While part of a national trend, the New York initiative is in the vanguard. The New York experience will undoubtedly set precedents and provide lessons applicable in other jurisdictions, nationally and perhaps internationally. This Report is on the status, as of April 1998, of New York State’s restructuring effort, which will introduce retail competition and choice of supplier for the New York electricity consumer. While many of the details remain nascent and in some respects untested, a brief review of the emerging structure may be useful to residential, commercial and industrial consumers of electricity, to participants in the electric utility industry, to investors, to their advisors and — because the process necessarily involves a complex of political issues — to voters and legislators.

This Report is in three parts. First, in Part I, the institutional and legal structure of the electric utility industry is sketched broadly. Several of the forces contributing to the restructuring initiative are also set forth in Part I together with a discussion of the process of change in New York. Second, in Part II, the restructuring plans of the seven investor-owned electric utility companies are summarized. Generally, these plans reflect collaborative efforts among a number of interested parties to reach agreement on a restructuring plan for each company. Each plan has been approved by the New York Public Service Commission (“PSC”). Finally, in Part III, several issues and questions about the future of the restructuring effort in New York are posed. A glossary of pertinent terms used in this Report is set forth in the Appendix.



The Traditional Structure Of The Industry


Historically, the dominant characteristics of the electric utility industry have been vertical integration and monopoly, with utility operations generally limited to a single state or locality. The reasons have been historical, technological and economic.
Industry pioneers at the end of the nineteenth century who wished to offer electric service to the public had no suppliers to buy from and hence had to generate their own supply. Also, since continuity and reliability of supply were essential to attracting customers for this new commodity, and since there was no practical way to store electricity, it was necessary for the distributors of electricity to have at their command a system of generators designed and operated so as to have the capacity to supply, from moment to moment, just the right amount of electricity to meet the demand of the distribution system’s customers as that demand fluctuated over the day, the week and the year. Limitations on early transmission technology tended to restrict utility systems to a single locality. As transmission technology developed, the transmission lines were built by the owner of the local generation/distribution system, to link different parts of the system, to link remote generation facilities to the distribution system, and eventually to establish links with neighboring systems. As these links developed, the vertically integrated generation/transmission/distribution systems found that interconnection permitted them to share reserve capacity, take advantage of load diversity and increase system reliability.

The capital-intensive nature of the business, the need to achieve economies of scale, the need to use public ways to locate distribution lines, the diseconomies (and environmental negatives) of multiple, redundant and competing lines and facilities, and public safety concerns led to legal recognition of a “natural monopoly” system under which a single vertically integrated electric utility would be designated as the sole supplier of electricity to the public within a franchised service area.
Over time, a regulatory framework developed, part statutory and part common law, under which electric utilities gained a franchise monopoly and eminent domain powers, and became responsible for providing safe and reliable electric service on a non-discriminatory basis to all members of the public requesting service within the franchise area, at regulated rates set by a government body (in New York State, the PSC). As part of its duty to serve, the electric utility would be obligated to implement social and environmental programs and policies set by the PSC, the legislature, or other government bodies having jurisdiction (e.g., pollution reduction, energy efficiency, low income programs and economic development rates). Some of these social/environmental programs and policies might have been uneconomic in a competitive market. For example, an unregulated competitive market participant might decline to provide service to a particular customer or class of customers, or to provide a particular service, if the business was deemed unattractive or not sufficiently profitable to justify the investment and risk involved in adding the capacity necessary to provide the service. The regulated utility would nevertheless be required to provide service, if so mandated. The regulated rates set by the PSC were designed to take this burden into account by providing a reasonable prospect of receiving sufficient revenues to recover all expenses reasonably incurred, and all investments reasonably made, for the purpose of providing mandated service, together with a reasonable return on such investments (the “prudent investment” standard).

Federal Legislation

Utility regulation has for the most part been a local matter left to the several states. However, three federal statutes have significantly affected the development of the electric utility industry in this country.

Public Utility Holding Company Act of 1935 (“PUHCA”)

PUHCA was enacted in 1935 in reaction to financing abuses and securities fraud involved in the organization and eventual spectacular collapse of an over-leveraged pyramid of holding companies in the electric and gas utility industries. The reforms introduced in these industries by PUHCA have been largely subsumed by the subsequent development of the federal securities laws, which were enacted contemporaneously with PUHCA. The Securities and Exchange Commission, which administers most of the provisions of PUHCA, has recommended that it be repealed. Nevertheless, PUHCA remains, and has strongly influenced the organizational structure of the electric utility industry. PUHCA’s principal feature is the imposition of a comprehensive and burdensome overlay of federal regulation on any “holding company” (defined as the owner of 10 per cent or more of the voting stock of an electric or gas utility company), and on the subsidiaries of such holding company, unless an exemption from PUHCA is available. The effect of this has been to impose on the electric utility industry a strong bias toward local, rather than regional or national, organization. PUHCA exemptions are generally unavailable to holding company systems with multi-state utility operations, and state law considerations generally require, as a practical matter, that utility companies be domestic corporations. While a few multistate utility holding company systems do exist and serve a significant portion of the country while operating under the PUHCA regulatory regime, the more general rule has been that where consolidation has occurred, it has been confined to a single state. Facility structures tend to follow organizational structures. Thus, no national electric transmission companies exist in this country, although we have built several national telephone systems.

Part II of the Federal Power Act (“FPA”)

Substantial interstate transmission and sales of electricity developed at the wholesale level among the various, mostly local, electric utility companies. Part II of the FPA was enacted in 1935 to establish federal regulation of this interstate commerce in electricity. The jurisdiction of the Federal Energy Regulatory Commission (“FERC”), which administers the FPA, extends to wholesale sales and transmission of electricity in interstate commerce. The uniformity of federal regulation of transmission facilities has helped to enable the disparate transmission facilities across the country to function as if they were parts of an integrated system, even though each element was designed and built to serve the separate interests of the local utility owning the facility.

Public Utility Regulatory Policies Act of 1978 (“PURPA”)

The oil crisis of the early 1970s brought about a drastic increase in energy prices, including the price of electricity. This in turn focused national attention on energy conservation, energy efficiency and alternatives to oil as a source of energy. One of the outcomes was the enactment of PURPA. Among other things, PURPA defined a new class of non-traditional electric generating facilities that would either (i) produce electricity with greater energy efficiency through “cogeneration” (a process or system utilizing waste heat from electric generation for a second purpose, such as using exhaust steam for space heating or process heat), or (ii) produce electricity from “alternative” energy sources, such as small hydro, wind, solar, biomass and geothermal sources. These new facilities could not be owned primarily by traditional utilities, but by independent operators. These independent power producers (“IPPs”), if they satisfied the PURPA requirements, would be entitled to exemption from normal utility regulation and would be entitled to require a traditional utility to purchase electricity from the IPPs at the utility’s “avoided cost.”
Initially, the electric commerce regulated under the FPA was almost exclusively a commerce among traditional electric utilities, as they provided transmission services to each other over their respective transmission lines, to facilitate wholesale purchases and sales of electric capacity and energy among themselves, and transactions with the entities discussed below under the heading, “Public Power.” This exclusivity ended with the enactment of PURPA. While many of the resulting power purchase agreements were with the local franchise utility, some agreements were with utilities more distant.
Enactment of PURPA at the federal level was followed in some states, including New York, by “little PURPA” state legislation offering further encouragement to the development of IPPs. The New York version included a provision — since repealed prospectively — that required the utility to pay a qualifying IPP the greater of the utility’s avoided cost or 6 cents per KWH. The legislation had the effect of mandating utilities to enter into long-term purchase contracts based on assumed future oil prices which proved to be lower than anticipated.
The economic incentives created by PURPA and the companion New York legislation had a dramatic effect. Numerous and large generating facilities were built by entrepreneurs attracted by assured revenue streams. The new cogeneration facilities incorporated the latest technology, often enabling the new facilities to produce electricity at substantially lower cost than the older machines of the traditional utilities.
PURPA also established a number of rate making standards, including standards addressing efficiency, conservation and rate payer protection. State regulatory authorities are required by PURPA to consider the standards set forth in PURPA and to determine whether it is appropriate to implement such standards.
The pace of changing operating and regulatory patterns, which had begun in the 1980s after the enactment of PURPA in 1978, accelerated with the enactment of the Energy Policy Act of 1992 and FERC’s issuance of its Order 888 in 1996. Under Order 888, FERC mandated that transmission facility owners operate their system on an “open access” basis. Under the FERC’s open access policy, the owners of all jurisdictional transmission facilities — effectively all transmission facilities — are required to make the use of their transmission facilities available under FERC-approved non-discriminatory tariff rates and terms. The FERC open access policy set the stage for electric utility restructuring.

Public Power

In parallel with the development of investor-owned utilities as outlined above, public entities have developed to serve a xdportion of the U.S. electricity market, including a portion of the New York market. In a relatively small but nevertheless significant number of communities in New York and elsewhere, the local electric distribution system is owned and operated by the local government or a government agency. These municipal systems typically do not own or operate a generating system, but purchase their electric supply from an outside source or sources. Typically, but not necessarily, these outside sources are also government entities. The Tennessee Valley Authority and the Bonneville Power Administration are two well-known electricity suppliers at the federal level. In New York State there is the New York Power Authority (“NYPA”). Created by the New York State Legislature (the “Legislature”) in 1931, NYPA developed the large St. Lawrence and Niagara hydro sites in the 1950s and 1960s and today operates these generating facilities along with a portfolio of nuclear, fossil and other hydro generating facilities and a system of major transmission lines linking various parts of the State with each other and with Ontario Hydro and Hydro-Quebec, two Canadian entities which export significant amounts of electricity to New York and other U.S. markets. NYPA sells electricity to investor-owned utilities, other public agencies within and without New York State and industrial customers, as well as to New York municipal systems.
In 1986, the Legislature created a second public authority, the Long Island Power Authority (“LIPA”), to resolve the controversy over the Shoreham Nuclear Power Plant (“Shoreham”). LIPA acquired title to Shoreham in 1992 and, pursuant to an agreement with the Long Island Lighting Company (“LILCO”), decommissioned Shoreham. In June 1997, LIPA agreed to acquire LILCO’s securities or assets after LILCO has transferred its Long Island generation and gas system to subsidiaries of a new LILCO/The Brooklyn Union Gas Company holding company.
NYPA, LIPA and the New York municipal systems are mentioned here only to complete the picture of the existing electric industry in New York; they are not directly addressed by the current restructuring initiative that is the subject of this Report.

The Drivers Of Change

The restructuring of the electric utility industry is fundamentally changing an essential component of society’s infrastructure. It is natural to ask why, and why now. The restructuring initiative is a response to three converging forces: progress in technology; economics; and the example of deregulation and increased competition in other regulated industries, notably the natural gas industry.

Progress in Technology

Many of the generating facilities in use by the traditional regulated utilities are decades old and incorporate technologies which would not be used in a generating plant being built today. Combined cycle gas fueled plants, for example, have been developed over the past 15 to 20 years. These plants provide high reliability, lower cost and reduced environmental impact because of the more efficient use of natural gas. Nevertheless, many of the older plants remain in service because a substantial part of their cost has not yet been amortized, i.e., recovered, under the cost-based rates of traditional regulation. The burden of proving that the investment in the new plant is a prudent (and hence recoverable) one, is on the utility. The issue is further clouded by the fact that in a cost-of-service-based pricing system, the output cost of the existing plant serves as a proxy for the market in determining the reasonable, or “right” price. Competition, and elimination of price regulation, in generation has encouraged the implementation of new technology and will provide a market test to determine the optimal time for replacement of old facilities.

The technology of long-distance power transmission continues to advance, making it feasible for a low-cost generator to sell its output in an ever wider area, and for a market to seek ever more distant low-cost suppliers of electricity. This increase in the number of potential market participants enhances the advantage of competitive electric pricing over regulated pricing.

The electric utility industry was among the first to recognize the potential of the computer and information technology. Continued and intensive implementation of this technology has created the necessary infrastructure for a true auction market in electricity. The same technology applied to capacity management makes it feasible to explore substituting a “virtual” generating system, constructed of shifting contractual commitments, for a dedicated system of physical generating plants.


A principal impetus for the restructuring initiative is the condition of the New York State economy. Despite a relatively healthy national economy and a booming financial sector which has benefited the downstate region, New York’s economy has lagged, particularly in the creation and retention of new business and jobs. A perceived factor in this lag is the high cost of electricity in New York State, relative to the national average, together with other factors, such as high taxes and heavy regulation of business. The restructuring initiative and the introduction of retail competition are seen as necessary steps to bring down the cost of electricity in New York and thereby restore New York’s competitiveness.

The effects of past regulatory policies have contributed to the current pressures for restructuring. New York utilities entered into long-term contracts mandated under PURPA and New York’s companion legislation which require the utilities to purchase substantial amounts of electric capacity and energy from IPPs at prices that are now substantially higher than the wholesale market. The resulting growth of IPP capacity has led to excess generating capacity in New York and elsewhere, forcing prices down in the wholesale electric market.

Another argument for changing the present system is the perceived disparity between the “regulated” and the “unregulated” prices of electricity in New York. The perceived disparity is great. It is important, however, to distinguish between perception and reality. While state-of-the-art unregulated generators are often able to produce energy at lower cost than older plants, this disparity is not the one which looms large for the consumer. Rather, it is the five-fold (or greater) differential between the wholesale price of electricity and the “regulated” (i.e., retail) price.

The regulated, retail price includes not only pure generation costs, but also other costs such as delivery and administrative costs, reliability and load factor costs, incremental costs of local generation imposed by transmission constraints, rate structure cross subsidies, recovery of prior investments determined by the PSC to be prudent, the costs of mandated social/environmental programs, and of course taxes. It is no secret that New York has cast the regulated utility in the unwelcome role of a major tax collector. All of this said, the differential was substantial and growing, as was popular demand for change by a public impatient with explanations for bills that, rightly or wrongly, were perceived as too high.

The development, in recent years, of a vigorous competitive wholesale market for electricity has suggested that a similarly competitive market could be developed at the retail level. The emergence of numerous independent “energy marketers” acting as intermediaries between wholesale sellers and retail customers has strengthened this belief. In a competitive retail market it is reasonable to expect that lowered wholesale prices will translate into lower retail prices.

The Example of Other Regulated Industries

Recent years have seen the introduction, at both national and state levels, of major regulatory restructuring and increased competition in the traditionally regulated telephone and natural gas industries.
The telephone industry has seen sweeping regulatory and statutory changes in the last two decades, with the introduction of competition and increasingly wider choices of service providers. From the perspective of the average consumer, the experiment has been a clear success in terms of lower long-distance rates, with mixed reviews for the cost and quality of local service.

The natural gas industry is seen as a particularly close parallel to the current electric initiative, since most New Yorkers purchase gas and electric service from the same utility. Retail gas customers of New York utilities now have the option to purchase their gas from suppliers other than their local gas utility. Such customers have their gas delivered by their supplier of choice to the local gas utility’s “city gate” (the point of interconnection between the local gas utility’s system of pipes and the interstate pipeline through which the supplier ships the gas). The gas is fungible and the local gas utility delivers a like quantity to the customer, charging the customer a transportation-only charge. The transportation-only charge amounts to the local gas utility’s normal “full service” rate, minus the utility’s normal charge for the gas commodity itself. Large gas customers have the option to purchase their gas directly at the well-head and arrange for their own pipeline transportation to the city gate. Most customers, and all small customers, choosing transportation-only service from their local gas utility will purchase their gas from an independent “gas marketer” who will assume responsibility for procurement and delivery to the city gate. Competition among gas marketers is vigorous and the transportation-only option from the local utility offers the gas consumer an opportunity — but not necessarily an assurance — of savings compared to traditional gas service. While the transportation-only option is fairly new, except for very large customers, and market penetration remains low, particularly for residential customers, no insuperable problems have surfaced to date.

The relatively smooth introduction of retail competition in the natural gas industry has provided both a model and an arguably practical demonstration of feasibility for a similar transition in the electric utility industry. Critics have questioned the applicability of the model, noting differences in the physical nature of the two commodities, the markets, the applicable statutes, the industry structures, and the lack of significant experience with large numbers of small customers in the gas retail competition initiative. In any event, the PSC has elected to proceed with retail electric choice.

The Special Case of Shoreham

A final element among the drivers of change in New York is the “Shoreham Problem.” Shoreham was a nuclear generating plant constructed on Eastern Long Island by LILCO over determined and protracted opposition. After many years of costly controversy and delay, the plant was finally completed in the late 1980s. However, the plant was not allowed to go into service, and was retired and dismantled, under an agreement negotiated with the intervention of the New York State government. The arrangement contemplated the recovery by LILCO of most of its prudent investment in Shoreham and related costs � a figure ultimately exceeding $5 billion � through LILCO’s electric rates over a long period of time. Despite the lengthy recovery period, LILCO’s electric rates soon rose to become among the highest in the nation. Repudiation of the opportunity to recover the Shoreham costs would have been an immediate threat to the solvency of LILCO, but the public outcry over electric rates on Long Island made it clear that something had to be done about the “Shoreham Problem.”

The Process Of Change In New York

The transition process in New York State has thus far been entirely an administrative one. The transition plan for each New York electric utility has been hammered out between the utility and the PSC in the context of existing statutory provisions, although not without challenge. Legislation enacted to date has been directed to a reduction of the utility gross receipts tax, which has helped to achieve a portion of the rate reductions sought by the PSC. Some individual utility plans do contemplate the possibility of further reductions in the gross receipts tax, and of legislation authorizing securitization of certain utility revenue streams.

In 1993, the PSC on its own motion began a proceeding to examine various issues relating to potential competition in the regulated gas and electric industries in New York State. (Order Instituting Proceeding, March 19, 1993, Case 93-M-0229.) In 1994, the PSC instituted Phase II of the proceeding, focusing on competition in the electric utility industry (Order Instituting Phase II, August 9, 1994, Case 93-M-0229.) The proceeding was redesignated Case 94-E-0952, reflecting its electric focus, by order issued November 30, 1994. This proceeding culminated in an opinion and order issued May 20, 1996, stating a “vision” for the New York electric utility industry. (Opinion No. 96-12, May 20, 1996, Case 94-E-0952) (hereinafter “Opinion No. 96-12”). The “vision” included the following elements: (1) introduction of effective competition in generation; (2) electric rate reductions; (3) customer choice of energy supplier; (4) retention of a “provider of last resort” requirement; (5) retention of a funding mechanism for social/environmental programs; and (6) creation of an independent (transmission) system operator (“ISO”) to ensure reliability.
Opinion No. 96-12 directed each of the five New York electric utilities other than Niagara Mohawk Power Corporation (“Niagara Mohawk”) and LILCO to file with the PSC by October 1, 1996 the utility’s plan for implementing the PSC’s “vision” and addressing: (1) a schedule for the introduction of retail access; (2) a rate reduction plan; and (3) changes in the utility’s corporate structure to accommodate the “vision”. Niagara Mohawk was exempted from the October 1, 1996 filing requirement because it had already filed a retail access and restructuring plan with the PSC.

LILCO was exempted because it was engaged in negotiating the restructuring transactions with The Brooklyn Union Gas Company (“Brooklyn Union”) and LIPA. As detailed below in Part II, LILCO and Brooklyn Union have agreed to combine their companies. The new combined entity will use a holding company form of organization. Contemporaneously, LILCO and LIPA agreed that LILCO would transfer its transmission and distribution system to LIPA, along with other assets and the responsibility of providing electric service to LILCO’s customers.

Each of the five utilities which were not exempted made the filing required by Opinion No. 96-12. Concurrently, they and other persons initiated litigation challenging certain aspects of Opinion No. 96-12, including challenging the PSC’s power to restructure the electric utility industry without statutory changes. While this effort was unsuccessful in the trial court, appeals were taken. Subsequent to these filings and after protracted negotiations with the staff of the PSC, namely the New York Department of Public Service Staff (“DPS Staff”) and other interested parties, each of the five utilities entered into a settlement agreement with the DPS Staff and other parties, which was subsequently approved by the PSC. A similar settlement was executed by Niagara Mohawk and the DPS Staff and approved by the PSC. The negotiation/approval process was completed for all six settlement agreements, which are summarized in Part II of this Report, by February 1998. As part of these settlements, the litigation challenging the validity of Opinion No. 96-12 was conditionally terminated by the utilities, but not by the other parties.

A significant issue in the restructuring proceeding was the maintenance of environmental protection. In Opinion No. 96-12, the PSC directed that a “non-bypassable system benefits charge” (“SBC”) be established for each affected utility at the level of “current utility expenditures” to support investments in energy efficiency, research, development and demonstration, low-income programs and environmental monitoring that might not be expected to take place in a competitive market. Under Opinion No. 96-12, the SBC is intended to mitigate certain adverse environmental impacts of utility restructuring identified in the generic environmental impact statement prepared by the PSC. Statewide, about $233 million in SBC funds will be collected through wires charges by the six utilities over the next three years, at a rate of $78 million per year, or about 0.75 mills (0.75 of a tenth of a cent) per KWH. In January, 1998 the PSC designated the New York State Energy Research and Development Authority (“NYSERDA”) to be the statewide administrator for the SBC program. The six utilities will continue to administer some existing programs. Legislation has been introduced in both chambers of the Legislature to increase SBC levels to 4 mills per KWH.
In August 1997, the DPS Staff issued a report calling for the utilities subject to PSC jurisdiction to divest their four nuclear power plants. The PSC instituted an administrative proceeding, Case 98-E-0405, on March 20, 1998 to address the issues raised in the DPS Staff report. That proceeding is pending.



The seven utilities’ restructuring plans are comparable in some respects, but each has certain distinct features. Each restructuring plan, reflecting the agreement of a number of interested parties and then approved by the PSC, is summarized in the paragraphs of this Part of the Report.

Most, but not all, of the plans call for scheduled reductions in electricity prices paid by all classes of customers, whether or not such customers choose to purchase their electricity from an alternative supplier. Most, but not all, of the plans call for disposition by the utility of all or substantially all, of the utility’s non-nuclear generating facilities. All of the plans contemplate that by the end of the period (three to five years) covered by the plan, all customers of the utility will have the ability to purchase their electricity from an alternative supplier, although the traditional utility will continue to deliver the electricity to the consumer, regardless of its source. All of the plans are premised on the expectation that a competitive market for the supply of electricity will result in lower electricity prices for all classes of customers.

Consolidated Edison Company Of New York, Inc.

On September 23, 1997, the PSC issued a one-commissioner order in Case 96-E-0897, approving the Amended and Restated Agreement and Settlement dated September 19, 1997 (the “Con Edison Settlement Agreement”) among Consolidated Edison Company of New York, Inc. (“Con Edison”), the DPS Staff and various other signatories. The Con Edison Settlement Agreement sets forth a comprehensive rate, restructuring and competitive access plan for Con Edison and its electric customers. The September 23 order adopted the terms of the Con Edison Settlement Agreement, subject to conditions and understandings set forth in the order, and incorporated them as part of the order. The September 23 order was confirmed by the order of the full PSC, issued October 1, 1997 in the same case. The bases for the PSC’s approval are set forth in the related Opinion No. 97-16 issued by the PSC on November 3, 1997 in the same case. Opinion No. 97-16 is currently the subject of litigation in the New York Supreme Court.

Rate Plan


The plan covers Con Edison’s electric rates for the five years ending March 31, 2002. The plan “freezes” the base rates (subject to limited exceptions) at the levels in effect at March 31, 1997, and provides for reductions from these levels over the five years. The rate freeze had the immediate effect of eliminating an electric rate increase that would otherwise have gone into effect on April 1, 1997 pursuant to a 1995 electric rate settlement approved by the PSC. The scheduled reductions for the first year of the five-year plan became effective January 1, 1998.

Scheduled reductions (to base rates)

Certain large industrial customers received, as of January 1, 1998, a 25 per cent electric rate reduction which will continue at that level throughout the remainder of the five-year period. All other customers will receive rate reductions beginning at 2 per cent and progressively increasing to 10 per cent by the beginning of the fifth year of the plan. The decrease for residential customers will be back-loaded, with 4.5 per cent of the total 10 per cent decrease occurring in the fifth year of the plan.
The scheduled electric rate reductions include the effects of a reduction, enacted in 1997, in the New York State utility gross receipts tax. The tax reduction, like the tax, flows through to the customer. The scheduled electric rate reductions equate to a cumulative revenue reduction of approximately $1.2 billion over the five-year period, including the effects of the tax reduction, or approximately $1 billion excluding such effects. Neither amount includes the forgone revenues (estimated at $436 million) that would have resulted from the April 1, 1997 electric rate increase eliminated by the plan’s five-year rate freeze.

Despite the relatively larger (25 per cent) decreases provided for certain large industrial customers, the relative cost to Con Edison will be only a small fraction of the revenue cost of the smaller — and slower — (10 per cent) decreases provided for Con Edison’s other customers, because large industrial customers constitute only a small portion of Con Edison’s revenue base.

Other significant rate provisions

Earnings Sharing: Common equity earnings in any rate year (12 months ending March 31) of the five-year plan in excess of 12.9 per cent (net of shortfalls below 11.9 per cent from prior rate years of the plan) will be shared, with 50 per cent of the excess being retained for shareholders, 25 per cent being applied to reduce generation plant balances (thereby reducing potential strandable costs, discussed below), and 25 per cent being applied to benefit customers through rate reductions or otherwise as determined by the PSC. The earnings sharing provision will cease to apply beginning with the first rate year (i) in which Con Edison has sold to third parties, pursuant to the divestiture requirement discussed below, 50 per cent or more of its in-City generating capacity or (ii) in which 15 per cent or more of Con Edison’s service area peak load (exclusive of customers of NYPA) is supplied by other than Con Edison, pursuant to the retail access provisions discussed below.

Exceptions to Rate Freeze: Notwithstanding the freeze, Con Edison will be permitted, subject to certain thresholds, to defer and recover in rate adjustments to be implemented in the third and fifth rate years of the plan (1) increases in annual utility costs resulting from changes in law, including federal, state and local income tax laws (above a $7.5 million threshold), (2) increases in local property taxes above levels estimated in the Con Edison Settlement Agreement, (3) Superfund and other environmental costs above certain levels, (4) the effects of inflation above 4 per cent annually, on a net cumulative basis, and (5) certain extraordinary expense or capital items. In addition, Con Edison may seek a general rate increase if its forecast return on common equity should fall below 8 per cent (calculated on a pro forma basis assuming a common equity capitalization of 52 per cent). Moreover, Con Edison’s charges for delivery service to customers of NYPA will be increased by $45 million over the five years of the rate plan, and the system benefits charge discussed below will not be subject to the rate freeze.

Retail Access Schedule

The plan, as modified by Con Edison, provides for an initial program offering retail access beginning June 1, 1998 to over 70,000 customers from all service classifications, with an aggregate demand of approximately 1,000 MW. The plan requires Con Edison to allocate up to $5 million for customer incentives, including cash payments, to encourage participation by small customers in this first phase.
The second phase called for by the plan will expand retail access by 1,000 MW, to a total of 2,000 MW, within ten months after the first phase begins (i.e., by April 1999). “To the extent feasible,” this expansion will begin in December 1998. All customer classes will be encouraged to participate.

Successive further expansions of 1,000 MW (“or more”) each are scheduled at 12-month intervals following the beginning of the second phase, with the objective of making retail access available to all customers by the earlier of December 2001 or 18 months after the ISO contemplated by the PSC’s Opinion No. 96-12 becomes “fully operational.”

The Con Edison Settlement Agreement (and by extension, the PSC itself) expressly recognizes “that even with widespread discussion of retail access, there has been little actual experience with retail access to date, particularly on a large scale . . . . Accordingly, the parties acknowledge that the retail access objectives and phase-in dates specified herein are targets and that flexibility to change the program schedule indicated herein as issues and obstacles are addressed more slowly (or more rapidly) than anticipated is essential. The schedule, therefore, will (with appropriate PSC oversight) be subject to adjustment . . . to address these developments. (Con Edison Settlement Agreement, § III.4 at 35-36.)

Rate Design And Back-Out Rates

Rate design
The plan introduces a number of significant changes in rate design for Con Edison’s electric customers. The Revenue per Customer/Electric Revenue Adjustment Mechanism provision was eliminated effective April 1, 1997. This provision in the prior rates was intended to eliminate the effect of weather (positive or negative), as adjusted for changes in the number of electric customers, from Con Edison’s electric revenues. The Partial Passthrough Fuel Adjustment Clause, which provides incentives or penalties for meeting or not meeting fuel efficiency targets, is continued, but incentives for demand-side management and customer service are replaced with a penalty-only provision for deficiencies in customer service and reliability. Other rate design features of the plan include:
Minimum Charges: The customer charge applicable to residential and small commercial electric customers will increase by $0.57 per month on April 1 in each of the five rate years of the plan. A minimum monthly charge will be implemented for all demand-billed customers.
Unbundled Tariffs: The plan requires Con Edison to file “unbundled” tariffs for all electric service classifications, to become effective April 1, 1998. The unbundled tariffs will disaggregate the major cost components of Con Edison’s electric system: generation capacity, energy, transmission and distribution. The unbundled tariffs will also include a separate component for the SBC discussed below.
The unbundled tariffs are, for the time being, primarily informational for customers which do not participate in the retail access program discussed above. They do not otherwise permit customers to purchase individual components of Con Edison’s service. However, they are a step in that direction. The Con Edison Settlement Agreement states “The unbundling process begun in this settlement agreement is expected ultimately to lead to customers having the ability to choose from among the unbundled cost elements set forth in the tariffs. The Commission will not be precluded from implementing such service unbundling following approval of this settlement agreement.” (Con Edison Settlement Agreement, § II.20(ii) at 20.)
Low Income Rate: The plan continues, through Rate Year Five, a low-income fixed customer charge of $5.00 per month for approximately 32,000 customers who also receive public assistance.

System Benefits Charge or SBC: As discussed below, the plan introduces a new funding mechanism for the costs of research and development, energy efficiency, low income and environmental programs which might not otherwise be recoverable in a competitive environment. The SBC will be a separately stated cost component and will not be subject to the plan’s rate freeze.

Back-out rates
The transportation/delivery service rate for retail access customers will be equal to Con Edison’s full service rate for the applicable service classification, minus adjustments to the energy and generation capacity components of the full service tariff.
Prior to the establishment of a fully operational ISO, the energy credit, or adjustments, would equal Con Edison’s buy-back energy tariff rate (which will average 2.5 cents/KWH at transmission voltages, and about 2.7 cents/KWH at secondary voltages, during the second rate year (the 12 months beginning April 1, 1998)) and the capacity credit would be based on revenues from sales of Con Edison’s capacity plus certain additional savings. After the ISO is fully operational, the energy and capacity credits will equal the market value for energy and capacity, respectively. In no event will the energy or capacity credits exceed the energy or generation capacity components, respectively, of the applicable full service tariff.

Generation Divestiture/Market Power Issues
The plan requires Con Edison to divest at least 50 per cent of its generating capacity located in New York City (“in-City generating capacity”) to unaffiliated third parties no later than December 31, 2002. By the same date, Con Edison is required to divest or transfer all of its generating capacity, except its Indian Point nuclear unit and the gas turbines associated with that unit, to unregulated entities, including unaffiliated third parties and affiliates of Con Edison. Con Edison was also required to file a detailed divestiture plan with the PSC by March 1998. Con Edison has made this filing. Within 90 days after approval of the divestiture plan by the PSC, Con Edison must initiate the process of selling at least 30 per cent of its in-City generating capacity.

The rationale for requiring Con Edison to divest at least half of its in-City generating capacity to unaffiliated third parties is that roughly half of New York City’s peak demand must be met with in-City generating capacity because of transmission limitations. Most of the in-City generating capacity is presently owned by Con Edison. By placing in other hands sufficient in-City generating capacity to meet the in-City requirement, the plan will require Con Edison to compete for this market.

Corporate Restructuring

Holding company structure
To facilitate the transition to a competitive energy market, the plan contemplates that, subject to shareholder approval and required governmental approvals, a holding company be established as the parent company of Con Edison, with the common stockholders of Con Edison becoming the stockholders of the holding company. This was accomplished effective January 1, 1998. Concurrently, Con Edison transferred to the holding company two previously organized unregulated subsidiaries and a third unregulated subsidiary was organized. As a result, the initial holding company structure consists of the holding company parent, Consolidated Edison, Inc., and its four subsidiaries: (1) the regulated utility, Con Edison, which will retain its historic name, Consolidated Edison Company of New York, Inc., (2) Consolidated Edison Solutions, Inc. (formerly known as ProMark Energy, Inc.), an energy marketer which will operate as an energy services company (an “ESCO”) in the new competitive environment, (3) Consolidated Edison Development, Inc. (formerly known as Gramercy Development, Inc.), which pursues unregulated energy-related ventures, and (4) Consolidated Edison Energy, Inc., the newly-formed subsidiary, which is expected to participate in the competitive wholesale electricity market. Consolidated Edison, Inc. is permitted to form additional subsidiaries and to establish one or more intermediate subsidiary holding companies to hold the stock of its utility subsidiary and the stock of its unregulated subsidiaries.

Functional realignment
To the extent that Con Edison’s fossil-fueled generating stations are retained within the holding company structure, they will be transferred during the transition period (i.e., by December 31, 2002) to Consolidated Edison Energy, Inc. or to another affiliate of Con Edison. For the time being, at least, Con Edison will retain its Indian Point nuclear unit. Con Edison will also retain its power purchase contracts with non-utility generators (“IPP contracts”) that are not securitized. (See discussion of securitization below under “Stranded Cost Recovery” and in Part III of this Report.) In general, over the five rate years ending March 31, 2002, the regulated utility, Con Edison, will move toward a pure “wires” (transmission and distribution) business serving only customers within its service area. However, to the extent that Con Edison continues to own generation assets or hold IPP contracts, Con Edison will be permitted (i) to make wholesale electric energy sales outside its service area, (ii) to make retail and wholesale electric energy sales within its service area, and (iii) (until Consolidated Edison Solutions, Inc., Con Edison’s ESCO affiliate, has all necessary approvals to do so) to make retail sales outside Con Edison’s service area.

Affiliate Transactions And Competitive Conduct Standards; Royalty

Affiliate transactions
In general, Con Edison must operate at arm’s length from its parent company’s unregulated subsidiaries. The unregulated subsidiaries may not occupy the same building as Con Edison. Transfers of assets or services between Con Edison and an unregulated subsidiary must be pursuant to a written contract filed with the PSC. The plan imposes pricing rules for such transfers, cost allocation rules, restrictions on common officers or employees and “revolving door” transfers of employees between Con Edison and the unregulated subsidiaries, and with limited exceptions requires an unregulated subsidiary to pay substantial compensation to Con Edison for transfers of employees from Con Edison to the subsidiary (25 per cent of the employee’s annual salary for the prior year).

Con Edison is required to raise its debt capital directly and not through its parent company. Without prior PSC permission, Con Edison may not make loans to its parent or any of the unregulated subsidiaries, or guarantee, or pledge its assets as collateral for, the obligations of its parent company or its affiliates. With limited exceptions, Con Edison may not pay dividends to its parent company in excess of Con Edison’s income available for dividends calculated on a two-year rolling average basis. Con Edison must certify annually that it has retained or otherwise has access to sufficient capital to maintain and upgrade its system in order to continue the provision of safe and reliable service.

Competitive Conduct Standards
There are no restrictions on the use of the name, “Con Edison” by the parent company or its unregulated subsidiaries, or on the use of common names, trade names, trademarks, service marks or derivatives, or on identifying the affiliation among these entities. However, Con Edison is prohibited from providing sales leads for customers in its service area to its affiliates, and from promoting its affiliates’ products or services within Con Edison’s service area. Con Edison must apply its tariffs in a non-discriminatory manner and offer equal access to competitive information relative to its service area. A mechanism is provided for complaints by competitors and sanctions against Con Edison in the event of violations of these competitive conduct standards.

The plan, and its approval by the PSC, lay to rest, for Con Edison at least, the “royalty” issue, which has been the subject of considerable litigation between New York utilities and the PSC in recent years. Under the royalty theory, unregulated affiliates of a utility enjoy intangible benefits from their association with a regulated utility, in the form of good will, name recognition, credit standing, etc. These benefits, according to the theory, constitute an asset to which the customers of the regulated utility have contributed, and for which they should be compensated, either through a direct payment from the unregulated affiliate, or through the imputation of such a payment, which would offset the revenue requirement to be raised from customer charges for utility service. The plan provides: “The rate plan covers all royalties that otherwise would be credited to . . . [Con Edison’s] customers, at any time, including after the expiration of the agreement.” (Con Edison Settlement Agreement, § V.12 at 51.) The rate plan does not provide for any separate royalty payment or imputation.

Stranded Cost Recovery

Definition and magnitude
The PSC’s Opinion No. 96-12 and the Con Edison Settlement Agreement define strandable costs as “those costs incurred by utilities that may become unrecoverable during the transition from regulation to a competitive market for electricity.” The parties to the Con Edison Settlement Agreement did not agree on any estimate of the amount of such costs, but Con Edison’s Annual Report for the year ended December 31, 1996 stated: The Company estimates that, on a present value basis, its electric strandable costs could be between $4.7 billion and $6.2 billion, including an estimated $650 million relating to its fossil-fueled power plants, $1.1 billion relating to its nuclear generating operations (including decommissioning costs) and $3 billion to $4.5 billion relating to capacity charges under the Company’s contracts with NUGs [IPPs].” (Annual Report at 21.) The Annual Report identifies these estimates as forward-looking statements which could be materially different from actual stranded costs.

Recovery mechanisms
The Con Edison Settlement Agreement provides a number of mechanisms for the mitigation and ultimate recovery of strandable costs. While it puts Con Edison “at risk” for a portion of these costs, it also provides mechanisms for reducing or eliminating the “at risk” portion, and even for possible recovery of any residual “at risk” portion .
Mitigation Opportunities:
(i) Con Edison agreed to reduce its generation plant balances by a total of $75 million of “extra” depreciation, in addition to normal depreciation, during Rate Years One through Five.
(ii) Under the earnings sharing provision described above, 25 per cent of the revenue equivalent of the “excess” earnings will be applied to reduce generation plant balances.
(iii) IPP contract mitigation efforts (through renegotiation, termination, “buyout”, or “buy down”) will continue. The costs of such mitigation will be deferred for recovery after Rate Year Five. As an incentive, Con Edison will retain the full reductions in fixed IPP costs through Rate Year Five and 30 per cent of reductions in variable IPP costs for 18 months. After the end of Rate Year Five, the net benefits of such IPP contract mitigation will be allocated 25 per cent to the reduction of generation plant balances and 75 per cent directly to rates in a manner to be determined by the PSC.
(iv) The first $50 million of net after-tax gains realized by Con Edison from the divestiture of generating capacity as described above will be retained by Con Edison. Any additional after-tax gains or losses will be deferred. Following the end of Rate Year Five (March 31, 2002) Con Edison will reconcile the remaining plant book values to the market values defined by the divestiture process, including deferred gains and losses and excluding any gains retained by Con Edison. The resulting balance (positive or negative) will be reflected in rates following Rate Year Five as described below.

“At Risk” Provision:
(i) Con Edison will be “at risk” for the disallowance of recovery of the lesser of:
�10 per cent of the actual or then estimated (on a net present value basis) above-market costs in each rate year after Rate Year Five of Con Edison’s IPP contracts, and

� a maximum of $300 million (net present value at the end of Rate Year Five), subject to possible reduction of the amount at risk pursuant to paragraphs (ii), (iii) and (iv) immediately below.
(ii) The total reduction in IPP contract costs after Rate Year Five resulting from Con Edison’s mitigation efforts during Rate Years One through Five (excluding any reductions in variable IPP costs that may continue to be retained by Con Edison pursuant to paragraph (iii) under “Mitigation Opportunities” above), plus any reductions in IPP costs flowed through to customers during Rate Years One through Five, will be credited as a reduction in the “at risk” amount.
(iii) Ten per cent of the proceeds of sale of Con Edison’s generating facilities to third parties pursuant to the divestiture requirement described above will also be credited as a reduction of the “at risk” amount.
(iv) To the extent that the “at risk” amount is not completely eliminated pursuant to the immediately preceding paragraphs (ii) and (iii), Con Edison may nevertheless be permitted a reasonable opportunity to recover such remaining “at risk” costs, depending on the PSC’s assessment of Con Edison’s good-faith efforts to implement the provisions of the Con Edison Settlement Agreement leading to development of a competitive electric market in Con Edison’s service area. In making this assessment the PSC will consider Con Edison’s performance in the areas of divestiture, retail access (including compliance with the affiliate transactions rules and competitive conduct standards outlined above), IPP contract mitigation and post-Rate Year Five levels of base electric rates.
Non-Bypassable Charge:
Subject to the foregoing “at risk” provision, Con Edison will be given a reasonable opportunity for recovery of strandable and stranded costs remaining at March 31, 2002, including a reasonable return on investment. To accomplish this recovery, Con Edison’s rates after March 31, 2002, including delivery/transportation rates for retail access customers, will reflect a non-bypassable charge for recovery of these amounts.

Recovery Periods:
In the absence of securitization: the recovery period for IPP contract mitigation costs and above-market costs will generally be the life of the related contract; the recovery period for Indian Point nuclear costs, including decommissioning, will generally be the period ending with the expiration of the Indian Point 2 operating license in 2013; the recovery period for stranded fossil generation costs will generally be a 10-year period ending March 31, 2012; recovery periods for Con Edison’s other stranded costs will be as determined by the PSC. If any of the foregoing costs are securitized, the recovery period will generally match the life of the related bonds.
The Con Edison Settlement Agreement contemplates that savings realized through securitization will be passed through to Con Edison’s customers, with a portion possibly allocated to the SBC (discussed below), for energy efficiency and new clean technologies.

Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities
Among the conditions expressly imposed by the PSC was the condition that Con Edison is obligated to be the provider of last resort for electric service during the transition to competition, until relieved of that obligation. This is consistent with a generic opinion and order previously issued by the PSC, establishing regulatory policies applicable to ESCOs. (Opinion No. 97-5, issued May 19, 1997, clarified in Opinion No. 97-17, issued November 18, 1997, Case 94-E-0952.) Opinion No. 97-5 directs that only a transmission and distribution utility, such as Con Edison, will be allowed to terminate electric service, even for a customer purchasing electric service from an ESCO.

To protect system reliability as retail access customers begin to purchase their electric service from ESCOs, the Con Edison Settlement Agreement imposes a requirement that ESCOs contract for capacity equal to 118 per cent of their customers’ coincident peak load (i.e., an 18 per cent reserve capacity requirement), which is the same reserve capacity requirement imposed on traditional utilities, such as Con Edison. Similarly, until June 1, 1999, ESCOs serving in-City customers are required to contract for generating capacity from in-City sources equal to no less than 70 per cent of the in-City peak load to be served by such ESCOs, with Con Edison being required to maintain existing in-City generating capacity sufficient to bring the ESCOs’ in-City generating capacity up to 80 per cent of their peak load. After June 1, 1999, unless the ISO has established generation capacity rules for New York City, the ESCOs’ in-City generating capacity requirement will increase to 80 per cent, unless the PSC orders otherwise.

Social/Environmental Programs

Environmental programs
The Con Edison Settlement Agreement commits Con Edison and the DPS Staff to work with ESCOs and others to develop and implement, where feasible, a meaningful and cost-effective approach to providing customers with fuel mix and emission characteristics of the generation sources relied on by each “load serving entity,” with a view to allowing customers to choose, to the extent they wish, between “green” power and less benign sources. Con Edison also agrees to develop detailed annual forecasts of major transmission and distribution projects (with specific details for projects of $10 million or more), to consider and implement cost-effective alternatives to such projects, and to consider new technologies and other means to minimize costs and environmental impacts of transmission and distribution projects.

The Con Edison Settlement Agreement incorporates Con Edison’s support for the adoption of improved building codes and standards as an appropriate mechanism for improving the energy efficiency of buildings, including its support of the objectives of the 1995 Model Energy Code.

Low-income assistance
As noted above, the rate plan continues, for Rate Years One through Five, a low-income customer charge fixed at $5.00 per month. The rate plan also continues, through October 1999, a low-income energy efficiency program.

Economic development
As noted above, the rate plan itself includes a large (25 per cent) and immediate electric rate reduction for certain large industrial customers, continuing through Rate Year Five. The Con Edison Settlement Agreement provides for phasing-out Con Edison’s two location-specific economic development programs and an expansion of the Business Incentive Rate program, Con Edison’s service area-wide economic development program.

System Benefits Charge
As contemplated by the PSC’s Opinion No. 96-12, the Con Edison Settlement Agreement provides for a “non-bypassable system benefits charge” as a funding mechanism for costs required to be spent on necessary environmental and other public policy programs that would not otherwise be recovered in a competitive market. The SBC funds will be administered by NYSERDA, the state-wide administrator chosen by the PSC. The SBC will not be subject to the rate freeze provided for by the Con Edison Settlement Agreement. The Con Edison Settlement Agreement allocates $111 million to SBC programs over the three-year period ending March 31, 2001. This expenditure level is approximately equivalent to an SBC charge of 1 mill (0.1 cent) per KWH of energy used.

Reliability Incentives/Penalties

As noted above, the rate plan includes a penalty-only provision for deficiencies in customer service and reliability. Penalties would be up to 35 basis points on common equity (revenue requirement equivalent) for any rate year in which the penalty is triggered. Only four of the penalty criteria (counting for a maximum 10 basis points of penalty) relate to reliability of service.

Nuclear Generation Issues

Con Edison’s nuclear generating unit, Indian Point 2, is excluded, for the time being at least, from the Con Edison Settlement Agreement’s generation divestiture requirement. This exclusion is presumably related to the potential issues that might arise under the Nuclear Regulatory Commission’s licensing and financial responsibility requirements if safety and decommissioning costs for a power reactor were no longer supported by cost-of-service-based rates, as well as to the special problems involved in transferring a nuclear operating license. The PSC is continuing to consider the appropriate treatment of nuclear generating units in a competitive environment.


Orange & Rockland Utilities, Inc.

On October 1, 1996, Orange & Rockland Utilities, Inc. (“O&R”) filed its initial rate and restructuring plan. An initial settlement agreement was signed on March 25, 1997. Following issuance of a recommended decision on July 2, 1997, O&R filed a revised settlement agreement on November 6, 1997. The PSC issued an abbreviated order approving the revised settlement agreement on November 26, 1997. On December 31, 1997 the PSC issued Opinion No. 97-20 approving the revised settlement agreement. In February, 1998 O&R filed unbundled proposed rates, which are intended to be revenue neutral, and an embedded cost of service study. The revised Settlement Agreement is referred to as the O&R Restructuring Plan in this Report.

Rate Plan


The effective date of the proposed rate plan is December 1, 1997. It continues for four years.

Scheduled reductions (to base rates)
Per centPer cent
Immediatelyover 4 years
Commercial/ Large Commercial & Indus. 1.092.09
Remaining Industrial8.58.5

Retail Access Schedule

At the time of the effectiveness of new rates, O&R expanded its existing energy-only PowerPick Program (an existing retail access program for certain customers) to all large industrial customers. On May 1, 1998, O&R further expanded this energy-only retail access program to all other customers. Provided that the ISO has become operational by May 1, 1999, O&R will further expand its retail access program at that time to cover both energy and capacity.

Rate Design and Back-out Rates

(a) Back-out rates are not included in the O&R Restructuring Plan because the unbundling phase of the proceeding will identify the amount of fixed production costs that will be backed-out of rates and the formula for determining the amount of such costs that will be recoverable through a CTC (assuming divestiture of generation assets is delayed beyond May 1, 1999).
(b) Until full retail access is achieved, energy costs will be collected through the Fuel Adjustment Clause (“FAC”) and the fixed cost of generation through base rates.
(c) Mandatory time of use (“TOU”) rates for residential customers and peak activated rates (“PAR”) will be phased-out.
(d) The Independent Power Producers of New York, Inc. and ENRON Capital and Trade Resources, two parties to the O&R restructuring proceeding before the PSC, proposed rate design changes which would entail a significant reduction in the unit cost of electricity for residential customers with a corresponding increase in the customer’s monthly charge. These proposed changes had the intent of reducing the cost of using electricity without reducing overall revenue to the company. The proposed changes, however, were not accepted by the PSC, at least in part because small users’ overall cost would not decrease, but would increase. The PSC indicated a willingness to look further at this issue.
(e) A rate plan is adopted which will allocate a greater share of the rate reductions to industrial customers so that they have an opportunity to realize an average price of 6 cents per KWH.

Generation Divestiture/Market Power Issues

O&R agreed to divest all of its generation assets, including hydroelectric and gas turbines. Generation assets are to be divested as soon as possible. Expected net gains to O&R from such divestiture are to be split between customers and shareholders as follows: 25 per cent to shareholders, 75 per cent to customers, if O&R selects the winning bidder before May 1, 1999. Net losses would be shared five per cent to shareholders and 95 per cent to customers. After that date, the shareholder/customer split is 20 per cent/80 per cent of the net gains and losses. The customers’ share of any gain to O&R on such sales is to be allocated for the benefit of customers, other than large industrial customers, up to a level necessary to produce five per cent rate reductions. This differential sharing is intended to encourage completion of the sale prior to May 1, 1999. There is a cap of $20 million (the New York State portion of the assets) on the shareholders’ gain.
O&R has advised the PSC that it will not participate as a buyer in the auction of its generation assets. O&R agrees not to own generation in the O & R service territory for 10 years.

Corporate Restructuring

O&R agreed to seek approvals that would allow it to form a registered holding company. At the time the generation operations are separated from the transmission and distribution business, O&R will be authorized to continue to provide basic energy services, either through the existing, regulated company, which is referred to in this Report as the “Delivery Company,” or through an affiliated energy services company (“ESCO”).

No explicit royalty, to benefit the Delivery Company’s customers, will be charged affiliates for the use of the O&R name as the benefit of such a royalty has been subsumed in the rate plan of rates for O&R.

Competitive Conduct Standards and Affiliate Transactions

(a) Affiliated subsidiaries may use the parent holding company’s name or the Delivery Company’s names, trademarks and derivatives of names and identify themselves with the holding company or the Delivery Company. The Delivery Company may not promote its affiliates.
(b) The Delivery Company will not provide preferential treatment to its marketing affiliate or the affiliates’ customers.
(c) The Delivery Company will provide its services at non-discriminatory rates to all persons.
(d) The Delivery Company will not disclose to its affiliate any customer or market information relative to its service territory, including but not limited to customer lists.
(e) There are no specific royalties due to the Delivery Company from the unregulated affiliates beyond what is already implicitly included in the Delivery Company’s rate levels set forth in the O&R Restructuring Plan.
(f) The DPS Staff shall have access to the books and records of the holding company, the Delivery Company and affiliates to audit and monitor transactions between the Delivery Company and such affiliates, to the extent the holding company possesses such records.
(g) The Delivery Company and affiliated subsidiaries of the holding company must be operated as separate entities, with separate books of account and separate offices.
(h) Any discount or special arrangement offered by the Delivery Company to an affiliate or a customer of an affiliate must be offered to all similarly situated merchants.
(i) Transfers of assets between the Delivery Company and an affiliate will not require prior PSC approval, other than transfers of assets from the Delivery Company which are subject to Public Service Law § 70. Assets, other than generating stations, shall be transferred at the higher of net book value or fair market value.
(j) The Delivery Company and affiliates must have separate personnel and officers of the Delivery Company may not be officers of the ESCO.
(k) Corporate services, such as corporate governance, administrative, legal, purchasing and accounting, may be provided by the holding company to affiliates at the fully-loaded cost.

Stranded Cost Recovery

The O&R Restructuring Plan provides O&R an opportunity to recover through a competitive transition charge (“CTC”) four types of stranded assets during the transition period. The vast majority of such stranded assets are associated with above-market generation costs. These stranded assets costs are to be collected through a CTC, beginning May 1, 1999, but only in the event O&R is not able to auction its generating assets prior to that date, or if O&R is delayed in completing the sales transaction. Twenty-five per cent of production labor expenses and property taxes would be at risk in the competitive market. If the auction is not completed by May 1, 2000, 35 per cent of those costs would be at risk. If the auction is not completed by October 31, 2000, the CTC will expire and O&R will be required to obtain PSC authorization to continue it.

Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities

(a) O&R will continue to be supplier of last resort, but by May 1, 1999 the PSC expects to have reviewed this issue further.
(b) The O&R marketing affiliate will not be precluded from competing during the period prior to commencement of full retail competition.

Social/Environmental Programs

Environmental programs

Rate design will be modified to eliminate mandatory TOU rates for residential customers and mandatory PAR for industrial and large commercial customers. The rate design supported by IPPNY/ENRON, described above in Section 3 of this Subpart, is not approved at this time. The PSC may readdress this rate at a later time.

Low-income assistance

There will be a four-year energy efficiency and assistance program, with a cost of $400,000 for approximately 400 customers located in the Port Jervis area. There will also be a low income aggregation pilot program, with funding up to $200,000.

Economic development

(i) The flex rate and economic development provisions already approved by the PSC will continue in effect during the term of the Rate Plan.
(ii) Existing NYPA Economic Development Power and High-load Factor customers are exempt from imposition of stranded costs.
(iii) O&R agreed to design and file a flex rate tariff for commercial and industrial customers who pose a serious threat of relocating or closing their facilities. The PSC approved this tariff on April 15, 1998. Such customers must also be receiving a comprehensive package of economic incentives from a state or local authority.

System Benefits Change

The SBC is to be 1 mill/KWH. For the first three years of the O&R Restructuring Plan, the SBC will be included in base rates. When the rates are unbundled, it will become a non-bypassable charge. The PSC has appointed NYSERDA to administer most of the SBC-funded programs. Funding levels for the fourth year will be addressed by the PSC subsequently. The SBC is expected to produce $3.3 million annually in revenues ($9.9 million over three years), of which $2.4 million will be spent on energy efficiency programs. The PSC also allows O&R to eliminate $1 million per year of expenditures on energy efficiency programs previously included in rates.

Reliability Incentives/Penalties

O&R must continue to perform under performance standards established in case 95-E-0491. The weighted O&R company-wide interruptions duration target is 1.46 hours/interruption. O&R must meet this target. If it does not, the sharing threshold, concerning sharing of earnings between shareholders and rate payers, is reduced by five basis points.

Nuclear Generation Issues

Nuclear generation issues are not addressed in the O&R Restructuring Plan nor in PSC Opinion No. 97-20, because O&R does not have any investment in nuclear power plants.

Central Hudson Gas & Electric Corporation

On October 1, 1996, Central Hudson Gas & Electric Corporation (“CHG&E”) filed its restructuring plan with the PSC. An initial settlement agreement was filed on March 12, 1997. On July 1, 1997, PSC Administrative Law Judge Rafael A. Epstein issued a Recommended Decision. CHG&E and certain other parties signed the Amended and Restated Settlement Agreement (“CHG&E Restructuring Plan”) on January 2, 1998. On February 19, 1998, the PSC issued an abbreviated order approving the CHG&E Restructuring Plan agreement. The PSC’s detailed opinion approving the CHG&E Restructuring Plan is expected to be issued in May, 1998.

Rate Plan


CHG&E agreed in the CHG&E Restructuring Plan not to file a request to increase base electric rates to be effective prior to June 30, 2001.

Scheduled reductions (to base rates)

In general, there are no scheduled rate reductions for CHG&E customers during the three and a half years of the CHG&E Restructuring Plan. Industrial customers in Service Class Tariff No. 13, which elect to enter into requirements contracts extending through June 30, 2001, however, are entitled to a five per cent rate reduction upon entering into the contracts.

While the CHG&E Restructuring Plan does not provide for specific rate reductions for residential, commercial and small industrial customers, it is expected that at least some of these customers will receive reductions in electric prices as a result of, among other causes, participation in retail access pursuant to the phase-in schedule described below. These price reductions are referred to as “customer benefits” in the CHG&E Restructuring Plan. Those price reductions are allocated as follows:
Residential$3.5 million/year
Commercial/small industrial$3.5 million/year
Large industrial (S.C. Tariff No. 13)$3.0 million/year

Retail Access Schedule

Date per cent of CustomersPhase-In
ResidentialSept. 19988 per centJuly 1, 2001
Commercial/Small indus.Sept. 19988 per centJuly 1, 2001
Large industrial Sept. 199812-18 per centJuly 1, 2001
The phase-in of retail choice for residential, commercial, small industrial and large industrial customers is capped at the maximum levels noted above through the end of the transition period covered by the CHG&E Restructuring Plan, namely, through June 30, 2001. The caps are eliminated at the end of that period. The participation of these customer groups in retail choice will lead to lost revenues for CHG&E which will be capped by the “customer benefits” limits described immediately above.

Rate Design

(a) General

Each year during the term of the CHG&E Restructuring Plan (i.e., to June 30, 2001), CHG&E customers are expected to obtain price reductions in an annual amounts totaling $10 million. This annual total will be allocated among customer classes as set forth above in connection with rate reductions and retail access options. CHG&E will continue to remain under Statement of Financial Accounting Standards (“SFAS”) No. 71 during the term of the CHG&E Restructuring Plan. The FAC, or its successor once the ISO is operational, as well as other aspects of traditional PSC rate making, will continue to operate to change rates based on short-term market conditions for fuel purchases and other short-term changes in costs to CHG&E. Other provisions of traditional CHG&E rate making will be continued under the CHG&E Restructuring Plan.

The return on equity (“ROE”) standard will be adjusted at the time of CHG&E’s divestiture of fossil generating assets. Prior to that time, CHG&E’s ROE will be capped at 10.6 per cent. After the divestiture, ROE over 10.6 per cent earned for the entire settlement period will be used to offset stranded costs and any amount in excess of that will be used to fund price reductions for consumers. Bids by CHG&E for sales to the Power Exchange, an energy auction that may be established as a part of industry restructuring from its own fossil-fueled generation facilities, may not be below cost of fuel plus variable operation and maintenance expenses (“O & M”).

The prudently incurred investments and decommissioning costs for (1) CHG&E’s share ownership of the Nine Mile Point No. 2 Nuclear Power Plant (“Nine Mile Point No. 2 plant”), (2) CHG&E’s hydroelectric plants and (3) combustion turbine plants shall continue to be treated as rate base investments as respects the regulated transmission and distribution entity.

(b) Industrial rate options

There are three rate and retail access options available to large industrial customers (S.C. Tariff No. 13):
(i) Customers not wishing to enter into requirements contract may continue to receive service under S.C. Tariff No. 13, with or without selecting retail access.
(ii) Industrial customers willing to enter into full or partial requirements relationships may enter into such contracts, cancelable on one year’s notice. There are three options:
� Full requirements customers, who agree to contract for the term of the CHG&E Restructuring Plan, may select a five per cent rate reduction.
� Partial requirements customers may select a 5 per cent rate reduction together with an Energy Value Option Plan (“EVOP”), described below.
� Partial requirements customers may also select retail access options, but in doing so they forego the five per cent rate reduction.

The EVOP option permits S.C. Tariff No. 13 customers to obtain energy from suppliers other than CHG&E. These customers are allowed to take their pro-rata share of CHG&E’s portfolio of nuclear and hydro power, which will represent approximately 20 per cent of such customers’ energy requirements.

CHG&E will expand the availability of its economic development growth incentive tariff by (1) increasing the size of the pool available for sale under this tariff from 50 MW to 75 MW, (2) expanding the eligibility of the tariff by adding additional customers and (3) making other changes.

Generation Divestiture/Market Power Issues

CHG&E will auction its fossil generation and will take commercially reasonable steps to complete the auctions’ closings by June 30, 2001. A CHG&E affiliate is permitted to participate as a bidder; in that event, however, an independent auctioneer will be employed to ensure fairness and an arm’s-length transaction.

CHG&E agreed not to own (within the regulated entity) central station generation (exclusive of on-site generation) within its service territory in addition to that already owned. CHG&E will not own, for a period of five years following the transfer of fossil generation, more than 1,700 MW of any form of generation capability at the Roseton/Danskammer site.

If a CHG&E affiliate does not participate in the auction, CHG&E shall receive an auction incentive on any gain over net book value, equal to 10 per cent of the total proceeds over net book value up to a $17.5 million cap.

Corporate Restructuring

CHG&E will functionally separate its generation facilities (apart from the Nine Mile Point No. 2 plant, combustion turbines and hydro) from its transmission/distribution facilities. CHG&E will establish a holding company that will own, inter alia, (i) a PSC-regulated electric and gas transmission and distribution company (“T&D Company”) that may contain generation assets, (ii) an “unregulated” generation company that owns or operates generation assets within and outside New York, and (iii) an unregulated affiliate that owns and operates IPP facilities and provides other, energy-related services. The generation company described in “(ii)” immediately above will be subject to regulation by the PSC no greater than PSC regulation of other owners of legally comparable facilities. The unregulated affiliate in “(iii)” may function as an ESCO and as a power marketer.

The regulated T&D Company will offer regulated and market-based wholesale energy services and retail energy services. It may also provide energy services company (“ESCO”)-type services.

Competitive Conduct Standards and Affiliate Transactions

The officers of the CHG&E holding company, apart from the Chairman and President, will not also be officers of an unregulated ESCO affiliate. The regulated part of CHG&E, the T&D Company, will not provide market information or sales information to any affiliate and will not give the appearance that it acts for any affiliate. The T&D Company may not give an affiliate preference over non-affiliated customers. The T&D Company, initially, will provide administrative services for itself, the CHG&E holding company and affiliates.

A dispute resolution process is established in Appendix “B” to the PSC’s February 19, 1998 order.

Stranded Cost Recovery

Stranded cost recovery will commence at the time of CHG&E’s next rate case, which will take effect on or after June 30, 2001. Net proceeds from the auction of generation assets, in excess of book value and net of the auction incentive, will be allocated as follows:
� First, to offset fossil generation stranded costs not recognized in the auction (such as “regulatory assets”);

� Second, to reduce book costs of Nine Mile Point No. 2 plant; and

� Third, to provide rate payer benefits.

If the auction proceeds are below net book value, the difference will be added to stranded costs.

Recovery of stranded costs will be through a competitively neutral non-bypassable wires charge. A CTC will be established at a level equal to approximately 50 per cent of CHG&E’s non-fuel production costs. The costs to CHG&E arising from residential, commercial and small-industrial customers participation in retail access during the period of the CHG&E Restructuring Plan will be recovered through the CTC. A goal will be to minimize cost shifting among and within classes of customers. All customers will be eligible for full retail access on July 1, 2001.

Supplier of Last Resort

CHG&E will remain the supplier of last resort during the term of the CHG&E Restructuring Plan.

Social/Environmental Programs

Environmental programs

The parties to the CHG&E Restructuring Plan agree to participate in a generic proceeding to develop means of providing customers with information on the fuel mix and emissions characteristics of generation. Time of use meters will not be required for customers not now using them.
Low-income assistance

There is no specific discussion of a low-income rate or assistance program in the CHG&E Restructuring Plan.
Economic development

CHG&E will expand the size of its growth incentive plan by 25 MW; it will increase the size of the incentive discount for S.C. Tariff No. 13 customers to 28 per cent; and it will make a growth discount program available for S.C. Tariff No. 3 customers (namely, Large Power, Primary Service customers). In general, these changes will end on June 30, 2001.

System Benefits Charge

CHG&E is expected to collect $4.1 million annually for SBC � funded programs over the next three years. Funding will be a one mill/KWH charge for three years. A statewide administrator, the New York State Energy Research and Development Authority, will administer the SBC-funded programs.

Reliability Incentives/Penalties

CHG&E agreed in the CHG&E Restructuring Plan to a Service Quality Incentive Plan (“SQIP”) which includes provisions addressing reliability. The reliability part of the SQIP was designed to reduce the total number of interruptions and the length of time each interruption lasts. If the score for the entire SQIP, including elements other than reliability, is below a target level agreed to by CHG&E, the T&D Company will suffer a reduction in permissible earnings.

Nuclear Generation Issues

The costs of CHG&Es share of the Nine Mile Point No. 2 plant, will continue to be included in CHG&Es rate base and as expense items, consistent with the PSC’s past treatment of such items. Following July 1, 2001, these costs will continue to be recovered by the regulated T&D Company. CHG&E agrees to participate in “good faith discussions” related to a future state-wide nuclear power plant resolution.

New York State Electric & Gas Corporation

On October 9, 1997, New York State Electric & Gas Corporation (“NYSEG”) filed an Agreement Concerning the Competitive Rate and Restructuring Plan of New York State Electric & Gas Corporation, dated October 9, 1997 (“NYSEG Agreement”), with the PSC establishing a framework under which NYSEG would restructure its activities, among other things, to implement retail competition in its service territory and institute rate reductions for its retail customers. A Recommended Decision, concerning this settlement reflected in the NYSEG Agreement was issued by PSC Administrative Law Judge Jeffrey Stockholm on December 3, 1997. On January 27, 1998, the PSC issued an abbreviated order approving the settlement, subject to certain conditions and modifications contained in the order. On March 5, 1998, the PSC issued an order and opinion (Opinion No. 98-6) explaining its decision in the January 27, 1998 order.

Rate Plan

In general, rate terms of the NYSEG Agreement cover a five-year period (the “Price Cap Period”). However, certain provisions extend beyond the five-year Price Cap Period. The effective date of the implementing tariffs for Year One of the Price Cap Period was March 3, 1998.

Scheduled reductions (to base rates)

NYSEG has agreed to forego two rate increases previously approved by the PSC in 1995 scheduled to occur in Years Two and Three of the previous settlement period established in a prior 1995 settlement of electric rate issues; this eliminates an approximate seven per cent price increase for residential and commercial customers. In addition, NYSEG will reduce customer rates as follows:

(i) Large customers (i.e., industrial customers with average, annual peak demands of 500 KW or greater and all demand billed customers with average, annual load factors of at least 68 per cent) will receive annual electric rate reductions of 5 per cent on average effective for each year of the Price Cap Period. (Customers with negotiated or incentive rates (“Flex Rate and Incentive Customers”) are not eligible for the rate reductions until their tariffs or contracts expire or unless such tariffs or contracts permit them to be eligible for the rate reductions.)

(ii) All industrial and commercial customers not eligible for the rate cuts described immediately above will receive a rate reduction of five per cent effective for the fifth year of the Price Cap Period. (Flex Rate Customers are not eligible for the rate reductions until their tariffs or contracts expire or unless such tariffs or contracts permit them to be eligible for the rate reductions.)

Retail Access Schedule

Retail access will be made available to NYSEG’s customers in three groups:

(a) Beginning on November 1, 1997, NYSEG implemented a targeted customer choice pilot program in compliance with the PSC’s “Order Establishing Retail Access Pilot Program” issued on June 23, 1997 in Case 96-E-0948 � Petition of Dairylea Cooperative, Inc. to Establish Open-Access Pilot Program for Farm and Food Processor Electricity Customers.
(b) Beginning on August 1, 1998, retail access will be available to: (i) all customers in the City of Norwich and the Lockport Division, subject to minimum load and aggregation requirements; and (ii) all industrial customers which are not eligible for the 5 per cent annual rate decreases and not taking service under special contracts. Eligible customers which choose a new electricity supplier will have power delivered by NYSEG from the new supplier by no later than December 31, 1998.

(c) Beginning on August 1, 1999, full retail access will be available to all remaining eligible NYSEG customers, e.g., other than Flex Rate and Incentive Customers, provided that an Independent System Operator is operating. Flex Rate and Incentive Customers will be eligible for retail access after their contract or tariff expires unless the contract or tariff permits the customer to become eligible for retail access sooner. Eligible customers which choose a new electricity supplier will have power delivered by NYSEG from the new supplier by no later than December 31, 1999.

Rate Design and Back-Out Rates

Rate design

(i) With respect to customers not eligible for the rate reductions described in Subpart 1.b.i above, NYSEG will freeze their rates for Years One and Two of the Price Cap Period.
(ii) By February 26, 1998, NYSEG must file marginal cost-based tariffs applicable to incremental energy usage above historical levels of the industrial and commercial customers not eligible for the annual five per cent annual rate reductions described in Section 1.b.i above.
(iii) NYSEG is required to file no later than February 1, 1999, new electric rate designs for Years Three, Four and Five that address marginal cost-based pricing for all customer classes. Beginning in Year Three of the Price Cap Period, NYPA savings for residential customers may be reflected in the basic service charge.
(iv) NYSEG is required to unbundle its electric retail rates over the five year Price Cap Period so that they reflect the separate service components such as the Basic Service Charge (as appropriate), SBCs, the Retail Access Credit, Power Supply Charges, Transmission, Distribution, Customer Sevice and the CTC.
(v) All customers, including those who switch suppliers, will be required to pay a non-bypassable CTC plus any related Gross Receipt Tax (“GRT”) to permit NYSEG to recover the stranded generation costs (discussed in Subpart 7, below).

Back-out rates

The back-out rates for initial retail access customers and full retail access customers are as follows:
Initial Retail Access � the retail access credit used to back-out generation during the period prior to NYSEG selling its non-nuclear generation assets will be the market price of electricity plus an adder of four tenths of 1 cent ($0.004) per KWH for customers eligible for the annual five per cent rate reduction described in Section 1.b.i above and an adder of 1 cent per KWH for customers not eligible for the annual five per cent rate reductions except for Flex Rate and Incentive Customers. The retail access credit cannot exceed 3 cents per KWH including GRT.

Full Retail Access � the retail access credit used to back-out generation after NYSEG sells its non-nuclear generation assets will be (a) 3.23 cents per KWH, including GRT, through July 31, 2000, (b) 3.47 cents per KWH, including GRT, from August 1, 2000 to July 31, 2001, and (c) 3.71 cents per KWH, including GRT, from August 1, 2001 until the end of the Price Cap Period. The retail access credit will be net of the CTC imposed for stranded costs after NYSEG sells its coal-fueled generation assets. After the Price Cap Period, all costs (other than the non-bypassable CTC) related to assets subject to auction or appraisal will be excluded from rates and all customers will pay the market price of generation plus applicable GRT. If the auction or appraisal of NYSEG’s generation assets is not completed by August 1, 1999, until the generation assets are sold, the retail access credit used to back-out generation will be the market price of electricity plus an adder of four tenths of 1 cent ($0.004) per KWH for customers eligible for the annual 5 per cent rate reduction described in Section 1.b.i above and an adder of 1 cent per KWH for customers not eligible for the annual 5 per cent rate reductions except for Flex Rate and Incentive Customers. The retail access credit cannot exceed 3.23 cents per KWH including GRT.

Generation Divestiture/Market Power Issues

In the NYSEG Agreement, NYSEG undertook to transfer its coal fueled generation plants to a third party or an affiliate (“GenSub”) in order to promote competition, mitigate stranded costs, and to establish a fair market value of the plants. NYSEG has agreed, however, that its GenSub will not participate as a buyer of its generation plants. The value of the generation plants will be determined in accordance with an auction designed to obtain the highest market value and to mitigate above market costs and establish a regulatory asset for the recovery of remaining above market costs. If no bids are received above the minimum bid requirement, an appraisal process will be used to value the plants. The auction and sale or appraisal process must be completed by August 1, 1999. NYSEG is required to submit an auction and appraisal plan, developed in consultation with the DPS Staff and parties to the NYSEG Agreement. NYSEG submitted this plan to the PSC, and the PSC approved such plan on April 24, 1998.
Corporate Restructuring

On April 29, 1998, NYSEG’s shareholders approved the formation of a new holding company, Energy East Corporation. NYSEG will be a regulated, wholly-owned utility subsidiary of this holding company. NYSEG will functionally separate its electricity distribution activities from its gas services. On February 10, 1998 NYSEG transferred its generating assets to NGE Generation, Inc., which will be a subsidiary of Energy East Corporation.

Competitive Conduct Standards and Affiliate Transactions

(a) The NYSEG Agreement contains numerous standards to govern affiliate transactions among NYSEG and its affiliates. These standards include provisions related to the following: (i) separation of business entities conducting regulated and unregulated activities; (ii) separation of the books and records of regulated and unregulated business entities; (iii) limitations on affiliate transactions to protect against cross-subsidies; (iv) limitations on NYSEG’s ability to provide competitive information to affiliates unless the same information is made available to competitors at the same time and under the same conditions; (v) DPS Staff’s access to the books and records of NYSEG and, under certain conditions, its major affiliates; (vi) dispute resolution process for PSC review of a competitor or customer’s complaint that NYSEG has acted in an anticompetitive manner; (vii) certain limitations on NYSEG’s ability to promote an affiliate as service provider to customers located in NYSEG’s service territory; (viii) prohibition on NYSEG’s ability to guarantee the securities of its affiliates or pledge any of its assets as security of an affiliate’s indebtedness; (ix) rules against NYSEG loaning operating employees to its affiliates; and (x) prohibition against NYSEG conducting certain competitive behind-the-meter energy services.

(b) The PSC can impose remedial actions on NYSEG for violations of the competitive conduct standards contained in the NYSEG Agreement.

Stranded Cost Recovery

NYSEG will be permitted to recover through the non-bypassable CTC (over a period of time to be determined by the PSC after the auction process) the stranded costs, if any, resulting from the sale of its coal fueled generation plants (as described in Subpart 4, above). The stranded costs related to the generation assets will be the difference between the net book value of the plants (less funded deferred taxes) and the net after-tax auction proceeds. After the Price Cap Period, NYSEG’s regulatory assets (other than those related to the auction of the coal fueled plants, hydroelectric facilities, non-utility generators, i.e., IPPs, and nuclear fixed costs (except if the nuclear assets are auctioned)) will be recovered through a non-bypassable wires charge (for the life of the amortization period, contract or license). NYSEG will propose to the co-tenants of the Nine Mile Point No. 2 plant that it be sold via auction. If they agree, and the nuclear plant is sold to a non-NYSEG entity, then NYSEG can recover through a non-bypassable wires charge the difference between the book value of its ownership interest in the plant (less funded deferred assets) and the net after-tax auction proceeds for a period determined by the PSC but not to exceed 15 years.
If during the Price Cap Period NYSEG achieves IPP contract cost savings through renegotiation or termination, but excluding securitization, 80 per cent of the net savings will be flowed through to customers in a manner determined by the PSC and NYSEG can retain 20 per cent of the savings. After the Price Cap Period, pass through to customers of IPP contract savings will be done in a manner to be determined by PSC.

Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities

NYSEG will be the provider of last resort during the Price Cap Period unless the PSC changes such status. Upon approval by the PSC, NYSEG may deny access to any other New York state utility or its load serving affiliate (“LSE”) which seeks to serve retail customers in NYSEG’s service territory if NYSEG or its affiliated energy service company is not permitted (in at least equal or greater proportion) to serve customers in the retail service territory of the LSE’s affiliated utility.

Social/Environmental Programs

Environmental programs

Pursuant to the January 27 order, the NYSEG Agreement includes the environmental provisions approved in the Con Edison proceeding. The PSC may evaluate potential ways to accomplish further environmental benefits through environmental protection and energy efficiency programs.
Low-income assistance

NYSEG will continue its current “Fresh Start” low income assistance program until a replacement program is approved. Pursuant to the PSC’s March 5, 1998 Opinion No. 98 – 6, NYSEG will file a proposed low income assistance program designed to provide service to customers known by NYSEG to receive benefits under the Energy Assistance Program (estimated to be 37,000). The annual cost of this program is estimated at $5 million; $2.5 million of this annual amount, from Rate Year One through Rate Year Three, will be obtained from the $13 million earmarked in the NYSEG Agreement for energy efficiency and other programs approved by the PSC for funding through the SBC.

Economic development

During the Price Cap Period, NYSEG will supplement existing programs or institute new programs for economic development. For example, NYSEG will continue existing tariffs for Economic Development Zone Incentive Rates (“EDZI”) but will provide new discounted rates for qualifying loads of existing and future customers and new zones. In addition, NYSEG will continue its Economic Revitalization Incentive Rate (“ERI”) tariff but reduce the customer eligibility requirement from a 500 KW to 300 KW billing demand. Also, NYSEG will implement new customer eligibility requirements for its S.C. Tariff Nos. 13 and 14. Finally, NYSEG will file a new tariff provision called the Business Retention Incentive to augment its existing retention and revitalization tariffs (e.g., Self Generation Deferral Incentive, EDZI, S.C. Tariff No. 13, S.C. Tariff No. 14, and ERI).

System Benefits Charge

Neither the NYSEG Agreement nor the January 27 order specifically addresses the cost level and mechanism of recovering costs associated with the SBC. The NYSEG Agreement states, however, that if the PSC determines a mechanism to recover SBCs in this proceeding or in the separate pending collaborative undertaking on SBCs in the PSC’s Competitive Opportunities Proceeding (which the PSC has determined), NYSEG and the parties to the NYSEG Agreement will support use of standard performance contracts with stipulated pricing as one way to disburse funds for energy efficiency programs. It is now expected that NYSEG will collect approximately $13.3 million annually, $40 million over three years, for SBC programs.

Reliability Incentives/Penalties

During the Price Cap Period, an Electric Service Quality Performance Mechanism will be in place which provides NYSEG with the incentive to render reliable electric service. NYSEG will be subject to a penalty if service falls below targeted levels. The mechanism, as modified by PSC Opinion No. 98 � 6, uses five indices to measure performance and reliability.

Nuclear Generation Issues

See discussion in Subpart 7 above.


Niagara Mohawk Power Corporation

On July 23, 1997, Niagara Mohawk proposed an amended five-year rate and restructuring proposal (“PowerChoice”) following almost two years of negotiations addressing an earlier PowerChoice proposal. The July 23, 1997 PowerChoice proposal includes the Master Restructuring Agreement (“MRA”), dated July 9, 1997, between Niagara Mohawk and 16 signing independent power producers (“SIPPs”) that represent about 80 per cent of the utility’s above-market outside power purchases. Under PowerChoice, the SIPPs will collectively own about 25 per cent of Niagara Mohawk after acquiring newly created common stock.
Niagara Mohawk further amended its PowerChoice proposal on October 10, 1997 in a settlement agreement with 20 parties to its restructuring proceeding. PSC Administrative Law Judge William Bouteiller recommended adoption of the modified PowerChoice plan, with several additional modifications, on December 29, 1997. The PSC approved PowerChoice (Opinion No. 98-8) with certain changes and conditions on March 20, 1998.
Niagara Mohawk’s PowerChoice proposal was issued at a time that the company found itself in a dire financial situation. In August 1995 Niagara Mohawk indicated that its contracts with IPPs were damaging the company and that it would have to restructure the contracts or take “even more severe actions” to “keep the company financially viable.” Niagara Mohawk’s Chairman reported that bankruptcy was an option. The payments to IPPs, which contributed to this financial condition, had grown from $198 million in 1990 to $1.01 billion in 1995. Meanwhile, business conditions in Niagara Mohawk’s service territory were stagnant.

Rate Plan


PowerChoice is a five-year plan. It begins after unbundled tariffs are in effect and Niagara Mohawk has restructured the individual IPP contracts referenced in the MRA. Other events must occur before the implementation of PowerChoice. They include: Niagara Mohawk receiving various approvals to sell debt and equity and the IPPs obtaining releases from existing contractual obligations to certain steam hosts. Currently, PowerChoice is forecast to begin in mid- to late-1998.

Scheduled reductions (to base rates)

The average residential and commercial customer will experience a 3.2 per cent reduction in prices (from 1995 base rates or the most current twelve-month period, whichever base year results in the lowest first year level) phased-in over a three-year period. Tariff rates for the industrial class will be reduced to below $0.06/KWH by 2000, which is a reduction of 25 per cent relative to 1995 price levels. The vast majority of surcharges resulting in “back-door” rate increases have been eliminated.

Retail Access Schedule

Customers will begin receiving retail access according to a schedule that begins on the PowerChoice implementation date.
Phase I: Transmission level customers >60 KV . . . . . .September 1998 (Estimated)
Phase II: All remaining customers with
peak demands >2 MW . . . . . . . . . . . . . . . . . . . . . . . . .September 1998 (Estimated)
Phase III: All remaining transmission and
Subtransmission customers >22 KV . . . . . . . . . . . . . . . May 1, 1999
Phase IV: All remaining residential customers . . . . . . . Phase-in: April 2, 1999 through
December 21, 1999
Phase V: All remaining non-residential customers . . .No later than August 1, 1999
Phase VI: Full retail access . . . . . . . . . . . . . . . . . . . .By December 31, 1999

Rate Design and Back-Out Rates

Rate design

(i) The starting point for establishing unbundled rates that will apply during PowerChoice is the 1995 actual rates, including all surcharges, annualized for the base rate increase, or the latest known twelve months’ actual rates, whichever is lower. Prices for transmission and distribution services will increase throughout the period of PowerChoice. However, increases in transmission and distribution services for Rate Years One through Three of the PowerChoice period will be offset by an equivalent reduction in the CTC to meet overall price reduction goals. In Rate Years Four and Five, the CTC will be adjusted quarterly for changes in IPP-indexed charges. Energy and customer service back-out rates have been established. Certain costs or savings can be deferred for recovery or refund in years four and five of PowerChoice.
(ii) On May 18, 1998, Niagara Mohawk submitted unbundled tariffs to be used during PowerChoice. These amended tariffs will become effective upon not less than 60-days notice.
(iii) Prices in Rate Years Four and Five may be increased by an amount not to exceed one per cent of the all-in fixed price except for energy. This “hard” price cap excludes recovery of certain expenses. Niagara Mohawk must affirmatively seek approval from the PSC to implement any price increases in Rate Years Four and Five of PowerChoice. In addition, any rate increase within the one per cent price cap may not exceed the rate of inflation.
(iv) All customers (except certain NYPA customers and certain on-site generators) must pay a non-bypassable CTC, or in prescribed circumstances, an exit fee. Niagara Mohawk will have a reasonable opportunity to recover costs associated with fossil and hydro units, nuclear assets and the MRA. Niagara Mohawk has not computed a final stranded cost amount to be collected from customers. The effect of certain cost factors, including plant auctions and IPP contract renegotiations, has yet to be determined.
(v) Over the five-year settlement period, it is estimated that Niagara Mohawk shareholders will have to absorb over $2 billion of stranded costs; shareholders will thus forgo ROE up to that amount which would otherwise have been allowable from the MRA regulatory asset. Unlike other investor-owned utilities, Niagara Mohawk expects little to no return on equity during the term of PowerChoice.

Back-out rates

The PSC has approved PowerChoice’s energy back-out rates for Niagara Mohawk customers that choose new suppliers. The amount backed out of Niagara Mohawk’s bundled rates will remain in effect until the ISO is in operation and develops a spot market price. The back-out rate represents estimated market prices. The energy back-out rate is projected to be approximately 2.5 to 3.0 cents per KWH for the first three years of the PowerChoice settlement period, depending on the customer’s class and location. A customer service back-out rate, approved by the PSC in January 1998, will be monitored and updated as necessary.

Generation Divestiture/Market Power Issues

Niagara Mohawk will divest its fossil and hydro generation assets at auction. Winning bids in the auction would be selected no later than 11 months after PSC approval of an auction plan. Niagara Mohawk may retain fossil/hydro assets that do not receive positive bids. Niagara Mohawk’s nuclear assets will become part of the surviving regulated company (“RegCo”) — although functionally separated — until a statewide nuclear solution is found. In addition, Niagara Mohawk has 24 months after the date of the PowerChoice settlement to file a plan with the PSC analyzing all possible nuclear solutions.

Niagara Mohawk’s auction plan was approved by the PSC on April 8, 1998. Under the approved plan, Niagara Mohawk will offer all its fossil and hydro assets for sale, comprising 4,217 MWs of capacity, in a two-stage sealed bid process. The bidding is open to all qualified outside parties. Niagara Mohawk has announced it would not participate in the auction bidding. Bidders may submit a bid on the Niagara Mohawk’s entire fossil/hydro portfolio, on individual fossil units, on any of six bundles of hydroelectric plants, or any combination thereof. Niagara Mohawk operates four fossil-fueled plants with a combined capacity of 3,256 MWs. In addition, the company will sell its 300-MW interest in the Roseton Station, operated by Central Hudson Gas and Electric Corporation. Niagara Mohawk’s 72 small hydro units (a total of 661 MWs) are packaged in groups ranging from five plants to 28. Buyers for these fossil and hydro plants will be selected six months after the PSC’s April 8, 1998 Order approving Niagara Mohawk’s auction plan. Transfer of ownership is expected to take place mid-1999.

The auction plan allows Niagara Mohawk 15 per cent of any gain above net book value as an incentive to obtain the highest possible prices for its generation facilities. Niagara Mohawk’s Oswego Steam station is subject to a separate five per cent incentive on proceeds in excess of $100,000. The Oswego Steam station incentive will increase as the auction value increases.

Corporate Restructuring

Niagara Mohawk is authorized to form a holding company (“HoldCo”) or similar utility parent. It will divest fossil/hydro assets (as discussed above), and operate a functionally separated transmission, distribution and gas company, RegCo, referred to above. RegCo may form subsidiaries, subject to PSC jurisdiction, if desired. The holding company structure may create lightly regulated and unregulated affiliates of Niagara Mohawk such as the existing Plum Street Enterprises. Niagara Mohawk may form other transitional subsidiaries in order to effectuate the fossil/hydro auction. RegCo must submit annual reports to the PSC concerning: transfers of assets, cost allocations, employee transfers and employees in common benefit plans. HoldCo will file a list of SEC reports with the PSC.

Competitive Conduct Standards and Affiliate Transactions

(a) PowerChoice contains rules to govern affiliate transactions among Niagara Mohawk and its subsidiaries and affiliates. The corporate code of conduct standards was approved by the PSC and is designed to ensure separation of business entities conducting regulated and unregulated activities. RegCo, HoldCo, and HoldCo’s other subsidiaries will maintain separate books and records of account.
(b) Specific provisions include:
(i) RegCo will provide no sales leads to affiliates involving customers in its service territory;
(ii) RegCo must respond to customer inquiries with a list of all known energy service companies doing business in its service territory;
(iii) no rate discrimination by RegCo is permitted; and
(iv) Niagara Mohawk and its affiliates may use the corporate name without specific royalty payments.
(c) Each distinct corporate entity will maintain separate books and records of account.
(d) The PSC can impose remedial actions on Niagara Mohawk for violation of the competitive conduct standards contained in PowerChoice.

Stranded Cost Recovery

The PSC will allow Niagara Mohawk a reasonable opportunity to recover its stranded generation costs and regulatory assets, including costs associated with its own generation as well as $3.6 billion new debt associated with the MRA. A non-bypassable CTC will be used to collect these costs. Certain on-site generators and new municipal systems (and certain recipients of other allocations) will be subject to access or exit fees established by amended tariffs filed by Niagara Mohawk and approved by the PSC.
In general, PowerChoice provides a mixed offering of CTC mechanisms to retail customers for stranded cost recovery. Customers in industrial, commercial and residential classes will have the option of a fixed CTC during the five years of PowerChoice.
In addition to the fixed CTC, customers in S.C. Tariff Nos. 1, 2 and 3 will have the option of a floating CTC. Customers in S.C. Tariff No. 3A (the largest industrial and commercial customers) do not have the floating CTC option. However, they can choose all-in bundled prices for a five-year period (with or without options to cancel) in addition to the fixed CTC option.

Supplier of Last Resort and Energy Service Company Responsibilities

Niagara Mohawk’s RegCo will retain the obligation to serve electricity to all customers in its service territory during the term of PowerChoice. ESCOs providing electric power to customers during PowerChoice must meet reasonable standards of operational conduct and acceptable standards of commercial creditworthiness. ESCOs may choose between a one� or two-bill system.

Social/Environmental Programs

Environmental programs

PowerChoice provides for a SBC to cover demand-side management efforts, research and development and energy efficiency for low-income customers. Niagara Mohawk will make $15 million available annually for these programs for the first three years of PowerChoice. Thereafter, the SBC program would be revisited and future funding levels would be set.
Niagara Mohawk will provide environmental benefits by retiring 5,000 of its sulfur dioxide emission allowances and by donating, selling and granting conservation easements for various parcels of land it owns in the Adirondack Park. Niagara Mohawk will also help develop windpower and photovoltaic generation and it will fund a long-term ecological monitoring program.

Low-income assistance

During PowerChoice, Niagara Mohawk will expand its Low-Income Customer Assistance Affordability Plan (“LICAP”). Under LICAP, Niagara Mohawk may accept partial payment from a non-public assistance customer. The settlement budgets between $4.4 million and $5.6 million for this program for 1998 through 2000.

System Benefits Charge

Niagara Mohawk will collect $45 million over three years for SBC programs.

Reliability Incentives/Penalties

PowerChoice provides for a “Customer Service Performance Incentive” that is capped at $13.2 million a year. The PSC will monitor complaints received over a 12-month period (rates of total complaints per 100,000 customers) and apportion penalties within a scaled interval:

Complaint Rate IntervalMax Penalty Within Scaled Interval
(per 100,000 custs.)

<10- zero �
10.0 � 10.9$440,000
11.0 � 11.9$1,320,000
12 (or more)$2,200,000

Niagara Mohawk has agreed with DPS Staff to develop a program of individual customer service guarantees. Emphasis initially will be placed on the scheduling of appointments. In addition, a service interruption frequency, interruption duration and power quality will be monitored. Penalties, if any, will be accrued to offset cost deferrals.

Nuclear Generation Issues

Under PowerChoice, Niagara Mohawk will recover costs for each of its nuclear plants. Niagara Mohawk has agreed to hedge those costs through a financial swap contract for the first three years of the PowerChoice period. Each nuclear cost recovery contract is based on the forecasted going forward costs of each plant. These forecasts will be included in overall rate goals and may be adjusted in years four and five. If a nuclear unit is retired during PowerChoice, the nuclear cost recovery contract will end and the energy associated with the retired unit will be unhedged. Niagara Mohawk will make a filing to the PSC after PowerChoice to continue cost recovery for its nuclear units.

Rochester Gas And Electric Corporation

On November 26, 1997, the PSC issued an abbreviated order adopting, subject to certain conditions and modifications, a settlement (“RG&E Settlement”), dated October 23, 1997, executed by Rochester Gas and Electric Corporation (“RG&E”) and other interested parties. The RG&E Settlement constitutes RG&E’s restructuring framework under which it will implement competitive customer retail choice in its service territory, rate reductions and a corporate reorganization. On January 14, 1998, the PSC issued a detailed order (Opinion No. 98-1) approving the settlement and providing the PSC’s views on certain matters. This order is the subject of pending litigation in New York Supreme Court. The RG&E Settlement, as modified by the PSC, is summarized below.

Rate Plan


The rate reductions under the RG&E Settlement will be for a five year term beginning on July 1, 1997 through June 30, 2002 (“Settlement Term”).

Scheduled reductions (to base rates)

Under the RG&E Settlement, rates for all customer classes will be reduced. Large industrial and commercial customers will receive the biggest decreases over the Settlement Term.

Average: 8 per cent

Small customers, incl. residential: 7.5 per cent

Medium customers: 8 per cent

Large industrial customers: 11.2 per cent

The annual revenue decreases, as a result of rate reductions from the levels in effect as of July 1, 1996, net of the monies set aside to cover a possible settlement of the Kamine dispute, will be as follows:

July 1, 1997: $3.5 million
July 1, 1998: $9.3 million
July 1, 1999: $19.2 million
July 1, 2000: $29.0 million
July 1, 2001: $54.1 million

The rate reductions shown above will not be increased or decreased, except as follows:
� the total cost of a resolution of Kamine issues is less than the $32.9 million RG&E has set aside, in which case the PSC can further lower the rates by the difference;
� the benefits of debt securitization can be used to further lower the rates;
� adjustments for SBC costs, whether or not specifically identified by a special charge;
� competition implementation costs that exceed $2.5 million in a single year;
� mandates and catastrophic events that individually exceed $2.5 million may be deferred and recovered after the settlement period;
� 50 per cent of any property tax variation shall be deferred until the end of the settlement period;
� if the total of deferrals, pre-tax, either owed customers or to shareholders, exceed $30 million; and
� annual rate changes due to the $30 million deferral limit cannot exceed $7 million in any of the final three years.

Retail Access Schedule

RG&E will open up its service territory to retail competition as follows:
Commencement Date
(i) Dairylea Pilot Program � eligible farm and food
processor customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .February 1, 1998
(ii) Energy-Only Stage � customers using up to 670 GWH
of energy per year, in the aggregate.(about 10 per cent of
customer load) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .July 1, 1998
(iii) Energy and Capacity Stage
– customers using, in the aggregate, up to
1,300 GWH of energy per year (about 20 per cent
of RG&E’s customer load) . . . . . . . . . . . . . . . . . . . . . . . . . . July 1, 1999
– customers using, in the aggregate, up to
2,000 GWH of energy per year (about 30 per cent
of RG&E’s customer load) . . . . . . . . . . . . . . . . . . . . . . . . . . July 1, 2000
(iv) all remaining retail customers . . . . . . . . . . . . . . . . . . . . . . . . . July 1, 2001
Customer eligibility to participate at any implementation stage of the retail access program is not restricted by customer class. If a statewide energy and capacity market in which RG&E can participate is not functioning by July 1, 1998, RG&E may petition the PSC for a delay in the Energy and Capacity Stage of its retail access program.

Rate Design And Back-Out Rates

Rate design

Subject to certain contingencies, the RG&E Settlement calls for an approximately $101 million reduction in RG&E’s revenues over the Settlement Term. RG&E will design rates that allocate the revenue reductions evenly among service classifications except as follows: (a) monthly customer charges to residential and small business customers will be subject to an annual $1.50 increase, until it reaches $17.50/month; (b) the differences between peak and shoulder-peak energy charges for large industrial customers will be eliminated; (c) the energy audit requirement in flex-rate tariffs will be modified; and (d) beginning on July 1, 1999 through June 30, 2002, the rates for certain incremental manufacturing load of at least 50 KW will be an average rate of $0.045 per KWH.

If RG&E achieves a return on common equity which exceeds 11.8 per cent, as adjusted for any return in a prior period over the maximum, for the Settlement Term, the excess will be treated as follows: (a) 50 per cent will be used to write down deferrals accumulated during the Settlement Term and RG&E can keep any remaining amount as retained earnings; and (b) the remaining 50 per cent will be used to write down deferrals and Sunk Costs (as defined in Subpart 7 below) and the PSC will determine the disposition of any remaining amounts.

Back-out rates

The back-out rates for the various stages of the retail access program are (a) approximately $0.019 per KWH in the Energy-Only Stage, and (b) approximately $0.032 per KWH in the Energy and Capacity Stage. The $0.032 per KWH is generally expected to be equal to the incremental costs (e.g., O&M and capital additions) that RG&E incurs to produce power from its fossil and hydro generating units and purchased power.

Generation Divestiture/Market Power Issues

RG&E must file a market power mitigation plan with FERC in connection with the New York Power Pool’s FERC filing for approval to form new wholesale market institutions (i.e., an ISO, Power Exchange and New York State Reliability Council). The PSC will implement market power mitigation measures, as appropriate, for retail service.

RG&E is not required to divest its generation assets. However, in the event divestiture occurs, gains from the sales will be shared by shareholders and rate payers. If RG&E’s existing generation assets are sold during the Settlement Term, gains from the sale will be shared between shareholders and rate payers as follow: (a) with sales occurring in the first three years of the Settlement Term, rate payers will be entitled to 60 per cent of the first $20 million of any gains and 80 per cent of the gains above $20 million while RG&E will be entitled to the remaining 40 per cent and 20 per cent respectively; and (b) with sales occurring in the last two years of the Settlement Term, rate payers are entitled to 80 per cent of the gains and RG&E can retain the remainder.

Corporate Restructuring

RG&E will functionally or structurally separate its existing operations into the following: (a) a separate distribution unit (“DISCO”); (b) a separate generating unit (“GENCO”); (c) a regulated load serving entity (“RLSE”); and (d) an unregulated load serving entity (“ULSE”). The settlement provides that RG&E may petition to form a holding company (“HOLDCO”) as the corporate parent for RG&E’s regulated and unregulated activities resulting from the corporate reorganization, and that the parties to the settlement will support the petition. The DISCO will continue RG&E’s transmission and distribution services and it will own either directly, or indirectly by owning the GENCO, RG&E’s generation facilities. GENCO will operate the generation facilities and be responsible for fixed and variable costs of the hydro and fossil fuel units and purchased power contracts. The RLSE will provide bundled service under tariffs to customers who elect to continue to receive it and will be the “provider of last resort” unless the PSC approves an alternative means of providing such service. The ULSE will be an energy marketer and energy service provider within and outside RG&E’s service territory. Whether RG&E conducts its unregulated activities through a HOLDCO or a separate subsidiary of a utility parent, it will be permitted to initially fund such activities in the amount of $100 million.

The PSC will have access to the books and records of the HOLDCO and its affiliates, subject to claims of confidentiality and privilege.

Competitive Conduct Standards and Affiliate Transactions

The RG&E Settlement contains standards of conduct which apply to affiliate transactions between RG&E’s DISCO and any of its energy supply and energy service affiliates. These standards include the following: (a) the DISCO cannot promote the services of its affiliates over non-affiliates to customers in the DISCO’s service territory; (b) the DISCO cannot give preferential treatment to either its affiliates’ customers or to its affiliates; (c) if the DISCO releases customer or market information, it must be made available to affiliates and non-affiliates on a simultaneous and comparable basis; (d) the DISCO and any unregulated affiliate providing services in the DISCO’s service territory must conduct their businesses with separate employees in separate buildings by July 1, 1998; and (e) asset transfers and the purchase and sale of goods among affiliates are subject to certain cost guidelines. The PSC may impose remedial action on the DISCO for violations of the standards of conduct if, after giving the DISCO full and fair opportunity to be heard, the PSC finds that violations occurred and the DISCO does not remedy the violations within a reasonable time.

Stranded Cost Recovery

All prudently incurred costs for electric plant investments and regulatory assets as of March 1, 1997 (“Sunk Costs”), will be recovered by RG&E through its distribution access tariff rates through the Settlement Term. The parties to the settlement will discuss the recovery of stranded costs after the expiration of the Settlement Term, provided that RG&E will have a reasonable opportunity to recover such costs following July 1, 2002. RG&E will also be permitted to recover the fixed costs of its fossil and hydro generating units, gas turbines and power purchase agreements (other than for Kamine) through its distribution access tariff rates until July 1, 1999.

RG&E may recover through its retail rates all prudently incurred cost for its nuclear generation assets (i.e., Ginna Station and RG&E’s share of Nine Mile Point No. 2 plant) provided that RG&E participates in negotiations with the Commission staff and the other cotenants of Nine Mile Point No. 2 plant regarding future rate treatment.

RG&E will also recover all prudently incurred incremental costs pertaining to the shut-down and decommissioning of generating facilities through its distribution access tariff rates. The decommissioning costs for nuclear assets are included in the Settlement and RG&E cannot make modifications to such costs unless approved by the PSC.

Supplier of Last Resort and Energy Service Company (ESCO) Responsibilities

As part of RG&E’s corporate reorganization (described in Subpart 5 above), RG&E will form a RLSE. The RLSE will be the “provider of last resort” unless the PSC approves an alternative means of providing such service. The settlement sets out a general outline of the responsibilities of load serving entities or ESCOs; however, their detailed responsibilities will be as set out in an operating agreement under RG&E’s distribution tariff.
RG&E’s Retail Access Program is a “single-retailer” model (i.e., the customer will receive only one bill), in which RG&E will supply distribution service to LSEs, including the RLSE, who will be directly responsible for the distribution charges. The RLSE and other LSEs can include distribution charges as a component of the price they bill to retail customers.

Social/Environmental Programs

(a) RG&E is allowed to petition to defer site remediation costs that exceed, net of insurance recoveries, $2 million, annually.
(b) Low-income assistance: RG&E will continue to implement a Low-income Program which will permit up to 1,000 customers, who meet certain criteria to receive a 25 per cent discount on their bills and forgiveness of up to 50 per cent of arrears after three years of satisfactory participation.
(c) Economic Development is addressed in the RG&E Settlement in terms of the $0.045 per KWH rate for incremental manufacturing discussed above in the Rate Design section, and in the continuation of the flex rate tariffs.

System Benefits Charge

Costs of certain mandated programs will be recovered through rates applicable to all customers which can be through a SBC. Such mandated programs include: research and development programs; energy efficiency programs; new, existing or expanded low income energy efficiency programs; and, environmental protection programs. It is estimated that funding for these programs, over three years, will be $14.7 million. RG&E is not required to contribute to the SBC program administered by NYSERDA.

Reliability Incentives/Penalties

RG&E will continue a Service Quality Performance Program (“SQP Program”) through June 30, 1999. RG&E will pay penalties to customers, up to $1.25 million in the aggregate, for failure to achieve minimum criteria established in the RG&E Settlement for service quality.

Nuclear Generation Issues

All prudently incurred costs of RG&E’s nuclear power plant ownership interests will be recovered through retail rates. RG&E, however, shall participate in ‘good-faith’ negotiations with the DPS Staff and the co-tenants of Nine Mile Point No. 2 plant regarding future rate treatment of such facility. Similarly, there are to be discussions concerning the Ginna Plant. The discussions should lead to a statewide solution, not an RG&E-specific agreement. These plants are subject to a provision that in the event of one or more “mandates” or “catastrophic events,” when the costs exceed $2.5 million, RG&E may defer such costs and recover them subsequently through rates.


Long Island Lighting Company/The Brooklyn Union Gas Company

On February 5, 1998, the PSC issued an order in Case 97-M-0567 adopting terms of a settlement agreement (“LILCO/Brooklyn Union Settlement”) by which the PSC authorized LILCO and Brooklyn Union to proceed with a corporate combination. The bases for the decision are set forth in PSC Opinion No. 98�9. The combination is expected to occur by means of a share exchange between the companies and a holding company. Brooklyn Union had previously, on September 29, 1997, completed a reorganization by which it became a wholly-owned subsidiary of a holding company, which restructuring had been authorized by the PSC in Opinion No. 96-26.
On June 26, 1997 LILCO entered into an agreement with LIPA which contemplates the acquisition by LIPA of LILCO’s electric transmission and distribution system, its interest in the Nine Mile Point No. 2 plant and the electric regulatory assets which are now owned by LILCO. LILCO’s gas assets and operations, the non-nuclear generating assets and operations would be transferred to LILCO subsidiaries whose stock would be owned by the new holding company associated with the corporate combination.

One or more of the holding company’s subsidiaries would then provide certain management services to LIPA with respect to the operation and maintenance of the electric transmission and distribution system, provide electric capacity and energy to LIPA from the generating plants and provide energy management services to purchase fuel and electric capacity and manage the scheduling and sale of electric capacity and energy for LIPA.

LILCO’s electric operations restructuring requirements and timetables differ somewhat from other New York State electric companies. Those provisions noted below are, in the most part, derived from the LILCO/Brooklyn Union Settlement and summarize provisions (on which the PSC has acted) which apply to the LILCO electric operations. Brooklyn Union does not have electric utility operations.

Rate Plan

LILCO/Brooklyn Union’s rate plan

The electric rate plan under the LILCO/Brooklyn Union Settlement provides credits which would reduce the non-fuel components of LILCO’s base rates by an average 3.21 per cent and fuel charges by an average 0.63 per cent. This rate plan would have a total bill impact of an average rate reduction of 2.47 per cent commencing on the consummation of the merger.

LILCO has extended suspension dates in Case 96-E-0132, a rate filing, until at least July 1, 1998. On or about May 1, 1998, all parties to Case 97-M-0567 and Case 96-E-0132 will be invited to confer regarding LILCO’s electric rates in light of the facts and circumstances at that time.

LIPA’s rate plan

On April 9, 1998, LIPA announced a decision of its Trustees (“Decision”) to implement rate reductions for Long Island customers, to become effective following LIPA’s acquisition of LILCO as described above. While the LIPA rate plan replaces the LILCO rate plan discussed above, LIPA will continue LILCO’s current rate designs. LIPA’s new rates, as announced on April 9, 1998, would represent an average rate reduction of 20 per cent. This reduction includes the reduction identified by LILCO/Brooklyn Union, discussed above.

Retail Access Schedule

LIPA has proposed, subject to the approval of its Trustees, a three-phase retail access program. Beginning on January 1, 1999, a pilot group of customers with an aggregate demand of 100 MW, evenly divided between residential and business customers, will be solicited. Deliveries from alternate suppliers will commence by May 1999. Phase II will involve an increase of the customer load for which retail access will be available by 400 MW, as well as the number of customers which will again be split evenly between residential and business. In Phase III of the program, customer choice will be increased so that by January 1, 2003, all remaining LIPA customers will be able to participate. LIPA has proposed that participants in all phases will be eligible to purchase both capacity and energy needs from suppliers of their choice.

Rate Design and Back-Out Rates

In the event that the transaction with LIPA identified at the outset of this Subpart is consummated, it is expected the LIPA will promulgate new rates consistent with the overall rate reduction detailed in its Decision and identified in Subpart 1.b, above. The LIPA rate plan announced in the Decision has the following key elements:

Residential rates

The LIPA rates will continue LILCO’s rate design which includes use of a “declining block” design for winter months and an “increasing block” design for summer months. Mandatory time of use rates will be discontinued for large users.

Non-residential rates

Commercial customers will continue to pay a seasonally-adjusted rated; commercial customers with demand in excess of 500 KW in the winter (or 145 KW in the summer) will continue to have mandatory time of use provisions.

Buy-back rates

LIPA will continue to have buy-back rates under a tariff based on time differentiation and LIPA’s avoided costs. Energy and capacity payments will continue in accordance with LILCO’s existing contractual arrangements.

Shoreham property tax settlement

LIPA proposed in its Decision to accept $625 million in settlement of the claims against Suffolk County, the Town of Brookhaven and several special service districts (school, fire and library) for excessive property taxes assessed on LILCO, and excessive payments in lieu of taxes imposed on LIPA, in connection with their ownership of Shoreham. This sum would be returned to Long Island rate payers in the form of one-time rebate checks and credits on customers’ electric bills for five years. LIPA plans to implement the rate aspects of its expected settlement of the Shoreham property tax dispute (1) as a part of LIPA’s commencement of service under new electric rates and (2) prior to concluding a final settlement of the property tax dispute. The impact on LIPA’s rates of the expected Shoreham property tax settlement are included in LIPA’s rate plan described above.

Generation Divestiture/Market Power Issues

LILCO’s non-Long Island generation, namely its interest in the Nine Mile Point No. 2 plant, is proposed to be transferred to LIPA. In addition, LILCO will transfer its electric transmission and distribution system to LIPA. The new holding company, through one or more LILCO subsidiaries, as noted above, will operate the transmission and distribution system for LIPA.

Corporate Restructuring

The proposed corporate combination between Brooklyn Union and LILCO is to be accomplished by a share exchange and the creation of a holding company. In addition, the proposed LIPA transaction identified above is expected to occur shortly before the Brooklyn Union � LILCO combination.

Competitive Conduct Standards and Affiliate Transactions

The LILCO/Brooklyn Union Settlement provides specific guidance on many activities among the new holding company, utility subsidiaries, non-utility subsidiaries and affiliates. It also provides competitive conduct standards.

Allocation of common costs and accounting for transactions between and among the new holding company and its subsidiaries

One or more corporate services subsidiaries will be formed, as subsidiaries to the new holding company, to perform the functions common to both utility operations and the unregulated subsidiaries of the new holding company. Distribution of costs will be based on causality with no requirement to capture incidental labor time.
(i) Transactions Between the New Holding Company and its Subsidiaries
The following procedures set forth the manner in which holding company costs, whether benefiting a subsidiary or of a general corporate nature, are to be charged to the subsidiaries.
� Direct charges are related to authorized services provided by the holding company or to the holding company by an affiliate. These services are charged to the benefiting entity on a direct time and materials basis. Affiliate business areas providing services to the holding company will report direct labor through the payroll system and other charges as appropriate.
� Allocated charges have been developed to distribute to affiliates costs that are not directly charged. Except for payroll loadings, which will be allocated to the subsidiaries based on direct or indirect labor charges, all other holding company costs which are not directly charged will be allocated to affiliates and business units within affiliates using a formula based on the ratio of the sum of revenues, net plant and direct payroll expense to the consolidated (holding company) total of these items. Building services costs charged to the holding company and allocated to the affiliates using the above formula will be determined based on the percentage of the total square footage of the corporate headquarters occupied by the holding company.
(ii) Transactions Between the Corporate Services Subsidiary(s) and the Affiliates of the New Holding Company
The following procedures set forth the manner in which all costs associated with work performed by the corporate services subsidiary(s) for affiliates or business units within affiliates is to be charged to the respective affiliates or business units within affiliates.
� Direct charges are related to authorized services provided by the corporate services subsidiary(s) to other subsidiaries of the holding company and vice versa. These services are charged to the benefiting entity on a direct time and materials basis. Labor costs will include an allocation for payroll loadings. Business areas will report direct labor through the payroll system and other charges as appropriate. Incidental labor charges should not be reported.
� Allocated charges will be used to distribute to affiliates costs that are not directly charged, based on an average cost per activity.
The remaining expenses of the corporate services subsidiary(s) represent costs associated with performing general corporate functions. These costs will be allocated to affiliates and business units within affiliates using a formula based on the ratio of the sum of revenues, net plant and direct payroll expense to the consolidated (holding company) total of these items.

Provision of services
(i) Service companies may provide corporate administrative services to regulated companies with protections provided for customer information and system information.
(ii) Utility service companies may provide certain services to the jurisdictional subsidiaries.
(iii) Regulated subsidiaries may engage in tariffed and non-tariffed transactions with each other but there are prohibitions against jurisdictional subsidiaries providing marketing services, transmission and distribution system planning, and use of marketing employees; any provision of goods or services between regulated subsidiaries and non-utility subsidiaries calls for written contracts and filings with the PSC.

Other restrictions on affiliate transactions

(i) Non-utility subsidiaries may not be located in the same building as regulated subsidiaries but the new holding company and service companies may be so located.
(ii) Limitations and restrictions on asset and employee transfers between the regulated subsidiaries, the service companies and the new holding company will be established.
(iii) Prior PSC approval is required for any loans, guarantees or credit support by the regulated utilities to the new holding company or non-utility-subsidiaries.
(iv) Standards of conduct between a regulated subsidiary and an energy related business affiliate include requirements both for compliance with generic conditions of the Electric Competitive Opportunities Proceeding (Case 94-E-0952):
� Requirements for safeguards to protect regulated subsidiary customer information and system information from access or use by any ESCO affiliates;
� Requirements to provide customers of regulated subsidiaries with lists of all qualified ESCOs;
� Offer of regulated electric service to similarly situated non-affiliated suppliers and customers in the service territory at the same prices, terms and conditions of service offered to affiliates or their customers and requirement that individually negotiated arrangements with affiliates or their customers be posted expeditiously on an electronic bulletin board; and
� Where regulated service offerings are limited and affiliates or their customers would qualify, those services shall be offered on an open season basis.

Stranded Cost Recovery

There is no explicit CTC included in LILCO’s rates. The transfer of LILCO’s interest in the Nine Mile Point No. 2 plant and LILCO’s regulatory assets to LIPA is intended, however, to allow for stranded cost recovery.

Supplier of Last Resort and Energy Service (ESCO) Responsibilities

Under the LILCO-LIPA transaction and under LIPA’s retail access proposal, LIPA will be the supplier of last resort of electric service in what is currently the LILCO service territory.

Social/Environmental Programs

LILCO has no low-income electric rate or assistance program. Some of the environmental programs are subject to consummation of the combination between LILCO and Brooklyn Union and last until November 30, 2000, and some may be terminated if the LILCO transmission and distribution systems are transferred to another entity. The requirements would require LILCO to:
(a)Create a multi-disciplinary renewable energy committee;
(b)Establish a fuel cell and photovoltaic demonstration program;
(c)Continue demand side management and research and development programs;
(d)Continue working with PSC on distribution pricing structure;
(e)Continue participation in Ozone Transport Assessment Group and join Ozone Attainment Coalition;
(f)Review major transmission and distribution projects to determine whether there are cost-effective alternatives with consideration to minimizing environmental impacts;
(g)Participate in market transformation collaboratives; and
(h)Support adoption of improved building codes and standards.

System Benefits Charge
LIPA has committed to create a $32 million (2 mills per KWH) Clean Energy Fund in the first year of its operation of the system to support energy efficiency and renewables on Long Island. LIPA will appoint an advisory panel for the Fund to recommend a permanent funding mechanism to continue support for the Fund at the $32 million per year level.

Reliability Incentives/Penalties

LILCO has committed in Case 97-M-0567 to reliability incentives and penalties commencing December 1, 1997 and in effect for each twelve month period thereafter until modified or discontinued by the PSC, or the consummation of the LIPA transaction. Those service quality measurement criteria are set forth in the table below.

Average Interruption Frequency in each of LILCO’s four Divisions: Western and Eastern Suffolk, Central and Queens-Nassau for Each Year (Excluding Major Storms)
Minimum level set for each division in Case 90-E-1119:
Western Suffolk – 1.60 Hours
Eastern Suffolk – 2.10 Hours
Central – 1.40 Hours
Queens-Nassau – 1.23 Hours

Customer Average Interruption Duration in each of LILCO’s four Divisions: Western and Eastern Suffolk, Central and Queens-Nassau for Each Year (Excluding Major Storms)
Minimum level set for each division in Case 90-E-1119:
Western Suffolk – 1.21 Hours
Eastern Suffolk – 1.19 Hours
Central – 1.35 Hours
Queens-Nassau – 1.12 Hours

Nuclear Generation Issues

LILCO’s interest in the Nine Mile Point No. 2 plant is proposed to be transferred to LIPA. LIPA will use the output reflected by this share to assist in meeting the needs of electric customers on Long Island.

Mergers and Acquisitions

Investments by the new holding company in non-utility businesses are limited generally to 50 per cent of total new holding company capital and must be made in areas described below unless otherwise approved by the PSC.

Energy-related business

Businesses that engage, as lessee, operator or owner, in the ownership, manufacture, production, transmission, distribution, storage and/or brokering and/or marketing of, or exploration for or production or gathering of: gas (natural or synthetic), electricity or steam or other energy sources; fuels for light, heat, transportation or power; devices for and equipment used in connection with the production of energy or fuel; appliances and equipment that consume or utilize gas (natural or synthetic) or electricity or steam or other energy sources; devices used in the control of, and information relating to the use of, natural or synthetic gas, electricity or steam or other energy sources; and businesses that provide services related to such activities, including without limitation management, project management, engineering and construction services.

Water, environmental and technical services

Businesses that include water distribution; waste management; pollution control systems; laboratory testing services; waste management services; management and consulting businesses related to such activities; and businesses that provide services related to these endeavors.

Telecommunication business

Businesses that include voice, video or data transmission services by radio, telephone, telegraph, fiber optics, cable or other means of communication, providing general or specialized information and databases, and radio, television or cable broadcasting, and designing engineering, manufacturing, constructing, maintaining, selling or leasing facilities and equipment for any such activities.

Area development business

Businesses that operate primarily in Brooklyn Union’s service area and that contribute to the economy of such service area by providing significant employment, the construction and/or improvement of the housing stock and/or commercial and industrial facilities and otherwise generally contribute to the overall economic health and well-being of Brooklyn Union’s service territory.

Financial services businesses

Businesses that include investment companies, financial planning, merchant banking, small business investment companies, credit reporting, financial information services, financing of otherwise allowable investments (including venture capital investments) and banking.




Winners And Losers

Will Competition Lower All-In Rates and, If So, by How Much?

The seven utility restructuring plans discussed above in Part II are intended to produce reduced electricity prices for all New York State customers over the long-term and, in most cases, in the short-term as well. The magnitude, timing and source of savings will vary from utility to utility, and among different customer classes. In general, there are three distinct sources of expected savings. The scheduled rate reductions identified in Part II have been agreed to by the respective utility companies and approved by the PSC. These scheduled rate reductions are the most certain to occur. The two other sources of savings, discussed below, may result in further savings for customers.
Additional, competition-stimulated price reductions for consumers which elect to take service from a competitive ESCO are a second source of potential savings. These expected savings result from the commencement of a competitive market in which customers may shop for energy from competing suppliers. The prices charged by companies offering electricity in competition with the regulated utility are expected to be below the regulated utilities’ approved rate schedules as these companies compete on price, as well as on other terms and conditions of service. The dimensions of the savings resulting from this source are hard to project.

A third source of savings may result from the divestiture of certain electric generating assets. Five of the six New York electric utilities which have detailed restructuring plans have announced plans to divest a significant part of their non-nuclear generation capacity. If the results of these asset sales are comparable to the (thus far) limited experience with sales of generating plants in other states, the selling utilities can look forward to receiving a premium over book value from the buyers for their divested assets. Most of the restructuring plans allocate a significant portion of any such premium to the reduction of the companies’ stranded investments and costs. Thus, there is a potential for the level of stranded investments, which the utilities are authorized to recover through the CTC, to be reduced as a result of the utilities’ gains on the divestiture of their generation assets. However, to the extent that gains on divestiture sales are not sufficient to offset stranded costs, the CTC may exert significant upward pressure on electricity prices actually experienced by customers, particularly in the intermediate-to-long term.

How Will the Benefits and Burdens of Competition Be Shared?

Residential customers

The scheduled rate reductions for residential customers specified above in Part II are not as large on a percentage basis as for industrial customers. A potential issue in the restructuring of New York’s electric utility industry is whether the magnitude of these reductions is so low as to make the introduction of the restructured market appear unimportant to residential customers, who are also voters. At this point it is not possible to state with assurance whether the public yet senses that any beneficial change will be made in electric bills.

Commercial and industrial customers

Commercial and industrial customers have generally received larger percentage scheduled rate reductions in the restructuring plans. Moreover, these customers stand to gain more from a competitive energy market, because energy and capacity constitute a far larger portion of their total electric bill. These customers, for whom the cost of electricity is often a critical component of the cost of production, have demonstrated sophistication in electric rate matters and have participated effectively in the restructuring proceedings. Commercial and industrial customers are, of course, of particular concern to the State’s regulators and policy makers as they are both the source of jobs and, relative to residential customers, significantly more mobile. Industrial customers, for example, can relocate their facilities to other states, or other parts of the globe. Nevertheless, the rate reductions contemplated in the utility restructurings discussed in Part II do not necessarily bring New York’s electric rates for these customers down to the national average. Will the price reductions contemplated in the restructurings provide a sufficient stimulus to these customers that they remain in business in New York and, even better, expand their businesses?

Utility, IPP and ESCO investors

While some of the restructuring plans put the utilities “at risk” for a portion of their potentially stranded investments, the amounts at risk do not appear to threaten their financial stability. Indeed, in some respects the plans may leave the utility investors better off. The risk of bankruptcy for Niagara Mohawk, for example, is significantly reduced as a result of the adoption of its restructuring plan, known as PowerChoice.
Looking to the future, it is likely that the nature of the utility business will change as a result of restructuring, with consequences that are not entirely predictable. Two hypothetical examples illustrate this potential change in business orientation. A utility company might choose to remain basically ‘pipes and wires’-oriented, that is, to focus on its transmission and distribution businesses. Such a company will be exposed to fewer marketplace risks, and, under continued rate regulation, may not be allowed to earn rates of return on invested equity capital that are as high in real terms as today’s allowed rates of return. Another company, in pursuit of higher profits, might emphasize more its unregulated business activities and, thus, increase its risk profile, at least as compared to the hypothetical ‘pipes and wires’ company. This diversification strategy recalls the experience of utilities in the 1980s when many companies entered new lines of business divorced from the electric utility business and thus outside of the utilities’ traditional area of expertise. Many of those investments did not fare well.
The threat of the past few years to the enforceability of power purchase agreements (“PPAs”) between IPPs and utilities, upon which IPP investors and lenders have relied, seems to be greatly diminished or eliminated as a result of the restructuring settlements. The decision by the PSC to provide a reasonable opportunity for utilities to recover above market payments made under PPAs, coupled with lower prices for electricity, reduced the pressure on utilities to continue to seek to terminate PPAs prematurely. Thus, there is increased likelihood that IPP investors will recover all or the bulk of their investment. Again focusing on Niagara Mohawk as an example, the resolution of the economic burden of its PPAs was a key issue in the company’s restructuring. After years of efforts to amend or terminate these contracts, Niagara Mohawk entered into the MRA with 16 IPPs with which it had 29 PPAs and thereby reduced Niagara Mohawk’s above-market costs. At the same time, the MRA provided the settling IPPs with assurance of recovery of a reasonable share of the benefits for which the IPPs had contracted in their PPAs.

On the other hand, IPPs will be increasingly exposed to market forces. IPPs that were able to secure long-term, regulatorily-approved PPAs in the old business environment will now have to build new plants and operate existing plants as ‘merchant’ generators. Companies will increasingly have to rely on short-term market performance, in place of firm, long-term contracts.

ESCO managers and their investors may also find the newly competitive market even more difficult, as they encounter increasingly intense competition. Retail marketers must compete in the near term with the incumbent utility as well as other marketers, some of whom operate nationally and in many different fields (e.g., fuels, commodities and wholesale power).

State and local government (tax revenues and tax base)

State and local governments may feel the most immediate financial effects of utility restructuring if increased economic activity attributable to lower electricity prices does not generate sufficient tax revenue to offset lower tax collections associated with lower electricity prices. Local assessments of property used for generation plants have often exceeded those for other industrial property. The owners of competitive generating facilities will likely seek to reduce the assessments, and as the utilities divest their plants, the methods used to make these assessments seem likely to change. On the other hand, to the extent that sales of plants in other states may be at prices in excess of book value, it is possible that some assessments could increase.

State taxes, such as the gross receipts tax imposed on utility receipts, seem likely to decline as well. New York has already enacted phased reductions in the gross receipts tax. This year, at least one proposal is before the Legislature to accelerate the pace of these reductions of gross receipts taxes. Sales tax revenues too may change. Under current law, if transmission and delivery services are purchased as an unbundled service, they are not subject to sales tax. These potential changes in the level of taxes imposed on the retail customer appear likely to be a major contributor to customers’ savings in the near-term.

The Customer Experience under Competition

New products and services

Economists suggest competition not only produces lower consumer prices, but also better and more varied goods and services. Whether residential electric customers will view the restructuring of their utility as providing better and more varied services is a question that cannot be answered at this time, although service innovations are certainly possible in a number of areas, such as unified billing for customers who receive service at multiple locations and ‘one stop shopping,’ in which electricity, gas, telecommunications and internet access are provided by a single supplier. Also, restructuring will provide an instant benefit to customers who highly value freedom of choice.

New technology has already played a significant role in the electric utility industry, as improved combined cycle, gas-fueled power plants have driven down the cost of power from new plants. Larger, more efficient combined cycle plants may prove to be even more cost effective At the same time, some industry analysts foresee a bright future for distributed generation, as more affordable fuel cells and micro turbines become more easily achievable. The siting and transmission issues associated with central station generation, such as plants in the 500-1500 MW range, differ markedly from the issues associated with plants that are one-tenth or one-hundredth the size. Highly efficient, small generators would give customers new self- and co-generation options and reduce the need for high voltage transmission lines.


Reliability is usually considered the unarguable, fundamental requirement for successful operation of the U.S. electrical system. Reliability issues, however, almost always have an economic aspect and the resolution of reliability issues will play an important role in the economics of restructuring the utility industry. Under traditional regulation, the reliability of the transmission system is maintained through the voluntary cooperation of the regulated utilities. As competitive pressures spread, will reliance on voluntary organizations continue to be an effective means of ensuring system integrity? As competition becomes more important, decisions will be made about which body, for example, will establish the standards for, and limits on, system operations. Who will participate in the formulation and refinement of reliability rules? Who will plan and execute the new construction needed to maintain system reliability? Who will provide the capital for new facilities needed for the continued development of the market, but of limited profitability to individual market participants? The answers to these questions have not yet been resolved.

Environmental issues

The advent of retail competition in New York brings both opportunities and risks for the environment. On the positive side, technological improvements in energy generation have already resulted in new, more efficient power plants that produce only a fraction of the emissions of older, less efficient plants. As discussed above, there is a potential for further development of distributed generation using a variety of environmentally compatible technology. Displacement of older plants with newer, cleaner generators will improve air quality and reduce greenhouse emissions. The emphasis on efficiency of operation resulting from competition is likely to lead to environmental benefits. Retail competition also offers customers the opportunity to vote with their pocketbooks and choose ‘green’ electricity sources as opposed to other energy sources which are lower priced, but not as environmentally compatible.

Restructuring of the electric industry, however, may pose a number of potential hazards for the environment. An increased emphasis on short-term price considerations may result in increased generation from coal-burning power plants. Another concern is that competition will disadvantage and undercut energy efficiency as an alternative to electricity generation. Funding for energy conservation and energy efficiency has already been reduced by more than two-thirds from 1992�1994 levels.

Economic and Political Effects at State and Local Levels

A major goal of electric restructuring is to reduce energy prices in order to increase economic activity in the state. Two questions that will require continuing attention over the transition period contemplated in the restructuring plans are whether the level of rate reductions contemplated in New York’s restructuring plans is sufficient to increase economic activity and whether any increase in economic activity can be measured and correlated to the reduction in power costs. Restructuring will also affect tax collections, though, as noted above, increased economic activity may offset reduced tax collections due to lower electricity prices and competitive pricing.

Utility Restructuring Programs

Organizational Restructuring

Six of the seven New York utility companies have announced plans to restructure their companies as a part of the PSC-approved restructuring plans. (LILCO also is expected to restructure its operations as a result of its combination with Brooklyn Union and its transaction with LIPA.) In general, each company is permitted to form a holding company with a subsidiary that continues the regulated transmission and distribution business of the utility (the “T&D Company”) and at least one unregulated affiliate. The restructuring plans of four of the utilities provide for an unregulated affiliate to act as a marketing company. The PSC has allowed these marketing affiliates to sell to retail customers in the service territory of the T&D Company.

The nature and control over the relations between the T&D Company and the holding company’s other affiliates are important aspects of the restructuring plans. As discussed above in Part II, each of the seven plans contains provisions addressing affiliate transactions and competitive conduct standards.

An area of potential disputes will be in the exchange of property between the T&D Company and an affiliate. What valuation should be placed on such property? Is it sufficient to allow transfers of property at its book value, when the market value significantly exceeds the book value? In New York, the PSC has traditionally required (in the sense of imputing the revenue to the regulated company) the transfer to be at the higher of market price or book value.

Complaints arising from such disputes may be lodged with the PSC. While the PSC has considered the potential for such complaints in at least one of the restructuring opinions, how such complaints will be addressed by the PSC remains to be worked out.


Several litigation challenges to the industry restructuring described in this report are pending. In particular, these claims raise the issue of the legal authority of the PSC to undertake the restructuring. The pending claims are identified here.
(a)In Public Utility Law Project v. Public Service Commission, Index No. 4509-96, Decision and Order (Sup. Ct., Albany County Apr. 29, 1997), (petitioners’ claim that residential service provided by gas marketers is subject to the Home Energy Fair Practices Act (“HEFPA”), Article 2 of the Public Service Law was dismissed by Supreme Court) (appeal pending);
(b)In Energy Association of New York v. Public Service Commission, 169 Misc. 2d 924 (Sup. Ct., Albany County 1996), (Supreme Court rejected the utilities’ challenge, inter alia, to the legal authority of the PSC to oversee the restructuring of the electric utility industry). While an appeal is pending, this case, as noted above, is subject to a conditional withdrawal by the utilities;
(c)In Public Utility Law Project v. Public Service Commission, Index No. 5685-97 (Sup. Ct., Albany County, filed Sept. 15, 1997), petitioners challenge the PSC’s ESCO order (Opinion No. 97 � 5) claiming, inter alia, that ESCOs are subject to HEFPA; and
(d)In Public Utility Law Project v. Public Service Commission, Index No. 894-98 (Sup. Ct., Albany County) and Travelers Group, Inc. v. Public Service Commission, Index No. 1155-98 (Sup. Ct., Albany County), petitioners contest the PSC’s order approved the Con Edison restructuring plan.

Merger Activity

The potential for merger activity in the electric utility industry is influenced by a number of factors, several of which discourage mergers or combinations. First, PUHCA requires the parent company of two or more utilities using the holding company form of organization, that are not in adjoining states or otherwise exempted from the Act’s requirements, to register as a holding company. Such registration exposes the utilities to substantial regulatory burdens. Second, the fact that utilities are regulated at both the state and federal level, and thus need regulatory approval of both state and federal authorities to merge, exposes any electric utility merger to extensive regulatory review. Third, it appears from the mergers that have been proposed in other states that regulators may require that all, or at least a significant portion, of any premium paid for the target company be paid by the shareholders, not the rate payers. Thus, a merger may have an adverse impact on earnings of the merged company at least initially.
At the same time, it is reasonable to assume that most utilities are considering the possibility of merger opportunities. The size of a company may be a factor in its success in a competitive market and the emergence of utilities from the regulated world into a competitive world requires that they consider this issue. Larger utilities can adopt different strategies than smaller ones. Larger utilities, for example, can hedge business risks in one geographic market by operating in several markets at the same time. Investments in service operations are very large, and may require a large customer base to be feasible.

In New York, as noted above in Part II, one intra-state combination between contiguous utilities is nearing a closing, namely the merger of Brooklyn Union and LILCO. On May 11, 1998, Con Edison announced an agreement under which, subject to regulatory and O&R shareholder approvals, Con Edison’s parent company will acquire for cash all of O&R’s common stock. In addition, in 1997, a tender offer was made by CalEnergy Company, Inc. for 9.9 per cent of the common shares of a second utility, NYSEG. CalEnergy also proposed to NYSEG to negotiate an acquisition of all of NYSEG’s shares. This offer and proposal were eventually withdrawn by CalEnergy.


In the 1980’s, electric utilities across the United States undertook active diversification programs. These companies invested in businesses related to the utility business and, in some cases, in businesses with no connection to the utility industry. While some of these ventures were successful, many of the investments in unrelated businesses were not successful. In a few cases, these unrelated investments were spectacularly unsuccessful. New York utilities generally avoided the most egregious of the diversification pitfalls that many other U.S. utilities experienced. As New York utilities face the competitive market, a major strategic question for each company will be whether to diversify their operations.

Generation Divestiture

As noted above, five of the utility companies in New York have committed to divestiture of all or a significant portion of their fossil-fueled (and, in some cases, hydro) generation. While the buyers may be large utilities or their affiliates with operations within or without New York, it is also possible that “non-utility” companies will buy some of these plants.

A significant issue is who will benefit from any premium over book value the utilities may receive for their divested assets. The most well known cases to date, outside New York, of divestiture of assets by utilities as a part of industry restructuring involve payment by buyers of premiums over book value. While these may merely be examples of the benefits of being the ‘first mover,’ this experience is influencing New York regulators and utility executives to expect that premiums will be paid. As discussed above in Part II, any such premium will be shared between the shareholders and customers.

Finally, another important issue is how utilities receiving significant cash proceeds through divestiture auctions will use these funds. Utilities electing to pursue a “wires-only” model are likely to have cash substantially in excess of the needs of their transmission and distribution operations. This “surplus” cash may drive utilities in one (or more) of three directions: diversification; acquisition of another utility; or a common stock buy-back. One New York utility, Con Edison, has announced both an acquisition and a common stock buy-back.

Transmission System Issues

The Independent System Operator

The ISO, when approved by FERC, will replace the transmission-related operational responsibility of the seven New York electric utilities, NYPA and the New York Power Pool. Although ownership of transmission facilities will be unchanged, the ISO will be responsible for the operation of the transmission grid in a safe and reliable manner and for the administration of a statewide transmission tariff. The ISO will also be responsible for generation dispatch based, in part, on input from one or more power exchanges. The ISO will conduct an auction, or settlement, twice for each hour’s production (a “two settlement” approach): first, there is a “day ahead” market with firm commitments made, and, second, there will be a “real time” market. Other power exchanges can also be established to schedule transactions for market participants and have the information delivered to the ISO.

A decision by FERC on the ISO proposal is expected by mid-1998.

Transmission System Planning

Transmission system planning is also proposed to be performed by the ISO, as a result of an amendment to the ISO proposal filed by the New York utilities in December, 1997. ISO transmission planning is intended to relieve congestion “bottleneck problems.”

What is not resolved, however, is the means of payment for transmission system upgrades. In the competitive market, it is less clear who benefits and who is responsible for upgrades in transmission capacity. This issue is before FERC in its review of the December 1997 filing.


Securitization is a financing device which may reduce the costs of the transition to a competitive electric market. Securitization legislation proposed in New York would enable the PSC to issue irrevocable and assignable rate orders authorizing the collection of a non-bypassable charge designed to recover stranded costs resulting from the transition to competition. These orders would be pledged to a financing entity as collateral for, and in exchange for the proceeds of, bonds issued by the entity to refinance, at a lower cost, the utility securities originally issued to carry the stranded costs. The necessary legislation has been introduced, but as of May 1998, it had not been enacted. Similar legislation is in effect in other states, and utilities have “securitized” portions of their stranded costs and regulatory assets.

Statement of Financial Accounting Standards No. 71

Only regulated enterprises whose operations meet the criteria of Statement of Financial Accounting Standards No. 71 (“SFAS No. 71”), “Accounting for the Effects of Certain Types of Regulation,” may account for their operations in accordance with SFAS No. 71, which in certain instances provides for accounting treatment for regulated enterprises that differs significantly from that applied to non-regulated enterprises. Under an accounting standard applicable to restructuring utilities, SFAS No. 101, a utility that is no longer regulated, and thus no longer has assurance of recovering its costs, is treated like other non-regulated companies. In particular, assets for which there is no assurance of recovery of capital must be written-off without deferral. If only some of an enterprise’s operations are regulated and meet the criteria of SFAS No. 71, that standard is applied only to the regulated portion of the enterprise’s operations.

Will the switch from accounting under SFAS No. 71 make a difference? In the case of Con Edison, the company announced in its 1997 Third Quarter financial statements that the application of SFAS No. 101 had no material adverse effect on Con Edison’s financial position or results of operations. The note to Con Edison’s financial statements explains that the estimated cash flows from the operation and/or sale of the fossil generating assets together with the cash flows from the strandable cost recovery provisions of the Con Edison Settlement Agreement will not be less than the net carrying costs of its assets; that recovery of the approximately $275 million of net regulatory assets attributable to the deregulated portion of the business is probable under the Con Edison Settlement Agreement; and that Con Edison has not accrued a loss for its IPP contracts because it is not probable that the charges by the IPPs will exceed the sum of the cash flows from the sale of the electricity provided by the IPPs and the cash flows provided pursuant to the Con Edison Settlement Agreement.


This Report summarizes the historic restructuring of the electric utility industry in New York, including developments in May 1998. Restructuring is not complete, however, and developments continue and will continue for a number of years.

This utility industry restructuring undertaking by the PSC is one of the most far-reaching regulatory undertakings in New York State history. The stakes of the restructuring are enormous, given the size of the investment of society in electric facility infrastructure, the pervasiveness of electricity in every day life, and the role of electricity prices in the economy. This restructuring effort thus merits the continuing attention of all who would understand and participate in New York’s future.


Charles M. Pratt, Chair*
Eric J. Schmaler, Secretary*
Joel I. Berson
F. Peter O’Hara*
Joseph J. Carline
Harold B. Obstfeld
Jonathan Hand Churchill
Jeffrey L. Riback
Terrence L. Dugan
Andrew Schifrin
Travis Epes*
Larry Shapiro
Ira Lee Freilicher
Gopal Swaminathan
Brenda L. Gill
Courtney-Anne Smith
Robert Glasser
Richard A. Visconti
Robert Grassi
Gary M. Wolf
Noel E. Hanf
David Wooley
Katherine Kennedy