EXHIBIT NO. 99-4
STATE OF NEW YORK
PUBLIC SERVICE COMMISSION
OPINION NO. 98-6
CASE 96-E-0891 - In the Matter of New York State Electric
& Gas Corporation's Plans for Electric
Rate/Restructuring Pursuant to Opinion
No. 96-12.
CASE 93-E-0960 - Proceeding on Motion of the Commission
as to the Rates, Charges, Rules and
Regulations of New York State Electric
and Gas Corporation - Tariff Filing
Governing the Sale of Economic
Development Power Generated by the New
York State Power Authority to Specific
Customers Recommended by the Allocation
Board.
CASES 94-M-0349 et al. - New York State Electric & Gas
Corporation - Electric Rates.
OPINION AND ORDER ADOPTING TERMS OF SETTLEMENT
SUBJECT TO MODIFICATIONS AND CONDITIONS
Issued and Effective: March 5, 1998
TABLE OF CONTENTS
Page
INTRODUCTION 1
PROCEDURAL HISTORY 2
The Restructuring Proceeding (Case 96-E-0891) 2
The EDP Proceeding (Case 93-E-0960) 5
The 1995 Rate Settlement (Cases 94-M-0349 et al.) 7
The Proposed Settlement 8
Recommended Decision and Exceptions 9
SETTLEMENT SUMMARY 10
Rate Plan 11
Recovery and Mitigation of Strandable Costs 13
Retail Access and Unbundled Tariffs 15
Corporate Structure 16
Public Policy Programs 16
Market Power 17
STANDARD TO TEST A PROPOSED SETTLEMENT 17
DISCUSSION 18
Rate Plan 19
1. Amount and Allocation of Rate Benefits 19
2. Return on Equity 22
3. Rate Design 23
a. Customer/Energy Charges 23
b. Back-Out Credit 24
Recovery and Mitigation of Strandable Costs 26
Retail Access and Unbundled Tariffs 27
Corporate Structure 28
TABLE OF CONTENTS
Page
Public Policy Programs 30
EDP Delivery Rates 32
Environmental Issues 34
Other Issues 36
1. Customer Service Incentive Program 36
2. Reciprocity 36
3. Cooperation 37
4. Statutory Authority 37
5. NYPA Hydropower 37
STATE ENVIRONMENTAL QUALITY REVIEW ACT (SEQRA) 38
CONCLUSION 40
ORDER 41
APPENDIX A - APPEARANCES
APPENDIX B - LIST OF ABBREVIATIONS
APPENDIX C - ENVIRONMENTAL ASSESSMENT FORM
STATE OF NEW YORK
PUBLIC SERVICE COMMISSION
COMMISSIONERS:
John F. O'Mara, Chairman
Maureen O. Helmer
Thomas J. Dunleavy
CASE 96-E-0891 - In the Matter of New York State Electric
& Gas Corporation's Plans for Electric
Rate/Restructuring Pursuant to Opinion
No. 96-12.
CASE 93-E-0960 - Proceeding on Motion of the Commission
as to the Rates, Charges, Rules and
Regulations of New York State Electric
and Gas Corporation - Tariff Filing
Governing the Sale of Economic
Development Power Generated by the New
York State Power Authority to Specific
Customers Recommended by the Allocation
Board.
CASES 94-M-0349 et al. - New York State Electric & Gas
Corporation - Electric Rates.1
OPINION AND ORDER ADOPTING TERMS OF SETTLEMENT
SUBJECT TO MODIFICATIONS AND CONDITIONS
(Issued and Effective March 5, 1998)
BY THE COMMISSION:
INTRODUCTION
This proceeding was established to investigate issues
related to competitive opportunities for electric service2 for
New York State Electric & Gas Corporation (NYSEG or the
company).3 After we encouraged the interested parties to seek a
____________________
1 The proceeding includes the captioned cases and cases
93-E-0284, 93-E-0664, 95-M-0017, 95-E-0425, and 95-E-0426.
See Opinion No. 95-17 (issued September 27, 1995).
2 A list of parties' appearances is attached as Exhibit A.
3 A list of abbreviations used in this document is attached as
Appendix B.
negotiated resolution of the issues raised, a Settlement1 was
filed on October 9, 1997, by NYSEG on behalf of five parties.
In the most general terms, the Settlement, in
accomplishing a major restructuring of NYSEG, provides for
substantial rate benefits for all customers, calls for prompt
divestiture of all NYSEG's fossil generation plants, allows for
competition to develop in the energy services sector, provides
all customers access to the competitive electricity market in
less than 18 months, and fairly addresses public policy and
environmental concerns. This Settlement will enable a robust,
competitive electric market to develop, resulting in widespread
consumer choice. Most importantly, due to the implementation of
the Settlement and the rapid opening of the competitive market,
NYSEG consumers will receive lower average electric bills.
We recently issued an order adopting the terms of the
Settlement subject to certain modifications and conditions.2 The
findings and decision made in that previous order are hereby
incorporated, and this opinion describes the bases for our
decision.
PROCEDURAL HISTORY
The Restructuring Proceeding (Case 96-E-0891)
Opinion No. 96-123 required NYSEG, among other
utilities, to file a proposed plan for rate/restructuring, no
____________________
1 The Settlement, dated October 9,1997, is summarized infra,
and was attached as Appendix A to the Order Adopting Terms of
Settlement Subject to Modifications and Conditions (issued
January 27, 1998). It is referred to in this opinion as "the
Settlement." See Procedural History, infra.
2 Cases 96-E-0891 et al., Order Adopting Terms of Settlement
Subject to Modifications and Conditions (issued January 27,
1998) (January 27 Order). NYSEG unconditionally accepted the
modifications and conditions in a letter dated February 4,
1998.
3 Cases 94-E-0952 et al., In the Matter of Competitive
Opportunities Regarding Electric Service, Opinion No. 96-12
(issued May 20, 1996).
later than October 1, 1996. The utilities were asked to address
the following matters in the filings: (1) the utility's
structure for both the short and long term; (2) a schedule for
retail access and a set of unbundled tariffs; (3) a rate plan
including mechanisms to reduce rates and address strandable
costs; (4) identification of public policy programs needing
special rate treatment and mechanisms to recover associated
costs; (5) examination of load pockets and proposals to mitigate
market power; and (6) a plan for the provision of energy
services.1
NYSEG's filing was submitted on September 27, 1996, and
shortly thereafter procedures and a schedule were established for
addressing the filing.2 We stated our "strong interest in
expeditiously negotiated resolutions of the individual utility
filings" and expressed our preference for a negotiated resolution
over a litigated outcome.3 To further that goal, the
notification procedures and other parts of the settlement
guidelines were waived.4
We also found it desirable to allow an opportunity for
interested parties and the public to participate. Accordingly, a
90-day period was established for discovery on and analysis of
the filings, and for settlement negotiations; and a subsequent
60-day period was allowed for closing the record if a settlement
____________________
1 These matters were the minimum the Commission asked utilities
to include in their filings. The actual list includes
somewhat more detail about what the filings were expected to
include (ibid., pp. 75-76).
2 Cases 94-E-0952 (et al., supra, Order Establishing Procedures
and Schedule (issued October 9, 1996); approved and confirmed
by the full Commission by Confirming Order (issued October 24,
1996).
3 Cases 94-E-0952 et al., supra, Order Establishing Procedures
and Schedule, p. 3.
4 Id., citing Cases 90-M-0225 et al., Settlement Procedures,
Opinion No. 92-2 (issued March 24, 1992), mimeo, Appendix B.
by major parties was reached.1 The 90-day period was
subsequently extended by a series of notices issued by the
Secretary at the Chairman's direction.2 Ultimately, March 25,
1997 was set as the date for a settlement or testimony to be
filed.3
In accordance with this schedule and in the absence of
a settlement, the following parties filed testimony on March 25,
1997 responding to NYSEG's September 27, 1996 submittal:
American Association of Retired Persons (AARP), New York State
Consumer Protection Board (CPB), New York State Department of
Economic Development (DED), Enerscope,4 Independent Power
Producers of New York, Inc. and Enron Capital & Trade Resources
____________________
1 Cases 94-E-0952 et al., supra, Order Establishing Procedures
and Schedule, pp. 3-4. During the first 90-day period, the
progress of the NYSEG proceeding was monitored through
procedural conferences held in Albany on November 18, 1996,
and December 20, 1996.
Also, during the first 90-day period, public input was sought
through educational forums and public statement hearings held
in Elmira, Binghamton, and Plattsburgh. Twenty-one speakers,
including Binghamton Mayor Richard Bucci, placed comments on
the record at the public statement hearings. The speakers
generally argued that: NYSEG's rates were too high; NYSEG
should not recover all its stranded costs; management errors
should be the responsibility of stockholders; and, competition
is likely to harm the environment and leave the small consumer
with few benefits. Mayor Bucci noted that, based on his
conversations, uncompetitively high utility rates are ". . .
one of the highest barriers to job creation and job growth."
(Transcript page (Tr.) 86.)
2 Cases 94-E-0952 et al., Notice to the Parties (issued
December 19, 1996); Cases 96-E-0909 et al., Notice to the
Parties (issued January 9, 1997); Cases 96-E-0909 et al.,
Notice to the Parties (issued February 13, 1997);
Case 96-E-0891 et al., Notice to the Parties (issued
February 27, 1997).
3 Cases 96-E-0909 et al., Notice to the Parties (issued
March 11, 1997), pp. 2-4.
4 The Enerscope and RE3SCO testimonies were not admitted because
neither party appeared at the hearings and no alternate
arrangements were made.
(collectively IPPNY/Enron), Multiple Intervenors (MI), New York
Power Authority (NYPA), Public Interest Intervenors (PII), Retail
Council of New York (Retail Council), RE3SCO Restructuring
Coalition (RE3SCO), Staff of the Department of Public Service
(Staff), and Wheeled Electric Power Company (WEPCO). NYSEG also
submitted direct testimony on March 25, 1997 that updated and, in
some respects, revised its September 27, 1996 filing. Included
in its March filing was a "Proposed Definitive Settlement
Agreement" offering a settlement-based resolution of the issues.1
By letter dated April 10, 1997, the company explained that its
Proposed Definitive Settlement Agreement superseded inconsistent
portions of its March 25 testimony.
At a Procedural Conference on April 16, 1997, a final
schedule of submissions was established. In accordance with that
schedule, NYSEG filed testimony supporting its newest proposal on
April 21, and rebuttal testimony was filed on May 6, 1997 by
Staff, CPB, IPPNY/Enron, MI, and NYPA.
Hearings were held from May 15 through May 22,
generating 3,718 pages of transcript and 204 exhibits. Initial
briefs were filed on June 13, 1997 by NYSEG, Staff, IPPNY/Enron,
MI, the Public Utility Law Project (PULP), DED, PII, Retail
Council, CPB, AARP, NYPA, and WEPCO.2 On June 23, 1997, reply
briefs were filed by Staff, NYSEG, PULP, CPB, WEPCO, DED, NYPA,
MI, IPPNY/Enron, PII, and the Retail Council.
The EDP Proceeding (Case 93-E-0960)
The rates for NYSEG's delivery of NYPA power to
Economic Development Power (EDP) customers were established in a
____________________
1 This document (Exhibit 117) is an offer of settlement. It was
not accepted by any party other than NYSEG.
2 On June 16, 1997, the New York Citizens Utility Board (CUB)
filed an initial brief. Staff moved to strike the brief as
untimely filed and prejudicial (Staff's Reply Brief, p. 1).
Staff's motion was granted by Administrative Law Judge
Stockholm (R.D., p. 4).
settlement agreement dated August 15, 1994.1 Under the
settlement and prior to July 31, 1996, NYSEG was to submit a
successor tariff establishing the terms and conditions for
continuing the EDP service. However, by letter dated July 31,
1996, NYSEG notified the signatories to the 1994 settlement that
it was not proposing any changes to the effective tariff at that
time.
On August 12, 1996, MI filed a petition and motion
requesting that NYSEG be required to file just and reasonable
tariff rates for the delivery of NYPA EDP. MI also asked that
the current tariff for EDP be made temporary and subject to
refund as of August 1, 1996. We granted MI's requested relief to
the extent that the parties were directed to meet with the
assistance of a Settlement Judge to negotiate a resolution of
future EDP rates.2 Despite the efforts of the parties, a
mutually acceptable negotiated resolution could not be found at
that time.
At a procedural conference on December 6, 1996,
however, an interim settlement was reached lowering EDP rates on
a temporary basis retroactive to December 1, 1996. The agreement
among the parties was summarized in a Memorandum of Understanding
(MOU) and corresponding tariffs3 were adopted, effective
February 12, 1997. The parties were subsequently notified that
the EDP rate issues in Case 93-E-0960 would be finally resolved
in conjunction with the issues in the restructuring proceeding.4
____________________
1 The settlement was approved by the Commission in
Case 93-E-0960, Order Approving Agreement and Requiring
Refunds (issued October 31, 1994).
2 Case 93-E-0960, Order Reconvening Proceeding (issued
September 20, 1996).
3 Under the tariffs, EDP customers would be charged $3.12 per kW
per month for service taken from NYSEG at 34.5 kV and above
and $8.53 per kW per month for service taken from NYSEG below
34.5 kV.
4 Case 93-E-0960, Procedural Ruling (issued March 20, 1997).
Testimony directly related to the EDP rate issue was filed by MI,
NYPA, DED, and NYSEG.
1995 Rate Settlement (Cases 94-M-0349 et al.)
In Opinion No. 95-17, a three-year settlement agreement
was approved which replaced the third year of a previous
settlement agreement.1 The 1995 rate settlement included rate
increases for years 2 and 3 of 2.8% and 2.7% respectively, which
were to have been effective on August 1, 1996 and August 1, 1997.
On January 31, 1996, NYSEG filed its proposed revenue
allocation and rate design for the second and third year rate
increases and subsequently submitted draft tariffs on July 18,
1996 for year two. On August 26, 1996, the tariffs were
suspended through December 30, 1996, and NYSEG petitioned for
rehearing. On December 18, 1996, the suspension period was
further extended through June 30, 1997.
On January 16, 1997, the Order Denying Petition for
Rehearing and Requiring Further Proceedings was issued in Case
No. 94-M-0349. In the order, NYSEG's petition for rehearing was
denied and it was determined that whether NYSEG should receive
the rate increases provided under the 1995 rate settlement would
be reviewed in the rate/restructuring proceeding.
By petition dated December 20, 1996, NYSEG sought a
judgment pursuant to Article 78 of the Civil Practice Law and
Rules, seeking inter alia, to allow the approved revenue increase
for year two to be implemented. In a letter dated May 29, 1997,
the company agreed to an extension of the suspension period
applicable to the increases for years two and three pending the
outcome of the rate/restructuring case.
In a letter dated June 2, 1997, NYSEG requested that
Justice Keegan (before whom the Article 78 petition was argued)
retain jurisdiction of the proceeding, but withhold a decision
____________________
1 Cases 94-M-0349 et al., Opinion No. 95-17 (issued September
27, 1995), rehearing denied Cases 94-M-0349 et al., Opinion
No. 96-5 (issued February 6, 1996).
until such time as the Commission either rejected the terms of
NYSEG's proposal for the extension of the suspension period or
failed to issue a final decision by October 1997. In a variety
of further orders, and finally in accordance with our January 27
Order, the suspension periods were extended through February 4,
1998.
The Proposed Settlement
Throughout the litigation phase of the cases NYSEG and
Staff continued their negotiations. On July 30, 1997, and before
a recommended decision was issued, the company filed a Joint
Statement of Principles executed July 28, 1997, by Staff and the
company, purporting to resolve the cases by agreement.
Negotiations with all parties began on August 5, 1997, and on
August 20 a draft agreement was circulated.
On October 9, 1997, NYSEG submitted an "Agreement
Concerning the Competitive Rate and Restructuring Plan of New
York State Electric & Gas Corporation"1 which purports to resolve
by agreement all issues in the above cases. The Settlement was
signed by Staff, NYSEG, DED, NYPA, the National Association of
Energy Services Companies (NAESCO), and the Joint Supporters.2
At the procedural conference on October 14, 1997, a
schedule was established for submitting statements or testimony
supporting or opposing the proffered Settlement. On October 23,
1997, statements supporting the Settlement were filed by all
signatories. On November 1, statements in opposition were filed
by MI, WEPCO, the New York Department of Law (DOL), PULP, the
____________________
1 The Settlement, entered in the record as Exhibit S-1, was
attached as Appendix A to the January 27 Order.
2 At the public statement hearings on November 4, 1997, System
Council U-7 of the International Brotherhood of Electrical
Workers indicated its support of the Settlement (Tr. 3764-66)
in light of the agreement reached with NYSEG as contained in
Exhibit 207. The Joint Supporters is a voluntary,
unincorporated association comprising ". . . consumers and
providers in favor of competitive opportunities for electric
service" (Joint Supporters' Statement of Support, p. 1).
Retail Council, CPB, IPPNY/Enron, and Tioga/Tompkins Counties
(the Counties).1 In addition, MI and PII filed testimony in
opposition to the settlement on November 1.
Legislative/evidentiary hearings were held on
November 7 and 10 at which witnesses prefiling testimony were
cross-examined, and the parties filing comments were questioned
from the bench. Additional public statement hearings and
educational forums were held on the proposed Settlement in
Lockport (October 30), Plattsburgh (November 3), Johnson City
(November 4 and 17), Auburn (November 13) and Hudson
(November 18) at which a total of 24 people spoke. The most
frequent concerns raised by the speakers included the disparity
between large and small customer rate reductions with the latter
occurring only in year five; the uncertain nature of the rate
reductions due to cost recoupment exceptions within the
Settlement; the absence of specified low-income and demand side
management (DSM) programs; and, an overall lack of balance in the
Settlement allegedly favoring stockholders over ratepayers,
industrial users over residential, and large
industrial/commercial users over small industrial/commercial
users.
The record concerning the proposed settlement includes
transcript pages 3,719-4,310 and 18 exhibits, including those
identified as S-1 through S-15, consisting of the Settlement and
the parties' comments, as well as exhibits 205-207 sponsored by
individual witnesses.
Recommended Decision and Exceptions
On December 3, 1997, Administrative Law Judge Stockholm
issued a recommended decision in which he concluded that the
Settlement contained the necessary framework and many of the
provisions of an acceptable plan, but it should nevertheless be
____________________
1 In correspondence addressed to Secretary Crary dated
November 9 and faxed on November 14, the Western New York
Sustainable Energy Association submitted comments opposing the
settlement.
returned to the parties for further negotiations on a number of
issues. Among other concerns, the Judge concluded that: the
Settlement benefits were not equitably shared by small commercial
and industrial customers; there was a significant possibility
that NYSEG would overearn during the plan; the back-out
generation credit specified in the Settlement could, under some
circumstances, dampen or destroy the competitive market; and, a
low-income program must be maintained by NYSEG during the
transition to competition as a matter of its provider of last
resort (POLR) obligations.
Briefs on exceptions were filed on December 22, 1997 by
Staff, the company, MI, IPPNY/Enron, PULP, PII, the Counties,
CPB, Joint Supporters, NAESCO, and WEPCO.1 Replies to exceptions
were filed on December 17, 1997 by Staff, the company, MI, DED,
IPPNY/Enron, and CPB.
SETTLEMENT SUMMARY
In accordance with our directions, the Settlement
contains a five-year rate plan, provisions concerning the
recovery and mitigation of strandable costs, a phased schedule
for providing retail access and unbundled tariffs, a proposed
holding company corporate structure, a funding source for public
policy programs, reduced delivery rates for EDP power, the
withdrawal of various Article 78 proceedings challenging our
orders,2 and a number of other terms. These terms are briefly
summarized below.3
____________________
1 DOL filed a letter supporting the remand recommendation.
2 The company has agreed to withdraw its court challenges
regarding the company's previously approved rate increases,
the Energy Association challenge to Opinion No. 96-12, and the
company's challenge to the mandated Dairylea retail access
program ordered in Case 96-E-0948 (Settlement, pp. 5, 6, 35).
3 This summary is provided for the reader's convenience. It
does not necessarily describe each provision of the Settlement
and, in all instances, the Settlement's wording and the
modifications and conditions in the January 27 Order govern.
Rate Plan
Subject to the exceptions noted below, the Settlement
provides for a five-year freeze of all rates, rate reductions of
5% in each of the five years for large customers, and a 5% rate
decrease by year five for all other customers. These rate levels
reflect concessions by the utility (including Gross Receipt Tax
(GRT) reductions) totaling $725 million, of which approximately
$104 million are rate reductions for large users, with the
balance ($621 million) allocated to residential and small
commercial and industrial customers. Of the $725 million total,
approximately $522 million is attributable to the accumulated
forgone revenues associated with the previously approved year two
and year three rate increases.1
Large commercial and industrial customers, who will
receive 5% annual rate decreases, are defined under the
Settlement as all industrial customers with average on-peak
demands of at least 500 kW and all demand-metered customers that
have average load factors of at least 68%.2 In addition,
existing EDP customers will receive 35-56% reductions in
transmission and distribution rates from those in effect prior to
December 1996.3 The Settlement also provides for business
retention, revitalization, and economic development rates, and
includes significant changes to the currently effective Economic
Development Zone Incentive Rates, Economic Revitalization
Incentive Rates, and Service Classification (SC) 13 and 14
____________________
1 Cases 94-M-0349 et al., Opinion No. 95-17 (issued
September 27, 1995).
2 Settlement, p. 10.
3 For example, prior to December 1996, transmission level
customers were paying $6.51/kW/month. As of the December 1996
temporary rate agreement, this amount was lowered to
$3.12/kW/month and under the Settlement it is lowered further
to $2.96/kW/month. In addition, refunds will be issued for
the August to December 1996 period.
rates.1 The quantified benefits of these new tariffs and
programs are not included in the $725 million and $104 million
figures discussed above.
The Settlement sets an earnings cap target of 12% and
provides that any earnings above that level are to be returned to
consumers as directed by the Commission. In calculating the
return on equity (ROE) for this purpose, the common equity
balance will not reflect any writeoff or writedown of assets, or
the repurchase of common stock. Subject to other provisions in
the Settlement,2 this term allows the company to include within
its ROE cap calculation the cost of accelerating the amortization
or depreciation of its assets. The Settlement also provides
that, should the company's ROE fall below 9.0%, the company may
petition for rate relief.
Regarding rate design issues, the Settlement expresses
the general objective of moving basic service and energy charges
toward marginal costs, while avoiding undue rate shock for any
customer. During the first two years of the plan, rate design
for customers not receiving annual rate decreases will not be
changed. The future rate design for these customers will be
specifically addressed in a filing required no later than
February 1, 1999.
Other provisions of the Settlement might allow the
utility to recover two different types of uncontrollable costs.
The first category involves non-recurring events such as force
majeure, but, to be recoverable, these costs3 must exceed 3% of
the regulatory subsidiary's (RegSub's) net electric income. The
second category of costs that may be recoverable involve mandated
____________________
1 SC 13 and 14 are NYSEG's tariffs for individually negotiated
contracts for business retention and expansion, respectively.
2 For example, in the event the company petitions for recovery
of uncontrollable costs, any recovery may be offset by the
amount of accelerated depreciation or amortization taken by
the company, which, if not taken, would cause the ROE to
exceed 12%.
3 Settlement, Appendix C, p. 1.
accounting, legislative, regulatory, or tax law changes and
variations in certain costs from the levels specified in the
Settlement.1
Recovery and Mitigation of Strandable Costs
NYSEG will initially transfer its coal-fired generating
plants and associated assets and liabilities to a generating
subsidiary (GenSub - see corporate structure discussion infra).
These assets will then be subject to an auction which is to close
no later than August 1, 1999.2 The Settlement permits NYSEG's
GenSub to participate as a bidder in the auction.
The purpose of the auction is to obtain the highest
possible market value for the company's coal generating assets
and to quantify any stranded costs associated with them. If the
result of the auction generates a net amount less than the
company's investment in the plants, the shortfall will be
quantified, booked as a regulatory asset, and recovered through a
competitive transition charge (CTC) over a period to be
determined by the Commission, but not to exceed the weighted-
average remaining life of the auctioned assets. In the event the
auction produces a net amount in excess of the company's
investment, the excess will be used to write-down the company's
stranded investment in the Nine Mile Point II nuclear generating
unit (NMII). Any remaining amounts will be used as directed by
the Commission.
The recovery of all costs, including the strandable
costs of the company's remaining generation assets (i.e., non-
____________________
1 Net increases in the total forecasted levels of nuclear
decommissioning costs, site remediation costs, System Benefits
Charge (SBC) program costs, and NYPA transition costs are
fully recoverable, subject to the accelerated depreciation or
amortization limitation noted above (Settlement, Appendix C,
p. 2).
2 The terms, conditions, and protocols to implement the auction
will be developed between the company and Staff and will be
submitted to the other parties for comments before being filed
for approval.
utility generators (NUGs), NMII, and hydroelectric assets) are
presumed to be recovered through existing rates during the five-
year period of the rate agreement. Following the end of the
five-year period, all remaining RegSub regulatory assets (except
those recovered through the CTC) as well as its hydropower, NUG,
and nuclear fixed costs would be recovered through a non-
bypassable wires charge.
The company has also agreed to propose to its NMII co-
tenants that the nuclear plant be subject to an auction and to
vote in favor of such an auction should the issue come to a vote
among the co-tenants. In the event the auction proceeds are less
than the company's investment in the plant, a regulatory asset
similar to that created for the coal plant assets would be
created, and those stranded costs would be recovered over a
period not to exceed 15 years. Should such an auction occur
during the five year rate plan, the Settlement provides a rate
adjustment to capture any net savings in nuclear operation,
maintenance, fuel, and tax costs realized as a result of the
sale.
Finally, the Settlement provides NYSEG an incentive of
20% of the savings from the renegotiation and/or termination of
above market NUG contracts. The remaining 80% of NUG contract
cost savings will be flowed through to customers, subject to
first reimbursing the company for: (1) any lost revenues
resulting from the implementation of the new EDP rates; (2) any
short-fall in revenues attributable to the new business retention
incentive; and, (3) any claimed uncontrollable costs. According
to the Settlement proponents, the generation auction and the NUG
contract renegotiation incentive fulfill the Commission's
objective of mitigating costs.1
____________________
1 See Cases 96-E-0897 et al., Consolidated Edison - Electric
Rate/Restructuring, Opinion No. 97-16 (issued November 3,
1997), mimeo p. 40.
Retail Access and Unbundled Tariffs
The Settlement introduces direct retail access for
eligible electric customers1 in three stages. NYSEG has
implemented a pilot program for approximately 12,000 farmers and
250 food processors that will permit those customers to purchase
electricity from other suppliers; this is stage one. On
August 1, 1998, in the second phase of retail access, customers
in the City of Norwich and in NYSEG's Lockport Division
(approximately 22,000 customers) will be provided retail access.
The final stage for the introduction of retail access begins on
August 1, 1999, and covers all remaining eligible customers.
This deadline may be extended either if the company experiences
unacceptable balancing/settlement difficulties, or if the State's
independent system operator (ISO) is not yet functioning.
Prior to the auction of the company's fossil assets,
customers choosing retail access will be provided a generation
credit equal to the market price of electricity plus 4 mills for
customers eligible for the 5% annual rate reductions, and market
price plus one cent for most other customers, subject to a
maximum credit of 3.0 cents per kWh. For the period following
the company's auction of its fossil units, ratepayers choosing
alternative suppliers will be provided a credit of:
(1) 3.23 cents per kWh through July 31, 2000; (2) 3.47 cents per
kWh from August 1, 2000 through July 31, 2001; and (3) 3.71 cents
per kWh from August 1, 2001 through the end of the rate
settlement. In each case, the credits will be net of any CTC
produced as a result of the fossil auction.2 At the end of the
rate plan, all costs related to the auctioned fossil assets
(except the CTC) will be removed from rates.
____________________
1 Separate provisions apply for customers receiving service
under negotiated or incentive rates.
2 The precise calculation of this net generation credit is left
in the Settlement for future determination. The company will
submit its calculation proposal no later than February 1,
1999.
The Settlement identifies the manner in which the
company intends to unbundle its electric rates and the schedule
for doing so. In the second year of the plan, energy and demand
rate elements will be unbundled, showing transmission rates
separately from delivery and power supply rates. In year three
of the plan, delivery and power supply rates will be further
unbundled into power supply, CTC, transmission, distribution, and
customer service categories. Customer service costs, unbundled
on a marginal cost basis,1 will be quantified in accordance with
a study to be filed no later than February 1, 1999, and will
become effective on August 1, 1999.
Corporate Structure
The company proposes to create a holding company
(HoldCo), regulated subsidiary (RegSub), and a generating
subsidiary (GenSub) as soon as possible. RegSub will continue to
be a regulated entity, and, during the rate period of the
Settlement, will continue to be the POLR for ratepayers. GenSub
could end up owning generating assets.
The Settlement also provides a number of terms and
conditions dealing with the relationships among and between
HoldCo and its subsidiaries. The purpose of the standards of
conduct and other affiliate transaction limitations2 is to
preclude anti-competitive actions, including the subsidization of
competitive endeavors by the regulated, monopoly operations.
Public Policy Programs
We expected the utilities to make proposals, including
sources of funding, for various public policy programs that might
not otherwise be sufficiently supported during the transition to
a competitive market. In particular, continued funding was
sought for research and development (R&D), DSM (both generally
____________________
1 All other services will be unbundled on an embedded cost
basis.
2 Settlement, pp. 29-34.
and low-income), and other programs. The Settlement provides
funding of approximately $13 million per year for the first three
years of the rate plan to address such programs (approximately
1.0 mill per kWh), but no specific recommendations are contained
in the Settlement regarding the use of such funds, and the
Settlement is silent regarding both funding and programs for
years four and five. Regarding DSM, the Settlement further
provides that the company need not obtain approval for its 1997
DSM plan, and its petition for approval of that plan would be
withdrawn.
The company's current Fresh Start program, which covers
2,500 low-income customers, is set to expire in 1998. The
company indicates that it has not determined whether the Fresh
Start program would be continued. If this program is not
continued, NYSEG would provide no program to assist low-income
customers.
Market Power
Vertical market power concerns are satisfied, according
to the settling parties, by the company's agreement to auction
its fossil units and to urge the co-owners of NMII to auction the
nuclear unit. Horizontal market power concerns are addressed
through the standards of conduct prohibiting anti-competitive
activities between and among HoldCo and its subsidiaries. Load
pocket concerns are not directly addressed in the Settlement, but
it is assumed that these concerns will be addressed by the
control requirements of the ISO, once it is established, and the
auction process.
STANDARD TO TEST A PROPOSED SETTLEMENT
Our Settlement Guidelines establish the following
standards for assessing a proposed settlement in light of our
obligation to set just and reasonable rates and a utility's
burden, under the Public Service Law (PSL), of showing the
reasonableness of a rate change it is proposing:
a. A desirable settlement should strive for a balance
among (1) protection of the ratepayers, (2)
fairness to investors, and (3) the long term
viability of the utility; should be consistent
with sound environmental, social, and economic
policies of the Agency and the State; and should
produce results that were within the range of
reasonable results that would likely have arisen
from a Commission decision in a litigated
proceeding.
b. In judging a settlement, the Commission shall give
weight to the fact that a settlement reflects the
agreement by normally adversarial parties.1
DISCUSSION
The issues are addressed in this opinion in the
following order: the rate plan; retail access; strandable costs;
environmental and public policy programs; and, market power and
corporate structure. In each area, this opinion will address our
overall vision as set forth in Opinion No. 96-12, the findings in
the recommended decision, the parties' exceptions,2 and, where
relevant, the modifications and conditions imposed by our
January 27 order.
____________________
1 Cases 90-M-0225 et al., supra, Opinion No. 92-2, Appendix B,
p. 8.
2 All issues raised in the parties' briefs and comments have
been considered, even if they have not been specifically
mentioned in this opinion.
Rate Plan
We have emphasized that customers should benefit from
lower rates with competition as compared with what would result
from continued rate regulation.1
The lower rates and forgone rate increases resulting
from the Settlement are addressed in this opinion in terms of the
amount and allocation of the rate benefits, return on equity, and
rate design.
1. Amount and Allocation of Rate Benefits
The recommended decision found that the claimed value
of the forgone rate increases ($522 million) should be reduced to
approximately $350 million to reflect the litigation risk of the
company's position.2 The Judge also concluded that, in the
absence of an anticipated, average return on equity for the rate
plan period, no conclusion was possible on the fairness of the
Settlement between stockholders and customers.3 On the balance
of the Settlement's benefits among the various customer classes,
he concluded that small industrial and commercial customers
received fewer relative benefits than did residential customers.4
____________________
1 We expressed this goal as follows:
Market forces overall are expected to
produce, over time, rates that will be lower
than they would be under a regulated
environment. As we move toward competition,
our expectation is that rates overall will be
reduced.
Cases 94-E-0952 et al., supra, Opinion No. 96-12, mimeo p. 26.
2 R.D., p. 31.
3 The Judge was concerned that the Settlement provided some
significant opportunities to improve NYSEG's earnings, which
might not be reflected in lower rates (R.D., pp. 33-34).
4 It was suggested that providing these groups earlier retail
access or a marginal cost-based tariff for incremental usage
could help to alleviate the imbalance (R.D., pp. 36-37).
On exceptions, Staff argues that shareholders have
surrendered $725 million in value ($522 million in forgone rate
increases, $155 million in rate reductions, $48 million in GRT
reductions) and have agreed to auction their generating plants
and open their franchise territory to competition by August 1999.
These ratepayer benefits are sufficient, Staff contends, to
justify the conclusion that stockholders are contributing a fair
share to resolve the strandable cost problem.
On the balance of the Settlement benefits among
customer groups, Staff argues that new or expanded economic
development, economic revitalization, and business retention
rates, and the expanded applicability of negotiated contracts
under SC 13 and 14 would benefit the small industrial and
commercial customers. Further, the $621 million in value
allocated to the small customers is fairly balanced, according to
Staff, with the $104 million of benefits provided to large
customers.
The company echoes many of the Staff arguments, adding
that the Settlement is better than most other agreements already
approved, even if the Judge's lower estimate of the value of the
Settlement's benefits is accurate. On the intra- and inter-class
balance of the Settlement, the company contends that all small
customers (industrial, commercial, and residential) were subject
to the previously approved rate increases, and, therefore, those
customers all equally benefit from the company's agreement to
forgo these increases.
CPB argues that the rate concessions made by NYSEG are
of virtually no value because the company's rates are already at
unacceptable levels, and it requests an immediate 5% rate
reduction for all customers (rather than in year 5) with rates
thereafter frozen. MI urges that the company's stockholders be
required to absorb at least 50% of stranded costs, and argues
that the availability of the annual 5% rate reductions should be
expanded to include all SC 7 customers.1 In the alternative, MI
contends the Settlement should be amended at least to allow
customers to qualify for 5% annual decreases if their load factor
is below the 68% threshold only due to energy conservation
efforts.
We have carefully examined the allocation of benefits
and costs under the Settlement and conclude that shareholder rate
and other concessions contribute significantly to the opening of
the market and to the resolution of strandable costs. While the
Judge correctly concluded that a fair value of the forgone rate
increases should reflect inherent litigation risk, even using the
Judge's reduced valuation we nevertheless conclude that the
Settlement is within the range of the other utility agreements.
Accordingly, the Settlement's overall balance between
stockholders and customers is fair and reasonable.
As to the balance of the Settlement's costs and
benefits between and within customer classes, we conclude that a
fair share of the Settlement's benefits has been provided to
large industrial and commercial customers (5% annual reductions)
and to residential customers (forgone rate increases and a 5%
reduction by year five). It appears, however, that the small
industrial customers would not have been subject to any material
portion of the forgone rate increases. It also appears likely
that small commercial customers would not have been subject to as
large a potential increase as residential customers.
Accordingly, the small industrial and small commercial groups do
not share the Settlement benefits equitably with other customers.
Accordingly, we required two changes to the Settlement
for these customers in our January 27 Order. First, we required
that retail access be provided to the small industrial customers
at the beginning of the second phase of the access plan (i.e.,
August 1, 1998). Second, we directed the company to file a
marginal-cost based tariff that would apply to increased usage by
____________________
1 SC 7 is NYSEG's tariff for its largest demand customers
(greater than 500 kW).
small industrial and commercial customers. These rates will
provide focused incentives for business expansion. With the
allocation of these additional benefits to these groups, we
conclude that the Settlement's benefits are fairly allocated
among the company's customers.
2. Return on Equity
The recommended decision concluded that the
reasonableness of the 12% ROE earnings cap and the 9% ROE trigger
for petitioning for rate relief could not be determined without
knowing the financial results expected under the terms of the
Settlement. The recommended decision further suggested that
limitations be placed on the company's ability to reduce its
earnings below 12% through the use of accelerated depreciation
and amortization.1
Staff argues on exceptions that a projection of
anticipated returns under the terms of the Settlement is not
required and points to the Commission's approval of the Con
Edison agreement without substantial reliance on such forecasts.
The 9% ROE trigger is reasonable, Staff contends, because it only
allows NYSEG to file for rate relief and does not provide any
assurance that rate relief would be provided. The 12% earnings
cap, Staff suggests, provides efficiency incentives, and it
further notes that 100% of earnings above 12% are allocated to
the benefit of ratepayers, a significant benefit compared to
other utility agreements where overearnings are shared between
customers and shareholders.
NYSEG agrees with Staff and provides its opinion that
the 12% earnings cap would not likely be reached during the five
year rate plan. It further argues that a limitation need not be
placed on its ability to use earnings above 12% for accelerated
depreciation, because writing-down recoverable, stranded assets
provides a benefit to ratepayers even greater than reducing
rates.
____________________
1 R.D., pp. 34, 38.
The 12% ROE cap and 9% earnings trigger are reasonable.
While it might be helpful to have a reliable estimate of
anticipated returns, the uncertainties involved in the transition
to a competitive market can render such estimates unreliable.
The 12% earnings cap under a price cap regimen is reasonable and
is within the range provided in other utility agreements.
Moreover, while the company will have opportunities to enhance
its earnings, given the company's recent subpar earnings, the
rate reductions, and likely future costs onsets, in particular
non-utility generation costs, we are satisfied that the plan
fairly balances shareholder and ratepayer interests. The 9%
earnings floor, below which the company would be permitted to
petition for a rate increase, also seems reasonable. Because
this provision only allows the company to file a petition, it
provides the company with no significantly greater rights than it
would likely have in any event under the Public Service Law.
However, to preserve our flexibility to apply any such
earnings in a variety of ways for the benefit of ratepayers, we
limited the ability of the company to apply such earnings to
accelerated depreciation or amortization without our prior
approval. We recognize that efforts to accelerate these costs
will ameliorate revenue requirement deficiencies for periods
following the plan, and, at this point, we would prefer to apply
any overearnings to the NMII investment. A final decision will
be made if and when overearnings arise.
3. Rate Design
a. Customer/Energy Charges
The recommended decision suggested that rate design
changes to better align fixed customer costs and energy costs
with tariff charges should be initiated now rather than waiting
until year three of the Settlement as proposed by the
signatories.
Staff excepts, arguing that a freeze in the current
design provides a benefit to small users who would otherwise
experience bill increases. Staff suggests that additional
funding may be available in year three of the rate plan that
could be used to avoid or ameliorate rate redesign bill increases
for low-use customers. The company states that further
negotiations on this issue would be fruitless. CPB agrees with
NYSEG and Staff. IPPNY/Enron urges significant changes now to
better align costs and rates, suggesting that adoption of
marginal-cost energy rates could significantly lower the
magnitude of the company's strandable costs.
It is clear that the significant disparity between
rates and costs of energy and customer service will require a
redesign of the fixed and variable components of customers'
rates. In fact, a number of the agreements we have approved
contain provisions that begin the required realignment. In this
case, however, redesigning residential rates will yield bill
increases for many customers, which will not be ameliorated by
base rate decreases until year five of the plan. Further, as
Staff notes, there may be funds available in year three of the
plan which could be used to offset these impacts. Under the
circumstances of this proceeding, we do not believe it reasonable
to begin the redesign of rates causing bill increases to a large
portion of residential customers.
b. Back-Out Credit
The recommended decision concluded that the levels of
the generation back-out credit1 set forth in the Settlement are
reasonable, but that the back-out credit levels should not be
capped at the Settlement amounts if the market price for
electricity is higher.
Staff excepts, arguing that a market price greater than
the NYSEG back-out credit (which is based on NYSEG's embedded
cost of coal generation) would indicate that the market has been
____________________
1 If a customer who has access to the generation market decides
to purchase generation from a supplier other than the utility,
the customer's bill from the utility would include a
generation back-out credit to reflect the cost of the
commodity no longer supplied by the utility.
slow to develop and that such a result is completely reasonable.
Staff contends that extending the credit to a higher market price
does nothing but subsidize an inefficient market, which could in
turn threaten service reliability.
NYSEG makes similar arguments and indicates that
allowing the back-out credit to float up to market price could
further strand company costs and shift risks to the company,
thereby unbalancing the Settlement. PULP contends that a back-
out credit that exceeds the market is both unsound and illegal.1
MI argues that the back-out credit does not include the cost of
NYSEG's nuclear generation and suggests that a proper back-out
credit would be based on fully unbundled, total generation costs.
IPPNY/Enron argues that setting the back-out credit at
the higher of the Settlement level or the market price does not
provide a penalty for NYSEG's shareholders. In light of the
stranded investment cost recovery otherwise provided in the
Settlement, both it and WEPCO contend that capping the generation
credit under circumstances where the market price of the
electricity exceeds that credit, would do no more than establish
a de facto monopoly in the retail supply market. A higher market
price would not mean, as Staff argues, that the generation market
is inefficient. A great number of causes, including the
imposition of market discipline on generation, could result in
the market price exceeding the Settlement's back-out credit.
During the transition to a competitive market, we will
be monitoring market development in all utility territories and
____________________
1 PULP states that the recommended decision "appears" to
recommend back-out credits that exceed market costs (PULP's
Brief on Exceptions, p. 9). The Judge's concern, however, was
not that the back-out credit should exceed the market price,
but rather, if the market price exceeded the back-out credit,
the market could be destroyed (R.D. pp. 39-40). The Judge's
recommendation was that the back-out credit not be permitted
to fall below the market price. Further, we find, as did the
Judge, that the back-out credits specified in the Settlement
as adopted are in the best interest of NYSEG ratepayers and
that the balance of the rates fairly compensate the company
for the use of its facilities (see PSL Subsection
66(12-b)(b)).
will take those necessary actions to assure that the development
of the market is not unreasonably constrained. One such
constraint might result from a fixed back-out credit lower than
market price. Accordingly, we have reserved the right to revisit
the appropriate level of the back-out credit, if the market price
exceeds the credit levels set forth in the Settlement.1
Recovery and Mitigation of Stranded Costs
In addressing the overall issue of stranded costs, the
recommended decision concluded that the Settlement provisions
establishing ratemaking principles for nuclear generation in the
post-2002 period should not be fixed today. The Judge also
suggested that a full return on all stranded costs as well as a
full return of all stranded costs would not necessarily be
reasonable unless it were determined that shareholders had
contributed significantly to the solution to the stranded cost
problem. Finally, the recommended decision reflected some
misgivings regarding the amortization periods allowed for various
types of company stranded costs.
Staff excepts, arguing that future nuclear ratemaking
principles can be established today and should be approved in the
form set forth in the Settlement. Staff is joined by NYSEG in
arguing that a full recovery of and return on all prudent
stranded costs are reasonable in light of the rate reductions,
rate incentive provisions, and auction terms in the Settlement.2
Finally, Staff argues that the lengthy amortization periods for
stranded costs set forth in the Settlement provide the Commission
flexibility to act depending on future circumstances.
CPB and MI argue that the company's stockholders should
be required to pick up a significant and identified portion of
the company's strandable costs. PII argues that all of the
____________________
1 January 27 Order, p. 5.
2 Our January 27 Order (p. 8) made it clear that the Settlement
provides no more than a reasonable opportunity to recover
prudent costs, subject to our statutory responsibilities.
company's nuclear costs should be subject to the market as soon
as possible, thereby opposing the Settlement which identifies
certain nuclear costs that, subsequent to 2002, will not be
subject to the market.
As we noted in the Con Edison case, significant rate
decreases and avoided rate increases are the equivalent of
strandable cost absorptions by the company's stockholders.1
Further, these rate benefits together with the auction terms and
business incentive provisions in the Settlement lead us to
conclude that stockholders have significantly contributed to the
elimination of strandable costs and to the opening of the
competitive market. Accordingly, allowing the company a
reasonable opportunity to recover its NMII and other strandable
costs, subject to our duty to set just and reasonable rates, is
acceptable. Further, the nuclear ratemaking provisions of the
Settlement will be approved, subject to future generic
pronouncements on nuclear ratemaking. Finally, because the
lengthy amortization periods for stranded costs are simply
maximum periods, the Settlement properly recognizes our
flexibility in future ratemaking.
Retail Access and Unbundled Tariffs
The recommended decision concluded that the retail
access schedule in the Settlement is reasonable and should be
approved. Under the Settlement all customers will be provided
retail access by August 1, 1999.
MI argues that full retail access should be provided to
all customers by early 1998 as suggested in Opinion No. 96-12.
The Counties, on exceptions, limited its earlier request that all
ratepayers in the counties be provided retail access as part of
the company's retail access program in August 1998, suggesting
instead that at least governmental customers within the counties
be provided participation at that time.
____________________
1 Cases 96-E-0897 et al., supra, Opinion No. 97-16, mimeo p. 39.
We conclude that the retail access schedule as adopted1
is reasonable and compares favorably to the schedules approved in
other utility agreements in that all customers will have retail
access by August 1999. For a great variety of reasons,2 it is
simply not possible to completely open the generation market in
early 1998 as requested by MI. We also conclude that the
company's retail access program, as amended, contains a
sufficient number and cross-section of utility customers. NYSEG,
however, should cooperate with the Counties to explore whether
its plan for being included in the 1998 retail access program is
feasible. If participation by the Counties can be accommodated
within the second phase of retail access, we would be prepared to
address any cost impacts on the company.
Corporate Structure
The recommended decision found that the code of conduct
and other corporate restrictions in the Settlement were
reasonable, considering our continuing jurisdiction to oversee
market development and take appropriate action should anti-
competitive activities require it. The Judge also recommended
that royalties for the use of the corporate name by unregulated
subsidiaries not be paid for the duration of the rate plan, but
that the issue be revisited in the future.
WEPCO argues that NYSEG affiliates should not be
permitted to use the NYSEG name in marketing within its own
service territory due to the potential barriers to entry and
other market power difficulties that could be created as a
result. Using a similar argument, CPB urges that NYSEG
affiliates should be permitted to use the NYSEG corporate name
____________________
1 The January 27 Order (p. 4) adjusted the access schedule by
requiring that all non-contract industrial customers, who are
not eligible for the annual rate decreases, should be provided
access by August 1998.
2 For example, neither the ISO nor the power exchange have been
created and a number of utility systems, such as computerized
billing, are not yet ready for the competitive market.
only upon the payment of a royalty to the regulated entity.
WEPCO also argues that an additional rule is required within the
code of conduct that would prohibit the regulated entity and its
unregulated affiliates from representing that customers may gain
an advantage if they deal with an affiliate of the regulated
company. IPPNY/Enron argue that a pre-separation study is
essential to provide a foundation for future reviews of cross-
subsidies and anti-competitive behavior.
In the Rochester Gas and Electric Corporation
proceeding we addressed issues concerning royalties and the use
of the corporate name by unregulated subsidiaries as follows:
RG&E's affiliates will not be prohibited
from using the name of RG&E or competing in
the company's service territory, or be
required to pay a royalty for the use of the
RG&E name and its affiliation. These
concessions were part of the give and take in
the negotiations and will not be disturbed.1
This outcome is also consistent with our approval of the Con
Edison agreement,2 and there is no reason to reach a different
result in this proceeding.
We have also previously addressed the concern that
further rules are required to preclude tying arrangements or
other anti-competitive activities. In Con Edison we concluded
that the standards of conduct in the agreement together with our
ability to establish a forum to consider misconduct allegations
were reasonable under the circumstances.3 We also reiterated our
intention to act swiftly and effectively to eliminate unwarranted
____________________
1 Case 96-E-0898, Rochester Gas and Electric Corporation's Plans
for Electric Rate/Restructuring, Opinion No. 98-1 (issued
January 14, 1998), mimeo p. 41.
2 Case 96-E-0897 et al., supra, Opinion No. 97-16, mimeo p. 49;
Order Adopting Terms of Settlement Subject to Conditions and
Understandings (issued September 23, 1997), Appendix A, p. 51.
3 Ibid., mimeo p. 48.
barriers to competition. Based on our review of the code of
conduct and other restrictions in the Settlement, our expressed
intent to remedy anti-competitive conduct or other barriers to
competition, and the Settlement provision to address violations
which we have required,1 we conclude that competitors are
protected reasonably and that neither a pre-separation study nor
further changes in the code of conduct are required.
Public Policy Programs
The recommended decision concluded that the funds
provided by the Settlement (approximately $13 million annually or
about 1.0 mill per kWh for the first three years) for DSM, R&D
(not related to transmission and distribution), and low-income
programs were reasonable. It also recommended that the funds be
allocated 70% to DSM, 20% to R&D, and 10% to low-income energy
efficiency based on historic trends. Finally, the Judge strongly
recommended that the company's low-income program (Fresh Start)
be continued and expanded to all eligible customers (basically
doubling the program in size at an annual incremental cost of
about $475,000) and be funded from the public policy program
amounts set aside in the Settlement.
Staff argues that up to the full $13 million could also
be used to fund incremental low-income programs or further rate
reductions. PII argues that a minimum of 1.35 mills per kWh
should be set aside and that low-income programs other than
energy efficiency should be funded from other sources. PII also
argues that NYSEG should not be allowed to administer the funds.
NYSEG repeats some of Staff's arguments and further
states that an allocation of these funds should be left to the
determination of the system benefit charge (SBC) Statewide Fund
Administrator.2 Finally, NAESCO expresses its concern that the
recommended decision failed to affirmatively endorse standard
____________________
1 January 27 Order, p. 7.
2 See Case 94-E-0952, supra, Opinion No. 98-3 (issued
January 30, 1998).
performance contracting with stipulated pricing as contained in
the Settlement.
The continuation of the company's Fresh Start low-
income program is the minimum required to address the concerns we
noted in Opinion No. 96-12.1 Accordingly, we required the
continuation of that program in our January 27 Order (p. 5).
We are also concerned with the scope of Fresh Start.
Under the program only 5,000 NYSEG customers are eligible for
assistance, yet some 37,000 customers receive HEAP assistance
with their energy bills and roughly 200,000 customers are
estimated to be eligible for that low-income assistance.2 In
addition, low-income assistance programs of other utilities
provide benefits such as budget training and assistance,
counseling on Department of Social Services programs like HEAP,
mandatory energy management workshops, etc., which are not
provided under the Fresh Start program.
Accordingly, we have required the company to file with
Staff and interested parties within 30 days of our January 27
Order a proposed affordability plan and budget that will target
approximately 37,000 customers during the five-year rate plan.3
In developing its proposal, the company should consider
approaches taken by Niagara Mohawk, National Fuel Gas
Distribution Corp., Brooklyn Union Gas, and others, and may
propose outside contracting for the program. Interested parties,
including the SBC Fund Administrator, are encouraged to comment
on the company's proposal or submit alternate proposals within
30 days of the company's filing.
____________________
1 Cases 94-E-0952 et al., supra, Opinion No. 96-12, mimeo p. 28,
n. 1.
2 Our January 27 Order (p. 5) incorrectly referred to 37,000
eligible Home Energy Assistance Program (HEAP) customers
rather than 37,000 who are currently receiving HEAP
assistance.
3 January 27 Order, p. 5.
A portion of the funding for the program (up to
$2.5 million/year for the first three years) will be derived from
the $13 million annual public policy program fund,1 and the
balance (up to $7.5 million over the three year period) will be
derived from the company's sale of excess land. We assume that
the program can become self-supporting due to savings from a
reduction of uncollectibles and arrearages, and the continuation
of contributions from customers who might otherwise leave the
system. Nevertheless, we intend to monitor the cost-
effectiveness and NYSEG's administration of the program.
Unsatisfactory performance on NYSEG's part in program development
or administration could result in the allocation of all funds to
the SBC Fund Administrator. Amounts not spent in any year will
be carried over and used subsequently and not retained by the
company. The future funding and administration of the program
will be re-examined during the third year of the rate plan.
EDP Delivery Rates
The recommended decision found that the rate reductions
(35% to 56%) provided in the Settlement for the delivery of EDP
were entirely reasonable. It also concluded that the failure to
freeze the rates at these reduced levels for the entire period of
the five-year plan was reasonable given the magnitude of the
initial reductions.
MI excepts to the recommended decision and opposes this
part of the Settlement on a number of grounds. First, MI objects
to the EDP wheeling rates, arguing that they are not cost based
and suggesting that they would be lower if they were based on
costs. In support of this position, MI cites the cost of service
evidence it presented in the litigated portion of the proceeding.
Second, MI objects to the continuation of a cap on EDP wheeling
which is not subject to a stranded cost charge. Prior to the
____________________
1 The low-income assistance program elements that can be
supported by SBC funds are defined in Opinion No. 98-3 supra.
The balance of the annual fund will be forwarded to the SBC
Statewide Administrator.
Settlement this cap was 32 MW, which the Settlement expanded to
38 MW. According to MI, any limitation on the amount of EDP
power NYSEG will wheel free of stranded cost charges is contrary
to law and our policies.
MI's arguments concerning the 38 MW wheeling limitation
are not persuasive. Its allegation, for example, that NYPA will
not be able to carry out the Legislature's mandate concerning
EDP,1 is refuted by NYPA's agreement to the Settlement. Nor do
we find that the Settlement, viewed in its entirety, is anti-
competitive. Rather than foreclosing competition in violation of
the antitrust laws,2 the Settlement opens NYSEG's transmission
and distribution system to competition on terms, including
stranded cost recovery mechanisms, that we find just and
reasonable and in the public interest. Finally, we have approved
analogous EDP caps where customers under the cap are not required
to pay (i.e., grandfathered) a CTC to recover stranded costs, but
customers above the cap are.3
MI's complaint that the EDP wheeling rates as reduced
in the Settlement are too high and are not based on costs, is
similarly unconvincing. Staff, NYSEG, and NYPA, normally adverse
parties on this question, reached the compromise in the
Settlement which included substantial rate decreases. If those
decreases are assured during the five-year rate plan, as we
required in our January 27 Order (pp. 7-8), and considering the
other benefits provided to MI's members under the Settlement, we
conclude that the resulting rates are just and reasonable. The
____________________
1 MI's Brief on Exceptions,p. 11.
2 Ibid., p. 12.
3 Case 97-E-0528, Niagara Mohawk Power Corporation, Order
Approving Tariff on Short Notice (issued October 24, 1997);
Order Approving Settlement Agreement (issued May 23, 1997).
Cases 96-E-0897 et al., supra, Order Adopting Terms of
Settlement Subject to Conditions and Understandings,
Appendix A, pp. 30-31. Case 96-E-0900, Orange and Rockland
Utilities, Inc.,'s Plans for Electric Rate/Restructuring,
Order Adopting Terms of Settlement (issued November 26, 1997),
Appendix, p. 33.
fact that the rate levels are the result of negotiations and
compromise rather than the litigation of cost of service studies
does not affect the validity of this conclusion.
Environmental Issues1
The recommended decision concluded that PII's proposed
"Price Cap Plus" form of regulation for the transmission and
distribution (T&D) company is not required and that mandatory
bill disclosures of emissions levels and generation sources is
not necessary to foster a "green" power market.
PII excepts, arguing that its Price Cap Plus plan (a
methodology intended to require consideration of DSM type
alternatives to T&D plant growth) should be adopted, or that
least-cost distribution planning (including environmental
externalities) should be mandated. It also argues that standards
for "green" products and emissions disclosure requirements should
be established through a working group and that an emissions
portfolio standard should be required for all electricity
sellers. CPB argues that bill disclosures of emission levels and
sources should be mandatory.
We have addressed these issues and have approved other
agreements that: require the utilities to consider
environmentally preferable alternatives to major T&D upgrades;
and require the development of a system to inform consumers of
the fuel mix and emission characteristics of their electricity
supplier.2 In addition, the Con Edison agreement as approved
contained provisions binding the company to support the adoption
of energy efficient building codes and standards and requiring
____________________
1 State Environmental Quality Review Act (SEQRA) considerations
are separately discussed infra.
2 Cases 96-E-0897 et al., supra, Order Adopting Terms of
Settlement Subject to Conditions and Understandings,
Appendix A, pp. 54-55. Case 96-E-0900, supra, Order Adopting
Terms of Settlement, Appendix pp. 28, 31; Opinion No. 97-20,
mimeo pp. 24, 27. Case 96-E-0898, supra, Opinion No. 98-1,
mimeo pp. 41-42.
the company to analyze the impacts of performance-based
ratemaking including the relationship between sales, distribution
revenues, and energy efficiency. Finally, as we have previously
recognized, we must carefully consider alternative energy sources
during the transition to competition, and, if opportunities
present themselves (such as through the passage of securitization
legislation), we will evaluate potential ways to accomplish
further environmental benefits through environmental protection
and energy efficiency programs.1 All of the above provisions
have been incorporated into the NYSEG Settlement as approved.2
We have also previously reviewed and declined to adopt
both a requirement that all ESCOs be required to maintain a
specified portfolio of generation types and the Price Cap Plus
form of regulation. In the RG&E proceeding we stated:
PII's price cap plus proposal is not
acceptable because it could lead to increased
rates if productivity is not sufficient to
offset inflation and, in any event, would
require annual regulatory oversight of the
true-up mechanism. In effect, this proposal
runs counter to our objective, which is to
rely more on competition and less on
regulation.3
Our concerns with the emissions portfolio proposal are that it
will tend to increase the average cost of electricity and it will
not likely create a level playing field for competing generation
sources.4 Nothing presented here suggests that a different
resolution would now be appropriate.
____________________
1 Cases 96-E-0897 et al., supra, Opinion No. 97-16, mimeo p. 66.
2 January 27 Order, p. 6, Appendix B.
3 Case 96-E-0898, supra, Opinion No. 98-1, mimeo p. 23; see
also, Case 96-E-0900, supra, Opinion No. 97-20, mimeo, p. 23.
4 Case 96-E-0900, supra, Opinion No. 97-20, mimeo, p. 27.
Other Issues
1. Customer Service Incentive Program
The Settlement contains a potential 15 basis point (bp)
penalty against the ROE cap based on two indicators of the
reliability of NYSEG's electricity supply.1 While these indicia
are important measures of the service provided by a
wires/transportation company, we prefer that a broader, total
service quality mechanism be used, including measurements of the
company's success in dealing with its customers and resolving
disputes, so long as the company retains its POLR
responsibilities. Accordingly, our January 27 Order required
(p. 6) that three indicia be added to the program,2 measuring the
level of customer satisfaction with company contacts and of our
complaints. Each indicator carries a maximum penalty of 8 bp for
a total annual exposure of 40 bp.
2. Reciprocity
The Settlement provides (p. 24) that another New York
State utility or utility-affiliated load serving entity (LSE) may
compete in NYSEG's territory only to the extent that NYSEG or its
subsidiaries can compete in the other's service territory. While
there might be circumstances when it would be equitable to place
such a constraint on the market, we do not believe it appropriate
to allow NYSEG alone to determine when a competitor may be
excluded. Accordingly, we have required the company to obtain
our approval before any LSE is excluded from NYSEG's territory.3
____________________
1 The indicators are: CAIDI--Customer Average Interpretation
Duration Index; and SAIFI--System Average Interruption
Frequency Index.
2 The additional indicators are the Public Service Commission
complaint rates, an overall customer satisfaction index, and a
contact satisfaction index.
3 January 27 Order, p. 6.
3. Cooperation
Our January 27 Order also requires NYSEG's commitment
to cooperate in the development of the market infrastructure
(i.e., ISO, power exchange, etc.). This condition is critical as
we move further toward competition for electric service in the
State.1
4. Statutory Authority
PULP argues on exceptions that we lack the legal
authority to approve retail access to all customers and to
establish requirements for energy services companies that differ
from those required of the electric utilities. These arguments
raise generic questions which PULP has raised in court
challenges, other rate/restructuring cases, and in the generic
portion of Case 94-E-0952. To the extent the issues are relevant
to this proceeding, our previous resolutions have disposed of the
arguments.2 The remaining concerns raised by PULP are being
addressed in the generic proceeding. Accordingly, a further
elaboration is not required here.
5. NYPA Hydropower
PULP urges that further negotiations and the
development of a "fuller" record be mandated on the question of
NYPA hydropower benefits allocated to residential customers.
PULP contends that the benefits are "obscured" in the company's
cost studies and that the "record is insufficient to show that
NYPA hydropower will not be sold at a marked up price in
violation of law."3
PULP's concerns cannot be addressed in detail based on
this record, but the questions it raises may be addressed in the
context of the company's unbundling process. It should be noted,
____________________
1 Cases 96-E-0897 et al., supra, Opinion No. 97-16, mimeo p. 60.
2 Ibid., p. 9.
3 PULP's Brief on Exceptions, p. 8.
however, that notwithstanding PULP's concerns, the record does
not support the conclusion that NYPA's hydropower benefits are
being or will be treated in an unlawful manner. Further, NYPA's
agreement to the Settlement suggests that it believes the
hydropower benefits are being allocated in accordance with the
statutory requirements.
STATE ENVIRONMENTAL QUALITY REVIEW ACT1
In conformance with SEQRA, a Final Generic
Environmental Impact Statement (FGEIS) was issued on May 3, 1996,
which evaluated the action adopted in Case 94-E-0952.2 We also
required individual utilities to file an environmental assessment
of their restructuring proposals. NYSEG filed an Environmental
Assessment Form (EAF) concerning the October 9 Settlement on
October 23, 1997.
The information provided by NYSEG in its EAF, the
parties' comments, the Settlement, and other information were
evaluated in order to determine whether the potential impacts
resulting from adopting the Settlement's terms would be within
the bounds and thresholds of the FGEIS adopted in 1996. The
evaluation also considered the conditions and changes to the
Settlement which we imposed in our January 27 Order.
Arguably, all of the potential impacts need not be
considered, given that some result from Type II exempt rate
actions. Nonetheless, the analysis examined all areas in which
impacts could reasonably be expected.
There were no impacts found to be associated with price
cap regulation. The possibility of prudence review is seen as an
important deterrent to excessive infrastructure investments as
well as an incentive for promoting the use of targeted DSM, as
appropriate, to avoid excessive T&D upgrades.
____________________
1 Attached as Appendix C is the Environmental Assessment Form.
2 Opinion No. 96-12 (issued May 20, 1996) sets forth our
findings under SEQRA at mimeo pp. 76-81.
The company asserts it has no plans to either retire
any of its existing electric generating facilities or construct
new generating facilities as a consequence of the Settlement.
While NYSEG has no plans to retire existing facilities, it could
happen under new ownership. This possibility should be
monitored. Any construction of new facilities should improve air
quality for critical emissions.
The Settlement will not result in significant new
transmission line construction impacts. The company's 1997 load
pocket study indicates that under high summer usage two load
pockets may occur. NYSEG has taken steps to eliminate one
potential pocket. The Agreement transfers generation control
within the second pocket, eliminating potential exercise of
market power.
Minor localized community economic impacts may occur
(e.g., due to reduced tax receipts), but these would be balanced
by positive effects in other localities.
A greater source of concern is the possible increase in
air pollution that could accompany increased demand for electric
energy. It is likely that increases in energy demand will result
from the Settlement's decrease in rates (0.48% average annual
increase in demand over the 1998-2012 period) and in DSM
expenditures (0.17% increase in demand). Each of these
incremental growth rates is an upper bound. For example, it is
not clear that all of the rate reductions from the Settlement
should be attributed to restructuring; also, the lower DSM
expenditures do not consider ESCO DSM spending. In our opinion,
the actual growth rates will be substantially less than the
corresponding rates in the FGEIS (1% annual incremental growth
from the "high sales" scenario, and 0.29% from the "no
incremental utility DSM" scenario).
Because of the inherent uncertainty in forecasting
future impacts, monitoring of NYSEG's restructuring and
environmental impacts is being implemented, as a matter of
discretion, and a system benefits charge is being established.
Based on these analyses, the potential environmental
impacts of the Settlement are found to be within the range of
thresholds and conditions set forth in the FGEIS. Therefore, no
further SEQRA action is necessary.
CONCLUSION
Our assessment of this Settlement reflects not only the
diverse interests of those parties who endorsed it, but also the
views of other parties whose comments have been less favorable.
The salient features upon which we focus are the rate plan, the
provisions to develop a competitive market, and the amelioration
of environmental concerns.
The rate plan is intended to promote jobs and economic
development by reducing rates for large industrial and commercial
customers to a level approaching the national average. At the
same time, rate increases of more than one-half billion dollars
applicable to other customers have been eliminated and a rate
reduction will be provided by the final year of the plan.
Furthermore, the residential and small commercial/industrial
reductions could be more appreciable in the event NYSEG's
earnings are significantly higher than it expects. Had we
apportioned the revenue reduction equally among all classes,
customers other than large industrial and commercial customers
would have realized a minimal gain, while the laudatory goal of
promoting job growth and economic development would have been
lost.
With regard to those parties who have advocated a
greater revenue reduction, we believe that by approving the short
timeframe for the full opening of the market, advancing the open
market access date for some customers, and requiring marginal-
cost based tariffs for small commercial and industrial customers,
we have accomplished a comparable outcome.
The competitive aspects of the Settlement are
particularly favorable, as NYSEG's customers will be able to
avail themselves of full retail access sooner than the customers
of any other New York utility except Orange & Rockland and
because NYSEG has now agreed to divest by auction all of its
fossil generating assets. This should contribute to the
development of a robust, competitive electric generation market.
The company's unbundling plan, as well as the auction plan, will
be subject to our approval, and we will ensure that market power
concerns are mitigated. The rate reductions and concessions
together with the development of a competitive electric market
will, therefore, produce just and reasonable rates that we expect
will be lower than they would be otherwise. As to concerns about
potential anti-competitive conduct, we are satisfied that the
standards of conduct and controls on affiliate transactions
(Settlement pp. 29-34) will preclude such conduct, particularly
given that we are authorized to impose remedial actions on RegSub
for any violation of the standards of conduct set forth in the
Settlement.1 Moreover, we have retained our authority to modify
those standards and controls should circumstances warrant.
Finally we are satisfied that the funding provided for
public policy programs and the additional environmental
protections agreed to by NYSEG adequately protect the
environment.
For the reasons stated, NYSEG and the parties
supporting the Settlement have demonstrated that the rate
reductions are reasonable and that the Settlement satisfies the
objectives of Opinion No. 96-12 and our Settlement Guidelines.
We therefore adopt the terms of the Settlement and reaffirm our
order of January 27, 1998, and our view that the development of a
competitive market will produce further consumer benefits.
The Commission orders:
1. The Order Adopting Terms of Settlement Subject to
Modifications and Conditions (issued January 27, 1998) is adopted
in its entirety and is incorporated as part of this opinion and
order.
____________________
1 January 27 Order, p. 7.
2. New York State Electric & Gas Corporation (NYSEG)
shall file its specific plans for the holding company structure
as soon as practicable. At least 20 days before any intermediate
holding companies acquire stock of the utility, NYSEG shall file
with the Commission a detailed description of any such
intermediate holding companies, including copies of filings with
the Securities and Exchange Commission relevant to such
transactions. Such transactions regarding any intermediate
holding companies shall be deemed approved, unless within 45 days
the Commission notifies NYSEG that the provisions are
inconsistent with the Settlement as approved or the January 27,
1998 order in this proceeding.
3. Cases 93-E-0284 and 93-E-0664 are closed.
4. Cases 96-E-0891 and 95-M-0017 are continued.
By the Commission,
JOHN C. CRARY
Secretary
APPENDIX A
APPEARANCES
FOR WHEELED ELECTRIC POWER COMPANY
Joel Blau, Esq., 32 Windsor Court, Delmar, New York 12054
FOR THE RETAIL COUNCIL OF NEW YORK
Cohen Dax, & Koenig, P.C. (Paul C. Rapp, Esq.), 90 State
Street, Suite 1030, Albany, New York 12207
FOR CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.
John Gallagher, Esq., 4 Irving Place, New York,
New York 10003
FOR MULTIPLE INTERVENORS
Couch, White, Brenner, Howard & Feigenbaum, LLP (Leonard H.
Singer, Esq.), 540 Broadway, Box 2222, Albany,
New York 12201
FOR NEW YORK STATE ELECTRIC & GAS CORPORATION
Huber Lawrence & Abell (Frank J. Miller, Esq.,
Robert G. Grassi, Esq., Amy Davis, Esq., Stuart A. Caplan,
Esq., Seth Davis, Esq.), 605 Third Avenue, 27th Floor,
New York, New York 10158
Robinson, Silverman, Pearce, Arson & Berman (Andrew Irving,
Esq.), 1290 Avenue of the Americas, New York, New York 10104
FOR THE NEW YORK ENERGY EFFICIENCY COUNCIL, INC.
William Hills, 355 Lexington Avenue, 19th Floor, New York,
New York 10017
FOR NEW YORK POWER AUTHORITY
Edgar K. Byham, Esq., 1633 Broadway, New York,
New York 10019
FOR NEW YORK STATE CONSUMER PROTECTION BOARD
Anne F. Curtin, Esq., Joanne DiStefano, Alfred Levine, Esq.,
5 Empire State Plaza, Suite 2101, Albany,
New York 12223-1556
APPEARANCES
FOR NEW YORK STATE DEPARTMENT OF ECONOMIC DEVELOPMENT
Gloria Kavanah, Esq., One Commerce Plaza, Albany,
New York 12245
FOR NEW YORK STATE DEPARTMENT OF PUBLIC SERVICE
Leonard Van Ryn, Esq., Nancy Russell, Esq., 3 Empire State
Plaza, Albany, New York 12223-1350
FOR PUBLIC INTEREST INTERVENORS
David Wooley, Esq., Mollie Lampi, Esq., Melanie Pien, Pace
Energy Project, 122 South Swan Street, Albany,
New York 12210
FOR PUBLIC UTILITY LAW PROJECT OF NEW YORK, INC.
Charles J. Brennan, Esq., Gerald Norlander, Esq., Trudi
Renwick, 90 State Street, Suite 601, Albany, New York 12207
FOR INDEPENDENT POWER PRODUCERS OF NEW YORK, INC and ENRON
CAPITAL & TRADE RESOURCES
Read and Laniado, LLP, (Kevin R. Brocks, Esq., Craig Indyke,
Esq.), 25 Eagle Street, Albany, New York, 12207-1901
FOR AMERICAN ASSOCIATION OF RETIRED PERSONS
Ward, Sommer & Moore, L.L.C. (Douglas H. Ward, Esq.,
Michael Moore, Esq.), Plaza Office Center, 122 South Swan
Street, Albany, New York 12210
FOR THE CONSOLIDATED NATURAL GAS COMPANIES
Whiteman Osterman & Hanna (Thomas H. O'Donnell, Esq.,
Meg Carr, Esq.), One Commerce Plaza, Albany, New York 12260
FOR JOINT SUPPORTERS AND NATIONAL ASSOCIATION OF ENERGY SERVICE
COMPANIES
Ruben S. Brown, M.A.L.D., The E Cubed Company, 201 West 70th
Street, Suite 41E, New York, New York 10023
FOR JOINT SUPPORTERS
Glenn Camus, Esq. CNG Energy Services Corp., One Park Ridge
Center, Pittsburgh, Pennsylvania 15275
APPEARANCES
FOR TIOGA AND TOMPKINS COUNTIES
Gorden M. Boyd, Salerni & Boyd, Inc., 6 Franklin Square,
Saratoga Springs, New York 12866
CASES 96-E-0891 et al. APPENDIX B
CASE 96-E-0891, et al.
NEW YORK STATE ELECTRIC & GAS CORPORATION
LIST OF ABBREVIATIONS
AARP - American Association of NAESCO - National Association
Retired Persons of Energy Services
bp - Basis Points Companies
CAIDI - Customer Average NMII - Nine Mile Point II
Interruption Duration Index nuclear generating facility
CON EDISON - Consolidated NUG - Non-utility Generator
Edison Company of New York, NYPA - New York Power
Inc. Authority or the Power
CPB - New York State Consumer Authority of the State
Protection Board of New York
CTC - Competitive Transition NYSEG - New York State
Charge Electric & Gas Corporation
CUB - New York Citizens PII - Public Interest
Utility Board Intervenors
DED - New York State POLR - Provider of Last Resort
Department of Economic PSC - New York State Public
Development Service Commission
DOL - New York State PSL - Public Service Law
Department of Law PULP - Public Utility Law
DSM - Demand Side Management Project of New York, Inc.
EAF - Environmental Assessment R.D. - Recommended Decision
Form R&D - Research and Development
EDP - Economic Development RegSub - Regulated Subsidiary
Power of NYSEG HoldCo
Enron - Enron Capital & Trade Retail Council - Retail
Resources Council of New York
FGEIS - Final Generic ROE - Return on Equity
Environmental Impact SAIFI - System Average
Statement Interruption Frequency
GenSub - Generation Subsidiary Index
NYSEG HoldCo SBC - System Benefits Charge
GRT - Gross Receipts Tax SC - Service Classification
HEAP - Home Energy Assistance SEQRA - State Environmental
Program Quality Review Act
HEFPA - Home Energy Fair Staff - New York State
Practices Act Department of Public
HoldCo - Holding Company Owner Service Staff
of GenSub and RegSub Tr. - Transcript
IPPNY - Independent Power WEPCO - Wheeled Electric Power
Producers of New York, Inc. Company
ISO - Independent System
Operator
kW - kilowatt
kWh - kilowatt-hour
LSE - Load Serving Entity
MI - Multiple Intervenors
MOU - Memorandum of
Understanding - Interim
Agreement Regarding EDP
Wheeling by NYSEG
MW - megawatt
CASE 96-E-0891 et al.
APPENDIX C
617.20 Appendix C
State Environmental Quality Review
ENVIRONMENTAL ASSESSMENT FORM
PROJECT INFORMATION
1. Applicant/Sponsor: New York State 2. Project Name: Elect. Rate/
Electric & Gas Corporation Restructuring-Case 96-E-0891
3. Project Location: New York State Electric & Gas Corporation Territory
Municipality NA County NA
4. Precise Location: (Street address and road intersections, prominent
landmarks, etc., or provide map)
NA
5. Proposed action is
___ New ___ Expansion X Modification/alteration
6. Describe project briefly: Cases 94-E-0952 & 96-E-0891 - In the matter of
competitive opportunities regarding electric service, filed in Case 93-M-0229;
Plans for electric rate/restructuring pursuant to Opinion No. 96-12; and the
formation of a holding company pursuant to PSL, Subsections 70, 108 and 110,
and certain related transactions -- Environmental Assessment Form.
7. Amount of land affected: NA
Initially________acres Ultimately ________acres
8. Will proposed action comply with existing zoning or other existing land
use restrictions? NA
___Yes ___No If No, describe briefly
9. What is present land use in vicinity of project? NA
__Residential __Industrial __Commercial __Agricultural
__Park/Forest/Open Space __Other
Describe:
10. Does action involve a permit approval, or funding, now or ultimately from
any other governmental agency (federal, state or local)?
X Yes ___ No If yes list agency(s) name and permit/approvals:
NYS Public Service Commission
11. Does any aspect of the action have a currently valid permit or approval?
___ Yes ___ No If yes, list agency(s) name and permit approval:
Stationary sources owned and operated by New York State Electric & Gas
Corporation have valid, approved certificates to operate.
12. As a result of proposed action will existing permit/approval require
modification? NA
___ Yes ___ No
I CERTIFY THAT THE INFORMATION PROVIDED ABOVE IS TRUE
TO THE BEST OF MY KNOWLEDGE
Agency: NYS Department of Public Service Date: January 26, 1998
Signature: ____________________________________________________________
Appendix C
PART II - ENVIRONMENTAL ASSESSMENT
A. Does action exceed any Type 1 threshold in 6 NYCRR, Part 617.4? If
yes, coordinate the review process and use the full EAF. ___ Yes X No
B. Will action receive coordinated review as provided for unlisted actions
in 6 NYCRR, Part 617.6? If No, a negative declaration may be superseded by
another involved agency. NA ___ Yes ___ No
C. Could action result in any adverse effects associated with the
following: (Answers may be handwritten, if legible.)
C1. Existing air quality, surface or groundwater quality or quantity,
noise levels, existing traffic patterns, solid waste production or
disposal, potential for erosion, drainage or flooding problems?
Explain briefly.
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C2. Aesthetic, agricultural, archaeological, historic, or other natural
or cultural resources; or community or neighborhood character?
Explain briefly.
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C3. Vegetation or fauna, fish, shellfish or wildlife species,
significant habitats, or threatened or endangered species?
Explain briefly.
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C4. A community's existing plans or goals as officially adopted, or a
change in use or intensity of use of land or other natural
resources? Explain briefly.
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C5. Growth, subsequent development, or related activities likely to be
induced by the proposed legislation? Explain briefly.
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C6. Long term, short term, cumulative, or other effects not identified
in C1-C5? Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C7. Other impacts (including changes in use of either quantity or type
of energy)? Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
D. Will the project have an impact on the environmental characteristics
that caused the establishment of a critical environmental area (CEA)?
___ Yes X No If Yes, explain briefly:
E. Is there, or is there likely to be, controversy related to potential
adverse environmental impacts? ___ Yes X No If Yes, explain briefly.
Part III - DETERMINATION OF SIGNIFICANCE (To be completed by Agency)
See the attached Environmental Assessment Form Narrative.
Staff recommends that the Final Generic Environmental Impact Statement
(FGEIS) issued on May 3, 1996 (Case 94-E-0952), with respect to the
proposed action of adopting a policy supporting increased competition in
electric markets be extended in applicability, without modification or
supplementation, to the approval of New York State Electric & Gas
Corporation's (The Company) Agreement and Settlement on the grounds that
the significance of the proposal's anticipated environmental impacts will
not exceed the threshold values examined in the FGEIS. Consequently, no
further State Environmental Quality Review Act (SEQRA) action is necessary
in approving the Proposal.
Staff further recommends that a monitoring program be instituted to provide
a record of changes resulting from the restructuring plan's implementation
to enable confirmation and/or exposition of unexpected outcomes and their
significance, and to assure that specific mitigation measures are
implemented as needed.
New York State Department of Public Service January 26, 1998
Name of Lead Agency Date
John H. Smolinsky
Print or Type Name of Responsible Officer in Lead Agency
Signature of Responsible Officer in Lead Agency
Chief, Environmental Compliance and Operations
Title of Responsible Officer
Signature of Preparer (If different from responsible officer)
I. BACKGROUND
On May 3, 1996, the Commission issued a FGEIS in the
competitive opportunities proceeding which addressed impacts
associated with the adoption of a policy supporting increased
competition in electric markets, and associated regulatory and
ratemaking practices. Several alternatives, including no-action,
were studied.
In Opinion No. 96-12,1 issued May 20, 1996, the
Commission set forth its findings with respect to the FGEIS (pp.
76-81). The Commission determined that the likely environmental
effects of a shift to a more competitive market for electricity
are not fully predictable but that:
In general, the proposed action will have
environmental impacts that are modest or not
distinguishable from those of alternative actions,
including the no-action alternative... Apart from
the areas of substantial concern noted below, the
FGEIS did not identify reasonably likely significant
adverse impacts.
With respect to air quality impacts related to
oxides of nitrogen and sulfur, it appears likely
that the retail or wholesale electric market
structures would have greater impacts than the no-
action alternative. It appears likely that, in the
absence of mitigation measures, research and
development in environmental and renewables areas
would lose funding if competitive restructuring
moves forward. In addition, there would likely be a
decrease in the amount of cost-effective energy
efficiency during any transition to wholesale or
retail competition...
In order to address the adverse environmental
effects identified above on air quality, energy
efficiency, and research and development, several
mitigation measures will be employed as necessary.
First, a system benefits charge will be used as
appropriate to fund DSM and research and development
in environmental and renewable resource areas during
the transition to competition. Second, the
competitive restructuring will be monitored closely
____________________
1 Cases 94-E-0952, et al., Competitive Opportunities Proceeding,
Opinion No. 96-12 (issued May 20, 1996).
to ensure that specific mitigation measures are
implemented if needed. Finally, the Commission will
support and assist efforts by New York State and
federal agencies to ensure that adverse
environmental impacts to the state's air quality
from upwind sources of air contamination do not
occur as a result of the movement toward
competition.
Notwithstanding the mitigation measures identified,
the proposed action to restructure the electric
industry may result in an unavoidable adverse
environmental impact on air quality related to
oxides of nitrogen and sulfur, loss of some DSM
activity, loss of some research and development
funding in the environmental and renewables areas,
and displacement of workers and local economic loss
where plants are closed. Nevertheless, weighing and
balancing these likely environmental effects of the
shift to competition in the electric industry in New
York with social, economic, and other essential
considerations, leads to the conclusion that
implementing the proposed action toward greater
competition is desirable.
The Commission also recognized that individual utility
proposals might bring to light new concerns. In Opinion No. 96-
12,1 and as further clarified in Opinion No. 96-17,2 it required
each utility to file with its restructuring plans an
Environmental Assessment Form and a recommendation on further
environmental review. The information to be provided was
expected to assist the Commission in determining the need for
additional mitigation measures with respect to company
restructuring.
On October 23, 1997, NYSEG submitted an addendum to the
Environmental Assessment Form (EAF) and SEQRA recommendation in
connection with the Agreement and Settlement dated October 9,
1997 in Case 96-E-0891.
____________________
1 Ibid, p. 78, n. 1.
2 Cases 94-E-0952, et al., Opinion and Order Deciding
Petitions for Clarification and Rehearing, Opinion No. 96-17
(issued July 17, 1996).
SEQRA and Commission Approval of the
New York State Electric & Gas
Restructuring Plan - Options
Before the Commission
The FGEIS issued by the Commission in conformance with
SEQRA in Case 94-E-0952, et al., addressed the following proposed
action:
adoption of a policy supporting increased
competition in electric markets, including a
preferred method to achieve electric competition;
and regulatory and ratemaking practices that will
assist in the transition to a more competitive and
efficient electric industry, while maintaining
safety, environmental, affordability, and service
quality goals.1
Commission approval of NYSEG's proposed restructuring
plan constitutes a "subsequent proposed action." SEQRA
requirements with respect to this "subsequent proposed action"
allow the Commission to pursue one of the four following options:
1. No further State Environmental Quality Review
(SEQRA) compliance is required if a subsequent
proposed action will be carried out in conformance
with the conditions and thresholds established for
such actions in the generic Environmental Impact
Statement (EIS) or its findings statement;
2. An amended findings statement must be prepared if
the subsequent proposed action was adequately
addressed in the generic EIS but was not addressed
or was not adequately addressed in the findings
statement for the generic EIS;
3. A negative declaration must be prepared if a
subsequent proposed action was not addressed or was
not adequately addressed in the generic EIS and the
subsequent action will not result in any
significant environmental impacts; and
____________________
1 Cases 94-E-0952 et al., Competitive Opportunities
Proceeding, Opinion No. 96-12 (issued May 20, 1996), p. 76.
4. A supplement to the final generic EIS must be
prepared if the subsequent proposed action was not
addressed or was not adequately addressed in the
generic EIS and the subsequent action may have one
or more significant adverse environmental impacts.1
The following environmental assessment will assist in
choosing the appropriate option. The assessment is based on
NYSEG's EAF, on party comments and on analysis by Department
Staff. The Assessment consists of:
- Section II - Description of NYSEG and Its
Rate/Restructuring Settlement;
- Section III - Summary of NYSEG's Environmental
Assessment Form (EAF);
- Section IV - Party Comments on NYSEG's EAF;
- Section V - Staff Analysis;
- Section VI - Mitigation of Impacts -- Monitoring;
- Section VII - Conclusion.
II. DESCRIPTION OF NEW YORK STATE
ELECTRIC AND GAS CORPORATION
AND ITS RATE/RESTRUCTURING SETTLEMENT
NYSEG's service territory covers 18,359 square miles
(about one-third the area of New York State) and has a population
of 2,223,000.2 The territory includes all or parts of 42
counties, 149 cities and villages and 373 towns. At year-end
1995, NYSEG served approximately 804,000 electric customers.
NYSEG's electric service territory is comprised of eleven
noncontiguous electric load areas. NYSEG relies on transmission
____________________
1 6 NYCRR Section 617.10 (d).
2 Wickham, Denis E., February 14, 1997, Testimony presented in
NYSEG Plan: Volume 2 - Electric System Operations, pp. 5-7.
service provided by others to serve a significant portion of its
franchise load.
NYSEG's net system capability (total of all owned
resources, plus firm purchases less firm sales) is approximately
3,500 MW. Of this, 863 MW is remote generation that must be
wheeled over neighboring transmission systems to serve NYSEG's
load requirements. Another 945 MW of NYSEG's system capacity is
remote generation which is located in Pennsylvania, but is
directly tied to the largest NYSEG load area through 424 miles of
345 kV transmission line.
NYSEG purchases approximately 600 MW of its system
capacity from Public Utility Regulatory Policy Act (PURPA)
Qualified Facilities (QFs). NYSEG purchases 1,450 MW of firm
transmission service on a long-term basis.
The total service area peak electric loads in the
summer and winter respectively were 2,276 MW and 2,497 MW in 1995
and 2,213 MW and 2,404 MW in 1996.1 In 1996, NYSEG had a total
energy requirement of 14,787 GWH.
NYSEG's generation capability (2,550 MW - Summer) is
distributed as follows: 8% nuclear; 89% fossil-fueled; and 3%
conventional hydro.2 Electricity is delivered through a
transmission and distribution system consisting of approximately
4,776 miles of transmission and 28,251 miles of distribution
lines.
Utilizing the Commission's definition of a load pocket,
NYSEG has identified a load pocket in the area of Ithaca and
Auburn, surrounding the Milliken Station.3
____________________
1 Report of the Member Electric Systems of the New York Power
Pool, Load & Capacity Data - 1997, (Table I-5), p. 12.
2 Load & Capacity Data - 1997, Table III-2, p. 47.
3 New York State Electric and Gas Corporation, NYSEG Plan:
Volume 2 - Electric Operations, February 14, 1997, "Exhibit
DEW-2: NYSEG Load Pocket Report".
NYSEG's study showed that at 85% or higher peak area
load conditions, 156 MW of generation at Milliken Station must be
on line to provide needed voltage support in the area. The
potential for this voltage condition exists approximately 175
hours per year, and will increase over time. In addition, the
system analysis of this area indicated that one unit at Milliken
Station would be required at half its maximum output (78 MW) to
survive the worst contingency during peak loads.1
NYSEG's Load Pocket Report also identified a potential
pocket in the Northern Oneonta load area. This constraint was
removed by the installation of a voltage regulator at the
Brothertown substation in November 1997.
The proposed Settlement is intended to facilitate
attainment of the Commission's vision for the electric industry
of effective competition in the generation and energy services
sectors, of reducing electric prices, and of increasing choice of
supplier.
The electric price cap and price reduction provisions
of the Agreement cover the five-year period beginning with the
effective date of tariffs implementing the Commission opinion
approving the Agreement.
The Agreement is expected to achieve the Commission's
vision primarily through measures which, as the Recommended
Decision notes, provide for: the establishment of electric rates
for the term of the Settlement "at levels that are, overall,
below their current levels. While rates for all customer classes
would be reduced, large industrial and commercial customers would
receive the most significant price decreases." In general, the
Settlement provides for:
1. lower rates for all customers as contrasted to
those that would have applied under NYSEG's 1995
electric settlement including:
____________________
1 Wickham, Denis E., Ibid, pp. 30-32.
a. rate reductions of 5% on average each year for
five years for industrial customers;
b. forgo second and third year rate increases
provided for in the Commission approved
settlement of September 27, 1995, equaling a
price reduction of about 7%;
c. rate freeze followed by 5% reduction for
residential and commercial customers beginning
in year five;
2. expansion or creation of new programs to further
business retention, revitalization and economic
development;
3. retail access program that will lead to retail
choice of power suppliers for all NYSEG customers
commencing August 1, 1999;
4. mechanism to assess market value of coal fired
generation and interest in nuclear plant;
5. authority to implement a holding company
structure;
6. a rate with the objective of moving basic customer
service charges and incremental demand and energy
use toward marginal cost, while avoiding undue
bill shock for any customer;
7. reasonable unbundling of existing electric rates;
8. extension of gas rate settlement after further
negotiation;
9. maintenance of service quality and retention of
NYSEG as provider of last resort for customers not
served by competitive market.
The cumulative revenue reduction and concessions over
the settlement period amounts to $725 million.
Rate reductions by customer class will be as follows:1
- large industrial customers with demands of at least
500 kW and all customers with load factors of at
least 68% (22.6%), and
- residential and small business customers (5%).
The Settlement will open up the company's service area
to increased customer choice as a result of the introduction of a
retail access program commencing on August 1, 1998.
Also scheduled to take effect is a restructuring of
NYSEG's operations into functionally separate generation,
distribution, retailing, and overall administrative segments.
Additionally, a holding company will be formed.
Certain functions, such as distribution, will remain as
regulated monopoly services, while others, such as retail
service, will be open to competition. For customers unable or
unwilling to select alternative suppliers of energy and/or
capacity, the Settlement provides for continued service by a
regulated unit of NYSEG.
The Settlement requires that NYSEG offer up its coal-
fired generation facilities for auction, but permits the utility
to participate in the auction. With regard to nuclear
generation, the company's investment in Nine Mile II (operated by
Niagara Mohawk Power Corporation), including liability for
decommissioning, may be auctioned subject to co-tenant,
Commission and Nuclear Regulatory Commission approval.
The Agreement makes available approximately $13 million
per year for the first three years for Public Policy Programs
(herein referred to as the System Benefits Charge or SBC). In
the past, these programs have included Demand Side Management
(DSM), Energy Efficiency, Research and Development and
____________________
1 The rate reduction amounts include the anticipated impacts of
recently enacted reductions in State gross receipts taxes
("GRT"). The rate reductions provided in the Settlement will
be revised accordingly in the event the average GRT rates are
other than anticipated.
Environmental Protection. No specific allocation of funds among
these groups was made.
Further, the Settlement contains provisions responding
to the Commission's directive1 to introduce retail access to farm
and food processor customers on an expedited basis and resolves
pending cases involving judicial review of Commission decisions
as they pertain to NYSEG.
III. SUMMARY OF NEW YORK STATE
ELECTRIC AND GAS CORPORATION'S
ENVIRONMENTAL ASSESSMENT FORM (EAF)
On October 23, 1997, NYSEG submitted an EAF which
assessed anticipated environmental impacts of the company's
October 9, 1997 Settlement. The EAF notes the expectation that
environmental impacts are apt to occur as an indirect rather than
a direct effect of the Settlement inasmuch as it chiefly involves
changes in business entities, practices and services rather than
physical construction. The company utilizes many cross-
references to the Commission's FGEIS in developing its
environmental assessment of possible changes induced by the
Settlement.
The EAF observes that, under the influence of both rate
reductions and the introduction of competition in the sale of
electricity, electric energy use will probably increase. The
company indicates it has no plans to construct new generation in
order to meet the new higher demands.
In the event a generating facility is retired, any
demand in excess of NYSEG's generating capability could be
provided through market transactions.
Plant dispatch, according to the EAF, will be dependent
on a number of factors, including the eventual structure of the
Statewide power exchange and rules of the Independent System
____________________
1 Cases 96-E-0948, et al., Petition of Dairylea Cooperative,
Inc., Order Concerning Retail Access Proposals (issued
February 25, 1997).
Operator, market conditions, and environmental regulations--
especially those imposing air quality and emissions standards.
NYSEG's fossil-fired and hydroelectric units will be run as
needed, on an economic basis, to support the system subject to
applicable environmental laws and regulations.
The EAF notes that to the extent the company's
Settlement brings about an increase in importation of out-of-
state power, it is within the environmental parameters considered
by the Commission in its FGEIS.
Pursuant to the Settlement, the company will have no
further DSM obligations under the terms of the 1995 Rate
Settlement. However, during the term of the Agreement, NYSEG
will continue to fund DSM, low income energy efficiency, R&D and
environmental programs through the SBC to the extent required by
the Commission.
The EAF indicates that, in the near term, NYSEG expects
to continue the operation of its existing generating facilities
with their existing fuel profile. However, under future market
conditions, it is impossible to predict the fuel mixes of
alternative energy sources competing with NYSEG's facilities.
The EAF does not specify any new transmission facility
construction. Although the Settlement does not contain
requirements to implement any specific mitigation measures, a
load pocket study undertaken in response to a Commission order
indicated the need for implementing some type of mitigation
measures. The company has proposed that the ISO control
operation of the Milliken Station during critical peak demand
periods to ensure that it, or a future owner, cannot exercise
market power as a result of the need to operate Milliken Station.
The company has eliminated a potential load pocket in the
Northern Oneonta area by installation of a 46 kV voltage
regulator at the Brothertown substation.
In summary, the EAF concludes that while the Settlement
could result in an increase in overall sales of electricity,
which in turn could increase airborne emissions of various
pollutants, the possible consequences -- regardless of the
uncertainties with respect to eventual fuel mixes and location of
points of emission -- fall within the bounds of the Commission's
analysis and conclusions in the FGEIS. NYSEG's EAF concludes
that no further environmental impact analysis is necessary.
IV. PARTY COMMENTS ON NEW YORK
STATE ELECTRIC AND GAS CORPORATION'S
ENVIRONMENTAL ASSESSMENT FORM (EAF)
On May 13, 1997, the Public Interest Intervenors (PII)
moved for the Department of Public Service Staff to prepare
Supplemental Environmental Impact Statements (SEISs) in several
restructuring cases, including Case 96-E-0891--the NYSEG case.
At the time the petition was filed, several of the
utilities, but not NYSEG, had submitted Environmental Assessment
Forms for their proposed restructuring plans. In its petition, PII
identified a number of claimed deficiencies in the EAFs. Some were
generic in nature and, in our understanding, were intended to apply
to all utilities. The following are the issues raised by PII which
pertain generically to NYSEG.
. The SBC is well below the thresholds and conditions
established in the FGEIS and warrants additional
environmental scrutiny.
. Providing retail choice without environmental
disclosure will have serious environmental
repercussions that should be examined.
. Environmental impacts associated with the
elimination of the existing "revenue per customer
mechanism" and the institution of a price cap form
of regulation for the T&D company must be evaluated.
. Failure to expose the utility's fossil generating
units to full market risk requires environmental
review.
. The environmental impact of new construction needed
to eliminate load pockets/market power must be
addressed, including the consideration of
alternatives.
. The air quality impacts of the reduced commitment to
energy efficiency should be examined.
. The tax revenue impacts associated with out-of-state
power purchases must be considered.
Chief Administrative Law Judge Lynch considered the PII
petition and reply comments by Staff and several other parties and
recommended that "the final EAFs prepared for Commission use in the
Con Edison and O&R cases consider the potential environmental
effects of T&D price cap regulation for Con Edison and the recovery
of non-variable generation costs in T&D rates for Con Edison and
O&R" but that "in all other respects, there is no reason to
commence preparation of SEISs."1 Nonetheless, Staff's analysis in
Section V will address the issues raised by PII which are relevant
to NYSEG.
PII also filed specific comments2 in this case, raising
three issues. PII claimed that the EAF is inadequate and that a
SEIS was required in that the Company did not allocate SBC funds to
specific programs to mitigate environmental impact. Further, they
argued that least cost investments, such as DSM, which minimize
environmental harm should be considered in transmission and
distribution planning. Finally, PII contends that it is necessary
to require the company to identify the source and emissions of the
power it sells, so that the consumer may make an informed choice.
V. STAFF ANALYSIS
The FGEIS covered the significant generic issues
connected with restructuring at considerable length. The following
analysis will not recapitulate the material in the FGEIS. Nor will
____________________
1 Cases 94-E-0952, et al., Ruling on the Motion for Supplemental
Environmental Impact Statements, (issued June 19, 1997), p. 17.
2 Supplemental Testimony of Ashok Gupt, Natural Resources
Defense Council, on Behalf of Public Interest Intervenors.
November 7, 1997. TR 3946-3950.
the analysis repeat the material adequately covered in the
company's EAF and summarized in Section III of this memorandum.
Instead, this analysis will deal with issues identified by staff or
by the PII comments on the NYSEG EAF where it is reasonable to
anticipate that unique features of the company's service territory
or restructuring plan might result in environmental impacts not
considered in the FGEIS or in excess of thresholds identified in
the FGEIS.
A. Effects of Restructuring on Overall Level
of Electric Sales in NYSEG Service Territory
A key determinant of the incremental environmental
impacts of restructuring the electric industry in New York is the
effect of restructuring on the overall level of electric sales.
This section of the EAF will address whether any likely effect of
the NYSEG rate/restructuring plan would cause sales growth (and
therefore, air emission increases or other impacts) in excess of
the levels contemplated in the FGEIS.
There appear to be three feasible ways in which
restructuring could have significant impacts on electric sales.
1. Price Elasticity Effects
If electricity prices drop--as a result of utility rate
reductions incorporated in restructuring agreements and/or
competition among the utility and alternative suppliers-- customers
may make the economic decision to consume more electricity. This
is a price elasticity effect. The FGEIS analysis included the
preparation of a statewide "high sales" scenario which estimated
the likely upper bound of sales increases that would result from
credible decreases in electric prices given the best information
then available to staff economists. The scenario assumed that
under the high sales assumptions used in the analysis, the
compounded statewide electric sales growth would be about 2.2% per
year.
This scenario was compared to an FGEIS base case
"evolving regulatory model" scenario. The base case assumed sales
growth of 1.2%.1 Thus, the additional incremental statewide sales
growth likely to result from the high sales scenario compared to
the no-action base case was estimated as about 1.0% a year.2
PROMOD simulation of comparative plant dispatching under
these scenarios showed that compared to the evolving regulatory
model, the high sales model would result in an incremental 2.9%
increase in SO2 emissions, a 5.5% increase in NOX and a 12% increase
in CO2 by 2012. The Commission determined that, although the FGEIS
showed the possibility of detrimental incremental air quality
impacts, "consistent with social, economic and other
considerations, from among the reasonable alternatives available,"
the Commission's restructuring policy "avoids or minimizes adverse
environmental impacts to the maximum extent practicable."3
Recently, Staff of the Office of Regulatory Economics
(ORE) estimated the expected sales growth for NYSEG under a
competitive environment using updated data for many variables.
ORE's forecast shows that NYSEG's incremental sales growth under
the new settlement is likely to be about 0.23%, the average annual
incremental sales growth over the 15 year modeling period used in
the FGEIS. An analysis of the price elasticity of demand using the
current settlement rate reductions (Attachment A, Table C) predicts
____________________
1 The 1994 Power Pool "Load and Capacity Data" (yellow book) was
the source of the pre-restructuring statewide growth forecast
used in the FGEIS. Although the FGEIS did not examine company
specific growth, the company forecasts are available in the
yellow book. For NYSEG, the growth forecast was about 1.1%.
2 To provide a sense of scale, NYPP retail sales for 1996 were
about 110,628 GWH, while NYSEG retail sales were 14,787 GWH.
Under the FGEIS comparative scenarios, a 1.0% per year
incremental growth rate would result in additional statewide
sales of about 1,106 GWH in 1997 and pro rata additional NYSEG
sales of about 148 GWH in 1997.
3 Case 94-E-0952, et al., In the Matter of Competitive
Opportunities Regarding Electric Service, Opinion and Order
No. 96-12 (issued May 20, 1996), p. 81.
an annual average incremental sales growth of about 0.48%. An ORE
high sales forecast shows that the maximum effect of restructuring
would be an incremental growth of about 0.73% per year.
2. Price Cap Regulation
While the proposed settlement provides for a transition
to a more competitive market for generation, the regulated portion
of NYSEG would have rate of return regulation and capped prices.
PII argues that price cap rate of return regulation gives
incentives to promote sales and to make excessive infrastructure
investments. According to PII, these incentives could result in
environmental impacts which should be considered in a separate
SEIS.
The possibility of prudence review will serve as an
important deterrent against excessive infrastructure investments
and might also encourage the company to use energy efficiency as
necessary to avoid upgrades.
3. Lower Energy Efficiency Effect
For all New York utilities, including NYSEG, the levels
of DSM expenditures have declined in recent years. NYSEG's DSM
expenditures peaked at $477 million in 1993 and they achieved an
annualized incremental energy savings of 247.6 GWH. By 1996, its
DSM spending had declined to $4.6 million and its DSM annualized
incremental energy savings was estimated at 60.7 GWH. The proposed
settlement includes provisions to discontinue the Company's 1995
DSM programs. The following analysis assumes no new DSM spending
(worst case). If, however, some of the Agreement's SBC funds are
allocated to DSM, as recommended in the RD, it is not likely that
this worse case will be realized.
The FGEIS base case "evolving regulatory model" scenario
included annualized incremental NYSEG DSM energy savings of 54.4
GWH for the years 1997 and beyond.1 If NYSEG's rate of DSM
____________________
1 Based on the plans for 1996.
achievements is decreased from the levels assumed in the evolving
regulatory scenario to those in the proposed settlement, the
average annual incremental increase in demand (over the 1997-2012
modeling period used in the FGEIS) would be about 0.17%. As a
consequence, modeling indicates NYSEG's cumulative in-state 1997-
2012 emissions would be 0.27% higher for SO2, 0.91% higher for NOx
and 2.28% higher for CO2 than the company's emissions in the
evolving regulatory scenario.
This analysis assumes that emissions are proportional to
load; as a result, these modeled changes in SO2 and NOx emissions,
and those discussed above, probably overestimate actual emission
changes which may result from competition. The utility, or any
successive owner, is expected to operate its generators in a way
that will minimize costs; it can make a number of choices,
including type of fossil fuel and mode of operation. For example,
where possible, pollution abatement equipment will be operated only
to the extent needed to meet regulatory limits. Therefore, even at
reduced load, many facilities are likely to operate near their
emission limits, and an increase in load is unlikely to produce a
proportional change in emission.
B. Effect on Public Benefit Programs
In Opinion 96-12, the Commission set a policy that a non-
bypassable System Benefits Charge (SBC) would be used to fund a
variety of public benefit programs unlikely to be continued by
utilities at historic levels under competition. Part of this fund
would be used to support energy efficiency programs. The
Commission may determine the appropriate level for SBC funding by
NYSEG in this or another proceeding.
C. Effect of Restructuring on Retirement or
Construction of New Generation
Another potential factor that could, in concept, affect
New York's environment is the direct or indirect effect of the
NYSEG restructuring plan on the mix of plants run to meet electric
sales in the company's territory. The following section analyzes
whether the NYSEG plan would result in impacts that are greater
than or different in nature or causation from those already
addressed in the GEIS.
1. Retirement of New York State Electric and
Gas Generating Facilities
Retirement of a major NYSEG generating facility would
change the mix of generation resources available in the region and
thus could have a potential environmental impact, both positive and
negative. In addition, permanent retirement and decommissioning of
a plant could have a variety of local fiscal, economic, employment
and land use impacts. While NYSEG has no plans to retire existing
facilities, there could be retirements under new ownership.
2. Construction of New Generating Facilities
In its EAF, the company asserts that it has no plans to
construct new generating facilities and it is unaware of plans by
others to do so within the NYSEG territory. In any case, under
current air regulations (particularly the emissions offset policy
for NOx), construction of new generation facilities should tend to
improve air quality for critical emissions.
D. Effect of Restructuring Plan on Construction
of New Transmission Facilities
In its EAF, NYSEG states that no new transmission
facilities are required to implement the Settlement. However, the
company's load pocket study indicates that, under conditions of
high summer usage and equipment failures, load pockets may occur.
The company has proposed a mitigation strategy to eliminate market
power potential in the Ithaca/Auburn area without new transmission.
Further, it has installed a voltage regulator to eliminate a
potential pocket in the Oneonta area. Therefore, Staff finds no
significant environmental impacts associated with transmission.
E. Environmental Disclosure
It is possible that some customers in a retail electric
market will consider the generation source of the power they
utilize and prefer to purchase power from a less polluting or
"green" source. PII has argued that customers will be more likely
to purchase, or even pay a premium for, green power if a
trustworthy source of information on the different environmental
impacts of electricity supplied by different suppliers is
available. An "environmental disclosure" requirement in the
restructuring plan would, it is argued, provide that information to
consumers. PII argues that since environmental disclosure is not
required by the proposed settlement agreement, restructuring would
lead to increased environmental impacts.
However, no allowance was made for the benefits of an
environmental disclosure mechanism in the estimation of any of the
scenarios in the FGEIS. Therefore, any negative effects of not
having an environmental disclosure plan are already inherent in the
worst case FGEIS scenario.
An environmental disclosure program could facilitate
customer choice and could have the potential to somewhat mitigate
the otherwise unavoidable environmental effects of electric
generation through a market based means. However, it would be
appropriate to consider environmental disclosure further as a
generic statewide mitigation measure.
F. Community Economic Impacts
Any effects on communities as a result of the Settlement
will likely occur with respect to employment and taxes.
A positive net effect on employment is anticipated. This
will primarily occur as a result of lower rates, which will induce
economic growth by encouraging expanded business activity and
increasing ratepayer disposable income.
A likely consequence of restructuring is that the opening
up of retail access will create the incentive and opportunity for
electric customers to purchase electricity from suppliers not
subject to the gross receipts taxes. This could have a negative
impact on the revenue flows to taxing jurisdictions. Restructuring
may also result in lower property tax revenues from generating
stations, either through negotiation or as a result of plant
retirements. However, changes in the state and local utility tax
structure are being studied in recognition of competition in the
electric industry and they could counteract any negative impact.1
Positive tax benefits may also occur as a consequence of
stimulated economic development and increased employment
opportunities, but possibly in a different geographic area than the
negative impacts.
VI. MITIGATION OF IMPACTS -- MONITORING
The FGEIS explicitly recognized that "the likely
environmental effects of a shift to a more competitive market for
electricity are not fully predictable"2 due to the absence of
precedents, complexity of the New York electric industry, future
regulatory activities, including those of other states and the
federal government, and the nature and degree of market response.
The same uncertainty persists with respect to NYSEG's restructuring
plan.
In Opinion No. 96-12, the Commission made certain
findings pursuant to the State Environmental Quality Review Act.
The Commission determined that "...adverse environmental impacts
will be avoided or minimized to the maximum extent practicable by
incorporating as conditions to the decision those mitigative
measures that were identified as practicable;.... These mitigation
measures are: (1) monitoring environmental impacts; (2) system
____________________
1 A step in that direction was recently taken by the Legislature
with reductions in the Gross Receipts Tax.
2 FGEIS, p. 77.
benefits charge; and (3) assisting efforts undertaken by other
agencies to address interstate pollution transport."1
Staff analysis of the NYSEG restructuring plan determined
that its implementation would result in environmental effects which
would most likely be less than the impact values assessed in the
FGEIS. To address any uncertainty and to evaluate unknown
outcomes, a monitoring program as envisioned in the FGEIS should be
developed.
The environmental impacts which could be monitored are
described in Section 6.2.3 of the FGEIS. In addition, this EAF
discusses a number of environmental activities and changes that
would be important to monitor during the transition to competition.
The monitoring should include:
. imported electricity from the midwest,
. SO2 and NOx emissions,
. retirement of NYSEG power plants,
. in-state and out-of-state purchased generation,
. fuel mixture of generation,
. funding for environmental R&D,
. new electric and gas transmission line
construction,
. acid precipitation in the Adirondacks, and
Catskills, and other sensitive receptor areas,
. mitigation of load pockets.
The proposed environmental monitoring plan should be
organized around the major environmental impacts considered in the
FGEIS and this EAF, including information necessary for analysis of
any restructuring environmental impacts, confirmation of expected
impacts and exposition of unexpected outcomes and their
____________________
1 Opinion No. 96-12, p. 81.
significance. Staff anticipates NYSEG's cooperation in the
development and implementation of this monitoring plan.
VII. CONCLUSION
Staff has considered features of the NYSEG generation,
transmission and distribution systems, the proposed October 9, 1997
Settlement Agreement, and the company's EAF, and has analyzed the
potential impacts of that agreement on the environment. The likely
impacts have been compared to those addressed in the FGEIS. The
analysis has been broadly framed and has looked at limiting cases
in order to encompass any modifications to that agreement likely to
be adopted by the Commission. In our analysis, we have also
considered issues raised by parties commenting on the NYSEG EAF.
It is likely that increases in demand will result from
the settlement's decrease in rates (0.48% average annual increase
in demand over the 1997-2012 modeling period used in the FGEIS),
and from a decrease in DSM expenditures (0.17% annual increase in
demand). These increases are upper bounds and do not consider
mitigating factors such as ESCO spending on DSM. Therefore, actual
growth rates will be less than the corresponding rates in the
FGEIS: 1% annual incremental growth from the "high sales"
scenario, and 0.29% from the "no incremental utility DSM" scenario.
The impacts on emissions from these factors are within the range of
thresholds and conditions set forth in the FGEIS.
We conclude that the NYSEG restructuring plan would not
result in significant new environmental impacts not considered in
the FGEIS, nor would it result in impacts likely to be greater than
those considered in the FGEIS. Therefore, no SEIS is required
under the provisions of SEQRA. Staff recommends that the
Commission determine that no further SEQRA compliance is required
with regard to the transitional restructuring plan for this
company.
Although no further SEQRA compliance is required, it is
appropriate to institute mechanisms for monitoring and, if
indicated, mitigating some of the potential impacts of
restructuring.
IMPACT OF POSSIBLE RATE DECREASES
ON SALES GROWTH
Several of the potential impacts of deregulation examined
in the Final Generic Environmental Impact Statement (FGEIS) are a
result of the increased sales that are expected to accompany
deregulation. Rate reductions, which are a primary driver of the
increased sales, are not considered explicitly in the FGEIS; rather
it was assumed that, beginning in 1997, sales would increase by an
additional 1% per year for 15 years. That is, if statewide growth
without deregulation is 1.2% per year (as was assumed in the FGEIS
evolving regulatory model), growth with deregulation would be 2.2%.
In each of the restructuring cases, specific rate
reductions are now being considered. Using price elasticity of
demand, these proposed rate reductions now permit the calculation
of an estimate of increased sales to be expected from
restructuring.
The following tables (developed by the Office of
Regulatory Economics) consider both short-run elasticity (the
increase in sales which occurs immediately after the rate
reduction) and long-run elasticity (increases which occur in
subsequent years). The first step in the calculation (Table F) is
to determine the weighted average elasticities based on the
elasticities for each sector (industrial, commercial and
residential) and the fraction of the utility's load in each sector
(sales weight). Also, the average price reduction per year is
calculated based on the expected rate decrease for each sector and
the sales weight.
Five price reduction scenarios (A through E) are
considered. Scenario C uses the price reductions from the
October 9, 1997 Agreement. Scenarios A and B consider smaller
price reductions; Scenarios D and E consider larger price
reductions.
Tables A through E then calculate the year by year
increase in sales due to competition (short-run (SR Sales), long-
run (LR Sales) and total), the cumulative change in sales, and the
annual average rate of sales growth (Annual Rate). Residential
Delta (Res. Delta) is the possible residential rate reduction
considered in the table; Percent Total Impact per Year (%TI/Yr) is
the average price reduction per year from Table F; and Lambda is a
parameter relating short-term and long-term elasticity. The end of
the five year settlement period and the end of the fifteen year
modeling period are highlighted.
NEW YORK STATE ELECTRIC AND GAS
Sales ch = (price elasticity*% price ch)+lambda*(sales ch lag 1)
A. %Res Delt %Tl/ Yr Lambda SR Elas. LR Elas
2.0 0.59 0.73 0.30 1.10
Year SR Sales LR Sales Total Cumlative Annu.Rate
1998 0.173 0.000 0.173 0.173 0.17
1999 0.173 0.127 0.300 0.473 0.24
2000 0.173 0.219 0.392 0.866 0.29
2001 0.173 0.287 0.460 1.325 0.33
2002 0.173 0.336 0.509 1.835 0.36
2003 0.000 0.372 0.372 2.207 0.36
2004 0.000 0.272 0.272 2.478 0.35
2005 0.000 0.198 0.198 2.677 0.33
2006 0.000 0.145 0.145 2.821 0.31
2007 0.000 0.106 0.106 2.927 0.29
2008 0.000 0.077 0.077 3.005 0.27
2009 0.000 0.056 0.056 3.061 0.25
2010 0.000 0.041 0.041 3.102 0.24
2011 0.000 0.030 0.030 3.132 0.22
2012 0.000 0.022 0.022 3.154 0.21
B. %Res Delt %Tl/ Yr Lambda SR Elas. LR Elas
5.0 1.21 0.73 0.30 1.10
Year SR Sales LR Sales Total Cumlative Annu.Rate
1998 0.359 0.000 0.359 0.359 0.36
1999 0.359 0.262 0.620 0.979 0.49
2000 0.359 0.453 0.812 1.790 0.59
2001 0.359 0.593 0.951 2.742 0.68
2002 0.359 0.695 1.053 3.795 0.75
2003 0.000 0.769 0.769 4.564 0.75
2004 0.000 0.562 0.562 5.126 0.72
2005 0.000 0.410 0.410 5.537 0.68
2006 0.000 0.300 0.300 5.836 0.63
2007 0.000 0.219 0.219 6.055 0.59
2008 0.000 0.160 0.160 6.215 0.55
2009 0.000 0.117 0.117 6.332 0.51
2010 0.000 0.085 0.085 6.417 0.48
2011 0.000 0.062 0.062 6.480 0.45
2012 0.000 0.046 0.046 6.525 0.42
NEW YORK STATE ELECTRIC AND GAS
Sales ch = (price elasticity*% price ch)+lambda*(sales ch lag 1)
C. %Res Delt %Tl/ Yr Lambda SR Elas. LR Elas
5.0 1.38 0.73 0.30 1.10
Year SR Sales LR Sales Total Cumlative Annu.Rate
1998 0.410 0.000 0.410 0.410 0.41
1999 0.410 0.299 0.709 1.119 0.56
2000 0.410 0.518 0.928 2.047 0.68
2001 0.410 0.678 1.087 3.134 0.77
2002 0.410 0.794 1.204 4.338 0.85
2003 0.000 0.879 0.879 5.218 0.85
2004 0.000 0.642 0.642 5.860 0.82
2005 0.000 0.469 0.469 6.329 0.77
2006 0.000 0.343 0.343 6.672 0.72
2007 0.000 0.250 0.250 6.922 0.67
2008 0.000 0.183 0.183 7.105 0.63
2009 0.000 0.134 0.134 7.238 0.58
2010 0.000 0.098 0.098 7.336 0.55
2011 0.000 0.071 0.071 7.407 0.51
2012 0.000 0.052 0.052 7.459 0.48
D. %Res Delt %Tl/ Yr Lambda SR Elas. LR Elas
8.0 1.88 0.73 0.30 1.10
Year SR Sales LR Sales Total Cumlative Annu.Rate
1998 0.556 0.000 0.556 0.556 0.56
1999 0.556 0.406 0.963 1.519 0.76
2000 0.556 0.703 1.260 2.779 0.92
2001 0.556 0.920 1.476 4.255 1.05
2002 0.556 1.078 1.635 5.890 1.15
2003 0.000 1.194 1.194 7.084 1.15
2004 0.000 0.872 0.872 7.956 1.10
2005 0.000 0.637 0.637 8.593 1.04
2006 0.000 0.465 0.465 9.058 0.97
2007 0.000 0.340 0.340 9.398 0.90
2008 0.000 0.248 0.248 9.646 0.84
2009 0.000 0.181 0.181 9.827 0.78
2010 0.000 0.132 0.132 9.960 0.73
2011 0.000 0.097 0.097 10.057 0.69
2012 0.000 0.071 0.071 10.127 0.65
NEW YORK STATE ELECTRIC AND GAS
Sales ch = (price elasticity*% price ch)+lambda*(sales ch lag 1)
E. %Res Delt %Tl/ Yr Lambda SR Elas. LR Elas
10.0 2.26 0.73 0.30 1.10
Year SR Sales LR Sales Total Cumlative Annu.Rate
1998 0.668 0.000 0.668 0.668 0.67
1999 0.668 0.488 1.156 1.824 0.91
2000 0.668 0.844 1.513 3.337 1.10
2001 0.668 1.105 1.773 5.110 1.25
2002 0.668 1.295 1.963 7.073 1.38
2003 0.000 1.434 1.434 8.507 1.37
2004 0.000 1.047 1.047 9.555 1.31
2005 0.000 0.765 0.765 10.319 1.24
2006 0.000 0.559 0.559 10.878 1.15
2007 0.000 0.408 0.408 11.286 1.08
2008 0.000 0.298 0.298 11.584 1.00
2009 0.000 0.218 0.218 11.802 0.93
2010 0.000 0.159 0.159 11.961 0.87
2011 0.000 0.116 0.116 12.077 0.82
2012 0.000 0.085 0.085 12.162 0.77
F. LARGE SMALL RES/ WGTED PRICE
IND IND/COM OTHER AVG PER YR
Sales Weights 0.12 0.41 0.47
SR Price Elasticity 0.43 0.31 0.25 0.30
LR Price Elasticity 1.28 1.17 0.99 1.10
Price Reduction A 10.00 2.00 2.00 2.96 0.59
Price Reduction B 15.00 5.00 5.00 6.20 1.21
Price Reduction C 22.60 5.00 5.00 7.11 1.38
Price Reduction D 22.60 8.00 8.00 9.75 1.88
Price Reduction E 25.00 10.00 10.00 11.80 2.26
Lambda (1-(SR Elast/LR Elast)): 0.73