# Appendix — Consolidated Edison Company of New York, Inc. v. Public Service Commission of New York

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## Record

- **Collection:** Supreme Court brief
- **Document type:** Appendix
- **Published:** January 1, 1985
- **Citation:** 470 U.S. 1075

## Text

OE7FL1i€CO FILED

| JAM 18 1685
No. 84- | ALEXANDER 1. STRVAR,
IN THE eRe,
Supreme Court of the United States

October Term, 1984

CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.,
Appellant,
v.

PUBLIC SERVICE COMMISSION OF THE STATE OF NEW
YORK, OCCIDENTAL CHEMICAL CORPORATION, and
THE BROOKLYN UNION GAS COMPANY,

Appellees.

ON APPEAL FROM THE COURT OF APPEALS OF THE STATE OF
NEW YORK

APPENDIX TO JURISDICTIONAL STATEMENT

JOY TANNIAN

Counsel of Record for Appellant
PETER P. GARAM

JOHN D. MCMAHON

CELESTE A. CONTRUCCI

4 Irving Place

New York, NY 10003

(212) 460-2063

BERNARD L. SANOFF
KRONISH, LIEB, SHAINSWIT, WEINER & HELLMAN
1345 Avenue of the Americas
New York, New York 10105
Of Counsel

Index to Appendix

Appendix A—Opinion of the Court of Appeals of
the State of New York, October 25, 1984....

Appendix B—Opinion of the New York Supreme
Court, Appellate Division, Third Judicial
Department, December 30, 1983...........

Appendix C—Final Judgment of the Court of Ap-
peals of the State of New York, October 25,
PS ck ooh eR ARS a he chewes Cine eases

Appendix D—Opinion and Order of the Public Serv-
ice Commission of the State of New York,
Oe Ms Feu ice ok eee eae

Appendix E—Notice of Appeal to the Supreme
Court of the United States, December 19,

Appendix F—Constitutional and Statutory Provi-
ns TG bs os 0h eee dees kescetee

Page

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29a

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Appendix A—Opinion of the Court of Appeals of the
State of New York, October 25, 1984

(This opinion is uncorrected and subject to revision before
publication in the New York Reports.)

STATE OF NEW YORK

COURT OF APPEALS

3 No. 438

IN THE MATTER
OF

CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.,

Respondent,
v.

PUBLIC SERVICE COMMISSION OF THE
STATE OF NEW YORK,

Appellant,

OCCIDENTAL CHEMICAL CORPORATION,

Intervenor,
and

THE BROOKLYN UNION GAS COMPANY,

Intervenor-Respondent.

2a

(438) Timothy P. Sheehan & David E. Blabey, Albany, for
appellant.

Bernard L. Sanoff, Joy Tannian, Peter Garam, John D.
McMahon, & Celeste H.Contrucci, NY City, for respond-
ent.

Earle H. O’Donnell, Washington, & Michael
Whiteman, Albany, for intervenor-respondent-appellant.

COOKE, Ch. J.:

The Public Utility Regulatory Policies Act of 1978
(PURPA) does not preempt this State from requiring elec-
tric utilities to offer to buy energy from those alternate
energy producers, that qualify under both federal and
state law, at a rate in excess of the maximum rate under
PURPA. However, the State is preempted by provisions
of the Federal Power Act (FPA) from requiring electric
utilities to offer to purchase power from purely state quali-
fying alternate energy facilities.

Responding to the nationwide energy crisis, Congress
enacted PURPA in 1978 for the purpose of encouraging
the development of alternate energy sources, in order to
reduce this country’s dependence on traditional fossil fuels
(see FERC v Mississippi, 456 US 742, 750). Accordingly,
section 210 of PURPA (16 USC § 824a-3 [a]) mandates the
Federal Energy Regulatory Commission (FERC) to
prescribe rules that will foster development of qualifying
cogeneration facilities and qualifying small power produc-
tion facilities.' By further directing FERC to promulgate

‘A “‘cogeneration facility’? is one that produces both electric
energy and steam or some other form of useful energy, such as heat
(see 16 USC §796 [18] [A]).

A *“‘small power production facility’’ is one that produces electric
power from biomass, waste, renewable resources such as wind, water
or solar energy, or geothermal resources and has a production capac-
ity Of not more than 80 megawatts (see 16 USC §796 [17] [A]).

Each cogeneration or small power production facility will be a
“qualifying” one if it satisfies the requirements regarding ownership,
size, fuel use, efficiency, and reliability under PURPA (see 16 USC
§796 [17] [C], [18] [B)).

3a

rules requiring electric utilities to offer to sell and purchase
electric energy to and from such federal qualifying fa-
cilities, Congress hoped to eliminate one of the central
problems that had hindered the development of alternate
energy sources: traditional electric utilities were reluctant
to buy power from, or sell power to the alternate power
producers (see FERC v Mississippi, supra, at 750 & n. 12).

With respect to the regulatory rates established by
FERC for purchases by electric utilities, PURPA directs
that they be (1) just and reasonable to the electric con-
sumers of the utility, (2) in the public interest, and (3) not
discriminatory against qualifying cogenerators or small
power producers (see 16 USC § 824a-3 [b]). PURPA fur-
ther limits the purchase rate by providing that FERC may
not establish a rate that exceeds the purchasing utility’s
‘tavoided cost’’? (see id.).

A second barrier to alternate energy producers was the
applicability of voluminous federal and state utility
regulations, involving tremendous amounts of paperwork.
To avoid financially and administratively overburdening
qualifying facilities, section 210 of PURPA authorizes
FERC to exempt many federal qualifying facilities from
certain federal and state laws, including the Federal Power
Act (FPA) (see 16 USC §824a-3 [e][1]; 18 CFR 292.601),
when deemed necessary in order to encourage alternate
power producers to enter the field (see FERC v Missis-
sippi, 456 US 742,750-751, supra; 1978 US Code Cong. &
Admin. News, p 7832).

°A ulility’s ‘‘avoided cost’’ is the amount that it would have cost
the utility to generate the same energy that it bought from the quali-
fying cogeneration or small power production facility, had that pur-
chase not been made (see 16 USC §824a-3 [d]). This is referred to in
the statute as the utility’s ‘incremental cost of alternate electric
energy.””

The purchase rate actually selected by FERC in its regulations is
generally equal to avoided purchase costs and although it may be
lower (see 18 CFR § 292.304[b][2]-[3]), FERC may not require it to be
higher (see 18 CFR § 292.304{a][2]).

4a

After the enactment of PURPA, New York State passed
a similar law in 1980 (L 1980, ch 553, § 7, as amended L
1981, ch 843, § 9, cod at Public Service Law, § 66-c). Its
purpose is 10 promote State energy goals of development
of alternate energy production facilities, cogeneration
facilities, and small hydro facilities (see Public Service
Law, §66-c; State Energy Master Plan, Final Report, Vol.
I, pp 5-10, 29-30[3/82]).To encourage this development,
the law requires electric utilities to both sell and purchase
power produced by state qualifying facilities (see Public
Service Law, § 66-c[1]). Generally, those facilities that
qualify under PURPA in this State also qualify under the
state law (see Public Service Law, §§ 2-a, 2-b, 2-c).?

Like PURPA, section 66-c of the Public Service Law re-
quires that the purchasing rates by a utility from a state
qualifying facility be just, non-discriminatory, and in fur-
therance of the public policy behind the legislation. The
State statute differs from PURPA, however, in that it
prescribes a uniform minimum purchase price of 6 cents
per kilowatt hour for electricity purchased by a utility
from a state qualifying facility, rather than PURPA’s
variable avoided-cost purchase rate. This state’s minimum
purchase rate may at times exceed a utility’s avoided cost,
the maximum purchase rate for energy from a federal
qualifying facility that can be required by FERC under
PURPA (see 16 USC §824a-3[a]; 18 CFR 292.304 [a][2]).

After conducting hearings to implement the federal and
state legislation and regulations, respondent Public Serv-
ice Commission (PSC) determined, among other things,

‘Unless otherwise indicated, when the term ‘‘federal qualifying
facility’’ is used in this opinion, it will include facilities that are also
state qualifying facilities. A ‘‘state qualifying facility’’ will refer to
any facility qualifying under the Public Service Law, regardless of
whether it is also a federal qualifying facility. Some facilities,
however, will qualify under one law and not the other (compare 16
USC §796 [17], [18] & 18 CFR 292.201-206 with Public Service Law,
§§ 2-a, 2-b, 2-c) and will be referred to as a ‘“*purely’’ state or
‘*purely’’ federal qualifying facility.

ne ee ne a

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that petitioner Consolidated Edison must offer to pur-
chase electric energy from on-site generation facilities*
that qualify under either federal or state law, or both. It
also required petitioner, under state law, to offer to pur-
chase at a rate of least 6 cents per kilowatt hour from state
qualifying facilities and at a rate of at least avoided cost
from any purely federal qualifying facility under PURPA.

On September 9, 1982, petitioner commenced this arti-
cle 78 proceeding challenging, on federal preemption
grounds, these two aspects of the PSC’s determination.

The Appellate Division granted the petition, in part,
holding that the FPA and PURPA preempted the area
and, therefore, that FERC had exclusive jurisdiction to
determine rates for sales of electricity at wholesale by on-
site generators. The court modified the determination of
the PSC by declaring that the State could only require peti-
tioner to offer to purchase electricity from on-site
generators that were federal qualifying facilities. The re-
quired purchase of electricity from purely state qualifying
facilities, however, was deemed to be under the preemp-
tive blanket of the FPA. Further, the state requirement of
a 6 cents per kilowatt hour minimum purchase rate was
held invalid to the extent it conflicted with the federally
mandated maximum rate of avoided costs.

I

The first issue is whether PURPA preempts state regula-
tion requiring electric utilities to purchase power from
federal qualifying facilities at a rate in excess of the
avoided cost purchase rate required under PURPA. This
court holds that PURPA has no such effect.

Based upon the Supremacy Clause of the United States
Constitution (see U.S. Const., Art VI, cl. 2), federal law
will prohibit the enforcement of state regulation in several

‘On-site generation facilities refer, in this opinion, to all alternate

energy producers regardless of whether they qualify under federal
and/or state law.

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circumstances. Preemption’ will arise if the federal statute
contains express language indicating Congressional intent
to preempt the field sought to be regulated by state law
(see Jones v Rath Packing Co., 430 US 519, 525). In the
absence of express preemption, such may be implied from
the comprehensive and pervasive nature of the federal!
legislation that indicates an intention by Congress to leave
‘*no room for the States to supplement”’ federal law, or if
the federal law concerns a dominant federal interest (see
Rice v Santa Fe Elevator Corp., 331 US 218, 230). Preemp-
tion may also be found when compliance with both federal
and state law is an impossibility (see Florida Lime &
Avocado Growers, Inc. v Paul, 373 US 132, 142-143). In-
deed, if the state law ‘‘stands as an obstacle to the ac-
complishment and execution of the full purposes and ob-
jectives of Congress’’, as expressed in the conflicting
federal statute, it must fall (Hines v Davidowitz, 312 US
52, 67; see also, Capital Cities Cable, Inc. v Crisp,
US ' , 104 S Ct 2694, 2700).

Analysis under the Supremacy Clause, however, begins
with the assumption that Congress did not intend to pro-
hibit state action (see Maryland v Louisiana, 451 US 725,
746; Chicago & North Western Transp. Co. v Kalo Brick &
Tile Co., 450 US 311, 317). This is especially so when the
federal enactment would displace a state statute governing
an area historically regulated under the State’s police
power (see Rice v Santa Fe Elevator Corp., 331 US 218,

‘Traditionally, the word ‘‘preemption”’ has referred to preclusion
of state law based upon express or implied Congressiona! intent to do
sO as expressed in comprehensive federal legislation. This type of
‘‘preemption”’ has been distinguished from the other manner of
preclusion which occurs because there is a direct conflict or incon-
sistency between state and federal law (cf. Consolidated Edison of
N.Y. v Town of Red Hook, 60 NY2d 99, 104-105). Both situations
however, result in the supremacy of federal over state law and the
term “‘preemption’’ has been used to refer to both (see Capital Cities
Cable, Inc. v Crisp, 104 S Ct 2694, 2700; Free v Bland, 369 US 663
664); for the purposes of this opinion, it is so used.

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230, supra). The regulation of local electric utilities has
been recognized as ordinarily arising under a State’s police

power (see Arkansas Elec. Co-op Corp. v Arkansas Public
Com’n, ___. US : - 103 S Ct 1905, 1914).

On its appeal, the PSC maintains that section 210 of
PURPA does not expressly. or impliedly by reason of a
pervasive scheme of federal regulation, preempt the
minimum rate provision of section 66-c of the Public Serv-
ice Law. Petitioner does not contest this but, instead,
asserts preemption on two other grounds: first, on the
basis that there is a direct conflict between PURPA’s max-
imum avoided-cost purchase rate and the 6 cents per
kilowatt hour purchase rate set by the Public Service
Law;° second, on the ground that the State’s 6 cents per
kilowatt hour rate thwarts accomplishment of the Con-
gressional objective that consumer rate payers not be re-
quired to subsidize the development of alternate energy
producers. Subsidies allegedly would occur because the
utilities would pass their increased costs of purchasing
power from ihe alternate producers through to the
ultimate consumer in the torm of increased rates.

The flaw in petitioner’s direct conflict argument is that
it is based upon the faulty assumption that the federal
maximum purchase rate of avoided cosis was intended to
be the absolute ceiling on the price that could be set by
either the federal or state regulatory authorities. This
analysis begs the question of whether Congress intended
only to establish a maximum rate that could be imposed by
federal regulations and to leave room for the states to
separately encourage alternate power production by im-
posing higher rates for utility purchases of power from
federal qualifying facilities.

*Petitioner reasons that when a utility offers to purchase
wholesale electricity from federal qualifying facilities at 6 cents per
kilowatt hour according to the state law, it will violate the federal

mandate, under PURPA, that the maximum purchase rate be avoided
costs, which here, the PSC found to be 4.17 cents per kilowatt hour at

certain off-peak times.

8a

This court holds that there is no direct conflict between
PURPA’s maximum purchase rate and the Public Service
Law’s higher minimum purchase rate. The language of
PURPA and its legislative history indicate that the
PURPA avoided-cost rate is only the maximum in the con-
text of the federa/ government’s role in encouraging alter-
nate power production (see 16 USC § 824a-3 [b] [it is only
a ‘‘rule prescribed (by FERC) under subsection (a)’’ that
may not require purchase rate higher than avoided cost to
utility]; Joint Explanatory Statement of the Committee of
Conference on PURPA, 1978 US Code Cong. & Admin.
News, pp 7831-7832 [FERC regulation making full
avoided costs the purchase rate was ‘“‘meant to act as an
upper limit on the price at which utilities can be required
under this section to purchase electric energy’’, implies
leaving room for requirements imposed outside this sec-
tion under state law (emphasis added)].’

Moreover, FERC determined thai independent, com-
plimentary state regulation in the field was not supplanted
by PURPA but could be used to expand the federal

"While not conclusive on this issue, there are numerous references
in the Congressional debates and legislative history indicating Con-
gress’s recognition of the traditional role of the States in electric utility
regulation and a desire not to infringe upon or impair the state role
(see 124 Cong Rec 34558 [Sen. Jackson, ‘‘[T]he essential feature of the
conference agreement is the limited nature of the authority granted to
the FERC’’}; 123 Cong Rec 32403 [Sen. Durkin, ‘‘{I] do not want to
abrogate State law with respect to the regulation of utilities’’]; Con-
ference Rep. No. 95-1750, 95th Cong., 2nd Sess., reprinted in 1978 US
Code Cong & Admin News, p 7831 [the limitation in § 210 of PURPA
of sales by qualifying facilities at wholesale was not intended to ‘‘limit
the States from allowing such sales to take place’’]). PURPA has been
characterized as a ‘‘limited federal regulation * * * on the relation-
ships between cogenerators and electric utilities’’ (FERC v Missis-
sippi, 456 US 742, 758). In addition, PURPA reserved to the States a
large role in implementing, enforcing, and administering the program
after FERC promulgated its regulations (see 16 USC § 824a-3 fal,
[e-g]).

a eee

A et ae me ee

9a

PURPA-based incentives.* As the administrative agency
charged by Congress with implementation of PURPA (see
16 USC 824a-3[a], [h]), FERC’s interpretation should or-
dinarily be deferred to (see Zenith Radio Corp. v United
States, 437 US 443, 450; Train v Natural Resources
Defense Council, 421 US 60, 87), unless it is arbitrary,
capricious or an abuse of discretion (see Amer. Paper Inst.

‘In the Preamble to FERC’s regulations (45 Fed Reg at
12221-12222, § 292.304 Rates for Purchases-Relation to State Pro-
gram), FERC left the States free to utilize their own means of en-
couraging alternate energy production, stating:

The Commission has become aware that several States
have enacted legislation requiring electric utilities in that
State to purchase the electrical output of facilities * * * at
rates which may differ from the rates required under the
Commission’s rules implementing section 210 of PURPA.

This Commission has set the rate for purchases at a
level which it believes appropriate to encourage cogenera-
tion and small power production, as required by section
210 of PURPA. While the rules prescribed under section
210 of PURPA are subject to the statutory parameters, the
States are free, under their own authority, to enact laws or
regulations providing for rates which would result in even
greater encouragement of these technologies. However,
State laws or regulations which would provide rates lower
than the Federal standards would fail to provide the re-
quisite encouragement to these technologies, and must
yield to Federal Law.

If a State program were to provide that electric
utilities must purchase power from certain types of
facilities, among which are included ‘‘qualifying
facilities,’’ at a rate higher than that provided by these
rules, a qualifying facility might seek to obtain the benefits
of that State program. In such a case, however, the higher
rates would be based on State authority to establish such
rates and not on the Commission rules. * * *

The Commission finds no inconsistency in a facility’s
taking advantage of section 210 in order to obtain one of
its benefits, while relying on other authority under which
io buy from or sell to a utility.

(Preamble to FERC Rules, 45 Fed Reg, 12214, 12221-12222.)

10a

v Amer. Elec. Power Serv. Corp., 461 US ; ,&n
7; 103 S Ct 1921, 1927-1928, & n 7).

Neither does adherence to the Public Service Law
thwart the objectives of PURPA. The purposes of both
the state and federal statutes are identical; they seek to en-
courage the development of alternate energy production
(see Public Service Law, § 66-c[1]). The state statute does
not hinder the federal objective; it furthers it, by enhanc-
ing the bargaining position of the alternate energy
developer through a predictable, guaranteed rate of 6
cents per kilowatt hour. The federal avoided-cost standard
requires complicated calculations and may fluctuate
greatly depending on, for example, the availability of inex-
pensive hydro-electric power, which will likely reduce the
utility’s avoided costs. The stability provided by the Public
Service Law to the alternate energy producers reduces the
perceived risk of a project, encourages investment, and
facilitates financing.

Petitioner asserts, however, that there is an equally
strong objective of PURPA—to avoid consumer-
ratepayer subsidies of the alternate energy producer.
Arguably, allowing the State to impose a higher rate than
avoided cost will conflict with this objective by inevitably
leading to subsidies, as the utilities will pass their increased
costs of purchasing power along to the consumer.

Petitioner misconstrues the importance of this objective
to the overall purpose of PURPA. The impact of the
utilities’ mandated purchase rate on the cost to consumer
ratepayers was but one factor that FERC was obliged to
consider when it established avoided costs as the max-
imum rate to be imposed by federal authorities (see Amer.
Paper Inst. v Amer, Elec. Power Service Corp., 461 US

: & n__., 103 S Ct 1921, 1928-1929, & n 9,
supra). The Supreme Court has noted that the PURPA re-
quirement that FERC establish purchase rates “‘just and
reasonable to the electric consumers,’” did not mandate

lla

adoption of the lowest possible reasonable rate (see id. at
—___, 103 S Ct at 1928, supra). The full-avoided-cost
regulation was upheld because FERC was found to have
met its obligation to consider the consumer’s interest even
though the adopted rate would not provide any ratesav-
ings. FERC’s explanation, that it was more important that
the rate “‘provide a significant incentive for a higher
growth rate’’ (see 45 Fed Reg at 12222-12223) and that the
resulting decreased reliance on fossil fuel and increased
energy efficiency would benefit the ratepayers and the na-
tion as a whole (see id.), was accepted by the Court as
reasonable and, therefore, was upheld (see Amer. Paper
Inst. v Amer. Elec. Power Serv. Corp., 461 US ___,
___., 103 S Ct 1921, 1929, supra). Thus, failure to achieve
consumer ratesavings is not necessarily abhorrent to the
primary purpose of PURPA, which is to encourage
development of cogeneration and small power facilities
(see ‘d. at ____, 103 S Ct at 1924, supra).

Similarly, while it is recognized that ratesavings may not
be achieved for consumers under section 66-c of the Public
Service Law because the 6 cents per kilowatt hour rate may
at times exceed current avoided costs, at least in the short
run’ (see Governor’s Bill Jacket, [L 1981, ch 843]; Gover-
nor’s Memorandum on approval of L 1981, ch 843,
McKinney’s Session Laws, pp 2627-2628), the rate does
nevertheless further PURPA’s objective because it en-
courages alternate energy production, and in a manner
Suited to the needs of this State.

In sum, as none of the criteria for preemption are pre-
sent, the PSC has the authority to require utilities to offer
to purchase power from federal qualifying facilities (in-
cluding those which qualify under both PURPA and the
Public Service Law). The PSC may also require a utility to

“If the price of fuels such as oil and gas goes up along with other
costs of producing energy, the utilities ‘tavoided cost’’ will be higher
and may grow to exceed the rate of 6 cents per kilowatt hour.

offer to purchase power from federal qualifying facilities
at a minimum rate of 6 cents per kilowatt hour'® in accor-
dance with section 66-c of the Public Service Law.

The second issue is whether part Il of the Federal Power
Act (FPA) (see 16 USC §824, et. seq.) preempts the PSC
from compelling utilities to offer to purchase power from
facilities that qualify only under the Public Service Law.

This court holds that it does. The FPA would also
preempt state regulation of the federal qualifying facilities
in New York except that they are exempted from the FPA
under section 210(e) of PURPA (see 16 USC $824a-3[e]; 18
CFR 292.602). The purely state qualifying facilities,
however, are not eligible for this federally authorized ex-
emption because they are not covered by PURPA."

Part II of the FPA applies ‘‘to the sale of electric energy
at wholesale in interstate commerce’’ (16 USC § 824{b)).
Such a sale is in ‘‘interstate commerce’’ if the electric
energy is ‘‘transmitted from a State and consumed at any
point outside thereof’’ (16 USC § 824[c]). The FPA was
enacted to ‘‘fill the gap’’left by the Supreme Court’s deci-
sion in Public Utilities Comm’n v Attleboro Steam & Elec-
tric Co. (273 US 83), which held that the states lacked
power to regulate interstate sales of electricity at
wholesale. Exclusive regulatory authority was delegated to
FERC under the FPA (see New England Power Co. v New
Hampshire, 455 US 331, 340).

There is no dispute that if transactions between peti-

tioner and purely State qualifying facilities for the pur-
chase of electricity are sa/es at wholesale in interstate com-

‘°Of course, if the utility’s avoided costs become higher than 6
cents per kilowatt hour, federal law would then require that the
avoided-cost rate be used (see FERC Preamble, 45 Fed Reg at 12221).

''It is assumed that the purely state qualifying facilities discussed
here are not exempt from the FPA for another reason (see 16 USC
§ 824 [f]), in which case they would be subject to the State Public Serv-
ice Law.

l3a

merce, the FPA preempts any state regulation in the area
(see New England Power Co. v New Hampshire, supra at
p 340-341; FPC v Southern California Edison Co., 376 US
205, 210).

The PSC asserts two arguments refuting FERC’s ex-
clusive jurisdiction over purely state qualifying facilities.
One is that the FPA only concerns regulations of ‘‘sales’’
and therefore, only the ‘‘seller’’. Thus, it is reasoned that
the PSC’s attempt to regulate a utility’s purchase rate is
merely a permissible regulation of the ‘‘purchaser’”’, which
Congress intended to leave to the states. The second is that
the energy produced by a local state qualifying facility and
purchased by a state utility is admittedly a sale for resale to
the utility’s New York State consumers but it is not in in-
ferstate commerce because the energy originates and re-
mains within the state.

As to the permissible-‘‘purchaser’’- regulation argu-
ment, there is no doubt that this State has long regulated
utilities (see Public Service Law, §§ 110[4]; 66[12]) and
that such regulation is ‘‘one of the most important of the
functions traditionally associated with the police power of
the States’’ (see Arkansas Elec. Co-op v Arkansas Public
Comm., __~ US ; , 103 S Ct 1905, 1908, supra).
Equally clear is the fact that the FPA did leave much
regulation of utilities to the states and that Congress did
not want to interfere with states’ rights in this area (see 16
USC §§ 824[a] [‘‘such Federal regulation, however, to ex-
tend only to those matters which are not subject to regula-
tion by the States.’’], 824[b] [FPA ‘‘shall not apply to any
other sale of electric energy’’]). While facially appealing, '
the argument distinguishing the admittedly preempted
regulation of sellers of wholesale electricity (on-site
generators) from purchasers in the same transactions (the
utilities) is, upon closer examination, untenable. Such a
distinction would simply achieve indirectly that which is

A “sale of electric energy at wholesale’’ is defined as ‘‘a sa/e of
electric energy /o any person for resale’’ (16 USC § 824[d] [emphasis
added]), which would imply regulation of only the seller, who sells so
another, not the buyer who purchases /rom another.

14a

not permitted directly (see Northern Natural Gas Co. v
State Corp. Commission of Kansas, 372 US 84, 91-93.) In
Northern Natural Gas, a state’s attempt to require in-
terstate pipeline companies to purchase gas ratably trom
local, state wells was rejected as an indirect attempt to im-
permissibly regulate wholesale prices of natural gas in in-
terstate commerce, which could ‘‘seriously impair’
FERC’s ability to regulate in the field.'’

The PSC’s second argument is readily disposed of. An
analysis under the FPA of whether a wholesale sale of
electricity from an on-site generator to a utility is purely
intrastate turns on scientific evidence regarding whether
any of the electricity involved originates or is consumed
outside the state (see FPC v Florida Power & Light Co.,
404 US 453, 454-455 [FERC jurisdiction upheld on basis
of scientific and technical evidence that was used to
determine that electrons from a Florida utility eventually
flowed into Georgia because of ‘‘commingling’’ of elec-
trons at the point of interconnection with Georgia utility
lines]).

It may be, as the PSC contends, that sales by the purely
state qualifying facilities to petitioner remain intrastate;
indeed, petitioner admits that some may be.'* However,
this basis for state regulation, which requires scientific
evidence regarding the flow of electricity, was not relied
upon by the PSC in its decision. ‘‘A fundamental principle
of administrative law long accepted by this court timits

'’While Northern Natural Gas was decided under the Natural Gas
Act (15 USC 717-717w), the distribution of regulatory power between

the federal and state governments is the same under the FPA (see /PC

v Southern California Edison Co., 376 US 205, 211-212).

'*Even if some electrons ultimately flow out of state, this state
regulation may have only an incidental effect on interstate commerce
while furthering legitimate local public interests and, thus, would not
offend the Commerce Clause (see Arkansas Elec Co-op Corp. v
Arkansas Public Com’n, —— US aus eS Ce ISS,
1915-1918). Arguably, if the Commerce Clause is not violated, the
State qualifying facility may not be subject to FERC’s jurisdiction
under the FPA (see /d.).

1Sa

judicial review of an administrative determination solely
to the grounds invoked by the agency, and if those
grounds are insufficient or improper, the court is
powerless to sanction the determination by substituting
what it deems a more appropriate or proper basis’’ (M/o
Trump-Equitable Fifth Ave. Co. v Gliedman, 57 NY2d
588, 593 [citations omitted]). The sole ground relied upon
by the PSC, permissible regulation of purchases of
wholesale electricity in interstate commerce, is erroneous,
and thus, the PSC’s assertion of jurisdiction over purely
state qualifying facilities is preempted by the FPA.

Accordingly, the order of the Appellate Division should
be modified by reinstating the determination of the Public
Service Commission insofar as it permits imposition on
utilities of a minimum purchase rate of 6 cents per
kilowatt hour for electricity generated by federal qualify-
ing facilities which also qualify under the Public Service
Law and, as so modified, affirmed.

Judgment modified, with costs to appellant, in accord-
ance with the opinion herein and, as so modified, af-
firmed. Opinion by Chief Judge Cooke. Judges Jones,
Wachtler, Meyer, Simons and Kaye concur. Judge Jasen
took no part.

Decided October 25, 1984

16a

Appendix B—Opinion of the New York Supreme Court,
Appellate Division, Third Judicial Department, De-

cember 30, 1983
STATE OF NEW YORK, SUPREME COURT

APPELLATE DIVISION—THIRD DEPARTMENT

#44910
IN THE MATTER
OF
CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.,
Petitioner,

against

PUBLIC SERVICE COMMISSION OF THE STATE OF NEW

YORK,

Respondeni,

and
BROOKLYN UNION GAS COMPANY,

Intervenor-Respondent.

Argued, November 22, 1983.
Decided, December 30, 1983.

17a

Before:

Hon. A. Franklin Mahoney,
Presiding Justice,
Hon. T. Paul Kane,
Hon. Robert G. Main,
Hon. Paul J. Yesawich, Jr.,
Hon. Leonard A. Weiss,
Associate Justices.

PROCEEDING pursuant to CPLR article 78 (transferred
to the Appellate Division of the Supreme Court in the
Third Judicial Department by order of the Supreme Court
at Special Term, entered in Albany County) to review cer-
tain aspects of a determination of the Public Service Com-
mission which established terms and conditions for the
purchase of electricity from cogeneration and small power
production facilities.

Kronish, Lieb, Shainswit, Weiner & Hellman (Bernard
L. Sanoff of counsel), and Joy Tannian, Peter Garam,
John D. McMahon and Celeste A. Contrucci for peti-
tioner.

David E. Blabey (Howard J. Read of counsel), for re-
spondent.

Cullen & Dykman (William R. Coleman, Joseph P.
Stevens, James F. Matthews and Theresa Mady Grove of
counsel), for intervenor-respondent.

Chadbourne, Parke, Whiteside & Wolff for American
Paper Institute, Inc., amicus curiae.

18a
MAIN, J.

On November 9, 1978, the Public Utility Regulatory
Policies Act of 1978 (PURPA) was signed into law as part
of the Federal response to the nationwide energy crisis.
Section 210 of PURPA (US Code, tit 16, § 824a-3) was
designed to encourage the development of alternate energy
sources, and thereby decrease dependence on traditional
fossil fuels, by requiring the Federal Energy Regulatory
Commission (FERC) to adopt rules requiring, inver alia,
electric utilities to purchase electric energy from any co-
generation facility or small power production facility
qualifying under Federal rules' (US Code, tit 16, § 824a-3,
subd [a]). Section 210 of PURPA further provides that the
rate established by FERC for the purchase of such elec-

tricity:

‘“(1) shall be just and reasonable to the electric con-
sumers of the electric utility and in the public interest, and

(2) shall not discriminate against qualifying
cogenerators or qualifying small power producers.

‘‘No such rule prescribed under subsection (a) of this
section shall provide for a rate which exceeds the in-

‘A *‘cogeneration facility’’ is defined as one that produces both
electric energy and steam or some other form of useful energy, such as
heat (US Code, tit 16, § 796, subd [18], par [A]). A “‘small power pro-
duction facility’’ is defined as one that has a production capacity of
not more than 80 megawatts and uses biomass, waste, geothermal
resources or renewable resources, such as wind, water or solar energy,
to produce electric power (US Code, tit 16, § 796, subd [17], par [A]}).
We will refer to such facilities together as Federal qualifying facilities.

19a

cremental cost to the electric utility of alternative electric
energy’’’ (US Code, tit 16, § 824a-3, subd [b]).

This section also permits FERC to exempt Federal qualify-
ing facilities from certain Federal and State laws governing
electric utilities if such was deemed necessary to encourage
cogeneration and small power production (subd [e]).
Under section 210 of PURPA, State regulatory authorities
are charged with implementing the rules promulgated by
FERC (subd [f]). These rules, in 1980, were promulgated
by FERC (18 CFR part 292) and they established the rate
for the purchse of electricity from Federal qualifying
facilities at the avoided cost (18 CFR 292.304[b] [2]), the
Statutory maximum rate, and ruled that all Federal quali-
fying facilities eligible for the exemption should be exempt
from certain provisions of the Federal Power Act (18 CFR
292.601).

Also in 1980, New York State enacted legislation, like
PURPA, designed to develop alternate energy sources by
encouraging cogeneration and small hydro facilities
(Public Service Law, § 66-c, subd 1). The definitions for
such facilities (Public Service Law, § 2, subds 2-a—2-c)
overlap aspects of the Federal definitions, but are not
identical thereto.’ The State law, as amended, further re-
quires electric utilities to enter into long-term contracts to
purchase electricity or useful thermal energy from State
qualifying facilities under terms that are ‘‘just and
economically reasonable to the corporation’s ratepayers,
non-discriminatory to [State qualifying facilities] and [in

*This ‘‘incremental cost’’ is defined as the cost to the utility of the
electric energy which, but for its purchase from a Federal qualifying
facility, the utility would generate or purchase from another source
(US Code, tit 16, § 824a-3, subd [d]) and shall be referred to herein as
either incremental cost or avoided cost.

*The cogeneration and small hydro facilities defined by State law
shall be referred to as State qualifying facilities.

20a

furtherance of] the public policy’’ behind the legislation,
but at a sales price not less than 6 cents per kilowatt hour
(Public Service Law, § 66-c, subd 1, par [a]).

Proceedings to implement the Federal and State legisla-
tion and regulations were held before respondent Public
Service Commission (PSC) and culminated in an opinion
issued May 12, 1982. On September 9, 1982, petitioner
Consolidated Edison Company of New York, Inc., insti-
tuted this CPLR article 78 proceeding to review various
aspects of the PSC’s opinion. After this proceeding was
transferred to this court, petitioner and the PSC stipulated
to hold the case in abeyance pending the outcome of
American Paper Inst. v American Elec. Power Serv.
Corp. (461 US , 103 S Ct 1921), then before the
Supreme Court and since decided. Based on the decision in
American Paper, which upheld the validity of FERC’s
rules under section 210 of PURPA, and Arkansas Elec.
Coop. Corp. v Arkansas Public Serv. Comm. (461 US
___, 103 S Ct 1905), decided the same day, petitioner
dropped all out the three issues concerning the rates for
the purchase of electricity from Federal and State qualify-
ing facilities now before us. We note that we granted leave
to intervene to Brooklyn Union Gas Company and leave
to file a brief amicus curiae to American Paper Institute,
Inc.

Petitioner challenges two of the PSC’s determinations
on pre-emption grounds. First, petitioner contends that
the PSC’s determination requiring it to purchase elec-
tricity from on-site generators that are not Federal qualify-
ing facilities is invalid as contrary to the Federal Power
Act (FPA) (US Code, tit. 16, § 791a er seq.), under which
wholesale sales of electricity from on-site generators to
electric utilities in interstate commerce are subject to
FERC’s exclusive jurisdiction (US Code, tit 16, § 824).
Second, petitioner contends that the State-mandated mini-

2la

mum purchase rate of 6 cents per kilowatt hour is at times
higher than the Federal rate of avoided cost set by FERC
and, thus, is invalid as contrary to Federal law.

[1-3] Initially, we reject the procedural challenges to
petitioner’s claims. The PSC failed to raise at the ap-
propriate time petitioner’s alleged lack of standing and
failure to exhaust its administrative remedies and, thus, we
deem these challenges to be waived (see Matter of Hilton
v Dalsheim, 81 AD2d 887, 888; Matter of Cook v Town
of New Scotland, 75 AD2d 703, 704; see, also, CPLR
7804, subd [f]). We further note that although the PSC did
not comment on the first pre-emption ground raised by
petitioner, apparently because petitioner did not raise it at
the time of the enactment of the State legislation before
the administrative law judge’s recommended decision, we
shall entertain this issue because petitioner did raise it in
submissions before the PSC’s final opinion. Likewise, we
reject Brooklyn Union’s claim that petitioner’s second
pre-emption ciaim is an impermissible collateral attack on
the PSC’s reliance on FERC’s Order No. 69 because the
rule against such attacks of administrative determinations
is not applicable where the agency acted outside its
jurisdiction in a manner not authorized by statute (see,
e.g., 2 NY Jur 2d, Administrative Law, §§ 150, 176, pp
236, 282), which is petitioner’s claim herein.

[4-5] On the merits, we conclude that Federal law has
pre-empted this area and that New York State law or regu-
lations cannot require petitioner to purchase electricity
from on-site generators unless they are Federal qualifying
facilities or to purchase electricity from such facilities at a
rate greater than the Federally mandated rate. A review of
the legislative intent behind the enactment of section 210
of PURPA as well as the legislative framework of the FPA

22a

and PURPA, ieads us to this result. In reaching this con-
clusion, we emphasize that the policy being addressed is
the Federal policy of developing alternate energy sources
to combat the nationwide energy crisis and not the State
policy of utility regulation. The Federal Government has
undertaken substantial activity in the energy field to
benefit the Nation as a whole and, where State action is
contrary, it must fall (see, e.g., Fidelity Fed. Sav. & Loan
Assn. v De La Cuesta, 458 US 141, 152-154; Chicago &
North Western Transp. Co. v Kalo Brick & Tile Co., 450
US 311, 317).

[4] The authority of FERC, and its predecessor the
Federal Power Commission, to regulate, under the FPA,
wholesale sales of electricity in interstate commerce, no
matter how small the interstate effect, is well established
(see, e.g., US Code, tit 16, § 824, subd [b]; Federal Power
Comm. v Florida Power & Light Co., 404 US 453; Federal

Power Comm. v Southern Cal. Edison Co., 376 US 205,
215-216). The PSC claims that the Supreme Court, in
Arkansas Elec. Coop. Corp. v Arkansas Public Serv.
Comm. (461 US ___, 103 S Ct 1905, supra), modified
FERC’s authority by permitting State regulation of
wholesale sales if the impact on interstate commerce was
not undue. The Supreme Court in that case, however, per-
mitted State regulation of wholesale sales of electricity
under the legislative framework of the Rural Electrifica-
tion Act (REA) and not the FPA, thus rendering the case
suspect as authority for modification of FERC’s jurisdic-
tion under the FPA.

The Supreme Court noted, though, that the State’s
authority to regulate such wholesale sales under the REA

would be pre-empted if the Federal agency with jurisdic-
tion ‘‘changes its present policy, and announces that state

rate regulation of rural power cooperatives is inconsistent

23a

with federal policy’’ (461 US, at p __, 103 S Ct, at pp
1914-1915). In this case, a somewhat different scenario ex-
ists, but the Supreme Court’s language is instructive.
FERC, the agency which has historically regulated whole-
sale sales of electricity in interstate commerce, did not an-
nounce any change in its policy of exclusive jurisdiction
over such wholesale sales, but merely acquired additional
statutory options under PURPA. Moreover, PURPA it-
self, enacted against the backdrop of the FPA and FERC’s
exclusive jurisdiction, did not herald any changes in
FERC’s jurisdiction except those specifically provided in
the statutory language, none of which transfers such
jurisdiction to State regulatory agencies. Consequently,
the PSC has no authority to act in this area.

[5] We also conclude that to the extent that the State re-
quirement of a 6 cents per kilowatt hour minimum pur-
chase price conflicts with the Federal rule establishing a
purchase price of avoided cost, the State requirement has
been pre-empted and is invalid. Our review of the legis-
lative history of section 210 of PURPA indicates that Con-
gress intended States to follow the Federal regulations and
not depart from them, especially with regard to the pur-
chase price provision. For example, the Joint Explanatory
Statement of the Committee of Conference on PURPA
stated that ‘‘[section 210] requires that States and utilities
follow rules which the Federal Energy Regulatory Com-
mission is to prescribe’? (US Code Cong & Admin News,
1978, p 7831) and that ‘‘[t}his [avoided cost] limitation on
the rates which may be required in purchasing [electricity
under section 210] is meant to act as an upper limit,on the
price at which utilities can be required under this section to
purchase electric energy’’ (id., at p 7832). Thus, it is ap-
parent that Congress did not intend for States to establish

24a

rates in excess of the Federal rate, established as the
statutory maximum of avoided cost.

This interpretation finds support in the recent Supreme
Court decision in American Paper Inst. v American Elec.
Power Serv. Corp. (461 US __, 103 S Ct 1921, supra). In
that case, the Supreme Court interpreted the ‘“‘just and
reasonable to the electric consumers’’ clause of subdivi-
sion (b) of section 210 of PURPA as requiring considera-
tion of rate savings for consumers (supra, p __, n 9, p
1929, n 9). Such savings are impossible if the State can
establish rates in excess of avoided cost. We are not per-
suaded by the fact that the State’s 6 cents per kilowatt
hour rate is greater than avoided cost at only certain times,
and then by only a very small amount. If we were to ap-
prove the State’s 6-cent minimum in the face of the lower
Federal maximum, we would be establishing a principle
which would permit even higher State minimum rates
despite lower avoided costs with the concomitant effect of
further limiting potential rate savings for consumers. In-
deed, at oral argument the PSC conceded that petitioner
may have to pay more for electricity under State law than
the avoided cost (see, also, Governor’s approval
memorandum, NY Legis Ann, 1981, pp 445-446). We
decline to approve this State law in the face of contrary
Congressional intent and Supreme Court language.

We further note that American Paper Institute’s conten-
tion that Federal Energy Regulatory Comm. v Mississippi
(456 US 742) recognizes PURPA’s intent to provide States
with an authority to go beyond the Federal standards
established in section 210 of PURPA is without merit. For
example, the Supreme Court’s reference to PURPA as
‘* “cooperative federalism that allows the States, within
limits established by federal minimum standards, to enact
and administer their own regulatory programs, structured

io meet their own particular needs’ ”’ (supra, at p 767) is

25a

found in a discussion of titles | and II] of PURPA, not of
section 210. Likewise, the fact that FERC, in explaining its
regulations, has indicated that States may prescribe pur-
chase rates higher than avoided cost see, e.g., 45 Fed Reg
12221) does not require us to decide differently. Although
administrative interpretations are usually accorded great
deference, such interpretations need not be followed when
contrary to legislative intent (see, e.g., Public Serv.
Comm. v Mid-Louisiana Gas Co., 463 US ; , 103
S Ct 3024, 3035, 3037). As noted, Congress clearly intend-
ed that States follow FERC rules and that avoided cost be
the maximum purchase price. Accordingly, the State mini-
mum purchase rate of 6 cents per kilowatt hour has been
pre-empted and cannot be enforced.

[6] The final challenge by petitioner is to the PSC’s
determination requiring it to give a capacity credit at $21
per kilowatt for electricity supplied by on-site generators
during the summer peak period. The PSC’s determination
must be upheld if it has a rational basis and is supported
by substantial evidence in the record (see, e.g., Matter of
New York State Council of Retail Merchants v Public
Serv. Comm., 45 NY2d 661, 672). Our consideration of
this issue and review of the record leads us to conclude
that this determination should be upheld. The record
reveals that petitioner charges its largest customers $21 per
kilowatt to purchase electricity during summer peaks on
the basis that they should pay for capacity costs. Although
there may be some uncertainty about the power output of
the on-site generators, evidence discloses that a supply of
electricity at the .k period has the same effect as a
customer’s refraining from using electricity during that
period and, thus, it is reasonable that the on-site generator
supplying the electricity receive a credit for the capacity in
ihe amount that the purchasing customer would have been

26a

charged. This rationale is consistent with FERC’s ap-
proach to alternate energy sources which have some uncer-
tainty in their power output but which can supply max-
imum power during the summer peaks, such as photo-
voltaic cells (45 Fed Reg 12225), as well as FERC’s regula-
tion, pursuant to PURPA, that electricity be purchased at
avoided cost. Thus, the PSC’s determination requiring a
capacity credit as noted above should be upheld as having
a rational basis and support in the record.

The determination should be modified, without costs,
by annulling so much thereof as asserted jurisdiction over
and made rules regarding wholesale sales of electricity by
non-Federal qualifying facilities and as required a mini-
mum purchase price of electricity generated by Federal
qualifying facilities in excess of avoided costs, and, as so
modified, confirmed.

MAHONEY, P. J., KANE, YESAWICH, JR., and WEISS,
JJ., concur.

Determination modified, without costs, by annulling so
much thereof as asserted jurisdiction over and made rules
regarding wholesale sales of electricity by non-Federal
qualifying facilities and as required a minimum purchase
price of electricity generated by Federal qualifying
facilities in excess of avoided cost, and, as so modified,
confirmed.

27a

Appendix C—Final Judgment of the Court of Appeals of
the State of New York, October 25, 1984

Remittitur
COURT OF APPEALS
STATE OF NEW YORK
e
3 No. 438

IN THE MATTER
OF
CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.,

. Respondent,

v.
PUBLIC SERVICE COMMISSION OF THE STATE OF NEW
YORK,

Appellant,
OCCIDENTAL CHEMICAL CORPORATION,
Intervenor,
and

THE BROOKLYN UNION GAS COMPANY,

Intervenor-Respondent.

The Hon. Lawrence H. Cooke, Chief Judge, Presiding

28a

The appellant in the above entitled appeal appeared by
David E. Blabey, Esq. the respondent appeared by Joy
Tannian, Peter Garam, John D. McMahon & Celeste A.
Contrucci, Esqs. and Kronish, Lieb, Shainswit, Weiner
&c: and Intervenor appeared by Whiteman, Osterman &
Hanna, Esqs. and Sutherland, Asbill & Brennan, Esqs.

The Court, after due deliberation, orders and adjudges
that the judgment is modified, with costs to appellant, in
accordance with the opinion herein and, as so modified,
affirmed. Opinion by Chief Judge Cooke. Judges Jones,
Wachtler, Meyer, Simons and Kaye concur. Judge Jasen
took no part.

The Court further orders that the papers required to be
filed and this record of the proceedings in this Court be
remitted to the Supreme Court, Albany County, there to
be proceeded upon according to law.

I certify that the preceding contains a correct record of

the proceedings in this appeal in the Court of Appeals and
that the papers required to be filed are attached.

Court of Appeals, Clerk’s Office, Albany, October 25,
1984

/s/DONALD M. SHERAW
DONALD M. SHERAW
Clerk of the Court

29a

Appendix D—Opinion and Order of the Public Service
Commission of the State of New York, May 12, 1982

STATE OF NEW YORK

PUBLIC SERVICE COMMISSION

COMMISSIONERS:
Paul L. Gioia, Chairman
Edward P. Larkin
Carmel Carrington Marr
Harold A. Jerry, Jr., dissenting
Anne F. Mead
Richard E. Schuler
Rosemary S. Pooler, not participating

CASE 27574—CONSOLIDATED EDISON COMPANY
OF NEW YORK, INC.—Electric Service Provided
to Customers With On-Site Generation

OPINION NO. 82-10

OPINION AND ORDER ESTABLISHING RATES,
CHARGES, RULES AND REGULATIONS FOR
ELECTRIC SERVICE PROVIDED TO CUS-
TOMERS WITH ON—SITE GENERATION.

(Issued May 12, 1982)
BY THE COMMISSION:

INTRODUCTION

In our Order instituting this proceeding, we observed
that the establishment of time-of-use rates for certain large
commercial and industrial customers of Consolidated
Edison Company of New York, Inc. (Con Edison or the

30a

company)! ‘‘might have an impact on the demand for on-
site generation in Con Edison’s service territory and that
this in turn might require changes in Con Edison’s other
electric service offerings.’’? We observed further:

Consumers who are interested in generating their
own electricity are likely to want to receive
breakdown, reserve, or auxiliary service from Con
Edison. In addition, they may be interested in sell-
ing electricity to Con Edison in times when they
find that their generating capacity is more than suf-
ficient for their needs. Con Edison currently pro-
vides back up service only under its S.C. 3
-Breakdown, Reserve, and Auxiliary Service tariffs
and offers to buy electricity only from customers
operating windmills. The S.C. 3 tariff requires a
customer to contract for a specific amount of
power, and pay a monthly demand charge for the
higher of that amount or the highest actual demand
over the past eleven months, whether service 1S
taken or not. Customers also pay an energy charge
based on their actual monthly consumption.

The prospect of a growing demand for on-site
generation and cogeneration in the City of New
York and for independent generation using water
power and other sources outside the City has raised
a number of environmental, tax, revenue require-
ment, and rate design issues. Our concern here is to
determine whether (1) Con Edison’s tariffs are an
obstacle to on-site generation, and (2) its service
rates for these customers are cost justified. We
want to begin the search for rate structures that
properly accommodate utility customers who can
sell as well as buy electricity.

‘Case 27029, Consolidated Edison Company of New York, Inc.
-Electric Rate Structure, Opinion No. 79-6 (issued March 15, 1979).

*Case 27574, Consolidated Edison Company of New York, Inc.
-On-site Generation, Order Instituting Proceeding (issued June 22,

1979), at mimeo p. I.

3la

On-site generation by utility consumers raises
two kinds of rate issues. The first is the determina-
tion of the correct price for utility service which is
auxiliary to, or backup for, the customer-generated
power. The second is the determination of the price

for electricity which the customer may sell back to
the utility. |

The Potential increase in demand for on-site
generation and backup service from Con Edison
convinces us that a review of the rates, terms and
conditions under which service is offered in this
market would be worthwhile at this time. Our goal
is to see that the Con Edison tariffs are neither an
artificial barrier, nor a spur, to the development of
on-site generation in its service territory. Of
Primary importance is whether the existing rate
levels and design are justified by properly measured
economic costs. But we will also expect the com-
pany to demonstrate that the terms and conditions
under which it provides the service are neither ar-
bitrary nor discriminatory.

Our consideration of these matters will be in light
of the requirements of Section 210 of the federal
Public Utility Regulatory Policies Act of 1978
[PURPA]. Because policy issues of significance to
our treatment of rates charged to customers with
on-site generation outside Con Edison’s service ter-
ritory may be resolved in this case, we will permit
other utilities, their customers, and other interested
parties to participate in this proceeding.

Hearings in this proceeding were held in New York City
and Albany on 38 days between September 25, 1979 and
April 10, 1981, the first of which was a public statement
hearing in the former city at which nine persons submitted

32a

statements in support of the encouragement of on-site
generation. The evidentiary record consists of 132 exhibits
and 6,682 pages of testimony.

On September 21, 1981, Administrative Law Judge
John T. Vernieu’s Recommended Decision was issued. In
it, the Judge addressed himself to the myriad of generic
and company-specific issues concerning ratemaking
guidelines, interconnection standards, and ‘‘social cost’’
issues raised by various parties to this proceeding. His
decision can perhaps most concisely be described as giving
substantial encouragement to the development of on-site
generation, to the dissatisfaction of the utility parties but
not entirely to the satisfaction of certain of the parties
favoring on-site generation. Accordingly, briefs on excep-
tions have been received from the following parties:
Department of Public Service staff (staff), Con Edison,
Central Hudson Gas & Electric Corporation (Central
Hudson), Niagara Mohawk Power Corporation (Niagara
Mohawk), Orange and Rockland Utilities, Inc. (Orange
and Rockland), Rochester Gas and Electric Corporation
(RG&E), the Owners Committee on Electric Rates and the
Greater New York Hospital Association (OCER), the New
York State Energy Office (SEO), the City of Rochester,
the Borough of Manhattan, the City of New York Energy
Office (New York City), Multiple Intervenors, In-Novo
Engineering and Development Company (In-Novo) and
Hon. Joseph Ferris, Member of the Assembly of the State
of New York. Reply briefs have been filed by staff, Con
Edison, Niagara Mohawk, Orange and Rockland, RG&E,
OCER, the Power Authority of the State of New York
(PASNY), New York City, Multiple Intervenors and In-
Novo.

In addition, comments on the Recommended Decision
were filed by Long Lake Energy Corporation (Long Lake)
and, jointly, Boise Cascade Corporation and International
Paper Company (Boise Cascade), parties which previously
had not participated in this case. Although several parties

33a

have requested that the comments not be considered, the
recommendations raised in them either have been raised
by other parties (and thus must be addressed anyway) or
can be at least preliminarily addressed in light of our
resolution of other issues in this proceeding.

Finally, we have given consideration to the recent deci-
sion of the United States Court of Appeals for the District
of Columbia in American Electric Power Service Corpora-
tion v. Federal Energy Regulatory Commission,’ in which
the court remanded to FERC for further consideration it
rules requiring utilities (1) to pay no less than 100% of
their avoided costs to on-site generators for power pur-
chased from them (in the absence of an agreement fixing a
lower amount);‘ and (2) to interconnect with on-site
generators pursuant to guidelines formulated by the
states.’ Comments on this decision have been filed, in
turn, by Con Edison, Assemblyman Ferris, OCER, The
Brooklyn Union Gas Company, Long Lake, Boise
Cascade, staff, In-Novo, the New York State Department
of Law and SEO. We shall discuss this decision at the
various points in our Opinion where it has a bearing on the
issue under consideration.

We now turn to the various »ssues remaining for our
resolution.

COSTING ISSUES
MARGINAL COSTS
Introduction

Section 210 of PURPA directs the Federal Energy
Regulatory Commission (FERC) to formulate regulations
governing the rates utilities are to pay qualifying facilities
for power purchased from them. Subdivision (b) of that

*No. 80-1789 (D.C. Cir., January 22, 1982).

*18 C.F.R. §292.304(b) (2).
18 C.F.R. §§292.303(c) (1).

34a

section requires that ‘‘no such rule . . . shall provide for a
rate that exceeds the incremental! cost to the electric utility
of alternative electric energy,’’ and subdivision (d)
thereunder provides that ‘“‘the term ‘incremental cost of
alternative electric energy’ means . . . the cost to the elec-
tric utility of the electric energy which, but for the pur-
chase from such [qualifying facility], such utility would
generate or purchase from another source.”’

Judge Vernieu observed as follows:

This definition also describes the marginal or in-
crementa! costs that have been adopted by the
Commission as being the costs relevant for rate
design. No one challenges their role as the basis for
rate design for on-site generators. The issues on
which parties disagree are how to calculate these
costs for on-site generation services, how to reflect
them in rate design and how to reconcile marginal
cost prices with revenue requirements.°

The costing issues raised by the parties on exceptions are
basically the same as those described by the Judge. The
Americen Electric Power decision has not added to or
changed these issues; for even if that decision were to re-
quire us to set the price for purchases from on-site
generators at some level less than 100% of avoided
costs—and we do not believe that decision requires us to
do so—we must still determine, as our starting point, what
those costs are.

Marginal cost studies were submitted only by Con
Edison and staff. These parties do not disagree about the
manner in which marginal transmission capacity and
distribution capacity costs should be computed. And
although staff had initially maintained that certain genera-
tion capacity costs are variable at the margin, while the
company maintained that none are, staff has not excepted

*Recommended Decision (R.D.), p. 172.

35a

to the Judge’s recommendation to exclude them from on-
site generation rates on the ground that no marginal
generation capacity costs are reflected in the company’s
existing firm service rate structure.’

Marginal Energy Costs

It is thus only with respect to the computation of
marginal energy costs that there remains some contro-
versy. There is, however, no controversy concerning Con
Edison’s marginal costs. As it had in other rate design
cases, staff contended here that the price for sales to
or—more likely in Con Edison’s case—purchases of
economy energy from the New York Power Pool is the
relevant marginal energy cost for the company. This cost
is termed the ‘‘financial lambda.’’ The company agreed
with this view, but the manner in which it estimated its
financial lambda differed from that employed in other
cases. Basically, the company averaged two amounts:

1. The New York Power Pool running cost or ‘‘Pool
dispatch lambda,’’ that is, the running cost(s) of
the plant(s) on the Pool’s margin at a given time;
and \

2. The company’s internal running cost or ‘‘island
lambda,”’ that is, the cost of the plant the company
would have to run to meet its load but for the inter-
connection with the Pool.

In the company’s view, this averaged cost was a
reasonable approximation of its financial lambda. Staff
agreed, and employed the company’s cost estimates in its
rate proposals. Judge Vernieu concluded that ‘hose
estimates ‘‘can be relied on in this case to develop rates.’”*
No party has excepted to this conclusion.

’These conclusions concerning marginal transmission and genera-
tion costs may change following the conclusion of the company’s
pending rate design case (Case 27353, Phase II).

*R.D., p. 184.

36a

The controversy concerns the Judge’s resolution of the
theoretical dispute between staff, on the one hand, and,
on the other hand, three upstate parties concerning the
proper measure of marginal energy costs for a utility that
is, as Con Edison is not, a net seller of energy to the Pool.
As noted, staff argued that the Pool transaction price, that
is, the financial lambda, is the relevant measure of a com-
pany’s opportunity cost, i.e., the benefits foregone as a
result of meeting an additional increment of on-system
consumption. In the case of a utility which is a net seller to
the Pool—the case which applies to some upstate
utilities—the financial lambda represents the sum of the
internal costs required to generate that increment and the
share of the savings foregone because that increment could
not be sold off-system. The upstate parties—Niagara
Mohawk, RG&E and Multiple Intervenors—argued that
only the internal costs are relevant, because the financial
lambda is not, for a variety of reasons, an accurate
measure of an upstate company’s opportunity to sell off-
system. The utilities also argued that basing payments to
on-site generators on marginal energy costs thus computed
would, in effect, allow the latter to benefit from the
former’s ability to sell power off-system.

The Judge concluded, after a lengthy and technical
analysis, that the proper measure of a selling utility’s
marginal energy costs, which he termed its ‘‘marginal
financial lambda,”’ is in fact that suggested by Con
Edison’s analysis. The rationale for his conclusion is as
follows:

1. The financia! lambda is fixed, roughly, at the
average of the seller’s internal costs and the buyer’s
hypothetical internal costs incurred to supply the
total amonnt of energy transacted between them.

2. The seller’s costs, however, rise as it supplies more
and more of that total amount. Thus, the marginal

37a

profit the seller foregoes when it must meet an in-
crement of on-system consumption is of the
average margin on all sales, contrary to staff’s con-
tention.

3. Instead, the marginal opportunity cost of meeting
an increment of on-system consumption is the
seller’s island lambda plus the change in its share of
the savings resulting from its sales off-system. The
change in its share of the savings, in turn, is half the
difference between its island lambda (the change in
costs the seller would incur without Pool opera-
tions) and the Pool dispatch lambda (the change in
costs incurred to meet the total load served by the
Pool). The marginal opportunity cost thus reduces
to one-half the seller’s island lambda plus one-half
the Pool dispatch lambda—in other words, their
average.’

The Judge did not recommend that this conclusion be
adopted generically at this time; he suggested, instead,
that it be explored further in connection with Niagara
Mohawk’s and/or RG&E’s on-site generation pro-
ceedings, since those parties opposed using Pool opera-
tions for costing purposes. He did find, however, that the
analysis underlying the conclusion is sufficient to warrant
rejection of both staff’s and the upstate parties’ positions.

Staff does not disagree with the analysis; in fact, staff
suggests on exceptions, the computerized model employed
by Con Edison to estimate the marginal financial lambda,
or similar models, can be employed for other utilities.
Thus, it argues, there should be no delay in developing
tariffs based on such models and the Judge’s analysis.

*The actual calculation differs slightly from the foregoing
description, because payments are also made to the Pool’s transmis-

sion fund; but the basic underlying principle is not changed by the fact
that these payments are made.

38a

In their briefs on exceptions, Niagara Mohawk and
RG&E both express uncertainties about the validity of the
analysis; they agree only with the recommendation that
the issue be considered further in their respective on-site
generation proceedings. Neither party, however, suggests
a method that might be employed to develop purchase
rates to be effective pending the outcome of those cases. In
addition, Niagara Mohawk suggests that the method used
by staff in other cases of projecting forward-looking
marginal costs from an historic period’s data is unaccep-
table. Instead, it argues, it should be permitted to employ
its future generation mix when developing internal costs,
and it should also be permitted to use more current fuel
costs when formulating purchase rates.

Multiple Intervenors stand alone in completely rejecting
the propriety of computing marginal energy costs by refer-
ring to anything but a company’s internal costs. Accor-
ding to this party, New York Power Pool transactions can-
not properly be employed in this process, because
economy dispatches are not physically controlled by the
Pool’s dispatch center. Instead, dispatches are merely
scheduled by the Pool, and member utilities are at least
theoretically, if not financially, free to disregard them.
Moreover, it continues, Pool transactions sometimes can-
not take place because of transmission constraints.

Multiple Intervenors’ latter argument is misplaced; for,
as Con Edison points out in response, the model it
employed takes transmission constraints into account.
And the former argument, that economy dispatches can-
not be relied upon because they are merely scheduled
rather than controlled by the Pool, forgets that economy
transactions do in fact take place and that they are priced
according to the dispatch schedule.'®

‘Identical arguments were considered and rejected by us, with
more discussion, in the most recent RG&E and NYSEG electric rate
design cases. See Case 27548, Rochester Gas and Electric Corporation
- Electric Rate Design, Opinion No. 81-6 (issued March 18, 1981), at
mimeo pp. 16-24; Case 27546, New York State Electric & Gas Cor-
poration - Electric Rate Design, Opinion No. 81-21 (issued October
21, 1981), at mimeo pp. 13-24.

39a

The remaining uncertainty about the propriety of adop-
ting the Administrative Law Judge’s analysis now con-
cerns the availability of suitable ‘‘island’’ cost data for the
various utilities, particulary at constrained levels of pro-
duction. Assuming that models of the New York Power
Pool’s operations can provide these data, as staff suggests,
there would be no problem with developing purchase
rates, and Niagara Mohawk’s request that contemporary
and projected fuel and generation mix data be employed in
the costing methodology would be answered. Moreover,
application of the Judge’s analysis now to both Niagara
Mohawk and RG&E will not lead to unacceptable results.
In the former’s last electric rate case, we concluded that its
marginal financial lambda and its financial lambda were
very close;'' and in the latter’s pending electric rate case,'?
it and staff have agreed that its marginal financial lambda
is, at least conceptually, the proper measure of its oppor-
tunity cost of on-system consumption.

In short, we conclude that the benefits of proceeding
now with the energy cost estimation methods developed in
this case warrant our doing so, even if there is a chance
that later analyses may necessitate some changes in the
resulting purchase rates. Accordingly, we shall adopt
staff’s recommendation that the costing model employed
by Con Edison in this case, or a similar model capable of
developing forecasted marginal financial lambdas, be used
to formulate those rates for other utilities in the state.

AVOIDED COSTS
Introduction

No arty excepts to the Judge’s conclusion that genera-
tion and distribution capacity costs should not be reflected

''Case 27984, Niagara Mohawk Power Corporation - Electric
Rates, Opinion No. 82-4 (issued March 8, 1982), at mimeo pp. 96-100.

‘ '*Case 28053, Rochester Gas and Electric Corporation - Electric
ates.

40a

in the rates Con Edison pays for power purchased from
on-site generators, because (1) as noted earlier, marginal
generation costs are not reflected in its existing firm rates;
and (2) distribution costs can be avoided only under cer-
tain conditions not alleged to be pertinent to Con Edison’s
system. Similarly, no party has contended that energy
costs are not avoidable by virtue of such purchases. The
parties disagree, however, about whether marginal
transmission capacity costs are avoidable, as Judge Ver-
nieu concluded. There is also some controversy, next
discussed, concerning the proper measure of avoided
energy costs, stemming from Long Lake’s contention that
the marginal energy costs of the utility to which an on-site
generator is interconnected may not be the proper measure
of avoidable energy costs.

Our resolution of these issues also provides the
background for our consideration of the applicability of
the American Electric Power decision to our own decision
establishing rates for utilities’ purchases from on-site
generators, for the manner in which costs are defined as
‘tavoidable’’ has an important, if not conclusive, bearing
on the propriety of paying full avoided costs for such pur-

chases. We have, accordingly, concluded our discussion of

these issues by relating them to the court’s decision.
Energy Costs

Apart from their disagreements about how these costs
should be determined, the parties to this proceeding agree
that the marginal energy costs of the utility to which an
on-site generator is interconnected are the relevant
measure of the avoided energy costs on the basis of which
the payments to that generator are to be calculated."'
However, Long Lake Energy Corporation, which is not a

'? Under FERC’s regulations, if both a qualifying facility and the
utility with which it is interconnected agree, power generated by that
facility may be delivered to a different utility, which then assumes the
obligation to purchase it.

4la

party to the proceeding but which filed comments (dated
October 23, 1981) on the Recommended Decision, con-
tends that, because of the operations of the New York
Power Pool, there is only one statewide avoided energy
cost: the running costs of the highest-cost generator in the
state that would be operating but for the availability of
economy energy through the Pool. It is this cost that Long
Lake contends should be paid to on-site generators, or, at
least, qualifying hydro-electric facilities. In the alter-
native, Long Lake argues that hydro facilities should be
permitted to sell power directly to the Pool and receive, in
return, a “‘split-savings’’ sale price; or that the utilities to
which they are connected should be compelled to wheel the
power to the highest-cost utility in the state.

If it were permissible for a qualifying facility that is con-
nected to a utility which is selling economy energy to the
Pool to sell energy, on its own behalf, directly to buying
utilities, Long Lake’s position would at least be possible to
implement. Such sales, however, are not authorized by
PURPA or by FERC’s regulations implementing that Act.
Long Lake’s argument forgets that all sales from qualify-
ing facilities to utilities that are connected to an interstate
power grid would be subject to FERC’s ratemaking
jurisdiction but for the exemption that FERC’s regula-
tions grant to transactions between a qualifying facility
and the utility to which it is connected. With one excep-
tion, the exemption only goes that far. Thus, the initial
purchase obligation lies with that utility.

FERC’s regulations authorize a qualifying facility to
impose a purchase obligation on a non-connected utility
only where the connected utility agrees to wheel the power.
FERC has explicitly retained the ratemaking authority
over such wheeling transactions where, as here, they in-
volve utilities already subject to FERC’s jurisdiction. '*
FERC cannot compel a utility to wheel power generated
by a qualifying facility to a particular utility simply to
stimulate production,'’ and we cannot presume to have

‘445 F.R. 12220 (February 25, 1980).
'SSee generally Federal Power Act, §§211 and 212.

42a

greater authority over bulk transmission. Thus, to the ex-
tent that Long Lake’s petition hinges on our issuing a
blanket order providing for mandatory wheeling between
utilities without reference to a specific on-site generation
facility, it must be rejected.

Long Lake claims implementation of its request would
maximize resource savings on a statewide basis. We do not
agree with that contention. We conclude instead that bas-
ing purchase rates on the connected utility’s avoided cost
better serves that end. In the case of a qualifying facility
connected to a utility that is a net buyer from the Pool, a
purchase price that reflects the availability of economy
energy generated by another utility will properly
discourage the development of facilities that may be less
efficient than those of the utility whose production is
available. Where a qualifying facility is connected to a sell-
ing utility, a purchase price equal to the marginal oppor-
tunity cost will stimulate production that is assuredly less
costly than the power that is displaced by that utility’s
sales to the Pool, which sales, in turn, are made possible
by the qualifying facility’s production.'® Thus, purchase
rates based on the connected utility’s marginal oppor-
tunity costs will encourage resource savings while leaving
the customers of the connected utility in no worse position
than if the transactions with the qualifying facility had not
taken place. Long Lake’s proposal, on the other hand,
would literally transfer unrealized resource savings to on-
site generators, at the expense of utility consumers. For
this reason, we must reject it."’

‘*This is so because the selling utility’s marginal opportunity cost
is, by definition, lower than the internal running cost of its transaction
partner(s). Assuming that no qualifying facility would generate power
in order to sell it at a loss, all power sold for a price equal to the
utility’s marginal opportunity cost must, ipso facto, be less costly to
produce than the buying utility’s (or utilities’) power that is being
displaced by the selling utility’s production.

‘The Judge suggested, however, that we nevertheless may wish to
reconsider our approval of the share-the-savings pricing formula
employed by the Pool’s members in light of its effects on marginal
energy costs. See pp. 136-137, infra.

43a

Transmission Costs

The single most controverted conclusion by the Judge is
that on-site generators will, by delivering power during
system peak load periods, enable utilities to avoid
transmission capacity costs; and that, conversely, by
generating (or otherwise not taking) power to meet their
own loads during peak periods, they will not impose such
costs on the utility. This conclusiun underlies, and gives
necessary support to, the Administrative Law Judge’s
recommendation that capacity payments and capacity
charges for back-up service be included in the rates for
each summer peak period kilowatthour produced or pur-
chased, respectively, by a qualifying facility.'*

The utility parties object to this conclusion. As iden-
tified below, they raise the following arguments:

1. There can be no transmission cost avoidance unless
each of the following criteria is satisfied:

a. It must be possible to identify a specific,
deferrable transmission project;

b. The capacity increment supplied by one or
more on-site generators is of an amount suffi-
cient to supplant a project;

c. The reliability of a qualifying facility must
be established by its operating history; and

d. The availability of the facility must be
guaranteed for the duration of the project’s
deferral. It is not sufficient that power actually
is delivered during peak periods; the facility
must be legally obligated to deliver it.

'*As noted earlier, the conclusion that transmission capacity costs

are avoidable may change following the conclusion of the company’s
pending rate design case.

44a

(Con Edison, Centrai Hudson, Niagara
Mohawk and RG&E)

. The record in this case demonstrates that Con Edison
cannot avoid any bulk power transmission costs for
at least the next ten years. (Con Edison)

. Because bulk transmission costs are not avoidable,
$14 of the $21/kW marginal transmission costs
should be backed out of the capacity credits adopted
by the Administrative Law Judge; and the remaining
$7/kW costs should be examined on a site specific
basis to determine if they, too, are not avoidable.
(Con Edison)

4. In the case of a utility with a geographically
widespread system, power produced by an on-site
generator might not be deliverable to the areas of
greatest load because of transmission constraints. In
such a situation, it is self-evident that decentralized
production would not enable the utility to avoid
transmission costs. (Niagara Mohwak)

Staff, in response, points out that marginal transmis-
sion costs are determined by aggregate system peak
demands, and that on-site generators can reduce the total!
peak load placed on transmission facilities either by
delivering power to the utility system or by supplying
power to reduce their own loads. Such decentralized
generation is, in staff’s view, the equivalent of not taking
power during peak periods. Thus, staff continues, it
wouid be inconsistent to charge back-up and supplemen-
tary customers, in particular, for transmission costs when
they take service--as Con Edison proposes--but not credit
those costs to them when they supply power. Staff also
argues that paying for power delivered during peak
periods on an as-delivered basis effectively differentiates
between reliable and unreliable on-site generators. There is
no need to commit them to deliver power day in and day
out, since the peak period loads, which they may or may
not affect, will continue to determine transmission costs.

tw

ee)

45a

Responding to Con Edison’s argument that an amount
less than $21/kW should be reflected in capacity credits,
staff points out that the $21/kW amount is the marginal
cost on which the company has proposed, in its pending
rate design case, to base its rates for firm service taken
during peak periods. Staff argues that it is inconsistent to
argue here that some lesser amount is variable at the
margin and, thus, avoidable.

Underlying the utilities’ opposition to the conclusion
that on-site generators can enable them to avoid transmis-
sion costs simply by delivering power during peak periods
is their lack of certainty and knowledge about their depen-
dability. Athough this is a justified concern, it does not
compel a conclusion that reliability cannot be reasonably
assured by means that are less stringent than the quasi-
regulatory, contractual controls they propose; for utilities
also face uncertainties about the demands firm service
customers will place on their systems at peak times. If the
payment for every kilowatthour delivered by an on-site
generator during the relevant peak period includes a
capacity credit, it would seem that rational on-site
generators, as a group, would be encouraged to deliver
power during peak periods in the same fashion as pur-
chasers will be discouraged from using electricity at peak
times if they are charged for capacity costs. In other
words, as the utilities recognize, the questions of cost
avoidance and the structure of purchase rates are probably
highly interrelated.

At this time, there is very little experience on which to
base a conclusion that one method of payment will work
better than the other. It may be that experience will show
that on-site generators deliver power erratically if they are
paid for their capacity without contracts. On the other
hand, the requirement of a contractual commitment as a
condition precedent for capacity payments may
discourage potentially useful on-site generation from
developing. In resolving this issue, staff’s principal argu-
ment bears repeating: transmission capacity costs are

46a

determined by aggregate system peak demands. If on-site
generators fail to level or reduce those demands, and thus
fail to enable utilities to avoid costs, they will not receive
capacity payments. If, on the other hand, they cause a
downward shift in those demands, costs will be avoided
even in the absence of a specific promise to do so. The on-
site generation will, in other words, have value to the
utilities whether or not there has been a promise to pro-
duce it. We shall, therefore, adopt the Judge’s conclusion
that the peak period delivery of power by on-site
generators, in and of itself, can enable a utility to avoid
transmission capacity costs, in the absence of clear
evidence to the contrary.'’

Relevance of Avoided Cosis to Purchase Rates

The court in American Electric Power remanded to
FERC for further consideration its rule requiring utilities
to pay On-site generators 100% of their avoided costs
because FERC did not, in the process of adopting that
rule, give sufficient evidence of having struck a proper
balance among the interests of cogenerators, the interests
of utility consumers and the general public interest.*°
Although the court did not decide that full avoided cost
payments could not be required--indeed, it suggested that
a range of percentages bounded at the upper end by 100%

‘*In this connection, Niagara Mohwak’s contention that an on-
site generator that is isolated from a utility’s peak loads because of
transmission constraints cannot enable the utility to avoid transmis-
sion costs might warrant further examination. It should be noted,
however, that the ratemaking implications of this situation are
possibly more complex than Niagara Mohawk imagines, because an
on-site generator that is located on the same side of a constraint as are
the peak loads could deliver power to meet those loads. Unless the
company can exactly match costs, charges and payments for each in-
dividual customer (whether a consumer or a small power producer),
something which we doubt it can do, its proposition has little rate-
making significance.

**American Electric Power Service Corporation v. FERC, supra,
Slip Op. at 13.

47a

might be acceptable--it outlined ‘‘some additional con-
cers raised by the full avoided cost rule, which [FERC]
should address in its subsequent rulemaking’’?' before
such a requirement could be reenacted. These matters in-
clude the following:

1. Whether full avoided cost payments might stimulate
the development of on-site generation in the service
areas of utilities that are ‘‘subject to higher pollution
control standards than are cogenerators, or [pay]
taxes at a higher rate than will cogenerators,’’ to
such an extent that the (assumed) detriments of in-
creased pollution and lost tax revenues are not offset
by ‘‘sufficiently countervailing external benefits”’
dervied from the on-site generation.

2. Whether on-site generation stimulated by full avoid-
ed cost rates in the area served by a utility with excess
capacity might result in unreasonably higher rates
for the ‘‘remaining customers of the utility”
(because fixed costs presumably must be spread over
fewer sales).

3. Whether, ‘‘but for FERC’s regulations,’’ utilities
might pay on-site generators rates set at less than full
avoided costs, ‘‘under a standard industry practice,”’
that would be no less adequate than the higher rates
to stimulate on-site generation; and whether, in the
same vein, ‘‘the market’’ might fix a lower price for
purchases, both because on-site generators are not
natural monopolists and because, in the court’s view,
utilities might not be monopsonists.”?

The court made it clear that a mandatory full avoided
cost standard might be sustainable after consideration of
all the foregoing matters; it simply held that FERC had
adopted its requirement without adequate discussion of
them. In this proceeding, however, all of the foregoing

Id., p. 14.
2Id., pp. 14-18.

48a

matters were thoroughly litigated on the record. We con-
clude, upon review of that record, that the full avoided
cost standard is still the proper one for purchase rates.

Our conclusion rests on the following analysis of the
three matters raised by the court:

1. Pollution and taxation. As discussed later in this
Opinion (pp. 109-123, infra), there are adequate non-price
means for controlling the environmental impacts of on-
site generation; there is no need to use pricing as a control
mechanism. And so long as the difference between the tax
burdens borne by utilities and on-site generators reflects a
reversible legislative decision to raise revenues by taxing
avoidable transactions, the potential for lost tax revenues
also should not be a ratemaking matter. The principle
underlying these conclusions is that economic regulatory
agencies should not be constrained to act as if only they
are capable of taking remedial actions in these areas,
especially where legislation governing them has been, or
can be, enacted where required by the public interest.?’

2. Excess capacity. The court’s discussion of this matter
reveals its belief that the level of purchase rates will be a
major, if not the principal, inducement for the develop-
ment of on-site generation, and that it might be necessary
to set such rates at a level below full avoided costs in order
to deter some potential on-site generators from leaving the
system of utilities with excess capacity. The validity of this
reasoning, however, is iimited, both because it is advanced
without the benefit of a definition of avoided costs and
because it fails to take into account the impact of retail
rates. The short-run marginal costs of a utility with

**The court acknowledged that the costs associated with these
matters “‘may not be easily quantifiable, especially at this initial stage
of regulation.’’ Nevertheless, the court continued, FERC ‘‘may find it
possible to take them into account.’’ American Electric Power, supra,
Slip. Op. at 14.

49a

substantial excess capacity are likely to be lower than the
embedded costs on which its retail rates are based. Thus, if
a state commission should decide to define avoided costs
as short-run marginal costs, full avoided cost rates by
themselves might provide little inducement for the
development of on-site generation. But such generation
may develop anyway if the costs of self-supply are lower
than the embedded cost-based retail rates. As is discussed
throughout this Opinion, these are precisely the cir-
cumstances that all parties agree apply to Con Edison. The
percentage of avoided costs paid to on-site generators,
therefore, may have little significance, by itself, to the
retai! customers of a utility with excess capacity. Or, to
state it another way, the mere fact that a utility has excess
capacity should not be a sufficient reason for permitting it
to pay less than full avoided costs for purchases from on-
site generators.

3. Necessity for full avoided cost rates to induce on-site
generation. It is not clear why the court believed that
utilities might not be monopsonists with respect to the on-
site generators to which they are interconnected, especially
since, as discussed earlier in this Opinion (pp. 13-15,
supra), other FERC regulations not at issue in American
Electric Power impose the primary obligation to purchase
power from on-site generators only on those utilities
unless they and the on-site generators agree to deliver the
power to other utilities. In any event, no party contends
that Con Edison is not a monopsonist; thus, the necessity
for establishing some sort of legally-mandated floor under
purchase rates is uncontroverted.** Given this fact, the in-

4It must be emphasized once again that on-site generators are
free to offer to sell their production at a price that is lower than
avoided costs. For example, a generator with a steady thermal load
but varying power requirements may find it advantageous to sell its
excess power at cost, thus offering the purchasing utility a bargain
price when its (the utility’s) marginal costs are highest in exchange ‘or
the assurance of receiving a compensatory price for sales made during
periods when the utility’s marginal costs are below the running costs
of the on-site facility.

50a

quiry as to the proper level of those rates reverts to the
more general inquiry concerning the propriety of full
avoided cost rates. The question of supply-side stimula-
tion, in other words, has no independent bearing on the
matter.

~ * *

Having decided that the various concerns raised by the
court in American Electric Power should not independ-
ently bear on the question of whether to adopt full avoided
cost purchase rates, at least for New York utilities, we are
left with the broader question of why avoidable costs—
more precisely, marginal energy and certain marginal
capacity costs—should be selected as the market mech-
anism for determining the amount of on-site generation
that should develop.

In fairness to the court, it should be noted that much of
its skepticism about FERC’s avoided cost standard
stemmed from that agency’s lack of discussion of the
justifications for such a standard, and in fairness to
FERC, we should point out that it is probably not possible
to write a concise discussion of the subject that would be
relevant to a rule having nationwide applicability. In this
state, however, our longstanding policy has been, as Judge
Vernieu correctly noted,’* that marginal costs are the costs
relevant for retail rate design. Having long ago decided
that a consumer’s decision to use electric power should be
made on the basis of his or her understanding of the
marginal cost of producing it at various times of day
throughout the year, we would establish a false distinc-
tion, were we to adopt purchase rates effectively signalling
that power delivered during those periods is less valuable
than power demanded.

The ability of on-site generators to produce power is
similar to the ability not to consume power that firm
customers have; and, therefore, rates for sales to and pur-
chases from on-site generators should deviate to the least

extent that is reasonable from firm rates, particularly if

“R.D., p. 172.

Sla

they are based upon marginal costs. The decision to con-
sume or produce power should be motivated by the same
consideration: the cost of that decision at the time it is
made. Once that principle is established, the relative costs
ol self-supply or utility service can be intelligently weighed
by each prospective on-site generator, and the market for
such generation will define itself. If capital investment for
the purpose of reducing energy consumption appears not
(o be cost effective, a customer will continue to take utility
service. If, on the other hand, it does appear cost effective,
a decision by the customer to invest in on-site generation
will enable the utility to serve other customers’ loads, and
some growth in them, without extending itself at the
margin. This, in turn, should lead to long-run savings for
both utilities and ratepayers.

The potential for such savings far outweighs the risk, ef-
fectively embodied in the court’s decision, that in the
short-run ratepayers and utilities will be affected by on-
site generation in the same manner as they would be if firm
ratepayers decided to forgo consumption. Stated another
way, the risk of ratepayer detriment apparently appre-
hended by the court could materialize even without the
development of on-site generation, and thus should not be
attributed either to it or to full avoided cost payments. On
the other hand, the loss to society is clear if capacity
costing $20/kW at the margin is not supplemented by
capacity costing $18/kW or $19/kW simply because a
utility was authorized to pay no more than $17/kW for it.
Similarly, the statewide power pooling process by which
marginal energy costs are measured ensures that energy
production stimulated by full avoided cost payments will,
directly or indirectly, displace more costly utility produc-
tion and thus lower the cost at the margin of meeting all
statewide demands without imposing additional costs on
ratepayers. Such a benefit should not be forgone simply
because purchases at full avoided costs would fail to
reduce firm customers’ rates in the short run.

52a

We do not read the court’s decision as requiring either
result; indeed, the court characterized its decision remand-
ing FERC’s full avoided cost requirement as follows:

We do not say, of course, that [FERC] must
adopt rules which have no adverse impact on elec-
tricity consumers. But we do say that [FERC] must
consider the rules’ impact on these consumers and
the public interest in striking the proper balance.*°

We find, on the basis of the record before us, that setting
purchase rates equal to full avoided costs—as we have
defined them—will, by parallelling our policies on the
development of retail rates, serve the end of optimal
resource utilization without creating any short-run or
long-run detriments to the interests of consumers or the
general public that cannot be controlled by non-price
mechanisms.

RECONCILIATION OF MARGINAL
COSTS AND EMBEDDED COSTS

Con Edison’s marginal costs, priced out over all con-
sumption, are lower than the company’s embedded
revenue requirement. These two amounts would ordinarly
be reconciled as part of the process of establishing rates
for firm service. In this case, however, rates are to be
determined for specialized services, namely, back-up and
supplementary service to on-site generators. An issue has
thus arisen as to which costs—marginal or embedded—
should be reflected in those rates.

The Judge recommended that back-up rates reflect only
marginal costs.’’ According to him, any benefit or burden
that results from reconciling embedded and marginal costs
should be conferred on all classes of ratepayers equally

“American Electric Power, supra, Slip. Op. at 15.
_ “As is discussed later in this Opinion (pp. 50-53, infra), the Judge
did not reach this issue insofar as it concerned supplementary rates.

53a

unless it can be shown that all classes benefit from a
greater or lesser allocation to one class. For example, he
continued, it would be desirable to set the price for back-
up service provided by a ‘‘rising cost’’ utility** as close to
marginal cost as is possible in order to discourage on-site
generators from purchasing service when a more efficient
use of society’s resources would result if they supplied
their own reliability reserves. The converse of this situa-
tion, of course, is that it would be preferable to have an
on-site generator purchase back-up service from a declin-
ing cost utility rather than build it for itself, since the latter
action would be wasteful.

When the need to reconcile marginal and embedded
costs arises in order to design firm service rates, the
method we have employed in past cases is to increase or
reduce those charges and rates that are least likely to in-
fluence the amount of service a customer takes, until the
sum of all revenues from all charges and rates equals the
revenue requirement. In other words, an adjustment is
made to those charges with respect to which consumer de-
mand is relatively inelastic.2? The Judge reasoned,
however, that such an adjustment to back-up rates would
not be proper, because even the least elastic decision for a
firm service customer—whether to join the system at
all—is one about which an on-site generator has some
discretion. Because all customers of a utility will benefit
from the encouragement of on-site generation, the Judge
continued, all of them will also benefit if one class—on-
site generators taking back-up service—is excused from
having to contribute to the company’s embedded costs.

The Judge’s recommendation may be correct, but, as
Con Edison and Orange and Rockland point out on excep-

**That is, a utility whose marginal costs exceed embedded costs.

"Case 27344 e1 al., Orange and Rockland Utilities, Inc.-Electric
Raie Design, Opinion No. 80-35 (issued October 22, 1980), at mimeo
pp. 28-31.

54a

tions, there is little evidence on this record concerning on-
site generators’ demand elasticity and, therefore, there is
equally little basis for concluding that all customers will
benefit by setting rates closer to marginal costs for one
group of customers. Orange and Rockland adds that the
entire issue of marginal-to-embedded cost reconciliation—
and the implications of employing alternative reconcilia-
tion procedures, including not reconciling costs for certain
classes—should be explored in the context of the generic
phase of Con Edison’s pending rate design proceeding,
and not sooner. And OCER, one of the representatives of
On-site generators’ interests participating in this pro-
ceeding, agrees with the companies, arguing that no record
basis has been provided for relieving back-up customers
from bearing a share of embedded costs.

Finally, Boise Cascade, which, although not a party to
this proceeding, filed comments in response to the Recom-
mended Decision, points out that regardless of whether
unadjusted marginal costs are employed in designing
back-up rates, they must be reflected in purchase rates.
Thus, Boise Cascade points out, on-site generation
customers of rising cost utilities will elect to take advan-
tage of their prerogative, granted by FERC’s
regulations,*® to take firm service at embedded cost-based
rates while simultaneously selling all their production to
the utilities at marginal cost-based rates. In other words,
and contrary to the Judge’s suggestion, the level of back-
up rates will not be as material a consideration as he
believed to on-site generation customers of rising cost
companies. But to the extent that back-up rates are seen as
important, Boise Cascade continues, no basis has been
presented for concluding that such on-site generators
should be denied the benefits of the marginal-to-
embedded cost reconciliation that firm customers of rising
cost companies enjoy.

As the foregoing suggests, all parties having a sufficient
interest in this matter to comment on it have agreed that

"18 C.F.R. §§292.304(b) (4) and 292.305(a).

55a

back-up rates should be adjusted to reflect embedded
costs. Their position seems correct. Regardless of the
possible merits of the Administrative Law Judge’s
analysis, we agree that the departure from our usual rate-
making procedures he urges should rest on a stronger
evidentiary basis than this record provides. We shall, ac-
cordingly, reverse the Administrative Law Judge’s deci-
sion not to adjust back-up rates to reflect embedded costs.

In staff’s supplementary and back-up rate proposals,
both of which we are adopting for the reasons set forth in
the next part of this Opinion, the contract demand charges
were the only charges adjusted in order to reconcile
marginal and embedded costs. Staff preferred adjusting
these, the least elastic demand charges, to adjusting
customer charges (the least elastic of all charges), because
it believed adjusting the latter would severely and ad-
versely affect smaller customers. We agree with staff’s
goal, but not its approach; for these charges, which reflect
only 50% of the company’s marginal distribution costs,
would also be significantly increased in the reconciliation
process. We shall, therefore, direct the company to in-
crease all demand charges by an equal percentage, or to
propose an alternative means, to reconcile marginal and
embedded costs in a manner that avoids harsh impacts on
smaller customers.

RATE DESIGN ISSUES
RATES FOR SALES TO ON-SITE GENERATORS

Introduction

In our discussion up to this point, the terms ‘‘back-up”’
and ‘‘supplementary’’ service have been referred to
without definition. At this point, it is important to define
these terms as they are used in the remainder of this Opi-
nion:

1. Back-up service: Back-up service is provided by a
utility to replace energy and capacity that an on-site

56a

generator ordinarily supplies to itself. Although
FERC’s regulations distinguish between services
provided during scheduled and unscheduled
outages at an on-site generation facility, no party
proposed, or provided a cost basis for, recongizing
such a distinction in the company’s rates. Con
Edison and staff agree that back-up service should
be iimited to customers with a load factor of less
than 10% in both the summer and winter periods:
i.e., whose average 'oad during a given period is
less than 10% of its peak load during that period.

i)

Supplementary service: Supplementary service ts
energy and capacity that is used by an on-site
generator in addition to the energy and capacity the
on-site generator supplies on its own.

FERC’s regulations require generally that utilities serve
on-site generators on a nondiscriminatory basis; in addi-
tion, they require utilities to provide back-up, supplemen-
tary and interruptible service upon request from on-site
generators. The latter requirement may be waived, in
whole or in part, if, after notice and opportunity for
public comment, a state regulatory commission finds that
implementation of it would impair a utility’s ability to
render service and/or unduly burden the utility. *'

The preamble to FERC’s regulations provides a great

deal of background discussion for the development of

rates for sales to on-site generators. With respect to the
general rule, it states:

Section 210(c) of PURPA provides that the rules re-
quiring utilities to sell electric energy to qualifying
facilities shall ensure that the rates for such sales are
just and reasonable, in the public interest, and non-
discriminatory with respect to [qualifying facilities].
This section contemplates formulation of rates on

“18 C.FLR. $292,305.

57a

the basis of traditional ratemaking (i.e., cost of serv-
ice) concepts.

x x *
{T]he rate for sales shall be the rate that would be
charged to the class to which the qualifying facility
would be assigned if it did not have its own genera-
tion.

*x * x
[1]f, on the basis of accurate data and consistent
system-wide costing principles, the utility
demonstrates that the rate that would be charged to a
comparable customer without its own generation is
not appropriate, the utility may base its rates for
sales upon these data and principles. The utility may
only charge such rates on a nondiscriminatory basis,
however, so that a cogenerator will not be singled out
to lose any interclass or intraclass subsidies to which
it might have been entitled had it not generated part
of its electric energy needs itself.

In situations where a qualifying facility
simultaneously sells its output to an electric utility
and purchases its requirements from that electric
utility, . . . the facility’s electric load is likely to have
the same characteristics as the load of other non-
generating customers of the utility. If the utility does
not provide data showing otherwise, the appropriate
rate for sales to such a facility is the rate that would
be charged to a comparable customer without its
own generation.”

With respect to rates for back-up service, FERC pro-
vides the following guidance:

A qualifying facility is entitled to purchase back-

up . . . power at a nondiscriminatory rate which
reflects the probability that the qualifying facility

will or will not contribute to the need for and the use
"45 F.R. 12228-12229 (February 25, 1980).

58a

of utility capacity. Thus, where the utility must
reserve Capacity to provide service to a qualifving
facility, the costs associated with that reservation are

properly recoverable from the qualifying facility, if

the utility would similarly assess these costs to non-
generating customers.
* * *

[R]jates for sales of back-up. . .power shall not be
based, without factual data, on the assumption that
forced outages or other reductions in output by each
qualifying facility on an electric utility’s system will
occur either simultaneously or during the system
peak. Like other customers, qualifying facilities may
well have intraclass diversity. . . . The effect of such
diversity is that an electric utility supplying back-up
...power to qualifying facilities will not have to plan
for reserve capacity to serve such facilities on the
assumption that every facility will use power at the
same moment. . .[The regulation] prohibits utilities
from basing rates on the assumption that qualifying
facilities will impose demands simultaneously and at
system peak unless supported by factual data.’

The foregoing passages state, with considerable force,
that the rates for sales to qualifying facilities must follow
the guidelines FERC has established. As will be explained
below, the Recommended Decision adheres very closely to
those guidelines.

Exceptions of In-Novo Engineering
and Development Company

Intervenor In-Novo Engineering and Development
Company (In-Novo) has filed a number of exceptions to
the Recommended Decision, nearly all of which sound the
theme that no basis has been established for adopting
back-up rates that differ from the firm service rates ap-
plicable to the classes to which on-site generators would
belong but for the fact that they generate power.

“4S POR. 12228-12229 (February 25, 1980).

59a

In summary form, In-Novo’s exceptions are as follows:

1. The 10% load factor limitation on eligibility for
back-up service is ‘‘arbitrary,’’ based as it is on
staff’s observations that a well-managed on-site
generation facility will be available for service at
least 90% of the time. According to In-Novo, staff’s
evidence shows that an even greater availability rate
is possible; thus, it argues, the 10% limitation is
‘*overdesigned.’’

tv

. While back-up customers individually may have dif-
ferent load patterns from those of firm customers, as
a class their load pattern will be similar. Thus, there
is no basis for giving each group different rates.**

3. Revenue recovery under firm and back-up rates for
customers with similar loads is divergent. In-Novo,
assuming that all rates must precisely track costs at
every level of consumption, contends that no cost
basis for the divergent trends in revenue recovery has
been established.

Although it is nowhere expressly stated, the tone of In-
Novo’s exceptions—particularly its contention that the
10% load factor limitation is too high and its repeated in-
sistence that firm service rates be made available to on-site
generators—suggest that it believes that the back-up rates
recommended by the Judge are mandatory for certain
customers. No fair reading of the Recommended Decision
supports such an assumption; and, in any event, FERC’s
regulations providing that back-up service be made
available ‘‘upon request of a qualifying facility’’’* com-
pels a contrary result.

If, on the other hand, it is In-Novo’s position that, for
whatever reason, back-up rates simply should not be of-
fered, FERC’s regulation requiring that they be made

‘4In the same vein, In-Novo objects to the class-wide time-of-use
metering and three-block demand charge structure recommended by
the Judge tor back-up service.

ER CBR. §292.305(b)(1).

60a

available unless offering them would jeopardize service or
be unduly burdensome to Con Edison compels rejection of
that position. Moreover, the rate structure recommended
by the Jisdge adequately complies with FERC’s guideline
requiring ‘‘a nondiscriminatory [back-up] rate which
reflects the probability that the qualifying facility will or
will not contribute to the need for and the use of utility
capacity.’’** In-Novo concedes the likelihood that back-up
customers individually wili have load characteristics dif-
ferent from those of individual firm customers, even if the
load patterns of the two groups will not differ. If this
assumption is correct-—and there appears to be no reason
to doubt its validity—the seasonal, time-differentiated
rates recommended by the Judge should adequately
recover the group’s contribution to utility costs while, at
the same time, avoiding or at least minimizing the
likelihood that back-up customers who take service en-
tirely in off-peak periods will subsidize the costs imposed
by customers whose outages occur on peak. It is fair to
read FERC’s regulations as encouraging the development
of such a rate structure.

One final point needs to be made. In-Novo’s
mathematical analysis, which purports to demonstrate
divergent trends in revenue recovery between firm and
back-up rates (specifically, Con Edison’s proposed rates)
proves too much. The design of firm service rates reflects
class tendencies, and frequently reflects an assumption
that individual and class load characteristics are more
similar than they actually are. Moreover, the recovery of
costs incurred on a seasonal basis frequently ts distributed,
in whole or in part, over an entire year. Finally, even

though certain costs may not vary at all with the level of

production, their recovery may be loaded on usage-

sensitive rates. None of these aspects of firm service rate

design is necessarily improper, but they are not usefully

employed in designing back-up rates that meet FFRC’s
°45 F.R. 12228 (Feoruary 25, 1980).

6la

guideline. In other words, the greater use, in back-up
rates, of fixed charges to recover fixed costs and seasonal
and time-differentiated rates to recover variable costs
more clearly delineates the costs and benefits of avoiding
outages of on-site generation facilities during peak
periods. In-Novo’s analysis demonstrates that firm service
rates may be less likely to accomplish this result.

Back-Up Service
1. Recovery of Transmission Costs

Although exceptions concerning a number of features
of the rates for back-up service recommended by Judge
Vernieu have been filed, the greatest controversy concerns
his recommendation that marginal transmission capacity
costs imposed by back-up customers taking service during
the summer peak period be recovered through peak period
energy (per-kWh) charges; /.c., only when power is actu-
ally taken.

Opposition to this recommendation comes from the
utility parties. Their arguments recall those raised in op-
position to the Judge’s conclusion that the mere delivery
of power during peak periods by on-site generators will
enable utilities to avoid marginal transmission capacity
costs: they contend, essentially, that transmission costs are
incurred not only when service is actually taken, but also
when the mere possibility that service may be required is
established. Staff’s response, which also recalls the earlier
debate, is that transmission costs are determined by
actually-observed peak loads, and the ability of back-up
customers to avoid taking service on-peak will affect those
costs.

The utilities’ arguments sound the same theme. They
have had very little experience serving on-site generation
facilities, they point out, so it is not possible to predict
their tendency to take service during peak periods.

62a

Because of this uncertainty, the utilities continue, they will
be required to provide sufficient peak load-related capaci-
ty to serve the on-site generators’ ful! loads just in case
their outages all occur on-peak. Accordingly, they reason,
the least risky course would be to adopt contract demand
charges that effectively guarantee the recovery of capacity
costs. If the potential for over-recovery of revenues that is
inherent in such a rate structure is a matter of concern,
they add, the contract charges can be scaled down using a
suitable coincidence factor. Only Con Edison has sug-
gested a way to develop such a factor without the benefit
of operating experience, although, as discussed below (pp.
40-42, infra), staff and OCER have demonstrated that the
company’s approach has several shortcomings.

Staff’s rate design proposal, which the Judge adopted
with one important modification (which will be discussed
shortly), was formulated on the basis of its assumption
that back-up customers will require service during peak
periods at random. The rationale behind staff’s proposal
is easily understood: if a customer takes | kW of service
during 100% of the hours in the (likely) peak period, there
is a 100% probability that he or she has contributed one
kilowatt to the utility’s system peak and, accordingly, he
or she should pay the full marginal transmission capacity
cost. If the customer takes | kW during 99% of the peak
hours, staff reasoned, he or she should pay slightly less;
and if service is taken during only one hour, the proba-
bility that it will be the peak hour will be so greatly re-
duced that the customer should contribute only a few cents
to marginal transmission costs. In short, staff’s proposal
treated a back-up customer’s contribution to the utilliy’s
system peak no differently than many firm customers’
contributions are treated. The current system peak con-
sists of a multitude of small, medium and large demands,
and the costs of serving it are billed to customers on the
basis of usage. If back-up customers add to that peak,
staff reasoned, they should be billed in the same manner.

a!

63a

Con Edison attempted to demonstrate before the Judge,
as before us, that it would not be unreasonable to assume
that back-up customers would be more likely to require
utility service during peak periods than during other times.
The company argued that on-site generators’ peak loads
will coincide with the compary’s peak load, contending
that an examination of the load data of a sample of poten-
tial on-site generators supports this assumption.
Moreover, it continued, the likelihood that only ore OL-
site generation unit at a multiple-unit site will break down
is greater than the likelihood that all units will break down
at once. This being the case, the only time that such an on-
site generator wil! require utility service is when its load is
highest--a time that the company contends will coincide
with its own system peak.

Staff doubts the validity of Con Edison’s argument,
pointing out that the company’s data analysis faiied to
compare customers’ loads at the time of its system peak
with their loads at other times during the summer peak
and shoulder periods. !n particular, staff produced, for
purposes of cross-examining the company’s witness, data
on the actual loads of certain potential on-site generators
that showed that their loads rose to within 10% of their
peak loads during periods when Con Edison’s system load
was not as high relative to its peak; that is, the customers
had individual load curves that are flatter and broader
than Con Edison’s system curve. These data imply that
even if such customers were to require back-up service ai
times when their loads were highest, as the company al-
leged, their calls for service would likely be at a time other
than when the system load is near its peak. If those
customers were required to pay contract demand charges

that reflected Con Edison’s assumption that they would
require only peak period service, staff argued, ‘ney would
be significantly overcharged.

FERC’s regulations, the preamble to which is quoted
earlier, require that back-up charges ‘*shall not be based

64a

on the assumption (unless supported by factual data) that
forced outages or other reductions in electric output by all
qualifying facilities on an electric utilliy’s system will oc-
cur simultaneously, or during the system peak, or both. . .
>” The company’s proposal for recovering transmission
costs, although premised more on the apprehension that
on-site generators’ Outages might occur on peak rather
than on the assumption that they will, nevertheless is in-
consistent with those regulations. Under that proposal, the
company would collect just as much revenue from a
customer regardless of whether that customer’s peak usage
coincides with the system peak by designing contract
charges on the basis of highly pessimistic expectations
about back-up customers’ behavior. And that customer
would be charged the same amount whether he took one
or many hours of peak period service, despite the fact,
noted by the Judge, that the likelihood that any individual
customer’s demand will occur during the cost-causing
peak period increases with the duration of that demand.

The distinguishing feature of staff’s rate design pro-
posal, on the other hand, is that it will coliect revenues
from customers in proportion to their energy usage. The
actual charge per kWh can be adjusted so that the amount
a typical customer will pay matches the marginal transmis-
sion costs that customer will likely cause the company to
incur. It is this aspect of staff’s proposal that the Judge
found to be most persuasive.

Judge Vernieu did not, however, completely accept
staff’s proposal. Instead, he modified it to reflect partially
Con Edison’s concern that all calls for service during the
504-hour summer peak period will likely fall within the
89-hour ‘‘load sensitive peak’? (LSP) period when the
cost-causing peak is most likely to occur. Staff had de-
signed its summer peak period energy (per-k Wh) rates on
the basis of its assumption that calls for service would be
spread fairly evenly throughout that 504-hour period;

"18 C.P.R. §292.305 (c) (1).

65a

more specifically, staff assumed that 22% of the back-up
customers’ usage during the summer peak period would
fall within the LSP period. Thus, staff argued, transmis-
sion costs should also be spread over a relatively large
number of hours. Con Edison, while not supporting
staff’s proposal to recover capacity costs in energy rates,
contended nevertheless that transmission costs should be
spread over only 89 hours, but that the resulting (higher)
energy rates should be charged for all usage during the
504-hour summer peak period, if such a rate design is
adopted. For Con Edison contended that none of the
back-up customers’ usage would fall outside the LSP
period; in other words, the company believed their usage
during the remaining 415 hours of the peak period would
be zero. The Judge generally favored staff’s assumption,
but he recommended that rates be

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385012_0173%3A03. Public record. Not legal advice.