Appendix — Enron Power Marketing, Inc. v. Northern States Power Co.
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99 91 6 NOV 39 1999
a one QEBICE OF THE pices
IN THE
Supreme Court of the United States
ENRON POWER MARKETING, INC.,
Petitioner,
Vv.
NORTHERN STATES POWER Co., et al.,
Respondents.
On Petition for Writ of Certiorari to the
United States Court of Appeals
for the Eighth Circuit
APPENDIX TO
PETITION FOR WRIT OF CERTIORARI
JEFFREY D. WATKISS Louis R. COHEN
RONALD N. CARROLL Counsel of Record
BRACEWELL & JOSEPH E. KILLORY, JR.
PATTERSON, L.L.P. MICHAEL PLOTNICK
2000 K Street, N.W. WILMER, CUTLER & PICKERING
Suite 500 2445 M Street, N.W.
Washington, D.C. 20006 Washington, D.C. 20037-1420
(202) 828-5800 (202) 663-6000
Counsel for Petitioner Enron Power Marketing, Inc.
3,3" ¢
AR TRO NL EET LST RO or rr em eee es -
TABLE OF CONTENTS
APPENDICES:
A.
Opinion of the Court of Appeals, Northern
States Power Company v. FERC, 176 F.3d 1090
(as amended, July 20, 1999) .............cccccccecceeceeeee
Order of the Federal Energy Regulatory Com-
mission in Northern States Power Company
(Minnesota) and Northern States Power Com-
pany (Wisconsin), 83 F.E.R.C. {| 61,098 (April
SN cit iceacteicsesenctiienneitasarvadnatesvanioepoutepniciancgne
Order of the Federal Energy Regulatory Com-
mission in Northern States Power Company
(Minnesota) and Northern States Power Com-
pany et in 83 F.E.R.C. ¥ 61,338 ore
29, 1998) . ia
Order of the Federal Energy Regulatory Com-
mission in Northern States Power Company
(Minnesota) and Northern States Power Com-
pany (Wisconsin), 84 F.E.R.C. 9 61,128 (July
OE ROOD: ait Ba eda
Order of the Federal Energy Regulatory Com-
mission in Northern States Power Company
(Minnesota) and Northern States Power Com-
pany (Wisconsin), 89 F.E.R.C. 9 61,178 (Nov.
15, 1999) (order on remand) ................--..---..-++-
Promoting Wholesale Competition Through Open
Access Non-Discriminatory Transmission Serv-
ices by Public Utilities and Transmitting Utili-
ties, Order No. 888, [1991-96 Reg. Preambles]
F.E.R.C. Stats. & Regs. nore at 31,643
(1996) (pertinent portions) . :
Order No. 888-A, [Regs. Ae teat Ill
F.E.R.C. Stats. & Regs. {| 31,048 (1997) (perti-
SE IID | inc sa sscesnssnciccicnanssatianadatacconsectennnenegnes
Order of the Court of Appeals denying rehear-
ing and rehearing en banc (Sept. 1, 1999)
Page
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128
36a
42a
44a
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2lla
281la
ii
TABLE OF CONTENTS—Continued
Sections 201, 205, 206, 211, 212, 213 and 318 of
the Federal Power Act, 16 U.S.C. §§ 824, 824d,
824e, 824j, 824k, 8241 and 8251...
Sections 1, 4, and 5 of the Natural Gas Act, 15
USL. §§ 717, 71%c, and 7174 .......................
Pro Forma Open Access Transmission Tariff of
Northern States Power Companies (July 1,
1997) (pertinent portions) .... tt
First Revised Open Access Transmission Tariff
of Northern States Power Companies (February
17, 1998) (pertinent portions)
Letter from Gary Johnson, Vice President and
General Counsel, Northern States Power Co. to
David Boergers, Secretary, FERC (Nov. 19,
1999) ......... SF5 8 Foie CE. SRS eet Ss ee RR Ie A
Page
283a
308a
3l4a
319a
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APPENDIX A
UNITED STATES COURT OF APPEALS
EIGHTH CIRCUIT
No. 98-3000
NORTHERN STATES POWER COMPANY,
A MINNESOTA CORPORATION:
NORTHERN STATES POWER COMPANY,
A WISCONSIN CORPORATION
Petitioners,
MINNESOTA DEPARTMENT OF PUBLIC SERVICE
DAIRYLAND POWER COOPERATIVE,
Intervenor on Appeal,
Vv.
FEDERAL ENERGY REGULATORY COMMISSION
Respondent,
WISCONSIN ELECTRIC POWER COMPANY:
SOUTHERN MINNESOTA MUNICIPAL POWER AGENCY:
MISSOURI RIVER ENERGY SERVICES:
ENRON POWER MARKETING INCORPORATED
Intervenor on Appeal
Submitted March 8, 1999.
Decided May 14, 1999.
As Amended July 20, 1999,
2a
Before FAGG, LAY, and WOLLMAN, Circuit Judges.
LAY, Circuit J.
On April 24, 1996, the Federal Energy Regulatory
Commission ("FERC") promulgated Order No. 888' requiring
"all public utilities that own, control or operate facilities used
for transmitting electric energy in interstate commerce to have
on file open access non-discriminatory transmission tariffs that
contain minimum terms and conditions of non-discriminatory
service." Order No. 888, 61 Fed.Reg. 21,540 (1996). FERC's
Stated goal was to encourage competition in the wholesale bulk
power market place "and to bring more efficient, lower cost
power to the Nation's electricity consumers." Jd. Order No. 888
became final and effective on July 9, 1996. Thereafter,
Northern States Power Company ("NSP") filed proposed
revisions of its Open Access Transmission Tariff ("NSP
Tariff") to comply with the requirements of FERC Orders Nos.
888, 888-A, 888-B and 888-C and to file new tariffs that were
consistent with the pro forma tariff of Order No. 888.
' See Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery of
Stranded Costs by Public Utilities and Transmitting Utilities, Order No. &&
[Regs. Preambles Jan. 1991-June 1996], FERC Stats. & Regs. 931,036,
clarified, 76 FERC 461,009 and 76 FERC {61,347 (1996), modified, Order
No. 888-A [Regs. Preambles], III FERC Stats & Regs. 431,048 (1997), order
on rehearing, Order No. 888-B, 81 FERC 461,248 (1997). on rehearing,
Order No. 888-C, 82 FERC $61,046 (1998), petitions for review pending
sub nom. Transmission Access Policy Study Group, et al. v. FERC, Nos. 97-
1715, et al. (D.C.Cir., Mar. 30, 1998) (hereinafter collectively as "Orders”).
° Order accepting Open Access Transmission C ompliance Tariff.
Accepting in Part and Rejecting in Part Proposed Revisions, Instituting
Investigation, Establishing Hearing Procedures and Refund Effective Date,
and Consolidating Dockets, 83 FERC 961,098 (April 30, 1998); Order on
Requests for Clarification, 83 FERC 461,338 (June 29, 1998): Order
Denying Requests for Clarification, Rehearing and Stay, 84 FERC 461,128
(July 31, 1998) (hereinafter collectively as "Curtailment Orders").
a i
3a
FERC rejected the proposed changes to the NSP Tariff's
curtailment provisions on the grounds that: 1) NSP had defined
curtailment priorities only through general references to
unexplained procedures; 2) NSP had failed to demonstrate that
the proposed terms were consistent with, or superior to, the pro
forma tariff terms required by Order No. 888: and 3) NSP's
description of the proposed procedures was misleading.
Thereafter NSP filed this petition for review. On August 25,
1998, this court denied NSP's stay request and shortly thereafter
denied FERC's motion to transfer the case to the United States
Court of Appeals for the District of Columbia, or to hold the
case in abeyance pending the omnibus appeal of FERC's Order
No. 888 rule-making in the D.C. Circuit.
JURISDICTION
Initially, FERC has moved to dismiss these proceedings for
lack of jurisdiction. It argues that the petitions for review filed
by NSP constitute a collateral attack upon Order 888. In
essence, NSP challenges FERC's regulation and possible
curtailment of bundled retail electric sales°, arguing that such
actions are outside of FERC's jurisdiction. In its Curtailment
Orders, both rejecting and accepting NSP's petitions, FERC
failed to raise the issue of collateral attack. Nevertheless,
FERC now asserts that NSP's proposed revisions were not
timely and should have been made at the time Order No. 888
was being promulgated. It urges that the belated challenges by
NSP should have been included in the rule-making proceedings
pending before the United States Court of Appeals for the
District of Columbia. We disagree.
‘NSP defines "bundled" electric sales to its retail customers as follows:
" ‘Bundled’ service means the generation, transmission, and distribution of
electricity together with all other services (meter reading, billing, equipment
repair, supply curtailment) hecessary to satisfy the customer's complete
electric service needs." Petitioner's Brief at 2.
4a
Section 313(b) of the Federal Power Act ("FPA"), 16 U.S.C.
$8251 (b), provides that "[a]ny [aggrieved] party to a proceeding
under [the FPA] ... may obtain a review of such order in the
United States Court of Appeals for any circuit wherein ... the
public utility to which the order relates is located or has its
principal place of business." /d. The proceedings in this
petition for review relate to the proposed tariffs filed by NSP
pursuant to Order No. 888. Involved are the differing
interpretations of the Orders as they affect the tariffs filed by
NSP.
FERC asserts, as it must, that it has no intention of
regulating retail sales to NSP customers, while also maintaining
that its curtailment provisions apply only to wholesale sales,
over which it has explicit jurisdiction. FERC concedes that its
jurisdiction relates only to terms and conditions of electric
transmission service provided by public utilities engaged in
interstate commerce. See Respondent's Brief at 34. FERC's
order requires that there be no discrimination in curtailment of
electrical power when power constraints take place between the
wholesale customer, who falls under FERC's jurisdiction, and
the native/retail consumers, who are regulated solely by the |
state. See Order Denying Requests for Clarification, Rehearing |
and Stay, 84 FERC 961,128 (1998). NSP points out that under
FERC's interpretation, the direct effect of FERC's curtailment
orders will cause a nonjurisdictional disruption of service
affecting NSP's native/retail consumers.
We conclude that these adverse arguments defeat FERC's
jurisdictional objections and lay bare the distinction between
the rule-making proceedings pending before the United States
Court of Appeals for the District of Columbia and the present
petition for review in this case. We therefore reject FERC's
argument to dismiss for lack of jurisdiction.
THE MERITS
The fundamental issue to be decided on this appeal is
whether FERC may, through its tariff orders, require NSP, a
Sa
public utility, to curtail electrical transmission to wholesale
(point-to-point) customers on a comparable basis with its
native/retai] consumers when it experiences power constraints.
FERC acknowledges that it cannot permissibly affect state
regulation of retail rates and practices. FERC argues that it has
simply required that, as to transmission curtailment, NSP may
not discriminate against a third party in favor of its own
native/retail consumers. Thus, it asserts that Order No. 888
makes clear that a transmission provider must curtail electrical
transmission on a comparable and nondiscriminatory basis,
including the provider's own use of the system. Under the
tariff, public utilities will not be allowed to continue
curtailment practices that give priority to bundled, native/retail
load consumers over point-to-point users involved in interstate
commerce. FERC suggests that there is no justiciable issue
here. It reasoned:
The pro forma tariff requires comparability of
curtailments when consistent with Good Utility Practice.
The Commission would not expect NSP Companies to
violate Good Utility Practice when implementing
curtailments. Further, the pro forma tariff allows the
Transmission Provider the discretion to curtail firm
transmission service when an emergency or other
unforeseen condition impairs or degrades the reliability of
its transmission system. Absent such system reliability
concerns, however, NSP Companies must engage in a pro-
rata curtailment.
Order on Requests for Clarification, 83 FERC 62,338
(1998).
However, the mere fact that the provider may exercise
curtailments within its sole discretion is not the problem. The
problem arises when NSP exercises its discretion to curtail
service, but may then do so only by curtailing both wholesale
and native/retail electric sales on an equal basis and not by
giving preferential treatment to its native/retail load. Thus,
NSP argues, when there exists a power constraint, by providing
6a
Curtailment to its native/retail consumers on a pro rata basis
with wholesale users, NSP will be forced to provide
interruptible service to its native/retail consumers. According
to NSP, a pro rata curtailment will detrimenially affect
native/retail consumers who have no other alternatives available
to obtain electrical service. NSP urges that when wholesale
(point-to-point) customers are curtailed in electrical
transmission, the wholesale customer has alternative sources
from which to obtain continuous electrical supply, through
either the purchase of electricity from another provider, or via
their own power generation facilities. Illustrative of this
argument, NSP points to the circumstances involving
Wisconsin Electric Power Company ("WEP"), an intervenor in
this proceeding, and itself when WEP experienced curtailment
of electrical transmission by NSP in the summer of 1998. WEP
had to resort to alternative power, albeit at a higher price due to
the emergency curtailment.’ Unless we totally miscomprehend
the arguments involved, we feel that FERC's observation that
no inherent conflict exists between its mandates and practical
application is viewed through an adversarial bias.
The more fundamental issue involved here, aside from the
practicalities of the situation, is whether FERC has the
jurisdiction to affect the curtailment practices of NSP when
dealing with NSP's native/retail consumers. FERC argues that
it does not, in any way, attempt to affect state regulation of
retail rates and practices. At the same time, FERC points out
that its jurisdiction over interstate sales is not made in a
vacuum. As in Conway Corp. v. FPC, 510 F.2d 1264
(D.C.Cir.1975), aff'd sub nom., FPC v.C. onway Corp., 426 U.S.
* Wisconsin Electric Power Company argues in its intervenor brief that
NSP should be required to furnish electrical transmission on a comparable
basis with its native/retail customers so as to obviate Wisconsin Electric
Power Company from having to black out its own retail customers, If such
an argument assumes that NSP must black out its retail customers so that
Wisconsin Electric Power Company's customers may have continuous
service, we deem such argument unrealistic.
Ta
271, 96 S.Ct. 1999, 48 L.Ed.2d 626 (1976). it argues the
jurisdiction of the FPC is not "insulated from nonjurisdictional
factors." Id. at 1272. ta Conway, an eectric utility was
engaged in jurisdictional (wholesale) and nonjurisdictional
(retail) sales. A portion of the utility's wholesale customers
competed against it by reselling electricity purchased from the
utility to other retail consumers. The wholesale customers
alleged that the wholesale price was inflated in order to prevent
them from competing for retail business. The Supreme Court
held that the Federal Power Act authorized FERC to examine
the entire factual context surrounding the wholesale rates.
including facts related to the nonjurisdictional _ retail
transactions. See Conway, 426 U.S. at 280. 96 S.Ct. 1999,
FERC relies upon the language of the United States Court of
Appeals for the District of Columbia in C onway that FERC may
take into consideration nonjurisdictional concerns "when
germane to the meaningful execution of a jurisdictional
function." Conway, 510 F.2d at 1272. We have no
disagreement with these abstractions. However, one of the
problems in the Conway case is the distinction pointed to by
Judge Douglas Ginsburg in Altamont Gas Transmission
Company v. FERC, 92 F.3d 1239 (1996). In Altamont, as the
result of perceived discrimination against interstate gas
shipments, FERC authorized a utility to begin building a new
facility, but lowered the utility's allowed rate of return until the
utility could demonstrate that its rates and policies no longer
discriminated against interstate shippers. In taking note of the
Supreme Court's delineation in Conway, Judge Ginsburg
posited that jurisdictional implications of a nonjurisdictional
transaction are germane only "{i]f the undue preference or
discrimination is ... traceable to the level of the jurisdictional
rate." Id. at 1247 (citing Conway, 426 U.S. at 277. 96 S.Ct.
1999). We have the same difficulty here, at least by analogy,
that the alleged discrimination is traceable to the
nonjurisdictional sale of bundled service provided by NSP to
8a
the native/retail consumer rather than to the service provided to
interstate customers.”
As NSP points out, it is given monopolistic control by the
five states in which it operates. NSP is a vertically integrated
electrical utility and provides electrical service throughout
Minnesota, Michigan, North Dakota, South Dakota, and
Wisconsin to an estimated two million retail customers. NSP
argues that the exclusive grant given by these states to sell to
native/retail consumers is on a quid pro quo basis: to wit, that
NSP's native/retail consumers may depend on bundled sales
without curtaiiment of service. In Order No. 888, FERC
recognizes its own jurisdictional limits and states "[w]e reiterate
that we are not requiring the transmission provider to unbundle
transmission service to its retail/native load nor are we
requiring that bundled retail service be taken under the terms of
the Final Rule pro forma tariff." /d. at 21,604. This apparent
concession is statutorily driven. Under 16 U.S.C. §824(a),
Congress has expressly provided that "Federal regulation ...
extend[s] only to those matters which are not subject to
regulation by the States." /d. Section 824(b)(1) provides:
The provisions of this subchapter shall apply to the
transmission of electric energy in interstate commerce and
to the sale of electric energy at wholesale in interstate
commerce, but except as provided in paragraph (2) shall
not apply to any other sale of electric energy or deprive a
State or State commission of its lawful authority now
exercised over the exportation of hydroelectric energy
which is transmitted across a State line. The Commission
shall have jurisdiction over all facilities for such
transmission or sale of electric energy, but shall not have
* We think it can also be questioned whether the bundled electric sales,
as defined n. 3 supra, is in the same class of service provided in the sale of
electrical power to point-to-point customers. We find the difference in the
products sold in itself justifies preferential treatment to native consumers
beyond the reach of Tariff Order No. 888.
9a
jurisdiction, except as specifically provided in this
subchapter and subchapter III of this chapter, over facilities
used for the generation of electric energy or over facilities
used in local distribution or only for the transmission of
electric energy in intrastate commerce, or over facilities for
the transmission of electric energy consumed wholly by the
transmitter.
Id.
NSP argues that to comply with FERC's interpretation of
Order No. 888, as requiring comparable and equal service to
point-to-point customers, along with its native/retail consumers,
would violate state regulatory laws. For example, in the state
of Minnesota NSP may not shed its retail load absent an
emergency or when electric supply is limited or unavailable.
See Northern States Power Company, MINNESOTA
ELECTRIC RATE BOOK, GENERAL RULES AND
REGULATIONS, Section 6, Curtailment or Interruption of
Service, §6.2 (Add.41); Minn.Stat. §216B.37-.42. The state
tariffs in the other states provide similar limitations.° Thus,
NSP argues that if it is required to provide comparable
transmission to both its retail and wholesale customers on a pro
rata basis, that its native/retail consumers will face power
Outages contrary to the obligation set out in the state tariffs, in
turn causing conflict with the long-held position that once a
tariff has been approved, it has the force of law and is binding
upon the parties. See Montana-Dakota Utilities Co. v.
Northwestern Public Service Co., 341 U.S. 246, 251-52, 71
S.Ct. 692, 95 L.Ed. 912 (1951). NSP urges that state authority
over its bundled service is jeopardized if FERC requires, under
the guise of nondiscrimination, pro rata curtailment of the
power supply to NSP's native/retail consumers.
As indicated, when the circumstances require curtailment in
the transmission of electricity, most wholesale customers may
* See Mich.Comp.Laws Chapter 460; N.D.Cent.Code Title 49: S.D.
Codified Laws Title 49; Wisc. Stat. Chapter 196.
10a
use alternative supplies from other utilities or generate power
themselves, and can avoid power outages through such practice.
The native/retail consumer, however, is unable to turn to
alternative sources of supply. For these reasons, NSP urges that
Good Utility Practice requires that wholesale transactions be
curtailed before a utility is forced to shed its native/retail load.
Thus, we find that NSP, through FERC's interpretation, is
placed between the proverbial rock and hard place, and will in
effect be in violation of either a state tariff or Order No, 888.
FERC responds simply that it does not operate in a vacuum
and that it is not exercising any of its regulatory powers
directly, but that through the enforcement of a federal tariff,
there could be a lawful, indirect effect upon NSP’s services to
its native/retail consumers. NSP urges that this allows FERC
to do indirectly what it is prohibited from doing directly,
intercede in a matter reserved by Congress to the states. See
Altamont, 92 F.3d at 1248. FERC’s ultimate answer to all of this
is that where there is a clash between its tariffs and the state
law, the federal tariff must prevail under the Supremacy Clause.
We cannot agree.
Before reviewing constitutional concerns relating to the
Supremacy Clause, it is fundamental that this court must first
satisfy itself that FERC has Congressional approval to regulate
NSP in the manner now attempted. Congress has drawn a
“bright line" between state and federal regulation. Here, there
is no conflict between the state and federal regulatory schemes.
In fact, FERC concedes that it has no jurisdiction whatsoever
over the state's regulation of NSP’s bundled retail sales
activities. See Order No, 888-A, 62 Fed.Reg. 12,274, 12,299
(1997). Additionally, any reliance upon Nantahala Power &
Light Co. v. Thornburg, 476 U.S. 953, 106 S.Ct. 2349, 90
L.Ed.2d 943 (1986), for the proposition that a state must defer
to FERC’s decision making for fear of running afoul of the
Commerce Clause is also misplaced. In Nantahala, the Court
applied the “fixed rate doctrine" under which interstate power
rates filed with or fixed by FERC had to be given binding effect
by state utility commissions in determining intrastate rates.
rap shana ont erence etc
ila
This is not an issue here. In Nantahala, the Court was dealing
with hydroelectric power and facilities which obtained its
power supply from the Tennessee Valley Authority, as well as
navigable waters and dams placed thereon. In the present case,
we have nothing comparable to the generation of electrical
power that was involved in Nantahala. Cf. FPC v. Louisiana
Power & Light Co., 406 U.S. 621, 92 S.Ct. 1827, 32 L.Ed.2d
369 (1972). We think it obvious that the indirect effect of
Order No. 888, as interpreted by the Commission, is an attempt
to regulate curtailment of electrical power to NSP's native/retail
consumers. Despite FERC’'s denial as to nonjurisdictional
regulation, we find it has transgressed its Congressional
authority which limits its jurisdiction to interstate transactions.
As such, its attempt to regulate the curtailment of electrical
transmission on native/retail consumers is unlawful, as it falls
outside of the FPA's specific grant of authority to FERC.
This cause is remanded to FERC to allow amendment te its
curtailment orders, as now interpreted under Order No. 888, so
as to not encroach upon the authority of the regulatory
commissions of the states.
IT IS SO ORDERED.
12a
APPENDIX B
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Docket Nos. OA97-25-000, OA97-606-000, ER98- 1890-000,
ER98-2060-000, and EL98-40-000
NORTHERN STATES POWER COMPANY (MINNESOTA) AND
NORTHERN STATES POWER COMPANY (WISCONSIN)
Order Accepting Open Access Transmission Compliance
Tariff, Accepting in Part and Rejecting in Part Proposed
Revisions, Instituting Investigation, Establishing Hearing
Procedures and Refund Effective Date, and Consolidating
Dockets
(Issued April 30, 1998)
Before Commissioners: James J. Hoecker, Chairman: Vicky
A. Bailey, William L. Massey, Linda Breathitt, and Curt Hébert,
Jr.
This order addresses various filings made by Northern States
Power Company (Minnesota) and Northern States Power
Company (Wisconsin) (collectively, NSP Companies)
concerning their open access transmission tariff and
transmission rates. We will accept the open access tariff
compliance filings and set one of the rate provisions for
hearing, accept in part and reject in part the proposed revisions
to the open access tariff, suspend the proposed revisions for five
months and set them for hearing, institute an investigation into
I3a
NSP Companies’ rates and establish a refund effective date, and
consolidate these dockets for purposes of hearing and decision.
BACKGROUND
On October 11, 1996, NSP Companies filed in Docket No.
OA97-25-000 an open access transmission tariff to comply with
the Commission's order No. 888.' On December 24, 1996, NSP
Companies filed a revised Attachment H to the open access
transmission tariff—which addresses the annual transmission
revenue requirement for network integration transmission
service—to modify the methodology for calculating credits for
customer-owned facilities.” On June 27, 1997, NSP Companies
filed in Docket No. OA97-606-000 a revised open access
transmission tariff to comply with the Commission's order No.
888-A.
On February 17, 1998, NSP Companies filed, in Docket No.
ER98- 1890-000, changes to the rates for firm point-to-point
transmission service under their open access transmission tariff
to reflect 1998 test year cost-of-service data. NSP Companies
also proposed changes to the rates and terms and conditions for
' See Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery of
Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888,
61 Fed. Reg. 21,540 (1996), FERC Statutes and Regulations, Regulations
Preambles January 1991-June 1996 P 31,036 (1996), order on reh'g, Order
No. 888-A, 62 Fed. Reg. 12,274 (1997), FERC Statutes and Regulations
$31,048 (1997), order on reh'g, Order No. 888-B, 81 FERC 961,248 (1997),
order on reh'g, Order No, 888-C, 82 FERC 461,046 (1998).
FNNSP Companies had previously requested a waiver of the requirement
to file an Order No. 888 compliance tariff, which we denied. Northern States
Power Company, et al., 76 FERC 61,250, at 462,293 ( 1996).
’ This revised filing was docketed in Docket No. OA97-25-000. and was
also inadvertently docketed as the separate Docket No. O.A97-162-000.
Docket No, OA97- 162-000 has been closed, and all matters relating to the
revised Attachment H will be considered as part of Docket No. OA97-25-
000,
I4a
various ancillary services, modifications to existing tariff terms
and conditions, and changes to the rates applicable under iong-
term transmission agreements with certain municipal
customers. NSP Companies request an effective date of May I,
1998 for these changes.
On March 2, 1998, in Docket No. ER98-2060-000, NSP
Companies filed proposed changes to the rates and terms of
service for the network integration transmission provisions of
the open access transmission tariff. The proposed changes
would increase the annual transmission revenue requirement to
reflect the 1998 test year cost-of-service data, change the |
mechanism for calculating the annual transmission revenue i
requirement to allow for annual updates starting May 1, 1999,
and modify certain existing tariff terms and conditions. NSP
Companies also request a May 1, 1998 effective date for these
changes.
NOTICE OF FILING AND RESPONSES
Notice of NSP Companies’ filing in Docket No. OA97-25-
000 was published in the Federal Register, 61 Fed. Reg. 59,433 |
(1996), with comments, protests and interventions due on or
before November 29, 1996. Motions to intervene were filed by
Commonwealth Edison Company (Commonwealth Edison),
Electric Clearinghouse, Inc. (ECI), and jointly by the Missouri
Basin Municipal Power Agency and the Minnesota cities of
Marshall, St. James, and Sauk Centre (Joint Municipals). A
motion to intervene and protest was filed by the Coalition for a
Competitive Electric Market (CCEM).
Notice of NSP Companies’ filing in Docket No. OA97-606-
000 was issued July 16, 1997, with comments, protests and
interventions due on or before July 30, 1997.° Wisconsin
* Notice of this filing was originally erroneously made in Docket No.
ER97-3487-000, but was corrected with an errata issued July 17, 1997 in
Docket No. OA97-606-000.
15a
Municipal Intervenors (WMD), which consists of The Wisconsin
Public Power Inc. SYSTEM and the municipalities of Bangor,
Barron, Cornell, Medford, and Rice Lake, filed a motion to
intervene on August |, 1997.
Notice of NSP Companies’ filing in Docket No. ER98- 890-
000 was published in the Federal Register, 63 Fed. Reg. 10,599
(1998), with comments, protests and interventions due on or
before March 20, 1998. A notice of intervention was filed by
the Public Service Commission of Wisconsin (Wisconsin
Commission). Motions to intervene were filed by Wisconsin
Electric Power Company (WEPCO), Otter Tail Power
Company (Otter Tail), Wisconsin Power & Light Company
(WP&L), Minnesota Power & Light Company (Minnesota
P&L), Minnesota Municipal Utilities Association (Minnesota
Municipal), city of Kasson, Minnesota (Kasson), city of
Buffalo, Minnesota (Buffalo), and WPS Energy Services, Inc.
(WESI). Motions to intervene and protests were filed by
Minnesota Wheeling Association (Minnesota Wheeling),
Wisconsin Public Service Corporation and WPS Energy
Services, Inc. (Wisconsin Public Service), the cities of Medford
and Rice Lake, Wisconsin (Medford and Rice Lake),
Commonwealth Edison, United Power Association (UPA),
Enron Power Marketing, Inc. (Enron), Southern Minnesota
Municipal Power Agency (Southern Minnesota), Dairyland
Power Cooperative (Dairyland), Cooperative Power
Association (CPA), Missouri Basin Municipal Power Agency
and the cities of Hillsboro, Marshall, St. James and Sauk Centre
(MBMPA), ECI, and Wisconsin Public Power Inc. (WPPI).
Central Minnesota Municipal Power Agency (CMMPA) filed
a motion to intervene out of time and protest. Some of the
intervenors requested other forms of relief. including motions
to reject the filing, requests for hearing and investigation,
requests for summary disposition, and motions to consolidate
Docket Nos. ER98-1890-000 and ER98-2060-000. NSP
Companies filed a response to the motions to intervene and
requests for relief.
16a
Notice of NSP Companies’ filing in Docket No. ER98-2060-
000 was published in the Federal Register, 63 Fed. Reg. 12,087
(1998), with comments, protests and interventions due on or
before March 20, 1998. Motions to intervene were filed by
Wisconsin Public Service, Anoka Electric Cooperative
(Anoka), WP&L, Minnesota Municipal, Otter Tail. Motions to
intervene and protests were filed by Minnesota Wheeling,
Medford and Rice Lake, National Rural Electric Cooperative
Association (NRECA), UPA, Southern Minnesota, Dairyland,
CPA, MBMPA, and WPPI. In addition, a motion to intervene
out of time was filed by Northwestern Wisconsin Electric
Company (Northwestern Wisconsin), and a motion to intervene
out of time and protest was filed by CMMPA. Some of the
intervenors requested other forms of relief, including motions
to reject the filing, requests for hearing and investigation,
requests for summary disposition, and motions to consolidate
Docket Nos. ER98-1890-000 and ER98- 2060-000, NSP
Companies filed a response to the motions to intervene and
requests for relief.
DISCUSSION
A. Procedural Matters
The notice of intervention of the Wisconsin Commission,
and the timely, unopposed motions to intervene of the persons
listed above serve to make them parties to the respective
proceedings in which they sought intervention. See 18 C.F.R.
§385.214 (1997). We will grant the motions for leave to
intervene out of time by WMI in Docket No. OA97-606-000,
Northwestern Wisconsin in Docket No. ER98-2060-000, and
CMMPA in Docket Nos. ER98-1890-000 and ER98-2060-000.
The other requests for relief will be discussed below.
17a
B. Open Access Transmission Tariff Compliance Filings in
Docket Nos. OA97- 25-000, and OA97-606-000
1. Non-Rate Terms And Conditions
We find that the open access transmission tariffs filed by
NSP Companies in Docket No. OA97-25-000 in order to
comply with Order No. 888, and in Docket No. OA97-606-000
in order to comply with Order No. 888-A, contain non-rate
terms and conditions that reflect the pro forma terms and
conditions established in Order Nos. 888 and 888-A.
Accordingly, we will accept these terms and conditions as of
the effective dates discussed below.
CCEM in its protest requested several changes in NSP
Companies’ terms and conditions concerning — specific
procedures and forms for implementing the right of first refusal,
reciprocity and creditworthiness procedures, the minimum term
for firm point-to-point service, and deadlines for requesting
short-term firm services. We will reject these proposed changes.
As we said in our prior orders addressing the non-rate terms and
conditions of open access compliance tariffs, we are concerned
at this point only with whether the compliance tariff conforms
with the pro forma tariff terms and conditions.* We find that
NSP Companies’ terms and conditions, in these respects, do
conform. We will, consistent with our prior orders, grant the
clarification requested by CCEM that a transmission customer
need not identify the specific source that will provide ancillary
services until the time for scheduling service. As we said
before, however, should the customer fail to make the
demonstration at the time of scheduling, it risks not being
* See Atlantic C ity Electric Company, et al., 77 FERC 961,144, at pp.
61,535, 61.537 (1996), order on reh'g, 82 FERC 461.075 (1998) (Atlantic
City Electric); See also Allegheny Power System, Inc., et al., 77 FERC
$61,266 (1996), order on reh'g, 82 FERC 961.251 (1998) (APS I), and
American Electric Power Service C orporation, et al., 78 FERC 461,070,
order on reh'g, 82 FERC 461,204 (1998) (AEP).
18a
allowed to schedule energy because of the lack of ancillary
MO
services,
2. Rates and Rate Terms and Conditions
NSP Companies are considered to be "Group |" public
utilities under Order No, 888,° which means that they had an
Open access transmission tariff on file before the date of
issuance of Order No. 888.’ As such, NSP Companies were
required to include in their Order No. 888 open access
compliance tariff the same rates as were in the pre-Order No.
888 tariff, except where changes were necessitated by the
revised non- rate terms and conditions.” We find, with one
exception, that NSP Companies have included in their Order
No. 888 compliance tariff the rates from their pre-Order No.
888 tariff without change.
The one change NSP Companies made to the rate provisions
concerns crediting for customers that own transmission
facilities. NSP Companies added a provision which (1)
establishes a methodology for computing the credit NSP
Companies will give a customer that owns transmission
facilities that operate as part of the integrated grid, and (2)
increases the network rate to reflect any su... credits granted
under the crediting methodology.’ As initially tendered in
* Atlantic City Electric, 77 FERC at p. 61,537.
* Order No. 888, FERC Statutes and Regulations at p. 31,964.
"Id. at p. 31,768. The NSP Companies’ pre-Order No. 888 open access
tariff was accepted subject to required modifications in Northern States
Power Company, 74 FERC 961,142 (1996),
" Order No. 888, FERC Statutes and Regulations at p. 31,770. See also
Allegheny Power System, Inc., et al., 80 FERC 461,143, at pp. 61,528-29
(1997), reh'g pending (APS II).
” For example, if NSP Companies negotiate a credit of $10,000/year in
recognition of the transmission facilities provided by one customer, NSP
Companies would increase the annual network revenue requirement by
$10,000, thereby increasing each network customer's rate to reflect its load
ratio share of the $10,000 payment.
19a
Docket No. 0A97-25-000, NSP Companies proposed to make
a filing under Section 205 in order to implement the credit and
the increase in the network rate. However, NSP Companies
amended the originally filed tariff on December 24, 1996, to
eliminate the filing requirement, i.e., to treat the surcharge as an
automatic adjustment clause.
The proposed methodology for computing customer credits
implements one of the pro forma tariff terms and conditions.
Therefore, we find that the change NSP Companies made to
their pre-Order No. 888 rates was necessitated by Order No.
888, and we will accept it for filing. However, our preliminary
review indicates that the proposed methodology has not been
shown to be just and reasonable, and may be unjust,
unreasonable, unduly discriminatory, or otherwise unlawful.
Accordingly, we will set this crediting methodology and rate
revision, including the reasonableness of using an automatic
adjustment clause, for hearing. Under Order No. 888, any rate
change necessitated by Order No. 888, such as this one, was
subject to a blanket suspension and is subject to refund."” The
crediting mechanism hereby set for hearing encompasses the
provision as contained in the filings in Docket Nos. OA97-25-
000 and OA97- 606-000. As discussed further below, we will
consolidate the hearing on this issue with the hearing on issues
concerning customer credits that have been raised in Docket
Nos. ER98- 1890-000 and ER98-2060-000.
We will reject the protests of CCEM and ECI to the extent
they protest aspects of NSP Companies’ ancillary service rates
that are unchanged from the pre-Order No. 888 rate. As we said
in APS Il, we will not set for investigation during the
compliance process rates that have simply been carried over
from a previous tariff and have already been determined to be
not unjust, unreasonable, or unduly discriminatory.'' We will
also reyect CCEM's proposal to add language concerning credits
Order No. 888, FERC Statutes and Regulations at p. 31,769,
"APS II, 80 FERC at p. 61,537.
20a
for non-firm customers whose service is interrupted. We
clarified the policy with respect to this issue in APS II and made
it applicable to all transmission providers. '” Accordingly, no
further change is required.
3. Effective Dates For Open Access Compliance Tariffs
NSP Companies requested an effective date of October 11,
1996 for its Order No. 888 compliance tariff filing in Docket
No. OA97-25-000, which was the date that it filed the tariff. We
will, however, make that tariff effective July 9, 1996, the date
on which all Order No. 888 compliance tariffs were to go into
effect.'* This will not affect any customer's bills because the
basic rates are unchanged, but it will ensure that NSP's
obligation to obtain transmission service under its pro forma
tariff for its own unbundled transactions began on July 9, 1996.
NSP Companies requested an effective date of November 1,
1996, for the revision it filed on December 24, 1996 conceming
crediting for transmission facilities as it applied to network
integration customers. NSP Companies explain that that is the
date that several customers commenced network integration
service and that the revision benefits customers. We will grant
waiver to permit this revision to become effective November 1,
1996.
NSP Companies requested an effective date of J uly 1, 1997,
for their Order No. 888-A compliance filing in Docket No.
OA97-606-000. We will, however, make the Order No. 888-A
compliance filing effective May 13, 1997, which is the date that
the changes required by Order No. 888-A became effective. '4
” APS II, 80 FERC at pp. 61,549-50.
“ Order No. 888, FERC Statutes and Regulations at p. 31,769.
“ See Order No. 888-A, FERC Statutes and Regulations at p. 30,500.
2la
C. Docket Nos. ER98-1890-000 and ER98-2060-000
1. Non-Rate Terms and Conditions
In Docket Nos. ER98- 1890-000 and ER98-2060-000, NSP
Companies have made what we have identified as ten changes
‘to the non-rate terms and conditions of their open access
transmission tariff. In Docket No. ER98-1890-000. NSP
Companies (1) revised Section 13.5 to limit their redispatch
obligation to NSP resources "under its control": (2) added a
reference to "redispatch costs" in Section 16.1: (3) changed the
word "schedule" to "request for service" in Section 18.4 dealing
with the determination of ATC: (4) changed Schedule 2 to add
limitations as to when NSP Companies will provide reactive
supply service; (5) revised Schedules 5 and 6 to specify that
customer-supplied operating reserves must be “acceptable to"
NSP Companies; and (6) revised Sections 14.6 and 18.3 to
establish earlier deadlines for reserving and scheduling nonfirm
service. In Docket No. ER98-2060-000, NSP Companies (1)
revised the definition of the customer's network load (Section
1.23) to include the "reserved capacity of the Network
Customer's firm point-to-point Transmission Customers;" and
(2) revised the definition for load ratio share (Section 1.17) to
replace the transmission provider's "total system load" with its
"Transmission System" load. With respect to all of these
changes, NSP Companies have either not attempted to
demonstrate how they are consistent with or superior to the pro
forma tariff, or have totally failed to even identify the change
made other than through redlining the revised page.
In New York State Electric & Gas Corporation, 78 FERC
(61,114, at pp. 61,434-35 (1997), reh'g denied, 82 FERC
{61,209 (1998), the Commission explained that it would reject
proposed changes found in the red-lined version of a revised
tariff but not otherwise identified or discussed in the filing, and
changes that were identified, but with no demonstration that the
changes were consistent with or superior to the pro forma tariff.
We will continue to strictly place the burden on the filing utility
to demonstrate that revised terms and conditions are consistent
22a
with or superior to the pro forma tariff. Accordingly, we will
reject NSP Companies’ proposed changes that are listed in the
preceding paragraph.
NSP Companies have made two revisions to non-rate terms
and conditions where they have attempted to demonstrate why
they are consistent with or superior to the pro forma tariff. First,
in Docket No. ER98-1890-000, NSP Companies propose to
eliminate Section 2.1, which deals with the initial allocation of
available transmission capacity, because the time frame for
requesting such an initial allocation has now expired by its own
terms. We will accept this revision because NSP Companies
have adequately explained how it is consistent with the pro
forma tariff.
The second revision that NSP Companies have attempted to
support involves the curtailment procedures in the pro forma
tariff. In Docket No. ER98-1890-000, NSP Companies have
revised the curtailment procedures in Sections 13.6 and 14.7 to
provide that curtailments would be made in accordance with the
Mid-Continent Area Power Pool (MAPP) Line Loading Relief
procedure (LLR). NSP Companies state that, under the MAPP
LLR, when a curtailment is required for a facility, a Power
Transfer Distribution Factor (PTDF) is calculated for
transactions utilizing the affected transmission facility. The
PTDF is the percentage of each current transaction that flows _
over the facility, e.g., if 5 MW of a 100 MW schedule flows
over the affected facility, its PTDF on that facility is 5%. NSP
Companies state that, under the MAPP LLR, all schedules with
a PTDF of 5% or higher are subject to curtailment under the
LLR before all schedules with a PTDF less than 5%. NSP
Companies' prepared direct testimony offers the following
explanation of the MAPP LLR:
Schedules are curtailed in priority order. All schedules
with a PTDF greater than 5% in a priority group are curtailed
before schedules are curtailed in the next higher priority
23a
group. Within each priority group, schedules are currently
curtailed on a pro-rata basis."” [emphasis added]
NSP Companies provide no description of "priority groups" and
do not explain whether the phrase “schedules are currently
curtailed” indicates that NSP Companies intend to adopt MAPP
practices, as they change from time to time, without a filing
with the Commission. NSP Companies’ witness asserts, without
elaboration, that the MAPP LLR is consistent with the pro
forma tariff requirement that curtailments "be made on a non-
discriminatory basis."
Several intervenors shave protested this change in the
curtailment provisions.’ ° They explain that, under the MAPP
LLR, there are 14 different priority groups which, among other
things, establish different priorities for firm services based on
factors such as the type of power sale that is being transmitted,
e.g., Short-term firm service would be curtailed before longer-
term firm service. Intervenors complain that these curtailment
priorities do not track the pro forma tariff curtailment priorities,
and do not provide curtailment on a comparable, non-
discriminatory basis.
We will reject NSP Companies’ proposed revisions to the
curtailment provisions. First, it is unacceptable to define tariff
curtailment priorities through a general reference to a MAPP
procedure that is unexplained in the tariff and that may change
from time to time. The specific curtailment priorities must be
delineated in the tariff and subject to change only by a filing
with the Commission under Section 205.'’ Second, the Order
'’ Prepared Direct Testimony of Mr. David B. Grover, Exh. No. ___
(NSP- 200(DBG)), at 5.
'* Among those protesting this change is ECI, Enron, Commonwealth
Edison, and Wisconsin Public Service
” This is consistent with the Commission's recent order finding that
Western Resources, Inc.'s proposed tariff provisions did not adequately
describe its proposed new curtailment terms. Coalition Against Private
Tariffs, 83 FERC 461,015 (1998).
a 24a
No. 888 requirement that tariff terms be demonstrated as
consistent with or superior to the pro forma tariff is not met by
NSP Companies’ one sentence assertion that this is the case.
Finally, NSP Companies’ description of the MAPP LLR is
severely misleading. Nothing in NSP Companies’ description
provides an appreciation of the number of curtailment priorities
or the basis for the priority used under the MAPP LLR.
2. Rates and Rate Terms and Conditions
In Docket No. ER98-1890-000, NSP Companies propose to
increase the rate for firm point- to-point service; to revise the
ancillary service rates in its tariff in several respects, including
the initiation of a reactive supply charge (there was no charge
for this service in the present tariff); to reduce the energy
deviation band for energy imbalance service from 4% to 1.5%;
to tie the charge for energy imbalance deviations to data
published by Continental Power Exchange (CPEX) concerning
the rates negotiated by utilities using its brokering services;
and to add some ancillary service charges to bilateral
agreements which presently do not include charges for these
particular ancillary services. In Docket No. ER98-2060-000,
NSP Companies proposed to increase the Annual Transmission
Revenue Requirement (ATRR) for network service and to
change the mechanism for calculating ATRR."”
'* While many transmission providers assess a penalty charge of 100
millskWh for energy imbalances outside the deviation band, NSP
Companies’ present tariff assesses a charge based on its own marginal energy
costs. NSP Companies state that the present rate actually creates an incentive
to under schedule when NSP’s marginal energy costs are less then the
prevailing market price for energy. NSP Companies propose to adopt the
highest price reported by CPEX for the day on which the deviations
occurred.
'’ NSP Companies have also identified revisions to four provisions of the
pro forma tariff that are related to their proposed rate changes, and these will
be accepted, subject to the outcome of the Commission's review of the rate
proposals. These revisions are: (1) revised the definition of network load
(Section 1.17) to eliminate references to a 12 month rolling average: (2)
aerate artnet
25a
A number of intervenors contend that NSP Companies’
filings in Docket Nos. ER98-1890-000 and ER98-2060-006
should be rejected as deficien;. They complain that certain
aspects of the cost methods are not explained (e.g., how
administrative and general expenses were functionalized to
transmission) and that the data on various Statements are not
cross-referenced to the Supporting statements, They also
contend that the workpapers are not adequate. Finally, they note
that NSP Companies have made a computational error in
developing the unit charge.
Our review indicates that NSP Companies’ submittals meet
the minimum threshold filing requirements, and we will
therefore not reject the filings as deficient. However, we will
summarily direct NSP Companies to file revised rates to correct
a computational error. As noted by the intervenors, and
acknowledged by NSP Companies, NSP Companies made an
error in transferring the demands developed on Statement BB
(91,691 MW) to Statement BL (89.913 MW), where those
demands are divided into the revenue requirement to develop
the unit charge. Correction of this error will reduce the
transmission rate by about 8%. NSP Companies have made
similar errors in developing some of the ancillary service rates.
Accordingly, although NSP Companies have submitted revised
cost-of-service statements,”’ we will direct NSP Companies to
also file revised rates to correct these computational errors
based on the demand data reflected in its cost study within 30
days of the date of the order herein.
revised the definition of the transmissionprovider's monthly transmission
peak (Section 1.48) to clarify that the current definition ("maximum monthly
usage") includes "all network and Firm Point-to-Point Transmission
Service;" (3) defines the annual billing year to begin in May each year
(Section 34.1); and (4) changes the network load calculation from a rolling
12 month average to single annual recalculation (Section 34.3.1 ).
” See NSP Companies’ Response in Docket No. ER98-1890-000.
26a
Our preliminary analysis of NSP Companies’ proposed rate
changes indicates that they have not been shown to be just and
reasonable, and may be unjust, unreasonable, unduly
discriminatory or preferential, or otherwise unlawful.
Accordingly, with the corrections made to the computational
errors noted above, we will accept the proposed rates for filing,
suspend them and make them effective subject to refund, and
set them for hearing, as ordered below. We will consolidate for
hearing all rate related issues in Docket Nos. ER98-1890- 000
and ER98-2060-000, and will also consolidate with this hearing
the issues related to customer credits for transmission facilities
as discussed above with respect to Docket Nos. OA97-25-000
and OA97-606-000.
In West Texas Utilities Company, 18 FERC 961,189 (1982),
we explained that where our preliminary examination indicates
that proposed rates may be unjust and unreasonable, but may
not be substantially excessive, as defined in West Texas, we
would generally impose a nominal suspension. Here, our
examination suggests that the proposed rates may yield
substantially excessive revenues. Therefore, we shall suspend
the proposed rates, and the related changes to rate terms and
conditions, for five months, to become effective, subject to
refund, on October 1, 1998.
Because the ultimately approved rates in this docket may be
lower than the last clean rate (i.e., the rates approved in Docket
Nos. ER94-1090-000 and ER94-1113-000),”' we will also
institute an investigation of the proposed rates under Section
206 of the Federal Power Act, in Docket No. EL98-40-000, and
establish a refund effective date.
In cases where, as here, the Commission institutes a Section
206 investigation on its own motion, Section 206(b) requires
that the Commission establish a refund effective date that is no
*' The last clean rate is that last rate in effect not subject to any refund
obligation. See Federal Power Commission y. Sunray DX Oil Company, 391
U.S. 9, 21-24 (1968).
27a
earlier than 60 days after publication of notice of the
Commission's investigation in the Federal Register, and no later
than five months Subsequent to the expiration of the 60- day
period. In order to give maximum protection to consumers, and
consistent with our precedent,”? we will establish the refund
effective date at the earliest date allowed. This date will be 60
days from the date on which notice of Our initiation of the
investigation in Docket No. EL98-40-000 is published in the
Federal Register,
Section 206 also requires that, if no final decision is
rendered by the refund effective date or by the conclusion of the
180-day period commencing upon the initiation of a proceeding
pursuant to Section 206, whichever is earlier, the Commission
shall state the reasons why it has failed to do so and shall state
its best estimate of when it reasonably expects to make such a
decision. To implement that requirement, we will direct the
presiding judge to provide a report to the Commission no later
than 15 days in advance of the refund effective date in Docket
No. EL98-40-000 in the event the presiding judge has not, by
that date: (1) certified to the Commission a settlement which,
if accepted, would dispose of the proceeding; or (2) issued an
initial decision. The judge's report, if required, shall advise the
Commission of the status of the investigation and provide an
estimate of the expected date of certification of a settlement or
issuance of an initial decision.
D. Joint Transmission Arrangements
NSP Companies’ filing in Docket No. ER98-2060-000 raises
an issue with respect to certain joint transmission arrangements
that warrants special procedures. Historically, there has been a
close interdependence, for transmission purposes, among NSP
Companies and neighboring transmission facility owners, which
include Southern Municipal, Dairyland, CPA, UPA, and
* See, e.g., Cambridge Electric Light Company, 75 FERC 461,177
(1996); Canal Electric Company, 46 FERC 461,153. reh'g denied, 47 FERC
961.275 (1989).
28a
CMMPA. NSP Companies had entered into agreements with
these neighboring facility owners, some dating as far back as
the 1960's, related to joint planning and joint use of
transmission facilities. Over the years, these joint transmission
agreements have been the subject of considerable dispute, not
only as to the compensation provisions, but as to the extent to
which the other party was permitted to use NSP Companies’
transmission system. In 1995 and 1996, pursuant to various
settlement agreements,” these neighboring facility owners
became network transmission customers under NSP
Companies’ open access tariff. As such, they qualified under
Section 30.9 of the pro forma tariff for billing credits
applicable to Network Customers that own transmission
facilities that are integrated into the Transmission Provider's
Transmission System.
In their filing in Docket No. ER98-2060-000, NSP
Companies now contend that the crediting for facilities owned
by these network customers is not working as envisioned.”
NSP Companies state that, in retrospect, they do not believe
that the Commission intended for the crediting provisions to
apply in some of the circumstances presented under NSP
Companies’ historical joint transmission arrangements. They
suggest that the crediting provision was intended to apply only
to tariff customers that owned discrete facilities located within
the NSP Companies control area. They assert that some of the
utilities with whom they had joint transmission arrangements
own extensive facilities, which in some instances result in
customer credits that equal or exceed the network rate that
would otherwise be billed. NSP Companies add that the
application of the crediting provision in these circumstances
** Some of these settlements were intended to gain the neighboring
facilities owners’ support for the NSP Companies’ ultimately unsuccessful
efforts to merge with Wisconsin Electric Power Company to form Primergy.
* NSP Companies’ position with respect to customer credits is presented
in the Prepared Direct Testimony of Mr. Anthony G. Shuster, Exh. No. <<
NSP-105 (AGS).
29a
could arguably be interpreted to require them to pay these
customers the difference, thereby allowing the customers to
effectively collect transmission revenues from NSP Companies
and other tariff customers, even though they ‘have no
transmission tariff on file with the Commission.
NSP Companies admit that they voluntarily entered into the
network service agreements, but state that the concept has not
operated as anticipated. They also assert that they are not trying
to avoid any payments that the neighboring facilities owners
may be due for NSP Companies’ use of their facilities, but want
to avoid cost-shifting and timing problems associated with the
existing method of crediting for use of these facilities. NSP
Companies’ remedy, as proposed in Docket No. ER98-2060-
000, is to revise Section 34.1 of their tariff to cap the credit at
the amount of the charge for network service that would
otherwise apply, i.e., credits may reduce the customer's bill to
zero, but NSP would not be required to make payments to the
customer if the credit exceeded the bill. NSP Companies also
propose various revisions to the mechanism for calculating the
credit. NSP Companies acknowledge that they are receptive to
other solutions, and ask that the Commission provide some
guidance on these issues.
The neighboring facilities owners protest NSP Companies’
proposal. Southern Municipal argues that NSP Companies
should not be surprised that they would be a net payer as a
result of the crediting mechanism since it replaces a joint
transmission agreement which assigned substantial cost
responsibility to NSP Companies for the joint transmission
system. Southern Municipal contends that data developed in
support of the settlement clearly indicated that its credit was
expected to exceed its bill and that NSP Companies would be
making payments to Southern Municipal each month. Finally,
Southern Municipal states that it is involved in continuing
disputes about which facilities are eligible for credits, and upon
the Commission's directive in response to its protests in other
dockets, it has attempted to resolve these disputes through the
ADR process under NSP's open access tariff. Southern
terrence
30a
Municipal also contends that all affected parties have urged
NSP Companies to convene joint Network Operating
Committee meetings to reach a broad resolution of these issues,
but that NSP Companies have resisted these efforts.
CMMPA supports Southern Municipal's comments.
CMMPA also complains that the NSP Companies’ proposal is
at odds with a moratorium which fixes CMMPA's credit for
three years. CPA/Dairyland and other intervenors challenge
NSP Companies attempted reliance on the approach in the prior
transmission agreements. CPA/Dairyland note that those earlier
agreements required investment equalization and did not
contemplate that the parties’ benefits and burdens would be
disproportionate. Finally, UPA argues that a regional tariff is
preferable and should be pursued now. UPA also contends that
NSP Companies’ current proposal (which caps the credit at the
amount of the network charges that would otherwise be billed)
is an attempt by them to relitigate a fundamental term and
condition of Order No. 888 that should be summarily rejected.
The Commission agrees with NSP Companies that Section
30.9 of the pro forma tariff was not intended to be the
foundation for joint transmission arrangements. Clearly, the
Commission did not expect that a customer facility which was
integrated with the transmission provider's system would, at the
same time, comprise part of the customer's own integrated
transmission gr/d. Section 30,9 was not designed to provide the
framework for the complicated arrangements necessary to
operate joint transmission systems such as the case here. That
said, it is also clear that NSP Companies created this untenable
situation by negotiating settlements promising something that
was not required under the pro forma tariff. We will reject the
last sentence of NSP Companies’ proposed revision to Section
34.1 of the tariff, which places a cap on customer credits,
because NSP Companies have not demonstrated how that
change is consistent with the negotiated settlements. We believe
that this issue presents special circumstances, and is not an
issue that can be resolved through litigation of the appropriate
terms for NSP Companies’ open access tariff. While the
3la
intervenors should not be deprived of the benefits of their
settlement bargains, those bargains also cannot be forced to fit
into the pro forma tariff.
We will therefore sever from the rest of the hearing ordered
herein the issue of appropriate compensation mechanisms for
use of the transmission facilities encompassed by network
service by NSP Companies to Southern Municipal, Dairyland,
CPA, UPA, and CMMPA. Because all of the affected parties
seem to recognize the desirability of a negotiated, regional
solution, we will assign this severed issue to a settlement judge.
We would expect that the settlement judge and the parties will
search for a solution that takes into account the promises
embodied in the prior settlements, and that resolves these
matters jointly and comprehensively and without resort to
bilateral negotiaticns that fail to reflect the joint operation of
these transmission facilities. We will direct that the settlement
judge report to us within 90 days from the date of this order,
and if these efforts appear unsuccessful, we will consider other
procedures.
E. WPPI's Request for Summary Disposition
WPPI is NSP Companies’ customer under two bilateral
transmission agreements: the long-term transmission agreement
for deliveries to certain western Wisconsin cities (WTA), and
the long-term transmission agreement for deliveries to eastern
Wisconsin (ETA), both of which were negotiated in 1990, The
WTA currently includes three ancillary services: scheduling,
load following and energy deviations, while the ETA includes
only scheduling. In Docket No. ER98-1890-000, NSP
Companies propose to revise the transmission rates in each
agreement to track the changes proposed for the tariff rates: to
add a reactive supply charge to each agreement; and to revise
the other ancillary service provisions in the WTA to track
changes proposed for the tariff.
WPPI moves for summary disposition, asking that we rule
that NSP Companies are prohibited by contract from seeking
certain changes to the transmission agreements. WPPI argues
ee ee ee
32a
that while the WTA and ETA allow for changes to rates, NSP
Companies do not have the right under those agreements to
unilateraily change the non-rate terms and conditions. WPPI
challenges specifically the addition of reactive supply charges
for each agreement and the proposed revisions to the energy
imbalance charges in the WTA. We will deny WPPI's request.
WPPI's contention that charges for reactive power and the
deviation band for energy imbalances are non-rate terms and
conditions is without merit. How much WPPI will pay for
reactive power is Clearly a rate matter, and the sole purpose of
an energy imbalance deviation band is to demarcate the point at
which the price changes from energy returned in kind (inside
the band) to a higher charge (outside the band). Also, WPPI is
incorrect in its contention that, under the WTA, energy
imbalance provisions are not covered under the provisions
permitting unilateral rate changes because they are not
contained in the exhibit listing rates. Section 7.04 of the WTA
states:
All compensation provisions under this Agreement are
subject to unilateral rate change filings by NSP at any time
under Section 205 of the Federal Power Act, and complaint
filings by WPPI at any time under Section 206 of the
Federal Power Act. NSP shall have the unilateral right, on
any basis whatsoever, to make unilateral rate change
filings for firm transmission services provided hereunder
Clearly, the location of the compensation
provision—whether or not it is in the rate exhibit—does not
affect NSP Companies’ ability to file changes to any
"compensation" provision. Finally, the absence of a reactive
power charge in the WTA and ETA is not surprising because
the rates were last revised to track NSP companies’ pre-Order
No. 888 tariff rates and that tariff did not include a rate for
reactive power. WPPI may pursue at hearing the amount of
credit it should receive, if any, for reactive supply provided by
its generating units.
33a
WPPI also argues that NSP Companies have eliminated
provisions from the WTA and ETA dealing with revenue
credits and credits for customer-owned transmission facilities
contrary to agreements reached as part of the Primergy merger
settlement. WPPI contends that these are also unilateral
revisions to non- rate terms that are not permitted under the
ETA and WTA. Contrary to WPPI's claim, NSP Companies
have not proposed any revision to the WTA or ETA related to
the revenue credits and Customer-supplied transmission.
Further, it does not appear that those settlement provisions were
ever codified in the WTA and ETA, Accordingly, WPPI's
request for summary disposition is denied.
The Commission orders:
(A) NSP Companies’ open access transmission tariff filed in
Docket No. OA97-25-000 is hereby accepted and set for
hearing in part, as discussed in the body of this order, to be
effective July 9, 1996.
(B) NSP Companies’ open access transmission tariff revision
to Attachment H filed on December 24, 1996, is hereby
accepted and set for hearing, as discussed in the body of this
order, to be effective November 1, 1996.
(C) NSP Companies’ open access transmission tariff filed in
Docket No. OA97-606-000 is hereby accepted and set for
hearing in part, as discussed in the body of this order, to be
effective May 13, 1997.
(D) NSP Companies’ proposed revisions to their open access
tariff made in Docket Nos. ER98-1890-000 and ER98-2060-
000 are hereby accepted in part, rejected in part, and, as
accepted, suspended for five months and made subject to
refund, and set for hearing in part, as discussed in the body of
this order, to become effective October 1, 1998.
(E) NSP Companies are hereby directed to submit amended
rate sheets reflecting the corrected computational error, as
discussed in the body of this order, within 30 days of the date
of this order, :
34a
(F) Pursuant to the authority contained in and subject to the
jurisdiction conferred upon the Federal Energy Regulatory
Commission by Section 402(a) of the Department of Energy
Organization Act and the Federal Power Act, particularly
Sections 205 and 206 thereof, and pursuant to the Commission's
Rules of Practice and Procedure and regulations under the
Federal Power Act (18 C.F.R. Chapter I), a public hearing shall
be held in the consolidated dockets concerning the justness and
reasonableness of NSP Companies’ proposed rates and rate
terms, as discussed in the body of this order.
(G) Pursuant to the authority contained in and subject to the
jurisdiction conferred upon the Federal Energy Regulatory
Commission by Section 402(a) of the Department of Energy
Organization Act and by the Federal Power Act, particularly
Section 206 thereof, and pursuant to the Commission's Rules of
practice and procedure and the regulations under the Federal
Power Act (18 C.F.R. Chapter I), a public hearing shall be held
in Docket No. EL98-40-000 concerning the justness and
reasonableness of NSP Companies’ rates and rate terms, as
discussed in the body of this order.
(H) The Secretary shall promptly publish in the Federal
Register a notice of the Commission's initiation of the
proceeding in Docket No. EL98-40-000.
(1) The refund effective date in Docket No. EL98-40-000,
established pursuant to Section 206(b) of the Federal Power
Act, will be 60 days following publication in the Federal
Register of the notice discussed in Ordering Paragraph (H)
above.
(J) Docket Nos. OA97-25-000, OA97-606-000, ER98-1890-
000, ER98-2060-000, and EL98-40-000 are hereby consolidated
for purposes of hearing and decision.
(K) A presiding administrative law judge, to be designated
by the Chief Administrative Law Judge, shall convene a
conference in these proceedings to be held within
approximately 15 days of the date of this order, in a hearing
35a
room of the Federal Energy Regulatory Commission, 888 First
Street, NE., Washington, DC 20426. Such conference shall be
held for the purpose of establishing a procedural schedule. The
presiding judge is authorized to establish procedural dates, and
to rule on all motions (except motions to dismiss) as provided
in the Commission's Rules of Practice and Procedure.
(L) The presiding administrative law judge shall advise the
Commission, no later than 15 days prior to the refund effective
date established in Docket No. EL98-40-000, in the event that
the presiding judge has not by that date certified to the
Commission a settlement which, if accepted, would dispose of
the proceeding or issued an initial decision, as to the Status of
the proceeding and a best estimate as to when the proceeding
will be disposed of by the presiding judge.
(M) Pursuant to Rule 603 of the Commission's Rules of
Practice and Procedure, 18 C.F.R. §385.603 (1997), the Chief
Administrative Law Judge is hereby directed to appoint a
settlement judge in this proceeding within approximately 15
days of the date of issuance of this order, for the limited
purpose of considering the issue severed from the hearing, as
discussed in the body of this order. The designated settlement
judge shall have all powers and duties enumerated in Rule 603
and shall convene an initial settlement conference as soon as
practicable. The settlement judge will report to the Commission
on the status of the negotiations and the prospects for settlement
within 90 days of the date of this order.
(N) The motions to intervene out of time, motions to reject,
and motions for summary disposition are disposed of as
discussed in the body of this order.
(O) NSP Companies are hereby informed of the rate
schedule designations shown on the Attachment to this order.
36a
APPENDIX C
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Docket Nos. OA97-25-000, OA97-606-000, ER98- 1890-000,
ER98-2060-000, and EL98-40-000
NORTHERN STATES POWER COMPANY (MINNESOTA) AND
NORTHERN STATES POWER COMPANY (WISCONSIN)
Order on Request for Clarification
(Issued June 29, 1998)
Before Commissioners: James J. Hoecker, Chairman; Vicky
A. Bailey, William L. Massey, Linda Breathitt, and Curt Hébert,
Jr.
On May 18, 1998, Northern States Power Company
(Minnesota) and Northern States Power Company (Wisconsin)
(collectively, NSP Companies) requested clarification of our
April 30, 1998 order (April 30 Order) in this proceeding.' The
requested clarification concerns our rejection of NSP
Companies’ proposed modification of their open access
transmission tariff that was intended to revise the curtailment
procedures to be in accordance with the Mid- Continent Area
Power Pool (MAPP) Line Loading Relief (LLR) procedure.
' Northern States Power Company (Minnesota) and Northern States
Power Company (Wisconsin), 83 FERC 461,098 (1998).
a
37a
Commonwealth Edison Company (Commonwealth Edison),
Wisconsin Electric Power Company (WEPCO), and Electric
Clearinghouse, Inc. (ECT) filed answers to NSP Companies’
request. We will grant NSP Companies’ requested clarification
in part and deny it in part, as discussed below.
Our April 30 Order rejected NSP Companies’ proposal to
revise their open access transmission tariff curtailment
provisions to reflect the MAPP LLR because the proposed
curtailment procedure was not adequately explained in the
tariff, and NSP Companies did not demonstrate that the
revisions were consistent with or superior to the pro forma
tariff,
NSP Companies state in their request for clarification that
they will make a compliance filing to return their tariff's
curtailment provisions to the pro forma language, and that they
are not asking the Commission to rule on the merits of the
LLR.* NSP Companies assert, however, that using the pro
forma language in their open access tariff subjects them to
potentially conflicting obligations as between the tariff and the
MAPP Agreement. NSP Companies, therefore, ask us to
approve of several procedures they propose to implement to
avoid conflicting obligations.
As a general matter, NSP Companies explain that the
MAPP LLR procedures are required to ensure regional
reliability. NSP Companies describe this procedure as follows:
Under MAPP requirements, if NSP or any other MAPP
utility encounters a situation which demands loading relief for
any of its transmission facilities, that entity has the right to
"Id. at p. 61,469,
* NSP Companies state that they would rely on the outcome of the
complaint case filed in Commonwealth Edison Company v. Mid-Continent
Area Power Pool, Docket No. EL98-19-000 (Commonwealth Edison y.
MAPP) for the merits of the LLR procedure. We will address
Commonwealth Edison's complaint in a separate. future order.
38a
invoke the MAPP LLR procedures. When a utility requests
MAPP to invoke LLR, the MAPP Security Center gathers all
schedules, including the schedules NSP has accepted under its
open access Tariff, notes the priority of each under MAPP LLR
and orders utilities, including NSP, to effect interruptions as
required under LLR.*
NSP Companies state that they intend to continue to
implement MAPP LLR requests to interrupt or curtail
schedules, but will ensure that the curtailment priority assigned
to all transactions under the NSP Companies’ tariff is the
priority required under the pro forma tariff. NSP Companies
explain that the MAPP LLR has a number of curtailment
categories for firm transactions, based upon the length of the
transaction. However, they state that by directing MAPP to
assign all of NSP Companies’ firm tariff transactions, regardless
of their duration, to the MAPP LLR highest firm priority group,
NSP Companies can ensure that MAPP does not direct any
curtailments that are inconsistent with NSP Companies’ pro
forma tariff. We find that this is reasonable and consistent with
our April 30 Order.” Contrary to ECT’s assertion, the procedure
* NSP Companies Request at 4.
* We note that in the Commonwealth Edison v. MAPP proceeding,
MAPP has filed a letter informing the Commission that effective June 2,
1998, all firm transactions under MAPP member tariffs are provided the
same, and highest, curtailment priority under the MAPP LLR. ECT asserts
there is a conflict created in that the MAPP letter referred to priority level 15
as the highest, and NSP Companies referred to priority level 14 as the
highest. Although we do not know the reason for this discrepancy, our
clarification ts based on NSP Companies’ representation that they will report
all firm transactions at the “highest available priority,” whatever that may be.
Commonwealth Edison's answer to NSP Companies’ request states that
it appreciates NSP Companies’ unplementation proposals, but asserts that
other MAPP members’ transmission customers will not benefit from this and
that a solution involving all of MAPP is required. As Commonwealth Edison
is concerned about the actions of transmission providers other than NSP
Companies, its concer is more appropriately addressed in its pending
complaint case,
39a
proposed will result in curtailment priorities that are consistent
with the pro forma tariff.
NSP Companies also explain that they, rather than MAPP,
have the responsibility for ensuring that curtailment priorities
for firm point-to-point transactions under NSP Companies’
tariff are the same as the curtailment priorities for NSP
Companies’ network/native loads. Section 13.6 of the pro forma
tariff requires (to the extent practicable and consistent with
Good Utility Practice) that curtailments to firm point-to-point
transactions, network customers, and native load be done on a
comparable basis, NSP Companies state that, when MAPP
orders LLR for a constrained facility over which power flows
to network/native load and firm point-to-point customers, NSP
Companies will redispatch the system in a manner that will
maintain comparability, For example, NSP Companies state
that when 50% of the load on a constrained interface is firm
point-to-point transactions and 50% is network/native load,
NSP Companies will redispatch their system to absorb half of
the load reductions required to relieve the constraint. We find
that this procedure is reasonable and comports with the
comparability requirements of the pro forma tariff.
Next, NSP Companies state that, in the Situation where
there is a need to reduce loads on facilities that are being used
to serve both NSP Companies’ network/native loads and NSP's
firm point-to-point tariff customers, but NSP Companies have
exhausted all network/native load generation redispatch
options, they do not believe they are required to shed network/
native load in order to preserve comparability with curtailments
of firm point-to-point transmission provided under their tariff.
" WEPCO asserts that, if NSP Companies can avoid shedding
network/native load by redispatching, it is not effecting a proportional
curtailment of load,We disagree, NSP Companies have committed to effect
a proportional curtailment of load on the constrained facilities, Having taken
this action, NSP Companies, like any other transmission user, have the
option to continue to serve load using other resources or transmission paths,
as long as those actions are otherwise consistent with the pro forma tariff,
40a
NSP Companies argue that this procedure is fair because it sold
transmission service "based on the assumption that curtailment
of firm service and its subsequent forced redispatch is
permitted."’ NSP Companies add that MAPP uses a smaller
Capacity Benefit Margin (CBM) than other regions, and
therefore withholds less transmission capacity "for emergency
uses,” allowing for the calculation of a greater Available
Transmission Capability (ATC) for firm transmission
transactions as compared to other regions.
We cannot, based on the facts before us, grant clarification
that it is acceptable for NSP Companies to curtail firm point-to-
point transactions without directing pro-rata curtailments for its
network/native load, because that procedure would not comport
with the pro forma tariff.® The fact that NSP Companies expect
that their tariff customers may have redispatch options in
circumstances when NSP Companies do not is not a criterion
under the pro forma tariff for disproportionate curtailments of
firm point-to-point services. Also, the fact that NSP Companies
may have granted requests for firm point-to-point service in the
expectation that they would not be required to adhere to the pro
forma tariff curtailment terms provides no basis to grant
clarification that NSP Companies need not adhere to its tariff
terms. Moreover, NSP Companies’ suggestion that it is a
practice of MAPP utilities to calculate ATC more expansively
” NSP Companies Request, Affidavit of Terry L. Volkmann at 7.
* In Order Nos. 888 and 888-A, the Commission rejected the argument
that native load should be protected from load shedding under pro rata
curtailments. See Promoting Wholesale Competition Through Open Acess
Non- Discriminatory Transmission Services by Public Utilities; Recovery of
Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888,
61 Fed. Reg. 21,540 (1996), FERC Statutes and Regulations, Regulations
Preambles January 1991-June 1996 ¢3 1,036, at pp. 31,748-49 (1996), order
on reh'g, Order No, 888-A, 62 Fed. Reg. 12,274 (1997), FERC Statutes and
Regulations $31,048, at pp. 30,278-79 (1997), order on reh'g, Order No,
888-B, 81 FERC 461,248 (1997), order on reh'g, Order No, 888-C, 82 FERC
$61 046 (1998).
4la
than other regions, also in the expectation that network/ native
load transactions will have a higher curtailment priority than the
firm point-to-point tariff transactions. is unsupported and
unpersuasive,
Finally, NSP Companies assert that for them to shed load
under certain curtailment circumstances may reduce system
transfer stability, and they rely on this as an additional reason
why they should not be required to do so.” This presents a
different issue. The pro forma tariff requires comparability of
Ccurtailments when consistent with Good Utility Practice. The
Commission would not expect NSP Companies to violate Good
Utility Practice when implementing curtailments. Further, the
pro forma tariff allows the Transmission Provider the discretion
to curtail firm transmission service when an emergency or other
unforeseen condition impairs or degrades the reliability of its
transmission system. Absent such system reliability concerns,
however, NSP Companies must engage in a pro-rata
curtailment,
The Commission orders:
NSP Companies’ request for clarification is hereby granted
in part and denied in part, as discussed in the body of this order.
” NSP Companies Request, Affidavit of Terry L. Volkman at 6.
42a
APPENDIX D
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Docket Nos. OA97-25-003, OA97-606-003, ER98- 1890-004,
ERYS8-2060-004, and EL98-40-003
NORTHERN STATES POWER COMPANY (MINNESOTA) AND
NORTHERN STATES POWER COMPANY (WISCONSIN)
Order Denying Requests for Clarification,
Rehearing, and Stay
(Issued July 31, 1998)
Before Commissioners: James J. Hoecker, Chairman; Vicky
A. Bailey, William L. Massey, Linda Breathitt, and Curt Hébert,
Jr.
On July |, 1998, as supplemented July 21, 1998, Northern
States Power Company (Minnesota) and Northern States Power
Company (Wisconsin) (NSP) filed an "Emergency Request For
Clarification, Or Rehearing And Conditional Motion For Stay"
of the Commission's June 29, 1998 order in this proceeding.
Northern States Power Company (Minnesota) and Northern
States Power Company (Wisconsin), 83 FERC 461,338 (1998).
The Commission's June 29 order made several clarifications in
response to an NSP request, one of which was that it was not
acceptable for NSP to implement transmission line loading
relief by curtailing firm point-to-point transmission customers
before network/native load customers.
————eeeeeeeeeeeeeeeeee
43a
NSP now argues that the Commission does not have
jurisdiction over bundled retail service, and the Commission
should clarify that the order was not intended to apply the tariff
curtailment requirements to network service that NSP uses to
serve bundled retail load. NSP asks that the Commission
immediately stay the order if the curtailment provisions apply
to network load. !
DISCUSSION
We deny NSP's requests for clarification, rehearing, and
stay. The Commission's June 29 order was clear that NSP
cannot give preferential treatment to its native load when
curtailing transmission. The Commission does not regulate
bundled retail sales, but the pro forma open access transmission
tariff implemented by Order No, 888° does require that
wholesale transmission users be treated comparably to the
transmission provider's native load customers, including retail
customers, See tariff Sections 13.6 and 1.19.
Finally, NSP has not shown that justice requires granting its
Stay request,
The Commission orders:
NSP's requests for clarification, rehearing, and Stay are
hereby denied.
' NSP also asks us to clarify the curtailment priority of certain firm
transmission agreements with Wisconsin Public Power, Inc. As our June 29
order did not address that issue, it is not an appropriate subject for
clarification or rehearing of that order.
’
See Promoting Wholesale Competition Through Open Acess Non-
Discriminatory Transmission Services by Public Utilities: Recovery of
Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888,
61 Fed, Reg. 21,540 (1996), FERC Statutes and Regulations, Regulations
Preambles January 1991-June 1996 431,036, at pp. 31,748-49 (1996), order
on reh’g, Order No. 888-A, 62 Fed. Reg. 12,274 (1997), FERC Statutes and
Regulations 431,048 at pp. 30,278-79 (1997), order on reh'g, Order No. 888-
B, 81 FERC 461,248 (1997), order on reh'g, Order No.888-C, 82 FERC
461,046 (1998).
44a
APPENDIX E
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: James J. Hoecker, Chairman; Vicky A.
Bailey, William L. Massey, Linda Breathitt, and Curt Hebert, Jr.
Docket No. 0A97—25-004, 0A97-606-004, ER98-1890-005,
ER98-2060-005, EL98-40-004
NORTHERN STATES POWER COMPANY (MINNESOTA)
NORTHERN STATES POWER COMPANY (WISCONSIN)
ORDER ON REMAND
(Issued November 15, 1999)
On May 14, 1999, the United States Court of Appeals
for the Eighth Circuit, in Northern States Power Co., et al. v.
FERC, 176 F.3d 1090 (1999), reh'g denied (9/1/99) (NSP),
instructed the Commission to allow amendment to its Northern
States Power Company (NSP) curtailment orders, as now
interpreted under Order No. 888, consistent with the Court's
opinion.” In this order, we modify our prior orders to permit
NSP's proposed curtailment procedures, but subject to NSP
filing further revisions to its curtailment provisions to reflect
the narrow circumstances addressed in the Court's order as well
as revisions to NSP’s rates for firm point-to-point transmission
service to reflect the inferior quality of service provided to
point-to-point Customers compared to the service provided to
native load customers,
* 176 F.3d at 1096
45a
Background
In Docket No. ER98-1890-000, the proceeding relevant to
this order on remand, NSP proposed, among other things, to
increase its rate for firm point-to-point transmission service
and, as a separate matter (i.e., unrelated to the revised rates), to
revise the curtailment procedures in Sections 13.6 and 14.7 of
its Open access transmission tariff to provide that curtailments
would be made in accordance with the Mid-Continent Area
Power Pool (MAPP) Line Loading Relief procedure (LLR). The
Commission rejected NSP's proposed revisions to the
curtailment provisions because those revisions improperly
defined tariff curtailment priorities through a general reference
to a MAPP procedure (which the Commission found NSP to
have described in a misleading manner) and were not
demonstrated to be consistent with or superior to the pro forma
tariff. The Commission accepted in part and rejected in part
NSP's proposal, suspended its effectiveness for five months, to
become effective October 1, 1998, subject to refund, and set
certain matters for hearing." Subsequently, in response to a
request for clarification, the Commission rejected, as
irreconcilable with Order No. 888, NSP's assertion that it is
acceptable for NSP to curtail firm point-to-point transmission
service without directing pro rata curtailments of transmission
service for its network/native load. Northern States Power Co.,
83 FERC 61,098, clarified, 83 FERC 61,338. reh'g,
clarification and stay denied, 84 FERC 61,128 (1998 ).
The Commission explained with respect to NSP's
clarification request:
* The Commission also instituted an investigation under section 206 of
the Federal Power Act because the ultimately approved rates may be lower
than the last clean rates. 83 FERC at 61,470-71. On April 28, 1999. the
presiding administrative law judge certified an uncontested offer of
settlement that is designed to resolve all remaining issues pending between
NSP and the active parties (the curtailment issue is not part of the settlement
offer). See 87 FERC 63,003 ( 1999). This certification is currently pending
before the Commission,
SC eee nme
46a
For example, NSP Companies state that when 50% of the
load on a constrained interface is firm point-to-point
transactions and 50% is network/native load, NSP
Companies will redispatch their system to absorb half of the
load reductions required to relieve the constraint. We find
that this procedure is reasonable and comports with the
comparability requirements of the pro forma tariff?
However, the Commission disagreed with NSP's argument
that when NSP has exhausted all of its network/native load
generation redispatch options (and the transmission
constraint had not been fully relieved) it can direct the
curtailment of firm point-to-point transactions without
directing pro rata curtailments of transmission service for its
network/native load. /d.
The Court, however, concluded as follows:
We think it obvious that the indirect effect of Order No.
888, as interpreted by the Commission, is an attempt to
regulate curtailment of electrical power to NSP's native/retail
consumers. Despite FERC's denial as to nonjurisdictional
regulation, we find it has transgressed its Congressional
authority which limits its jurisdiction to interstate
transactions. As such, its attempt to regulate the curtailment
of electrical transmission on native/retail consumers is
unlawful, as it falls outside of the FPA's specific grant of
authority to FERC.°
The Court instructed the Commission to allow
amendment to its NSP curtailment orders, as now interpreted
under Order No. 888, consistent with the Court's opinion. f
> 83 FERC 61,338 at 62,369 (footnote omitted).
° 176 F.3d at 1096.
"Id.
47a
Discussion
The Court addressed NSP's concerns in the context of a
narrowly circumscribed _ factual circumstance the
implementation of curtailment over a transmission constraint
after NSP has exhausted all of. its network/native load
generation redispatch options, but the firm point-to-point
transmission customer still has options with which to avoid
having to shed load."
NSP itself has asserted (in response to the Commission's
petitions for rehearing before the Court) that "this case is quite
narrow."” It maintained to the Court that
[t]his case addressed the relatively rare circumstance in
which generation redispatch is inadequate or unavailable to
relieve the transmission constraint fully. The June 29
Curtailment Order clearly required NSP to curtail pro rata even
if redispatch has been exhausted. In that circumstance, NSP
would be required to curtail electric power by reducing service
to native load customers on the constrained line, thereby
causing blackouts. NSP stands ready under its tariffs to shed
load in tandem with other transmission customers. Being forced
under the Curtailment Orders to shed load, however, merely to
preserve a wholesale transaction's economic expectancy when
that customer has redispatch options that could be used to help
solve the problem, goes too far,'”
* Id. at 1093,
” Response at 3 n.3.
és Response at 4. NSP also pointed to a recent Commission decision, in
which the Commission stated:
[W]e emphasize that the pro forma tariff does not prescribe procedures for
curtailing loads, whether wholesale or retail. Rather, it prescribes procedures
for reducing transmission on a constrained transmission facility.
48a
The Commission will permit NSP to amend its open access
transmission tariff to reflect its proposed curtailment procedures
that would be effective in such "rare circumstances.” However,
it grants that permission subject to NSP also filing further
revisions to its curtailment provisions to reflect the
circumstances addressed in the Court's order, ‘e¢., the
implementation of curtailment over a transmission constraint
after NSP has exhausted all of its network/native load
generation redispatch options, and the firm point-to-point
transmission customer whose firm service is being curtailed still
has options with which to avoid having to shed load.
Specifically, if NSP amends its open access transmission tariff
to reflect its proposed curtailment procedures, NSP must also
revise its tariff to:
(1) curtailment that does not reflect a pro rata approach, will
follow to ensure that NSP has exhavced all of its redispatch
options, including invoking all cptions to purchase power
from other suppliers and to purcaase emergency energy from
neighboring utilities;
(2) specify a methodology that NSP will use to confirm that
any firm point-to-point transmission customer that is
curtailed in excess of its pro rata curtailment has redispatch
or other options available at the time NSP determines, under
the procedures in (1) above, that NSP has exhausted all of its
redispatch options; and
(3) specify a method to compensate a firm point-to-point
transmission customer for any redispatch costs the customer
may incur to protect NSP's native load and network
customers from pro rata curtailment, including the cost of
Response at 10 (citing North American Electric Reliability Council, 88
FERC 61,046 at 61,124 (1999) (emphasis in original), According to NSP,
"[t}his statement implies that FERC now intends ‘curtailment’ to be limited
to redispatch, a positive development but a fundamental departure from the
requirements in the Curtailment Orders.” /d.
49a
any transmission service (on the customer's system) that the
Customer would need to support its redispatch on behalf of
NSP's native load and network customers. ''
In addition, if NSP amends its tariff to reflect its proposed
curtailment procedures, NSP must revise its rates for firm point-
(0-point transmission service effective October 1, 1998 (the date
its rate revisions went into effect subject to refund) to recognize
the inferior quality of that service compared to the service
provided by NSP to its native load and network
customers, and provide cost support for such rates consistent
with section 35,13 of the Commission's regulations. See 18
C.RR. 35,13 (1999),
" Bor example, assume that NSP must reduce the use of a transmission
line by 100 MW at a time when NSP and a firm point-to-point transmission
customer each account tor 50 percent of the total use of the line. Under the
pro forma tariff, NSP and its firm point-to-point customer each would reduce
its use of the line by 50 MW. Assume that, after following the procedures in
(1) above, NSP can only remove 25 MW through redispatch of its system,
but as confirmed by the procedures in (2) above, the firm point-to-point
customer has additional redispatch options beyond those needed for its 50
MW pro rata curtailment. If NSP curtails its own uses by 25 MW and
curtails the firm point-to-point customer's use by 75 MW, the customer has
provided 25 MW of redispatch service to NSP. NSP must compensate the
firm point-to-point customer for this Service just as it would for any other
redispatch service offered voluntarily by other market participants.
. The Commission notes that the issues in this case would likely not
arise in the context of a one-service tariff, under which there would no longer
be point-to-point and network services but only a capacity reservation type
tariff (see, e.g., Capacity Reservation Open Access Transmission Tariffs,
Notice Of Proposed Rulemaking, FERC Stats, & Regs. 32,519 (1996)).
Similarly, the distinction between third-party and native load service would
hot arise under a tariff administered by a regional transmission organization,
which, for example, manages congestion on a regional basis (see Regional
Transmission Organizations, Notice Of Proposed Rulemaking, FERC Stats.
& Regs, 32,541 (1999)),
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The Commission orders:
NSP is hereby ordered, unless it chooses to withdraw its
proposal to amend its tariff with respect to curtailment
procedures, to file revised curtailment provisions and revised
rates, as discussed in the body of this order, within 30 days of
the date of this order.
By the Commission.
(SEAL) /s/_ David P. Boergers
DAVID P. BOERGERS
Secretary
Sla
APPENDIX F
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
61 F.R. 21540 (May 10, 1996) 18 CFR Parts 35 and 385
[Docket Nos. RM95-8-000 and RM94-7-001: Order No.888]
Promoting Wholesale Competition Through Open Access
Non-Discriminatory Transmission Services by Public
Utilities; Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities
Issued April 24, 1996,
SUMMARY: The Federal Energy Regulatory Commission
(Commission) is issuing a Final Rule requiring all public
utilities that own, control or Operate facilities used for
transmitting electric energy in interstate commerce to have on
file open access non-discriminatory transmission tariffs that
contain minimum terms and conditions of non-discriminatory
service. The Final Rule also permits public utilities and
transmitting utilities to seek recovery of legitimate, prudent and
verifiable stranded costs associated with providing open access
and Federal Power Act section 21 | transmission services, The
Commission's goal is to remove impediments to competition in
the wholesale buik power marketplace and to bring more
efficient, lower cost power to the Nation's electricity
consumers,
I. Introduction/Summary
Today the Commission issues three final, interrelated rules
designed to remove impediments to competition in_ the
wholesale bulk power marketplace and to bring more efficient,
lower cost power to the Nation's electricity consumers.' The
legal and policy cornerstone of these rules is to remedy undue
discrimination in access to the monopoly owned transmission
wires that control whether and to whom electricity can be
transported in interstate commerce. A second critical aspect of
the rules is to address recovery of the transition costs of moving
from a monopoly-regulated regime to one in which all sellers
can compete on a fair basis and in which electricity is more
competitively priced.
In the year since the proposed rules were issued,’ the pace of
competitive changes in the electric utility industry has
accelerated. By March of last year, 38 public utilities had filed
wholesale open access transmission tariffs with — the
Commission, Today, prodded by such competitive changes and
' These rules are the rules on open access and stranded costs in the
above dockets (FERC Stats. & Regs. 31,036), and an accompanying rule on
Open Access Same-Time Information System and Standards of Conduct
(OASIS Final Rule) (FERC Stats. & Regs. 31,037) being issued
contemporaneously. The Commission also is issuing contemporaneously a
notice of proposed rulemaking on capacity reservation open access
transmission tariffs in Docket No. RM96-11-000, FERC Stats. & Regs.
32,517. These final rules and proposed rule are being published
concurrently in the Federal Register.
*On March 29, 1995, the Commission issued two notices of proposed
rulemaking conceming open access transmission and stranded cost recovery.
Promoting Wholesale Competition Through Open-Access Non-
Discriminatory Transmission Service by Public Utilities and Recovery of
Stranded Costs by Public Utilities and Transmitting Utilities, Notice of
Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking,
60 FR 17662 (April 7, 1995), FERC Stats. & Regs. 32,514 (1995). On
December 13, 1995, the Commission issued a notice of proposed rulemaking
on information systems. Real-Time Information Networks and Standards of
Conduct, Notice of Proposed Rulemaking, 60 FR 66182 (December 21,
1995), FERC Stats. & Regs. 32,516 (1995).
—
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encouraged by our proposed rules, 106 of the approximately
166 public utilities that Own, control, or operate’ transmission
facilities used in interstate commerce have filed some form of
wholesale open access tariff. In addition, since the time the
proposed rules were issued, numerous State regulatory
commissions have adopted or are actively evaluating retail
Customer choice programs or other utility restructuring
alternatives. These events have been spurred by continuing
Pressures in the marketplace for changes in the way electricity
is bought, sold, and transported. Increasingly, customers are
demanding the benefits of competition in the growing electricity
commodity market.
The Commission estimates the potential quantitative benefits
from the Final Rule will be approximately $3.8 to $5.4 billion
Per year of cost savings, in addition to the non-quantifiable
benefits that include better use of existing assets and
institutions, new market mechanisms, technical innovation, and
it imperative that this Commission take the necessary steps
within its jurisdiction to ensure that all wholesale buyers and
Sellers of electric energy can obtain non-discriminatory
transmission access, that the transition to competition is orderly
und fair, and that the integrity and reliability of our electricity
infrastructure is maintained.
In this Rule, the Commission seeks to remedy both existing
and future undue discrimination in the industry and realize the
Significant customer benefits that will come with open access,
Indeed, it is our Statutory obligation under sections 205 and 206
“The Commission's notice of Proposed rulemaking in the above dockets
Proposed to apply the Proposed requirements to public utilities that own
wd/or control facilities used for the transmission of electric energy in
interstate commerce. "Own and/or control" is intended to include public
utilities that “operate” facilities used for the transmission of electric energy
in interstate commerce. However, we have modified the Final Rule
regulatory text to remove any ambiguity.
S4a
of the Federal Power Act (FPA) to remedy undue
discrimination,
To do so, we must eliminate the remaining patchwork of
closed and open jurisdictional transmission systems and ensure
that all these systems, including those that already provide some
form of open access, cannot use monopoly power over
transmission to unduly discriminate against others, If we do not
lake this step now, the result will be benefits to some customers
at the expense of others. We have learned from our experience
in the natural gas area the importance of addressing competitive
transition issues early and with as much certainty to market
participants as possible.
Accordingly, in this proceeding and in the accompanying
proceeding on OASIS, the Commission, pursuant to its
authorities under sections 205 and 206 of the FPA:
* Requires all public utilities that own, control or operate
facilities used for transmitting electric energy in
interstate commerce
¢ To file Open access non-discriminatory transmission
tariffs that contain minimum terms and conditions of
non-discriminatory service;
¢ To take transmission service (including ancillary
services) for their own new wholesale sales and
purchases of electric energy under the open access
tariffs;
¢ To develop and maintain a same-time information
system that will give existing and potential transmission
users the same access to transmission information that-
the public utility enjoys, and further requires public
utilities to separate transmission from generation
marketing functions and communications;
e Clarifies Federal/state jurisdiction over transmission in
interstate commerce and local distribution and provides
for deference to certain state recommendations; and
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* — Permits public utilities and transmitting utilities to seek
recovery of legitimate, prudent and Verifiable stranded
COSIS associated with providing open access and FPA
section 211 transmission services.
Open Access
The Final Rule requires public utilities to file a single open
access tariff that offers both network, load-based service and
point-to-point, contract-based service. The Rule contains a pro
forma tariff that reflects modifications to the NOPR's proposed
terms and conditions and also"permits variations for regional
practices. All public utilities subject to the Rule, including
those that already have tariffs on file, will be required to make
section 206 compliance filings to meet the new pro forma tariff
non-price minimum terms and conditions of non-discriminatory
transmission. Utilities may propose their own rates in a section
205 compliance filing.
The Rule provides that public utilities may seek a waiver of
some or all of the requirements of the Final Rule. In addition,
non-public utilities may seek a waiver of the tariff reciprocity
provisions,
The Final Rule does not generically abrogate existing
requirements contracts, but will permit customers and public
utilities to seek modification, or termination, of certain existing
requirements contracts on a case-by-case basis. As to
coordination arrangements and contracts, the Rule finds that
these arrangements and contracts may need to be modified to
remove unduly discriminatory transmission access and/or
pricing provisions. Such arrangements and agreements include
power pool agreements, public utility holding company
agreements, and certain bilateral coordination agreements. The
Rule provides guidance and timelines for modifying unduly
discriminatory coordination arrangements and contracts, and
Specifies when the members of such arrangements must begin
to conduct trade with each other using the same open access
tariff offered to others. The Rule also provides guidance
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regarding the formation of independent system operators
(ISOs).
The Rule does not require any form of corporate
restructuring, but will accommodate voluntary restructuring that
is consistent with the Rule's open access and comparability
policies,
As discussed in the NOPR, not all owners or controllers of
interstate transmission facilities are subject to the Commission's
jurisdiction under sections 205 and 206 of the FPA and
therefore are not subject to this Rule's open access
requirements. Therefore, the Final Rule retains the proposed
reciprocity provision in the pro forma tariff. Without such a
provision, non- Open access utilities could take advantage of the
competitive opportunities of open access, while at the same
time offering inferior access, or no access at all, over their own
facilities. Thus, open access utilities would be unfairly
burdened. We note that some non-jurisdictional utilities have
expressed an interest in a mechanism for obtaining a
Commission determination that their transmission tariffs satisfy
the reciprocity provisions in the pro forma tariffs, and we
provide such a mechanism in the Rule.
The Final Rule does not generically provide for market-
based generation rates. Although the Rule codifies the
Commission's prior decision that there is no generation
dominance in new generating Capacity, intervenors in cases may
raise generation dominance issues related to new capacity. In
addition, to obtain market-based rates for existing generation,
we will continue to require public utilities to show, on a case-
by-case basis, that there is no generation dominance in existing
capacity. Further, in all market-based rate cases, we will
continue to look at whether an applicant and its affiliates could
erect other barriers to entry and whether there may be problems
due to affiliate abuse or reciprocal dealing.
Finally, contemporaneously with this Rule the Commission
issues an NOPR on capacity reservation tariffs as an alternative,
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and perhaps Superior, means of remedying undue
discrimination,
Transmission/Local Distribution
The Rule clarifies the Commission's interpretation of the
Federal/state jurisdictional! boundaries over transmission and
local distribution. While we reaffirm our conclusion that this
Commission has exclusive jurisdiction over the rates, terms,
and conditions of unbundled retail transmission in interstate
commerce by public utilities. we nevertheless recognize the
very legitimate concerns of state regulatory authorities as they
contemplate direct retail access or other state restructuring
programs. Accordingly, we Specify circumstances under Which
we will give deference to state recommendations. Although
jurisdictional boundaries may shift as a result of restructuring
programs in wholesale and retail markets, we do not believe
this will change fundamental state regulatory authorities.
including authority to regulate the vast majority of generation
asset Costs, the siting of generation and transmission facilities,
and decisions regarding retail service territories. We intend to
be respectful of state objectives so long as they do not balkanize
interstate transmission of power or conflict with our interstate
open access policies.
Stranded Costs
With regard to stranded costs, the Final Rule adopts the
Commission's Supplemental proposal. It will permit utilities to
seek extra-contractual recovery of stranded costs associated
with a limited set of existing (executed on or before July 11,
1994) wholesale requirements contracts and provides that the
Commission will be the primary forum for utilities to seek
recovery of stranded costs associated with retail-turned-
Wholesale transmission Customers, It also will allow utilities to
seek recovery of stranded costs Caused by retail wheeling only
in circumstances in which the state regulatory authority does
not have authority to address retail stranded costs at the time the
retail wheeling is required. The Rule retains the revenues lost
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approach for calculating stranded costs and provides a formula
for calculating such costs.
Environmental Issues
The Commission has prepared a Final Environmental Impact
Statement (FEIS) evaluating the possible environmental
consequences of changes in the bulk power marketplace
expected to occur as a result of the open access requirements of
this Final Rule. The FEIS focuses, as do most commenters, on
possible increases in emissions of nitrogen oxides (NOx) from
certain fossil-fuel fired generators, which could affect air
quality in the producing region and in areas to which these
emissions may be carried.
In response to comments on the Draft EIS, the Commission
performed numerous additional studies. The FEIS finds that the
relative future competitiveness of coal and naturai gas
generation is the key variable affecting the impact of the Final
Rule. If competitive conditions favor natural gas, the Rule is
likely to lead to environmental benefits. Both EPA and the
Commission staff believe this projected scenario is the more
likely one. If competitive conditions favor coal, the Rule may
lead to small negative environmental impacts. However, even
using the most extreme, unlikely assumptions about the future
of the industry, the negative consequences are not likely to
occur until after the turn of the century. Because the impacts
will remain modest at least until 2010, there is no need for an
interim mitigation program. In addition, even if the data
showed more significant negative consequences requiring
mitigation, the Commission does not have the statutory
authority under the Federal Power Act or the expertise to
address this possible far-term problem. The Commission
believes, however, that there is time for federal and state air
quality authorities to address any potential adverse impact as
part of a comprehensive NOx regulatory program under the
Clean Air Act.’
442 U.S.C. 7401, et seq.
LOPE Spe eee OEE ee”
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SANTO ANS ret
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Despite our conclusions regarding the lack of environmental
impacts expected to result from the Rule, the Commission fas
examined a wide variety of proposals for mitigating possible
adverse effects. We share the view of most commenters that
the preferred approach for Mitigating increased NOx emissions
generally is a NOx cap and trading regulatory program
comparable to that developed by Congress to address sulfur
dioxide emissions in the Clean Air Act Amendments of 1990.5
The Commission has examined various means of establishing
such a program, including use of existing federal authorities
under the Clean Air Act. cooperative efforts by state and federal
air quality regulators, and development of a new emissions
regulatory program administered by the Commission under the
Federal Power Act. The Commission has concluded that a NOx
regulatory program could best be developed and administered
under the Clean Air Act. in cooperation with interested States,
and offers to lend Commission Support to that effort should it
become necessary.
Conclusion
4
The Commission believes that the Final Rule will remedy
undue discrimination in transmission services in interstate
commerce and provide an orderly and fair transition to
competitive bulk power markets.
a ok ok
Ill. Background
In the NOPR, we set out a detailed statement of the events
leading up to this rulemaking. We repeat that background here.
updated to reflect what has happened since March 1995, and
discuss why it is necessary to undertake regulatory reform in the
electric industry at this time. We do so to provide the necessary
backdrop to our action in adopting this Rule.
A. Structure of the Electric Industry at Enactment of
Federal Power Act
*42 U.S.C.A. 765 1b-e.
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The Federal Power Act was enacted in an age of mostly self-
sufficient, vertically integrated electric utilities, in| which
generation, transmission, and distribution facilities were owned
by a single entity and sold as part of a bundled service
(delivered electric energy) to wholesale and retail customers,
Most electric utilities built their own power plants and
transmission systems, entered into interconnection and
coordination arrangements with neighboring utilities, and
entered into long-term contracts to make wholesale
requirements sales (bundled sales of generation and
transmission) to municipal, cooperative, and other investor-
owned utilities (IOUs) connected to each utility's transmission
system, Each system covered limited service areas. This
structure of separate systems arose naturally due primarily to
the cost and technological limitations on the distance over
which electricity could be transmitted.
Through much of the 1960s, utilities were able to avoid price
increases, but still achieve increased profits, because of
substantial increases in scale economies, technological
improvements, and only moderate increases in input prices.”
Thus, there was no pressure on regulatory commissions to use
regulation to affect the structure of the industry.’
B. Significant Changes in the Electric industry
In the late 1960s and throughout the 1970s, a number of
significant events occurred in the electric industry that changed
the perceptions of utilities and began a shift to a more
competitive marketplace for wholesale power.” This was the
beginning of periods of rapid inflation, higher nominal interest
* Paul L. Joskow, Inflation and Environmental Concern: Structural
Change in the Process of Public Utility Regulation, 17 J. Law & Econ, 291,
312 (1974); see also Charles F. Phillips, Jr., The ie austen ot Public
Utilities 11 (1988).
Te Te
‘See Joskow, supra at 312; see also Phillips, supra at 12.
* See Joskow, supra at 312; see also Phillips, supra at 12-13.
Ola
rates, and higher electricity rates.” During this time, consumers
became concerned about higher electricity rates and questioned
any price increases filed by utilities,"
During this same time frame, the construction of nuclear and
other capital-intensive baseload facilities--actively encouraged
by federal and some state governments--contributed to the
continuing cost increases and uncertainties in the industry."
These investments were made based on the assumptions that
there would be Steady increases in the demand for electricity
and continued large increases in the price of oil.” However,
due to conservation and economic downturns, the expected
demand increases did not materialize. Load growth virtually
disappeared in some areas, and many utilities unexpectedly
found themselves with excess capacity." In addition, by the
1980s, the oil cartel collapsed, with a resulting glut of low-
priced oil."" At the same time, inflation substantially increased
the costs of these large baseload generating plants,'’Surging
interest rates further increased the cost of the capital needed to
finance and capitalize these projects and completion schedules
*See Joskow, supra at 312-13; see also Phillips, supra at 13. The Arab
oil embargo resulted in significantly higher oil prices through the 1970s. See
Richard J, Pierce, Jr., The Regulatory Treatment of Mistakes in Retrospect:
Canceled Plants and Excess Capacity, 132 U. Pa. L. Rev, 497. $01 (1984).
" See Joskow, supra at 313: see also Phillips, supra at 13,
4 See generally Jersey Central Power & Light Company v. FERC, 810
F.2d 1168, 1171 (D.C. Cir. 1987),
2 ig,
See Pierce, supra at 503, By 1983, the Department of Energy had
estimated that the sunk costs for canceled nuclear plants alone amounted to
$10 billion, Id. at 498,
tid,
'S See Bernard S. Black & Richard J. Pierce, Jr.. The Choice Between
Markets and Central Planning in Regulating the U.S, Electricity Industry, 93
Col. L. Rev. 1339, 1346 (1993) ("Actual costs of nuclear power plants vastly
exceeded estimates, sometimes by as much as 1000%."),
62a
were significantly extended by, in part, more stringent safety
and environmental requirements."
As a result, expensive large baseload plants for which there
was litthe or no demand, came onto the market or were in the
process of being constructed, Accordingly, between 1970 and
1985, average residential electricity prices more than tripled in
nominal terms, and increased by 25% after adjusting for general
inflation.” Moreover, average electricity prices for industrial
customers more than quadrupled in nominal terms over the
same period and increased 86% after adjusting for inflation."
The rapidly increasing rates for electric power during this
period, together with the opportunities provided by the Public
Utility Regulatory Policies Act of 1978 (PURPA) (discussed
infra), also prompted some industrial customers to bypass
utilities by constructing their own generation facilities. This
further exacerbated rate increases for remaining customers--
primarily residential and commercial customers,
Consumers responded to these "rate shocks" by exerting
pressure on regulatory bodies to investigate the prudence of
management decisions to build generating plants, especially
when construction resulted in cost overruns, excess capacity, or
© See Phillips, supra at 13. Fossil fuel-fired plants became subject to
increased regulation as a result of the Clean Air Act of 1970, and its 1977
amendments. - 42 U.S.C. 7401-7642. In 1971, nuclear plant licensing
became subject to the environmental impact statement requirements of the
National Environmental Policy Act of 1969, 42 U.S.C. 4332. Following the
1979 accident at the Three Mile Isiand nuclear plant, nuclear plants also
became subject to additional safety regulations, resulting in higher costs.
See Energy Information Administration, The Changing Structure of the
Electric Power Industry 1970-1991 (March 1993) 35. Between 1976 and
1980, most states and many localities instituted laws governing power plant
siting.
“ Based on retail prices reported in Energy Information Administration
(EIA), Monthly Energy Review, January 1995, Table 9.9 (Prices adjusted
for inflation using the GDP Deflator (1987 = 100)).
id,
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ERTS NANG SRN ROO
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both. Between 1985 and 1992. writeoffs of nuclear power
plants totalled $22.4 billion.” These writeoffs significantly
reduced the earnings of the affected utilities.°” Delays in
obtaining rate increases to reflect the effects of inflation further
reduced investor returns, Thus. many utilities became reluctant
to Commit capital to long-term construction decisions involving
large scale generating plants."
In addition to economic changes in the industry, significant
technological changes in both generation and transmission have
occurred since 1935, Through the 1960s, bigger was cheaper
in the generation sector and the industry was able to capitalize
on economies of scale to produce power at lower per-unit costs
from larger and larger plants.” As a result, large utility
companies that could finance and manage construction projects
of larger scale had a price advantage over smaller utility
companies and customers who might otherwise have considered
building their own generating units. Scale economies
encouraged power generation by large vertically-integrated
utility companies that also transmitted and distributed power,
Beginning in the 1970s, however, additional economies of
scale in generation were no longer being achieved.’ A
Significant factor was that larger generation units were found to
need relatively greater maintenance and experience longer
downtimes.” The electric industry faced the situation "Where
" See Black & Pierce, supra at 1346 (These writeoffs were “about 17%
of the book value of total 1992 utility investment.").
“)
“te.
? " ‘ . . ° ‘ 7 '
“Id. ("The high perceived risk of future disallowances reversed utilities
incentives to overinvest, and made utilities extremely reluctant to build new
power plants."),
*2 See Preston Michie, Billing Credits for Conservation, Renewable, and
Other Electric Power Resources: an Alternative to Marginal-Cost-Based
Power Rates in the Pacific Northwest, 13 Environmental Law 963, 964-65
(1983),
“1d. at 965.
64a
the price of each incremental unit of electric power exceeded
the average cost."”* Bigger was no longer better.
Further dictating against larger generation units were
advances in technologies that allowed scale economies to be
exploited by smaller size units, thereby allowing smaller new
plants to be brought on line at costs below those of the large
plants of the 1970s and earlier. Such new technologies include
combined cycle units and conventional steam units that use
circulating fluidized bed boilers.”
The combined cycle generating plants generally use natural
gas as their primary fuel, This technology has been made
possible by the development of more efficient gas turbines,
shorter construction lead times, lower capital costs, increased
reliability, and relatively minimal environmental impacts.”’
Similarly, the circulating fluidized bed combustion boilers,
fueled by coal and other conventional fuels, provide a more
efficient and less polluting resource.
Today, "the optimum size (of generation plants) has shifted
from (more than S00 MW) (10-year lead time) to smaller units
“ Energy Information Administration, The Changing Structure of the
Electric Power Industry 1970-1991 (March 1993) 37 ("As larger units were
constructed, however, utilities discovered that downtime was as much as $
times greater for units larger than 600 megawatts than for units in the LOO-
megawatt range." )
Id.; see also George A. Perrault, Downsizing Generation: Utility Plans
tor the 1990s, Pub, Util. Fort. 15-16 (Sept. 27, 1990) ("The large base-load
generating units that form the backbone of utility systems are almost totally
absent from capacity plans for the 1990s.").
*“ "From 1982 through 1991, the average capacity of fluidized-bed units
increased rapidly to 72 megawatts for 4 units in 1991, The average capacity
for the 19 units planned to begin operating in 1992 through 1995 increases
to 83 megawatts.” Energy Information Administration, The Changing
Structure of the Electric Power Industry 1970-1991 (March 1993) 38,
~ See Charles E. Bayless, Less is More: Why Gas Turbines Will
Transform Electric Utilities, Pub. Util. Fort. (Dec. 1, 1994) 21.
er
65a
(one-year lead time) (in the 50- to 150-MW range)."”" Indeed,
smaller and more efficient gas-tired combined-cycle generation
facilities can produce power on the grid at a cost ranging from
S cents per kWh to less than 3 cents per kWh.” This is
significantly less than the costs for large plants constructed and
installed by utilities over the last decade, which were typically
in the range of 4 to 7 cents per kWh for coal plants and 9 to 15
cents for nuclear plants." Significant changes have also
occurred in the transmission sector of the industry,
Technological advances in transmission have made possible the
economic transmission of electric power over long distances at
higher voltages." This has made it technically feasible for
utilities with lower cost generation sources to reach previously
isolated systems where customers had been captive to higher
cost generation, In addition, the nature and magnitude of
coordination transactions” have changed dramatically since
“Id. at 24, See also Wallace E. Brand, Is Bigger Better? Market Power
in Bulk Power Supply: From FDR to NOPR, Pub. Util. Fort. (Feb, 15, 1996)
23 at 25 (while the optimal baseload unit size is about 500 MW for coal-
fired steam turbines, the optimal size for gas fired combined-cycle units is
about 150 to 200 MW),
” PERC staff calculations based in part on combined-cycle plant cost
data reported in 1994 FERC Form No. | for a sample of units placed in
service during 1990-94. Costs vary with regional fuel and construction
costs, among other reasons,
“ Coal and Nuclear plant cost data reported in 1994 FERC Form No, |
and the EIA report, Electric Plant Cost and Power Production Expenses
1991, 1993 DOEBIA-0455(91), for plants placed in service during 1986-94;
see also The 1994 Electric Executives’ Forum, Bakke (President and CEO
of the AES Corporation), Pub. Util. Fort. (June 1, 1994) 45 ("New
generation can be built at about 3 cents per kilowatt-hour (U.S, average).
Old generation costs about twice that * * #" ),
“\ See Black & Pierce. supra at 1345 (In the late 1960s and 1970s.
improved transmission efficiency and development of regional transmission
networks “made it possible to build power plants up to 1000 miles from
power users.”),
»> ‘ : :
™ Coordination transactions are voluntary sales or exchanges of
specialized electricity services that allow buyers to realize cost savings or
66a
enactment of the FPA, allowing increased coordinated
operations and reduced reserve margins. Substantial amounts
of electricity now move between regions, as well as between
utilities in the same region. Physically isolated systems have
become a thing of the past.
C. The Public Utility Regulatory Policies Act and the
Growth of Competition
In enacting PURPA," Congress recognized that the rising
costs and decreasing efficiencies of utility-owned generating
facilities were increasing rates and harming the economy as a
whole.” To lessen dependence on expensive foreign oil, avoid
repetition of the 1977 natural gas shortage, and control
consumer costs, Congress sought to encourage electric utilities
to conserve oil and natural gas.” In particular, Congress
sanctioned the development of alternative generation sources
designated as "qualifying facilities” (QFs) as a means of
reducing the demand for traditional fossil fuels.“ PURPA
reliability gains that are not attainable if they rely solely on their own
resources. For sellers, these transactions provide opportunities to earn
additional revenue, and to lower customer rates, from capacity that ts
temporarily excess to native load capacity requirements.
“Pub. L. No. 95-617. 92 Stat. 3117 (codified in U.S.C. sections 15. 16.
26, 30, 42, and 43).
“ See generally FERC v. Mississippi, 456 U.S. 742, 745-46 (1982).
= The Power Plant and Industrial Fuel Use Act of 1978. Pub. L. No. 95-
617, 92 Stat. 3117 (codified in U.S.C. sections 15, 16, 26, 30, 42. and 43).
“ QFs include certain cogenerators and small power producers. PURPA
also added sections 210, 211, and 212 to the FPA, providing the
Commission with authority to approve applications for interconnections and,
in limited circumstances, wheeling. However, under section 211, as enacted
in PURPA, the Commission could approve an application for wheeling only
if it found, inter alia, that the order “would reasonably preserve existing
competitive relationships.” Because of this and other limitations in sections
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required utilities to purchase power from QFs at a price not to
exceed the utility's avoided costs and to sell backup power to
QOFs.”
PURPA specifically set forth limitations on who, and what,
could qualify as QFs, In addition to technological and size
criteria, PURPA set limits on who could own QFs.™
Notwithstanding these limitations, QFs proliferated. In 1989,
there were 576 QF facilities. By 1993, there were more than
1,200 such facilities.” For the same time period, installed QF
capacity increased from 27,429 megawatts to 47,774
megawatts.” The rapid €xpansion and performance of the QF
industry demonstrated that traditional, vertically integrated
public utilities need not be the only sources of reliable power,
During this period, the profile of generation investment
began to change, and a market for non-traditional power supply
beyond the purchases required by PURPA began to emerge.
QFs were limited to cogenerators and small power producers."
211 and 212 as originally enacted, the Provision was Virtually ineffective.
Only one section 211 order was ever issued pursuant to the original
Provision, and it was pursuant to a settlement. See Public Service Company
of Oklahoma, 38 FERC 61.050 (1987). As discussed infra. section 211 was
subsequently revised by the Energy Policy Act of 1992,
2 456 US. at 75 ). Congress recognized that encouragement was needed
in part because utilities had been reluctant to purchase electric power from,
and sell power to, nonutility generators. Id. at 750-5.
* For example, PURPA provided that a cogeneration facility or small
power production facility could not be owned by a person primarily engaged
in the generation or sale of electric power (other than from cogeneration or
small power production facilities). See 16 U.S.C.
“Energy Information Administration, Electric Power Annual 1993
(December 1994) 124 (Table 77).
Id. EIA data for 1989 through 1991 was for, facilities of 5 megawatts
Or more and for 1992 and 1993 was for facilities of | megawatt or more. A
comparison with Table 74 on page 121 for the years 1992 and 1993 reveals
that this mixing of data bases is likely of minimal effect.
at Generally, the law has imposed an 80 MW cap on small power
68a
However, other non-traditional power producers who could
not meet the QF criteria began to build new capacity to compete
in bulk power markets, without such PURPA benefits as the
mandatory purchase requirements. These producers, known as
independent power producers (IPPs), were predominantly
single-asset generation companies that did not own any
transmission or distribution facilities. While traditional utilities
were generally reluctant at that time to invest in new generating
facilities under cost of service regulation, utilities increasingly
became interested in participating in this new generation sector.
They organized affiliated power producers (APPs), with assets
not included in utility rate base, and sought to sell power in
their own service territories and the territories of other utilities.
At the same time, power marketers arose. These entities--
owning no transmission or generation--buy and sell power.”
There were two major impediments to the development of
IPPs and APPs. First, the ownership restrictions of the Public
Utility Holding Company Act (PUHCA)" severely inhibited
these new entities from entering the generation business.”
producers. A limited exception enacted in 1990 permitted small power
facilities that could exceed 80 MW and still qualify as QFs under PURPA,
This exception was limited to certain solar, wind, waste, and geothermal
small power production facilities and only covered applications for
certification of facilities as qualifying small power production facilities that
were submitted no later than December 31, 1994 and for which construction
commences no later than December 31, 1999. See Solar, Wind, Waste, and
Geothermal Power Production Incentives Act of 1990, Pub. L. No. 101-575,
104 Stat. 2834 (1990), amended, Pub. L. No. 102-46, 105 Stat. 249 (1991),
* The first power marketer in the electric industry was Citizens Energy
Corporation. See Citizens Energy Corporation, 35 FERC 61,198 (1986).
Power marketers take title to electric energy. Power brokers, on the other
hand, do not take title and are limited to a matchmaking role.
15 U.S.C. 79 et seq.
4 As discussed intra, Congress eventually provided a means to avoid the
PUHCA restrictions by creating exempt wholesale generators (EWGs) in the
Energy Policy Act.
— = =
a ? ne (one REE en VEN REET M DE MIRAE TS eee
eae EGE Tes ee ee AY a har sii ma
69a
Second, these entities needed transmission service in order to
compete in electricity markets,
While the Commission had no authority to remove PUHCA
restrictions,’ it encouraged the development of IPPs and APPs,
as well as emerging power marketers, by authorizing market-
based rates for their power sales on a case- by-case basis and by
encouraging more widely available transmission access. From
1989 through 1993, facilities owned by IPPs and other non-
traditional generators (other than QFs) increased from 249 to
634 and their installed capacity increased from 9,216 megawatts
to 13,004 megawatts.” Indeed. “[iJn 1992, for the first time.
generating capacity added by independent producers exceeded
capacity added by utilities,""’
Market-based rates helped to develop competitive bulk
power markets, A generating utility allowed to sell its power at
market-based rates could move more quickly to take advantage
of short-term or even long-term market opportunities than those
laboring under traditional cost-of-service tariffs, which entail
procedural delays in achieving tariff approvals and changes.
In approving these market-based rates, the Commission
required, inter alia, that the seller and any of its affiliates lack
market power or mitigate any market power that they may have
possessed.“ The major concern of the Commission was
© The industry was successful to some extent in developing ownership
Structures that permitted such investment. See, e.g., Commonwealth Atlantic
Limited Partnership, 51 FERC 61,368 at 62,240 and n.20 (1990).
i Energy Information Administration, Electric Power Annual 1993
(December 1994) 124 (Table 77),
© Black & Pierce, supra at 1349 n.25.
48
See, e.g., Ocean State Power, 44 FERC 61,261 ( 1988);
Commonwealth Atlantic Limited Partnership, 51 FERC 61,368 (1990);
Citizens Power & Light Company, 48 FERC 61,210 (1989); Orange and
Rockland Utilities, Inc., 42 FERC 61,012 (1988); Doswell Limited
Partnership, 50 FERC 61,251 (1990) (Doswel); and Dartmouth Power
Associates Limited Partnership, 53 FERC 61,117 ( 1990).
70a
whether the seller or its affiliates could limit competition and
thereby drive up prices. A key inquiry became whether the
seller or its affiliates owned or controlled transmission facilities
in the relevant service area and therefore, by denying access or
imposing discriminatory terms or conditions on transmission
service, could foreclose other generators from competing.” As
we have previously explained:
The most likely route to market power in today's
electric utility industry lies through ownership or
control of transmission facilities. Usually, the
source of market power is dominant or exclusive
ownership of the facilities. However, market power
also may be gained without ownership. Contracts
can confer the same rights of control. Entities with
contractual control over transmission facilities can
withhold supply and extract monopoly prices just
as effectively as those who control facilities
through ownership.”
As entry into wholesale power generation markets increased,
the ability of customers to gain access to the transmission
services necessary to reach competing suppliers became
increasingly important.” In addition, beginning in the late
” See, e.g., Doswell, 50 FERC at 61,757.
“ Citizens Power & Light Corporation, 48 FERC 61,210 at 61,777
(1989) (emphasis in original); see also Utah Power & Light Company,
PacifiCorp and PC/UP&L Merging Corporation, 45 FERC 61,095 at 61,287-
89 (1988), order on reh'g, 47 FERC 61,209, order on reh’g, 48 FERC 61,035
(1989), remanded in part sub nom. Environmental Action, Inc. v. FERC, 939
F.2d 1057 (D.C. Cir. 1991), order on remand, 57 FERC 61,363 (1991).
! In earlier years, a few customers were able to obtain access as a result
of litigation, beginning with the Supreme Court's decision in Otter Tail
Power Company v. United States, 410 U.S. 366 (1973). Additionally, some
customers gained access by virtue of Nuclear Regulatory Commission
license conditions and voluntary preference power transmission
arrangements associated with federal power marketing agencies. See, e.g.,
Consumers Power Company, 6 NRC 887, 1036-44 (1977) and The Toledo
Edison Company and Cleveland Electric Iluminating Company, 10 NRC
Tla
1980s, in order to mitigate their market power to meet
Commission conditions, public utilities seeking Commission
approval of mergers or consolidations under section 203 of the
FPA or Commission authorization for blanket approval of
market-based rates for generation services under section 205 of
the FPA, filed "open access” transmission tariffs of general
applicability.” The Commission applied its market rate
analysis to IOUs, as well as IPPs, APPs. and marketers, and
allowed IOUs to sell at market-based rates only if they opened
their transmission systems to competitors.** The Commission
also approved proposed mergers on the condition that the
merging companies remedy anticompetitive effects potentially
caused by the merger by filing "open access" tariffs. These
early "open access” tariffs required only that the companies
provide point-to-point transmission services, which is a much
narrower requirement than that being imposed in this Rule and
did not require transmission owners to provide to others the
same quality of service that they themselves en joyed.
265, 327-34 (1979). See Florida Municipal Power Agency v. Florida Power
and Light Company, 839 F. Supp. 1563 (M.D. Fla. 1993). See also
Electricity Transmission: Realities, Theory and Policy Alternatives, The
Transmission Task Force Report to the Commission, October 1989. 197.
= See, ¢.g., Public Service Company of Colorado, 59 FERC 61,311
(1992), reh'g denied, 62 FERC 61.013 (1993); Utah Power & Light
Company, et al., Opinion No. 318, 45 FERC 61,095 (1988), order on reh'g,
Opinion No. 318-A, 47 FERC 61,209 ( 1989), order on reh'g, Opinion No.
318-B, 48 FERC 61,035 (1989), affd in relevant part sub nom.
Environmental Action Inc. v. FERC, 939 F.2d 1057 (D.C. Cir. 1991):
Northeast Utilities Service C ompany (Public Service Company of New
Hampshire), Opinion No. 364-A, 58 FERC 61,070, reh'g denied, Opinion
No. 364-B, 59 FERC 61,042, order granting motion to vacate and dismissing
request for rehearing, 59 FERC 61,089 (1992). affirmed in relevant part sub
nom. Northeast Utilities Service C ompany v. FERC, 993 F.2d 937 (Ist Cir.
1993).
* See, e.g., Public Service of Indiana, Inc., $1 FERC 61.367 (1990),
reh’g denied, 52 FERC 61,260 (1990), appeal dismissed sub nom. Northern
Indiana Public Service Company v. FERC, 954 F.2d 736 (D.C.Cir. 1992).
72a
Following PURPA, the economic and technological changes
in the transmission and generation sectors helped give impetus
to the many new entrants in the generating markets who could
sell electric energy profitably with smaller scale technology at
a lower price than many utilities selling from their existing
generation facilities at rates reflecting cost. However, it became
increasingly clear that the potential consumer benefits that
could be derived from these technological advances could be
realized only if more efficient generating plants could obtain
access to the regional transmission grids. Because many
traditional vertically integrated utilities still did not provide
open access to third parties and still favored their own
generation if and when they provided transmission access to
third parties, barriers continued to exist to cheaper, more
efficient generation sources.
D. The Energy Policy Act
In response to the competitive developments following
PURPA, and the fact that PUHCA and lack of transmission
access remained major barriers to new generators, Congress
enacted Title VII of the Energy Policy Act of 1992 (Energy
Policy Act).*’ A goal of the Energy Policy Act was to promote
greater competition in bulk power markets by encouraging new
generation entrants, known as exempt wholesale generators
(EWGs), and by expanding the Commission's authority under
sections 211 and 212 of the FPA to approve applications for
transmission services.”
An EWG is defined as
“ Pub. L. No. 102-486, 106 Stat. 2776 (1992), codified at, among other
places, 15 U.S.C. 79z-5a and 16 U.S.C. 796 (22-25), 824j-l.
* See El Paso Electric Company and Central and South West Services
Inc., 68 FERC 61,181 at 61,914 (1994) (CSW); see also Paul Kemezis,
FERC's Competitive Muscle: The Comparability Standard, Electrical World
45 (Jan. 1995) ("In EPAct, Congress made it clear that the electric-power
industry was to move toward a fully competitive market system, but left most
of the implementation to FERC.").
i
Hye MG i Sm Lan ON SE ee he RES CR OR OER!
73a
any person determined by the Federal Energy Regulatory
Commission to be engaged directly, or indirectly through
one or more affiliates as defined in [PUHCA} section
2(a)(11)(B), and exclusively in the business of Owning or
operating, or both owning and operating, all or part of one
or more eligible facilities and selling electric energy at
wholesale.”
If the Commission, upon an application, determines that a
person is an EWG, that person will be exempt from PUHCA.”’
This provision removed a Significant impediment to the
development of IPPs and APPs by allowing them to develop
projects as EWGs free from the strictures of PUHCA or the QF
PURPA limitations.
While sections 211 and 212, as enacted by PURPA, were
intended to provide greater access to the transmission grid, the
limitations placed on these sections made them unusable in
Virtually all circumstances, However, as amended by the
Energy Policy Act, these sections now give the Commission
broader authority to order transmitting utilities to provide
wholesale transmission services, upon application, to any
electric utility, Federal power marketing agency, or any other
person generating electric energy for sale for resale.
The Energy Policy Act also added section 213 to the FPA.
Section 213(a) requires a transmitting utility that does not
agree to provide wholesale transmission service in accordance
with a good faith request to provide a written explanation of its
proposed rates, terms, and conditions and its analysis of any
physical or other constraints.” Section 213(b) required the
“15 U.S.C. 792-Sa.
7 15 U.S.C. 792-5a(e).
4
“ See supra note 36.
“See Policy Statement Regarding Good Faith Requests for Transmission
Services and Responses by Transmitting Utilities Under Sections 21 I(a) and
213(a) of the Federal Power Act. as Amended and Added by the Energy
Policy Act of 1992, 58 FR 38964 (July 21, 1993), FERC Stats. & Regs.,
74a
Commission to enact a rule requiring transmitting utilities to
submit annual information concerning potentially available
transmission capacity and known constraints.”
E. The Present Competitive Environment
Following the Energy Policy Act, the Commission
established rules: (1) For certain generators to obtain EWG
status and thus an exemption from PUHCA;" and (2) that
required transmission information availability. The
Commission also pursued a number of initiatives aimed at
fostering the development of more competitive bulk power
markets, including aggressive implementation of section 211,
a new look at undue discrimination under the FPA, easing of
market entry for sellers of generation from new facilities, and
initiation of a number of industry-wide reforms. As stated by
the Commission, in recognition of the Congressional goal in the
Energy Policy Act of creating competitive bulk power markets:
Our goal is to facilitate the development of competitively
priced generation supply options, and to ensure that wholesale
Regulations Preambles 30,975 (1993) (Policy Statement Regarding Good
Faith Requests for Transmission Services).
“ See New Reporting Requirements Implementing Section 213(b) of the
Federal Power Act and Supporting Expanded Regulatory Responsibilities
Under the Energy Policy Act of 1992, and Conforming and Other Changes
to Form No. FERC-714, 58 FR 52420 (October 8, 1993), FERC Stats. &
Reys., Regulations Preambles 30,980 (Order No. 558), reh'g denied, Order
No. 558-A, 65 FERC 61,324 (1993), regulations modified, 59 FR 15333
(April 1, 1994), FERC Stats. & Regs., Regulations Preambles 30,993.
“ See Order No. 550, Filing Requirements and Ministerial Procedures
for Persons Seeking Exempt Wholesale Generator Status, 58 FR 8897
(February 18, 1993), FERC Stats. & Regs., Regulations Preambles 30,964,
order on reh'g, Order No. 550-A, 58 FR 21250 (April 20, 1993), FERC
Stats. & Regs., Regulations Preambles 30,969 (1993). As recognized by
Congress and the Commission, availability of transmission information is
critical in developing competitive markets. See supra notes 59 and 60, This
opened the “black box" of information that previously was available only to
transmission Gwners.
RS te ays sate fp
A
a alia ei .
sore " 7
PT a
PAR DAA RABE YS
75a
purchasers of electric energy can reach alternative power
suppliers and vice versa.”
Il. Use of Sections 211 and 212 to Obtain Transmission
Access
The Commission has aggressively implemented sections 21 |
and 212 of the FPA, as amended by the Energy Policy Act, in
order to promote competitive markets.’ When wheeling
requests under sections 211! and 212 have been made. the
Commission has required wheeling in almost all of the requests
it has processed. To date, the Commission has issued orders
(proposed or final) requiring wheeling in 12 of the 14 cases it
has acted on.™
As a general matter, section 211 has permitted some inroads
to be made by customers in obtaining transmission service from
public utilities that historically have declined to provide access
to their systems, or have offered service only on a
discriminatory basis. Under section 211, the Commission has
granted requests for the broader type of service that most
utilities historically have refused to provide--network service.
Although transmission owners have provided limited amounts
of unbundled point-to-point transmission service, third-party
customers have not been able to obtain the flexibility of service
that transmission owners enjoy.
= See Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Notice of Proposed Rulemaking, 59 FR 35274 (July 11, 1994),
FERC Stats. & Regs., Proposed Regulations 32,507 at 32,866 (Stranded
Cost NOPR); American Electric Power Service Corporation, 67 FERC
61,168, clarified, 67 FERC 61.317 (1994),
“* 16 U.S.C.A. 824j-824k (West 1985 and Supp. 1994).
* See, ¢.g., final orders issued in City of Bedford, 68 FERC 61.003
(1994), reh'g denied, 73 FERC 61,322 (1995): Florida Municipal Power
Agency v. Florida Power & Light C ompany, 67 FERC 61,167 (1994), order
on reh'g, 74 FERC 61,006 (1996): Minnesota Municipal Power Agency, 68
FERC 61,060 (1994); and Tex-La Electric Cooperative of Texas, 69 FERC
61,269 (1994); see also Appendix A.
76a
In Florida Municipal, a section 211 case, the Commission
ordered "network," rather than the narrower "point-to-point,"
service.” Network service permits the applicant to fully
integrate load and resources on an instantaneous basis in a
manner similar to the transmission owner's integration of its
own load and resources. At the same time, the Commission
made the generic finding that the availability of transmission
service will enhance competition in the market for power
supplies and lead to lower costs for consumers. The
Commission explained that as long as the transmitting utility is
fully and fairly compensated and there is no unreasonable
impairment of reliability, transmission service is in the public
interest.”
As discussed infra, based on the mounting competitive
pressures in the industry and rapidly evolving markets, we have
concluded that section 211 alone is not enough to eliminate
undue discrimination. The comments received on the proposed
rules, discussed in detail infra, confirm this conclusion. The
significant time delays involved in filing an individual service
request for bilateral service under section 211 place the
customer at a severe disadvantage compared to the transmission
owner and can result in discriminatory treatment in the use of
the transmission system. It is an inadequate procedural
© See Florida Municipal Power Agency v. Florida Power & Light
Company, 65 FERC 61,125, reh'g dismissed, 65 FERC 61,372 (1993), final
order, 67 FERC 61,167 (1994), order on reh'g, 74 FERC 61,006 (1996).
The Commission has “characterized point-to-point service as involving
designated points of entry into and exit from the transmitting utility's system,
with a designated amount of transfer capability at each point.” El Paso
Electric Company v. Southwestern Public Service Company, 68 FERC
61,182 at 61,926 n.9 (1994) (citing Entergy Services, Inc., 58 FERC 61,234
at 61,768 (1993), reh'g dismissed, 68 FERC 61,399 (1994)). Network
service allows more flexibility by allowing a transmission customer to use
the entire transmission network to provide generation service for specified
resources and specified loads without having to pay multiple charges for
each resource-load pairing.
** Florida Municipal, 67 FERC at 61,477.
77a
substitute for readily available service under a filed non-
discriminatory open access tariff. As the Commission noted in
Hermiston Generating Company, "[t}he ability to spend time
and resources litigating the rates, terms and conditions of
transmission access is not equivalent to an enforceable
voluntary offer to provide comparable service under known
rates, terms and conditions."””
2. Commission's Comparability Standard
In the Spring of 1994, the Commission began to address the
problem of the disparity in transmission service that utilities
provided to third parties in comparison to their own uses of the
transmission system. In the seminal case in this area, American
Electric Power Service Corporation (AEP), the company
voluntarily proposed a tariff of general applicability that would
offer firm, point-to-point transmission service for a minimum
of one month.“ The Commission accepted the proposed
transmission tariff for filing and suspended its effectiveness for
one day, subject to refund.” Rehearing requests challenged the
Commission's summary approval of the restriction of service to
point-to-point as being discriminatory and anticompetitive.”
The rehearing requests argued that the tariff should be expanded
to include network services such as those used by the
transmission owner. On rehearing, the Commission announced
a new standard for evaluating claims of undue discrimination.
“ 69 FERC 61,035 at 61,165 (1994), reh'g denied, 72 FERC 61,071
(1995); see also Southwest Regional Transmission Association, 69 FERC
61,100 at 61,398 (1994), order on compliance filing, 73 FERC 61,147
(1995) (SWRTA).
* 64 FERC 61,279 (1993), reh'g granted, 67 FERC 61,168, clarified, 67
FERC 61.317 (1994).
@ The Commission explained that AEP could limit the service it was
offering because it was “providing the service voluntarily under a tariff of
general applicability." 64 FERC at 62,978.
2” AEP, 67 FERC at 61.489.
78a
The Commission found that a voluntarily offered, new open
access transmission tariff that did not provide for services
comparable to those that the transmission owner provided itself
was unduly discriminatory and anticompetitive.”' In reaching
that conclusion, the Commission broadened its undue
discrimination analysis (which traditionally had focused on the
rates, terms, and conditions faced by similarly situated third-
party customers) to include a focus on the rates, terms, and
conditions of a utility's own uses of the transmission system:
[A]n open access tariff that is not unduly discriminatory or
anticompetitive should offer third parties access on the same or
comparable basis, and under the same or comparable terms and
conditions, as the transmission provider's uses of its system.”
Refocusing the analysis was necessitated by the changing
conditions in the electric utility industry, including the
emergence of non-traditional suppliers and greater competition
in bulk power markets. Because a transmission provider may
use its system in different ways (e.g., to integrate load and
resources when serving retail native load, to make off-system
sales or purchases, or to serve wholesale requirements
customers), the Commission set for hearing the factual issues
associated with identifying those uses, as well as any potential
4 With respect to anticompetitive effects, the Commission explained that
it has "adhered to the Supreme Court's determination that the Commission's
‘ important and broad regulatory power * * * carries with it the responsibility
to consider, in appropriate circumstances, the anticompetitive effects of
regulated aspects of interstate utility operations pursuant to sections 202 and
203, and under like directives contained in sections 205, 206 and 207.’ Gulf
States Utilities Company v. FPC, 411 U.S. 747, 758-59 (1972)." Id. at
61,490 (footnote omitted). The Commission reaffirmed that it would
examine how best to fulfill this responsibility, as well as its responsibility to
prevent undue discrimination, in light of the changing conditions in the
electric utility industry. Id.
2 Id. at 61,490.
Ba ga i co ee
79a
impediments or consequences to providing comparable services
to third parties.”’
After AEP, the Commission applied this comparability
standard to a proposed Open access transmission tariff that was
filed by Kansas City Power & Light Company (KCP&L) in
support of a proposal to sell generation at market-based rates.”
The Commission explained that, in light of AEP. the utility's
proposed open access transmission tariff (which provided only
for point-to-point service) did not adequately mitigate its
transmission market power so as to justify allowing the
requested market-based rates. KCP&L could charge market-
based rates for sales only if it modified its proposed
transmission tariff to reflect the AEP comparability standard.
Since then, the Commission has required comparable service
in a variety of contexts, and has set for hearing the factual
issues associated with comparable service. For example, the
Commission found that market power can be adequately
mitigated only if a merged company offers transmission
services in accordance with the AEP comparability standard,”®
The Commission further held that, even if a merger does not
result in an increase in market power, the merger would not be
consistent with the public interest under section 203 of the FPA
unless the merged company offers comparable transmission
services, as defined in AEP.” The Commission therefore
annouriced a transmission comparability requirement for all
new mergers:
Given the transition of the electric utility industry as a
whole, we conclude that, absent other compelling public
interest considerations, coordination in the public interest
21d. at 61,490-91.
4 See Kansas City Power & Light Company, 67 FERC 61,183 (1994 ),
reh'g pending.
** E.g., CSW, supra, 68 FERC at 61.914,
1d,
80a
can best be secured only if merging utilities offer
comparable transmission services.”
In Heartland Energy Services, Inc.,™ the Commission
applied its comparability standard to an affiliated electric power
marketer seeking blanket authorization to sell electricity at
market-based rates. The Commission explained that
for all future cases involving blanket approval of market-
based rates an offer of comparable transmission services
will be required before the Commission will be able to find
that transmission market power has been adequately
mitigated. In the context of an affiliated power marketer,
this means that all of its affiliated utilities must have a
comparable transmission tariff on file.”
The Commission also denied a request by a company
affiliated with a transmission-owning utility seeking permission
to sell power at market-based rates to a particular customer.
The denial was without prejudice to refiling such a request in a
new section 205 proceeding, but only after the affiliated
transmission-owning utility filed a comparable transmission
service tariff." The Commission added that it will require
comparability in any situation in which a seller seeking market-
2 1d. at 61,915 (footnote omitted).
™® 68 FERC 61,223 (1994).
2 id. at 62,060. In InterCoast Power Marketing Company, 68 FERC
61,248, clarified, 68 FERC 61,324 (1994), the Commission rejected an
affiliated marketer's proposal to sell at market rates without its affiliate utility
offering comparable transmission services. The Commission stated that the
only way to ensure that InterCoast does not have transmission market power
is to require its affiliated public utility to offer comparable transmission
services. See also LG&E Power Marketing Inc., 68 PERC 61,247 at 62,120-
21 (1994), The Commission added that this
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