ML20082P445
| ML20082P445 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 08/28/1991 |
| From: | Feigenbaum T PUBLIC SERVICE CO. OF NEW HAMPSHIRE |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NYN-91138, NUDOCS 9109100332 | |
| Download: ML20082P445 (154) | |
Text
_
hh Ted C. Feigenbaum President and Chief Executive Officer NYN 91138 August 28, 1991 United States Nuclear Reguatory Commission Washington, D.C.
205$5 Attention:
Document Control Desk
References:
(a)
Facility Operating, License No. NPF 86, Docket No. 50 443 (b)
Application to Amend Facility Operating License No. NPF-86 to Authdrize North Atlantic Energy Corporation ("NAEC") as a Licensee, to Acquire and Possess the PSNil Ownership Interest in Seabrook (c)
NHY Letter NYN 91004 dated, January 14, 1991, T. C. Feigenbaum to Document Control Desk (FERC Initial Decision and SEC Memorandum and Order Related to Joint Plan and Operating License Applications?
Subject:
FERC Opinion and Order Affirming in Part, Modifying in Part and Reversing la Part initial Decision and Conditionally Approving Disposition of Facilities Gentlemen:
New Hampsure Yankee (NHY) hereby supplements the Application filed on November 13, 1990 in the above Docket [Referet.ee (b)].
In Reference (c). '.. ' submitted a decision of a FERC Administrative Law Judge that concluded that the ', rv
'an, as proposed, with some additional conditions, should be and that approved the sale of power by NAric to the approved in the publ' irat t a successor PSNil. Enck wu i;nd the decision of the FERC Commissioners which approved the merger of Northeast Utilities and ISNH subject to conditions relat ng primarily to the i
merged company's obligation to provide transmission service to third parties. Also included is the dissenting opinion of Commissioner Trabandt und the concurrir g opinion of Commissioner 1 :rzic, if you have any questicas on this matter please c-Terry L. Ilarpster at (603) 4/4-9521, extensibn 2765.
Very truly yours,
[M 6 Ted C. Feiginbaum TCF:JBH/ss 9109100332 C't.OB28 "DR ADOCK.35000443 h
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.hv New Hampshire Yankee Division of Public Service Company of New Hampshire
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- Seabrook, NH 03874
- Telephone (603) 474-9521 t
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United States Nuclear Regulatory Commission August 28, 1991 Attention:
DotJ.i.ent Control Desk-Page two l
. cc:
Mr. Thomas T. Martin Regional Adelaistrator United States Nuclear Regulatory Commission Region 1.
475 Allendale Road King of Prussia, PA 19406 Mr. Gordon E. Edison, Sr. Project Manager Project Directorate 13 Division of Reactor Projects -
U.S. Nuclear Regulatory Commission l
Washington, DC 20555 -
]
Mr. Noel Dudley NRC Senior Resident inspector i.O. Box - 1149 Seabrook,- NH 03874 Mr. George L. Iverson, Director Office of Emergency Management State Office Park Scuth 107 Pleasant-Street Concord, NH 03301 l
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OPINION NO. 364
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Northeast Utilities Service
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Docket Hos. EC90-10-000, Company
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ER90-143-000, ER90-144-000, (Re Public Service Company of )
ER90-145-000 and EL90-9-000 New Hampshire)
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OPINION AND ORDER AFFIRMING IN PART, MODIFYING IN PART AND REVERSING IN PART INITIAL DECISION AND CONDITIONALLY APPROVING DISPOSITION OF FACILITIE".
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August 9, 1991
UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION l
Northeast Utilitics Service
)
Docket Hos. EC90-10-000, Company
)
ER90-143-000, ER90-144-000, (Re Public Service Company of )
ER90-145-000 ar.d EL90-9-000 Hev Hampshire)
)
OPINION NO. 364 APPEARANCES Robert P. wax, Doualas G.
Green, David B.
Raskin, J.A.
Bouknicht, m, Cta ry A.
- Morgans, C.
Duane_Blinn, Robert P.
Knickerbocker. Jr. and David T. Doot f or Northeast Utilities service company Alan H. Richardson and Michael Oldak for American Public Power Association and National Rural Electric Cooperative Association Lynn N.
Harais, Robert F.
Shaniro and Amy S.
Koch for Applied Energy Services, Inc. and the American Paper Institute, Inc.
James T. McManus, Michael E.
Small, Mecan A. Soerlina, Frederick S. Samp and Stephen A. Johnson for Bangor Hydro-Electric Company and Maine Public Service Company Wayne R.
Fricard, John M. Cl e a ry, Richard D.
Fortin, John J.
Desmond III and Susan G.
White for Boston Edison Company Donald R.
Allen, Eenneth E.
Natalt, John P.
Covie and James McTarnacha.D for Boylston Municipal Light Department, Braintree Electric Light Department, Georgetown Municipal Light Department, Holden Municipal Light Department, City of Holyoke Gas and Electric Department, Ipswich Municipal Light Department, Littleton Electric Light and Water Departments, Paxton Municipal Light Department, Princeton Municipal Light Department, Reading Municipal Light Department, Town of Rowley Municipal Lighting Plant, Shrewsbury Electric Light Plant, Sterling Municipal Light Department, Taunton Municipal Lighting Plant and West Boylston Municipal Lighting Plant Philip L. Chabot. Jr. for Boylston, Braintree, Holden, Ipswich, Littleton, Paxton, Princeton, Reading, Shrewsbury, Sterling, Taunton, West Boylston and Georgetown, Massachusetts (13 Massachusetts Systems)
Georce M. Williams.
Jr., Joel F.
Zipp, Alan P.
Loeb, Franklin M.
Hundley and Paul W.
Diehl for Canal Electric Company,
)
i-Dockot No. EC90-10-000, 11 gl. <
Commonwealth Electric Company and Cambridge Electric Light Company (jointly "Com/ Electric")
. gerald M. Amero and Arthur w. Adelbera for Central Maine Power Company Donald L. Rushford for Central Vermont Public Service Corporation Fobert A. O'Neil and John Michael Adraana for Chicopee, South Hadley and Westfield, Massachusetts and Wallingford, Connecticut (the."MACT Towns")
Walter R.
Hall II for Citizens Utilities Company David J.
Bardin, Eucene J.
Melcher, Michael J.
- KurmaD, Steven R.
Milqa, Marilyn D. Sonn_and Noreen M.
Lavan for City of Holyoke Gas and Electric Department Edward G. Bohlen, Nancv Brockvay and James W.
Stetson for the Commonwealth of Massachusetts and Massachusetts Department of Public Utilities Robert S.
Golden. Jr.,
Phyllis E.
Lemell, Robert _R.
- Nordhaus, Howard E.
Shapiro, Charles B.
Curtis and Michael A.
Svicer for Connecticut _ Department of Public Utility Control William A. Chesnutt-for Connecticut Industrial Energy Consumers Scott Hemolina, Philio L. Sussler and Robert M.
Sussler for Connecticut Municipal Electric Energy Companies R1J1 Kowalski and Scott Hemolina for Connecticut Of fice of Consumer Counsel Richard M. Herriman and James K. Mitchell.for Eighteen Vermont Utilities gu s a n K.._- Be nd e t, Sara D. Schotland and Michael J.
By rne s f or -
Electricity Consumers Resource Council Sam - Behrends and _ Harry A. Voict.for Fitchburg Gas and Electric Company-and UNITIL Power Corporation Christooher L. Dutton - for Green Mountain Power Corporation Mary Anne Sullivan,~Mitchell M. Tannenbaum, James A.
Buckley and Joseph C.
Bell for Maine Public Utilities Commission Wallace L. Duncan, Alan J. - Roth, Nicholas J.
Scobbo, Frederick L.
Miller, Robert Weinbero, Thomas L.
Rudebusch, Scott H.
Strauss, William S. Huana and David E.
Pomoer for
- Massachusetts Municipal Wholesale Electric company J
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Dockot No. EC90-10-000, 21 A1 Curtis C. Pfunder, David A.
Fazzone and Donald J. Williamson for Montaup Electric Company Charles F. Wheatlev. Jr. and Peter A.
Goldsmith for the Municipal Electric Systems of Concord, Norwood and Wellesley, Massachusetts Robert J. Keecan, Stephen H.
Auaust and Donna C.
Sharkey for New Brunswick Power Kenneth M.
Simon and Larry F.
Eisenstat for New England Cogeneration Association, O'Brien Energy Systems, Inc.,
Masspover, PG&E-Bechtel Generating Company and Independent Energy Corporation Edward Berlin, Andrew D.
Weissman, Thomas A.
Belles, Erederic E.
Greenman and Cynthia Arcate for New England Power Company Robert C.
McDiarmid, Barbara S. Esbin and Stechen R.
Murrill for New Hampshire Electric Cooperative Geoffrev M. Kalmus and Howard J. Berman for the official Committee of Unsecured Creditors of Public Service Company of New Hampshire Coven'for the Official Committee of Equity Security Rocer B.
Holders of Public Service Company of New Hampshire Thomas'B. Getz and Georce Bruder for Public Service Company of New Hampshire James R. Lacey, William R.
Hoatson, Shawn Leyden, Eenneth Brown, Richard Frvlina. Jr. and Frederick W. Peters for Public
-Service Electric and Gas Company Sheldon'Whitehouse for Rhode Island Division of Public Utility and Carriers Ortman, John S. Moot and Clinton A. Vince Harold T.
Judd, Glen L.
for the_ State of New Hampshire and the New Hampshire Public Utilities Commission Thomas N. McHuah. Jr. for the Towns of Merrimac and Groveland, Massachusetts Arnold H.
Ouint, Laura M.
Wilson, William F.
Younc, Noel E. Hauf and. Linda L. Randell for the United Illuminating Company
, Tames A. Gresser for the U.S. Department of Justice and the Rural Electrification Administration Thomas N. Wies for Vermont Electric Power Company, Inc. (Velco)
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Docket No._ EC90-10-000, gt A1
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-Allen Martin for Velco and 18 Vermont Utilities-l
-Will'iam I.
Markavav, Harvev L.
Reiter, Kathleen L. Mszure, Carl M. Fink, James Volz and Michael-H. Dworkin for Vermont.
Department of Public-Service and Vermont Public Service Board Michael R.
Postar,-Dawn K.
Martin, Becky ' Bruner, Thomas J.
conley, Steohen-Anale and Richard L.
Miles for the Staff of f
the Federal Energy Regulatory Commission
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i j-a TABLE OF CONTENTS 2
i I.
Introduction.
1 a
c A.
l Parties-to the. Proposed Merger.
1 2
1B.
NEPOOL
~-
k C.'
Reorganization of PSRH 3
D.
The Rate Schedules.
4 E.
Statement of Public Interest 5
F.
Other Proceedings.
5 G.
Procedural History 6
H.
Intercontinental's Motion-to Intervene 9
I.
Motion for: Oral Argument 10 J.
Motion for. Pro-Forma Tariff.
10 11 K.
. Motion to Reopen the Record '.
-L.
Issues Summarily Affirmed.
13 M.
Statutory Standard 15
- II.
Benefits of the Merger.
16 A.
-Introduction 16 4
B.
NEPOOL Savings 19
- III..The Effect on Competition 21 A.-
The. Commission's Responsibilities 21 B.
The Relevant Comparison' for Assessing the Merger's-23 Competitive Effects.
C.
The Relevant Markets 24-1.
Relevant Geographic Markets 24 27 2.
Relevant Products ~
D.
Market Power 32 1.-
The Merger's Market Power Effects 32 2.-
Market Concentration Measures 39 E.
Anticompetitive Ef fects.
40 44 IV.
Conditions.
- 44 A.
Disposition ~of the Merger.
B.
Statutory Authority To Impose Conditions 45
- ~
C.
General Transmission ~ Commitments 14 9 1.-
Existing Transmission Capacity.
49
.. 50 a.-
Priority for Settlements b.
Ten-Year Priority for Transmission of Surplus Generation Sales 51
-c.
-Power Purchases-on Behalf of Native Load 56 Customers...........-.....
2.-
.New Transmission Capacity
-61
.........-.=,
a.
General Conditions
=....
61 b.
. Immutable Constraints.
63 66-
~3.
Transmission Rate Issues.
a.
Rate for Service From Existing - Capacity.
66
-b.
Tie Line-and Opportunity Charges 68 c.
Cost' Responsibility and Pricing-for Transmission Upgrades.
72 4
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,y 79
-4..
Duration ~ of-~ Sorvica-c.
Maximum Duration of Servica..
79:
'b..
Minimum' Duration for Non-Firm _ Service '.
83 5.-
-Vermont Department of Public Service 84 85-D.
New Hampshire Corridor Proposal _.
86 1.
Size-of Corridor.
89 2.-
Eligibility-93 3.
Deadline for Subscribing.
4.
Maximum-Duration of Service 94 95-E.
Regional _ Transmission Arrangement.
F.-
NEPOOL Voting.
97 G.
New Hampshire Electric Cooperative 100 101 H.
Env.ironmental Assessment 103 I.
-Ombudsman..
104
.J.
Transmission-Dependent Utilities V.
Rates
-..... = 107 A.
- Capacity Interchange _ Agreements' Return On Equity.107-B.
Seabrook-Power Contract's Return On Equity 109 bv i
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4 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners:
Martin L. Allday, Chairman; charles A. Trabandt, Elizabet.h Anne Moler, Jerry J. Langdon and Branko Terzie.
Northeast Utilities Service
)
Docket Noc. EC90-aO-000, Company
)
ER90-143-000, ER90-144-000, (Re Public Service Company of )
ER90-14 5-000 and EL90-9-000 New Hampshire)
OPINION No. 364 OPINION AND ORDER AFFIRMING IN PART, KODIFYING IN PART AMD REVERSING IN PART INITIAL DECISION AND CONDITIONALLY APPROVING DISPOSITION OF FACILITIES (Issued August 9, 19SI)
I.
Introduqtiom On January 8, 1990, Northeast Utilities Service Company (NUSCO), on behalf of Northeast Utilities (NU) and NU's operating
.ubsidiaries, filed an application-under section 203 of the Federal Power Act (FPA), 1/ seeking authorization for Public Service Company of New Hampshire (PSNH) to dispose of all of its jurisdictional facilities.
Concurrent with the disposition of facilities, PSNH would merge with, and become a subsidiary of, NU.
(Hereinafter, the disposition of facilities and t.'
merger will be referred to interchangeably).
NUSCO also fileo four rate schedules to implement the proposed operating arrangement between the companies:
the Seabrook Power Contract, the Sharing Agreement and two Capacity Interchange A7reements.
A.
Parties to the Proposed Mercer NU is a registered bolding company under the Public Utility L
Holding Company Act of 1935 (PUHCA). 2/
NUSCO is a service company subsidiary of NU and supplies centralized administrative and support services to NU's operating companies.
1/
16 U.S.C.
5 824b (1988),
2/
15 U.S.C. 5 79 et sea. (1988).
i Dock 0t No. EC90-10-000, gj; gl.
-2 NU's operating companics are Connecticut Light and Power company (CL&P), Western Massachusetts Electric Company, Holyoke Water Power Company (HWP) and HWP's subsidiary, Holyoke Power and Electric Company.
These companies are wholly-owned subsidiaries of NU and are public utilities supplying retail and wholesale electric service in Connecticut and Hassachusetts.
The operating companies own and operate approximately 2,300 miles of transmission lines.
PSNH is the largest electric utility in New Hampshire.
PSNH supplies retail electric service to approximately three-fourths of the state's population, in approximately 200 cities and towns.
PSNH provides wholesale service to the New Hampshire Electric Cooperative, three New Hampshire municipalities, and one PSNH has investor-owned utility, Vermont Electric Power Company.
the largest ownership share (approximately 35.6 percent) of Seabrook Unit No. 1, 2/ a nuclear generating f acility declared to be available for service on June 30, 1990.
PSNH owns approximately 1,800 miles of transmission lines.
B.
NEPOOL NU and PSNH are members of the New England Power Pool (NEPOOL).
A brief summary of NEPOOL's operations will aid the reader's understanding of many of the issues in this proceeding.
NEPOOL operates all of its members' electric facilities as a single system and provides for coordinated regional planning of generation and transmission facilities.
NEPOOL's members include nearly all the electric utilities in New England and account for 99 percent of the region's generating facilities and 100 percent of the region's transmission facilities. 1/
NEPOOL's operations are governed by the NEPOOL Agreement, f/ which is on file with the Commission.
The New England Power Exchange (NEPEX) uses economic operating all of the NEPOOL members' generation and
- dispatch, transmission systems to maximize the use of the least expensive resources to meet the_ demand within the pool, while maintaining appropriate standards of reliability.
NEPOOL's actual dispatch of a participant's resources is compared, after the fact, to a simulated "own load" dispatch of that participant's system to meet its load as if it were not part of NEPOOL.
The difference between this actual and simulated dispatch is used to calculate
'the level of fuel savings from NEPOOL's centralized dispatch.
The resulting fuel savings are shared among the NEPCOL members 2/
Ex. 1 at 9.
A/
Ex. 601 a 9.
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Ex. 603.
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. Docket No. EC90-10-000, d A1 based.upon their contributions of generation resources and power purchases. f/
The process under which NEPOOL participants share responsibility for generating capacity was summarized by NU witness Schultheis.
First, according to Mr. Schultheis, NEPOOL
. determines the amount of capacity (Objective Capability) required to reliably meet HEPOOL's total load.
Mr..Schultheis described y Objective Capability as:
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O the total amount of electrical capacity
~~C (generation or purchased power) that the odM Participants need to meet their combined peak O]Z load with an agreed-upon minimum level -of 2h reliability.
NEPOOL uses a loss-of-load probability (LDLP) calculation to establish O%
Objective Capability. (2/)
-4 Oy O Second, NEPOOL determines how much capacity (Capability each participant needs to contribute to meety-ths - IT
'-q Responsibility) r-,
. pool's Objective Capability.
formula-for determining Capability Responsibility. E/
Mr.
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, 23 5
Schultheis testified that, "[c]ach Participant's capability ri ss y, Responsibility is based on the relationship of t: e Participant R
1 M. 2.
. peak load to an estimate of the aggregate peaks of all-(all calculated o
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LParticipants
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Third, NEPOOL determines how much capacity each participant has.
And fourth, NEPOOL assesses charges (Adjustment and Deficiency Charges) to the participants lacking adequate capacity to meet their Capability Responsibility obligations 1pf C.
-Reorcanization of PSNH On January 28, 1988, PSNH filed a voluntary petition for
~
i reorganization under Chapter 11'of~the Federal Bankruptcy Code, 12/ in the United States Bankruptcy Court for. the District of New Hampshire.
Several competing reorganization plans were
- ff Ex. 603 at-14r Ex. 123 at 37-45.
JJ Ex. 123 at 47-48.
2/
Ex. 603 at 52-65.
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Ex.-123 at 52.
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Id. at 46.
11/
11 U.S.C. 5 1101 & sec. (1988).
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Dock 3t No. EC90-10-000, c1 A1
-4 submitted to the bankruptcy court, including NU's proposea plan to acquire PSNH.
NU's reorganization plan was jointly proposed the Of ficial Committee of Unsacured Creditors, the by NU, PSNH, Official Committee of Equity Security Foldtrs, Citicorp, consolidated Utilities & Communications, Inc. and Shearson Lehman The bankruptcy court held a hearing on NU's proposed Hutton Inc.
plan in late 1989, and confirmed the plan by order issued on April 20, 1990.
Under HU's plan, PSNH will emerge from bankruptcy and be acquired by NU in two steps.
In stop one, PSNH wii) emerge fram bankruptcy as a stand-alone company bound to a merger agreement with NU.
PSNH's creditors and stockholders will be compensated to the extent required by the reorganization plan.
Step one commenced on May 16, 1991, Phen PSNH emerged from bankruptcy.
PSNH will be merged with an NU subsidiary Under step two, created solely for the acquisition, NU Acquisition Corporation, with PSNH being the surviving entity.
After the merger, PSNH will be a wholly-owned subsidiary of NU.
Concurrent with the acquisition, PSNH will transfer its ownership interest in Seabrook to North Atlantic Energy Corporation (North Atlantic),
a newly-formed NU subsidiery.
Step two will occur only af ter all necessary regulatory approvals are received.
If the regulatory approvals are not received by January 1, 1992, the merger agreement will terminate unless NU and the two official bankruptcy committees agree upon an extension.12/
Under the Transitional Management Services Agreement (HSA),
NUSCO has complete management responsibility for PSNH's business operations, activities and affairs for the time between the bankruptcy court's confirmation of the reorganization plan and
.the consummation of the merger.
The MSA was accepted by the Commission in its order setting the merger for hearing. 11/
D.
The Rate Schedules 1.
The Seabrook Power Contract Concurrent with NU's acquisition of PSNH and the transfer of PSNH's share of Seabrook to North Atlantic, PSNH will enter into a life-of-the-unit power sales agreement with North Atlantic to purchase all of North Atlantic's share of Seabrook capacity and The contract is energy, under a cost-of-service f ormula rate.
intended to ensure that North Atlantic, a single-asset company, 12]
Ex. 1 at 25-26.
12/
50 FERC 1 61,266 at 61,83 6-37 (Hearina Order), reh'a denied, 51 FERC 1 61,177, clarification aranted on other arounds, 52 FERC 1 61,046 (1990).
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_ _. ~ _ _ _ _ _ _.... _ _. _ _ _. _ _
4 Docket.No. EC90-10-000, jda A1 will recover all of its costs from PSNH regardless of whether or not Seabrook operates.
2.-
The Sharina Aareement The Sharing Agreement allocates the benefits and obligations from the integrated operation of PSNH and the current NU -system, as-well as the joint planning and operations of these-systems.
As members of NEPOOL, PSNH and the NU operating companies are responsible for meeting their Capability Responsibility determined under the NEPOOL Agreement.
NEPOOL members with capacity below their Capability Responsibility must reimburse, through NEPOOL, members with capacity exceeding their Capability Responsibility.
After the merger, the merged company intends to seek " single participant status" under the NEPOOL Agreement, from which the merged company expects to benefit by lowering its capability Responsibility.
The merged company also-expects to benefit by retaining certain energy cost savings that are now shared with other NEPOOL members.
The' Sharing Agreement provides the methodology under which these expected benefits will be shared between PSNH and the NU operating companies.
3.
The Cappcity Interchance Aareements The two capacity Interchange Agreements provide for the sale and purchase of capacity and energy between PSNH and CL&P over an initial ten-year term.
The two agreements are similar except that one agreement is for sales by PSNH to CL&P while the other agreeuent is for sales by CL&P to PSFH.
The capacity entitlements are to be established for six-month periods and are intended to allow PSNH and CL&P to meet their respective shares of the combined system's capability Responsibility.
E.
Stat _ement of Public Interest NUSCO states that the merger will benefit the public interest by providing superior management resources to PSNH and Seabrook, by resolving PSNH's bankruptcy, and by relieving the planning uncertainty plaguing PSFH andg by extension, NEPOOL, as a result of PSNH's bankruptcy.
NUSCO also claims that the merger between NU and PSNH is consistent with the public interest because it vill improve the efficiency of their utility operations.
Since NU is a summer-peaking system while PSNH is a winter-peaking system, the combined system will require. less capacity than if the systems continued to operate separately.
NUSCO claims that the combined system will use capacity more efficiently to satisfy the combined load, resulting in lower fuel costs.
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Docket No. EC90-10-000,-gi gl. F.
Other Proceedinog NU's reorganization plan and/or proposed merger with PS!TH has been reviewed and approved by several other governmental entities, including the United States __ Bankruptcy Court for the District of New Hampshire, 11/ the Securities and Exchange Commission (SEC),11/ the New Hampshire legislature, 15/
the-New Hampshire Public Utilities Commission (New Hampshire commission), 12/ the Connecticut Department of Public Utility Control (Connecticut Commission),11/ the Maine Public Utilities Commission 12/ and the Vermont-Public - Service Board.
2f/
G.
Procedural History On March-2, 1990, the. commission ordered a hearing on whether the_ proposed merger is consistent with the public_
interest-and on whether the rates, terms and conditions of the-Seabrook Power Contract, the Sharing' Agreement and the Capacity Interchange Agreements are just and reasonable and in the public interest. 21/
The Commission limited the scope of the hearing on the proposed merger to two issues:
the merger's effect on the existing competitive situation and the merger's effect on wholesale costs and rate levels. 22/
11/
Ex. 628.
11/
Northeast Utilities, SEC Release No. 35-25221; 70-7695 (Dec.
21, 1990), reconsideration cranted, SEC Release No. 35-25273; 70-7695 (March 15, 1991). -The SEC citedithis Commission's statutory responsibility for " operational issues, including transmission access and bulk power supply," and conditioned its. approval of the_ merger-on this Commission's issuance of a final order approving the merger.
Order _ Granting Reconsideration at 8-9.
1s/
N.H. Rev. Stat. Ann. 5 362-C (1989).
Ebf Ex. 239A.
13/
PSNH Form No._1 (1990) at 109j.
12/
14 l
20/
Id.
1 L
2J/
Hearina Order, 50 FERC at 61,840-41.
l 22/
ld, at 61,833-37.
-Docket No.'EC90-10-000, gi gl..
. Af ter NUSCO filed its application f or approval of the proposed merger, a number of parties entered into agreements with In general, these parties agreed not to oppose the proposed NU.
merger.in exchange for NU's agreement to provide transmission service across the merged company's transmission system.
Since,-
in many respects, these settlements are the basis for certain j
transmission commitments that NU has offered here, we will identify the key elements of the mor' significant settlements.
On February 24, 1990, NU and the New England Power Company (NEPCO) entered into a settlement on all issues except the post-merger management and operation'of Seabrook. 21/
This agreement forms the basis of the New Hampshire Corridor Proposal (NH Corridor Proposal). - 11/
The NH Corridor Proposal would obligate the merged company and NEPCO to provide each other and 7
other utilities with transmission service across a " corridor" extending from eastern Hassachusetts and Rhode Island (specifically,-from an area referred to by the parties as Eastern The transmission REMVEC)-to New Hampshire's border with Haine.
capacity currently available under the NH Corridor Proposal consists of 452 megavatts of PSNH capacity through New Hampshire (with 200' megawatts. reserved for NEPCO's use; 40 megawatts for use by Vermont utilities; and 12 megawatts for use by New Hampshire utilities) and 200 megawatts of NEPCO capacity from New Hampshire into Eastern REMVEC.
The NH Corridor Proposal also obligates NU and NEPCO to install additional capacity under certain circumstances but allows them to reserve half of any added capacity for themselves.
On July 20, 1990, NU and NEPCO entered into a settlement on Seabrook-related issues, with NEPCO agreeing to withdraw certain pre-filed testimony on those issues. 25/
On-April 9, 1990, the United Illuminating Company filed a notice of withdrawal of its pleadings, based on a settlement agreement reached with NU. 25/
The settlement requires NU to
-transmit 150 megawatts of power from United Illuminating's system o
.in Connecticut over NU's system into Eastern REMVEC or elsewhere until the-year 2010.
r f.
22/- Ex. 605.
t ZA/
Ex. 154.
25/
Ex. 40B.
25/. Ex. 606.
l
l Docket No. EC90-10-000, g1 gl. On July 16, 1990, NU and a group of utilities referred to as the "18 Vermont Utilities" 11/ entered into a settlement agreement. 2E/
NU agreed to provide the 3 8 Vermont Utilities up to 40 MW of transmission service to Maine under the NH Corridor Proposal and to allow utilities in southern New England to use their NH Corridor Proposal capacity for transactions with the 18 Vermont Utilities.
The 18 Vermont Utilities continued their intervention in the proceeding in order to support the merger and protect their settlement agreement.
On September 21, 1990, af ter the close of the evidentiary record, the principal intervenors in the proceeding filed a joint statement of Core Conditions and a proposed Merger Tarif f.
The Core Conditions are the general conditions that these intervenors contend should be imposed if the merger is approved.
The Merger Tariff is a proposed comprehensive tariff for transmission service by the merged company.
The Core Conditions and the Merger Tariff supersede the conditions previously proposed by these parties individually. 21/
The substance of the Core conditions and Marger Tariff is discussed infra.
On November 29, 1990, the Connecticut Municipal Electric Energy Cooperative (CMEEC) filed a Notice of Withdrawal of Conditions, withdrawing its proposed conditions on the merger.
CMEEC'c withdrawal was baced on its agretment with NU on an amended and restated transmission service agreement settling CMEEC's concerns with the uerger.
The CMEEC agreement was filed in Docket No. ER91-209-000 and accepted by letter order issued on June 14, 1991.
Under the new agreement, CMEEC maintains a priority for using NU's transmission system equivalent to the priority assigned to NU's native load customers.
In return, CMEEC will continue to pay for its load-ratio share of NU's 22/
Allied Power and Light Company, City of Burlington Electric Department, Central Vermont Public Service Corporation, Citizens Utilities Company, Franklin Electric Light Company, Green Mountain Power Corporation, Town of Hardwick Electric Department, Village of Jacksonville E: actric company, Village-of Ludlow Electric Light Department, Village of Morrisville Water and Light Department, Village of Northfield Electric Department, Village of Stowe Water and Light Department, Village of Swanton, Vermont Electric Power Company, Inc., Vermont Electric Cooperative, Inc., Vermont Electric Generation and Transmission Cooperative, Inc.,
Vermont Marble Company and Washington Electric Cooperative, Inc.
2E/
Ex. 123T.
19/
Tr. 6936-38.
l Docket No. EC90-lO-000, gi al. transmission system. 23/
Also, under certain conditiv;.s, CMEEC will pay for new transmission facilities needed to serve CREEC's generation capacity additions.
On December 20, 1990, the presiding judge issued his initial decision. 21/
The judge recommended approval of the merger subject to certain conditions.
The conditions are based on RU's own proposed commitments, modified in some respects.
The bases for NU's commitments are the General Transmission Commitments (GTC) and the NH Corridor Proposal.
The GTC requires NU to of fer transmission service to other utilities on its existing transmission =cs.pacity and, subject to certain restrictions, to install additional capacity. 22/
(The NH Corridor Proposal is described supra, as part of NU's settlement with NEPCO).
On January 9, 1991, 18 briefs on exceptions Vere filed.
On January 24, 1991, 11 brief s opposing exceptions were filed.
H, Intergontinental's d211on to Irttervene On January 9, 1991, Intercontinental Energy Corporation (Intercontinental) filed a motion to intervene.
Intercontinental is the general partner for two partnerships that are each building a 300 megawatt cogeneration unit, one in New Jersey and one near Boston, Massachusetts.
Intercontinental seeks to oppose "the impact and the broad policy implications" of denying transmission service to qualifying f acilities under the NH Corridor Proposal, 12/
Intercontinental states that it did not intervene earlier because its "small staff and limited resources" precluded more extensive participation in the case.
23/
Intercontinental agrees to accept the record as it stands.
Intercontinental esserts that its interests are not adequately represented by other parties.
We vill deny Intercontinental's motion to intervene.
Intercontinental does not allege a lack of notice of this proceading or of the issues af f ecting qualif ying f acilities.
Intercontinental's claimed Jack of resources is not credible, coming as it does f rom an entity involveu in building two 300 megawatt facilities.
Also, Intercontinental's interests in this 20/
CMEEC's " load-ratio" is the ratio between CMEEC's annual peak load and the annual peak load f or the NU system.
21/
53 FERC $ 63,020 (1990).
22/
Ex. 178.
22/
Intercontinental motion at 4-5, 1AJ Is. at 5.
-. - -.... -. - - -. ~
Docket No. EC90-10-000, A_t al. -. proceeding are adequately-represented by the New England l
Cogeneration Association, which has sought throughout this
. proceeding to advance or protect:the' interests of qualifying facilities.
Moreover, the presiding judge denied as " grossly out
.of time" an intervention filed by others in October 1990. 25/
LIntercontinental has alleged no circumstances justifying approval of its motion to intervene. filed three months later than a motion already found to-be " grossly out of time."
I,.
Motion for oral Araumont On January 24, 1991, a motion for oral argument was filed by the City of Holyoke Gas & Electric Department (Holyoke), the New Hampshire Electric Cooperative and four municipal utilities referred to as the "MACT Towns." aff These parties request an oral argument before the Commission limited to-the issues raised in their-briefs on exceptions.
The parties argue that their concerns received "short shrift" in the initial-decision.
They also argue that their issues are only two-sided disputes between them and NU, and are thus more amenable to oral argument than-many of the more compicx issues with multiple-sided gradations of positions.
We will deny the motion for oral argument.
Oral argument is unnecessary here since the parties have stated their views clearly and compreisensively in the briefs on and opposing exceptions.
J.
Motion for Pro-Forma Tariff On December 31, 1990, the " Eastern REMVIC Utilities" (Boston Edison Company, Canal Electric Company, Commonwealth Electric Company, Cambridge Electric Company _and Montaup Electric Company) filed a motion seeking.to require NU to file a pro-forma
- transmission tariff implementing the.terrs of the -initial decision.
According to the Eastern REMVEC Utilities, this pro-forma-tariff would provide the-Commission with specific tariff' language, not just broad concepts, to review while deciding the
-issues in this proceeding, and would also allow more timely.
7
. implementation of a tariff after the Commission issues its decision.- 'The Eastern REMVEC Utilities also argue that a pro--
forma tariff would allow the Commission to " avoid-a wasteful iterative process in which subsequent round(s) of tariff 25/ ' Order. Denying. Intervention and Rejecting Reply Brief (October 19, 1990).
2n/
City of Chicopee, Massachusetts Municipal Lighting Plant, Town of' South Hadley, Massachusetts. Electric Light 1
Department, City of Westfield, Massachusetts Gas and Electric Department and Town of Wallingford, Connecticut.
l
~
-Docket No. EC90-10-000, gtLA1 submittals attempt to implement what the commission. meant 'in its order." 22/f We will deny the motion for a pro-forma tarif f.
Reviewing a pro-forma tariff would only delay the Commission's resolution of The commission.has consistently sought to this proceeding.-
resolve this_ case expeditiously so that any benefits of the if approved, would not be unduly delayed. 21/
The
- merger, to decide Commission is fully able, without a pro forma tarif f, the issues involved in. concluding whether the proposed merger is consistent with the public interest.
The language of NU's tariff can and will be resolved in the compliance phase of this proceeding.
K.
Motion to Reopen the Record on June 7, 1991, the Massachusetts Municipal Wholesale filed a motion to reopen the evidentiary Electric Company (MMWEC) record to receive recently-developed evidence from another NU proceeding, 11ortheast Ut;ilitien_1gryjee corJ2AIly, Docket Hos.
ER90-390-000, ga A12 MMWEC contends that this evidence, contradicts the consisting of testimony by NU witnesses, testimony of NU's witnesses in the present proceeding.
.MMWEC asserts that the new evidence relates to two issues.
'The first -issue is NU's proposal to give existing generating including NU's ovn, a ten-year priority over future
- capacity, generating capacity 'for the use of NU's post-merger transmission MMWEC claims that recent tectimony by Mr. John Ash, capacity.
. NU's Manager-of _ Power Contracts, demonstrates that-NU's surplus capacity off-system sales practices are discriminatory and MMWEC argues that, according to Mr. Ash, NU's anticompetitive.
off-system sales include' a lower rate for transmission of NU's power than NU charges MMWEC and others f or transmission service of equal orJ higher priority.
MMWEC contends that this testimony warrants rejection of NU's proposed ten-year priority for existing generating capacity.
The second issue cited by-MMWEC concerns the type of transmission service that NU provides to its transmission MMWEC claims that, according to Mr.
dependent' utilities (TDUs).
Ash, TDUs buying power from NU receive a transmission priority equivalent to-NU's own native load, while TDUs buying only l-MMWEC transmission service f rom NU receive a lower priority.
l asserts that Mr. Ash's testimony contradicts NU's representation p
even if TOUs bought only transmission in.this proceeding that, NU would give the TDUs a transmission priority
- service, g
i Eastern REMVEC Utilities motion at 6.
22/
21/
Eearinc Order, 50 FERC at 61,834.
+
=
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u rT
[
Dockot-No. EC90-10-000,,tt A1 equivalent to NU's native load.
MMWEC argues that, based on this i
testimony, the Commission should condition its approval of the merger to require NU to give the TDUs a transnission priority equivalent to NU's native load.
The State of New Hampshire and the New Hampshire Commission (together, New Hampshire), NU and the Connecticut Commission each
- filed answers opposing MMWEC!s motion, raising essentially three First, they argue that MMUEC's motion is nothing more arguments.
than an effort to delay the Comission's decision on the merits of the merger ~ application.
They contend that further delay would be contrary to the public interest.
Second, they ar.Jue that the facts cited by MMWEC as new evidence are already set forth and explained in the evidentiary record of this proceeding.
They claim that NU witness Schultheis testified that NU's accounting practice is to use its non-firm transmission rate as the transmission component of its off-syctem but that this practice does not af fect the " bundled" price
- sales, of its off-system sales, which is determined by the market price for delivered power, Thus, they argue that NU's accounting particularly since NU's customers are practice is irrelevant, already paying for the transmission facilities used to make of f-system sales.
They also claim that'Mr. Schultheis testified for transmission priority purposes, NU would treat TDUs
- that, like native-load only if they agreed to pay a load-ratio share of They argue that Mr. Ash's testimony NU's transmission costs.
instead descri.bes NU's current arrangements with most of its TDUs, which have purportedly declined to pay u load-ratio share of NU's transmission costs.
Third, they argue that MMWEC has f ailed to meet, or even acknowledge, the legal standard for reopening an-evidentiary record. - This standard, they argue, requires a novant to show
" extraordinary circumstances," defined as a change that "goes to the very heart of' the case."
We vill deny MMWEC's motion to reopen the record.
Under-Rule 716 of the Commission's Rules of Practice and Procedure, 2.2/ an evidentiary record may be reopened when warranted by "any changes in conditions of fact or of law or by the public The question of whether to reopen the interest. -..
evidentiary record is a matter of agency discretion, io/
q Agencies must reopen the record only in cases of " extraordinary 2,9/_
18 C.F.R. S 385.716-(1991).
LO/
Southern Company Services, Inc., Opinion No. 300, 43 FERC 1 Q
61,003 at 61,024, reh'a denied, Opinion No. 300-A, 43 FERC 1 61,394 (1988) (Southern Company).
1
-m*
--1w-
+- anw e
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se.-p-e-wey-e a r-,
e m
-r s - v s s-wars = + -s y yy e s e ~ wa t -gr s,a g gw, as wt*,y,+ g y swe, a-p rgy$,-wy g-s,p-y -wgwwmy*m.g--susrT''T""*FP T" W W 9 %F **-V""r-FF*'W'8"'*'T'FN*Tt'*NTT.,
i Docket No. EC90-10-000, gt al.
- 13 circumstances.* Alf
" Extraordinary circumstances" have been defined as a change in circumstances "that is not merely
' material' but rises to the level of a change in ' core' the kind of change that goes to the very heart of circumstances, the case." 12/
The policy of not reopening the record except in extraordinary circumstances rests upon the need for finality in the administrative process.11/
Here, MMWEC does not demonstrate, or even allege, such
" extraordinary circumstances."
Hor do ve find such circumstances.
The evidence prof fered by MMWEC, even if allowed into the record, would establish only tangential points and would not alter our resolution of the issues cited by MMWEC.
NU's practice of " charging itself" a non-firm transnission rate for off-system sales is already established in the record, AA/
as shown later, is not a significant factor in our analysis
- and, of NU's proposed ten-year p-iority for existing generating capacity.
Also as shown later, NU's alleged practice of providing a higher transmission priority for power that TDUs buy from NU instead of others would not alter our analysio of the merger's ef fects on TDUs.
MMWEC's motion vill therefore be denied.
L.
Issues sutrarily Affirred As discussed below, we agree with the presiding judge's overall conclusion that an unconditioned merger vould lively have substantial anticompetitive effects.
We also agree vil.3 the presiding judge's overall recommendation to approve the u*;rger subject to certain conditions, but disagree with the judge's recommendations on certain specific conditions.
We vill summarily af firm the initial oecision on the following issues:
resolution of PSNH's bankruptcy; 15/ cost savings due to NU's operation of Seabrook; 31/ fossil unit 11/
ld.; Bovsan Transportation, Inc. v. Arkansas-Best Freight System, Inc., 419 U.S.
281, 296 (1974).
12/
American Financial Services Association v. FTC, 767 F.2d 957, 964 n.5 (D.C. Cir. 1985); American Optometric Association v. FTC, 626 F.2d 896, 907 (D.C. Cir. 1980).
32/
Eputhern Ccepany, 43 FERC at 61,024.
11/
Tr. 3631; Ex. 123C at 332-34.
15/
53 FERC at 6 5,211-12.
15/
Id. at 65,212.
e 14 Docket No, EC90-2,0-000,. gA A1
~
operating savi.ngs;.42/ administrative and general. expense-savings; M/ coal purchasing savings; _.43/ the merged company's' right to seek single participant status in NEPOOL; SS/ NU's' proposed reciprocity requiremen'; 51/ whether the NH Corridor Proposal is a market allocat in agreement; 52/ -the 3
ten-year minimum increment of service-under the NH Corridor Proposal: 5)f the conflict override provision: 5_4/ the New Hampshire ~ Electric Cooperative's second and third proposed conditions on the merger; 55/ Holyoke's proposal to force NU's divestiture of HWP; 5p NU's " untouchable package" argument; 52/ the automatically adjusting rate of return on equity in the Seabrook Power Coritract; 5.af section 12 of the Seabrook Power Contract;_ 53/ the lag for fuel expense in cash working capital; SS/ decommissioning expense; 51/ the rate of P
A2/
M. at 65,213.
LQ/
Jh.
UJ M*
}&/
M. a t - ' 6 5, 213 - 14.
51/
M. at 65,221._
kne Utah Power & Light Co., opinion No. 318-A, - 47 FERC 1 61,209 at 61,7 4 5-4 6 (1989), grcier on rehga, ring, opinion No. 318-B, 48 FERC 1 61,035 (1989), gopeal docketed
_pigh nom. Environmental Action v.
FERC, No. 89-1333 (D.C.
Cir. May - 2 2, 1989) (Q1Ab).
12/
53 FERC at 65,227-28.
52/
Jd. at 65,228.
5_4/
JA. at 65,229.
15/
M. at 65,231.
16]. M.-at 65.232.
5))
M. at 65,234.
ES/
M. at 65,235.
- 19/
E fS,235-36.
We Vill, however, require NU to exclude
- 25. at 5A/
nuclear $'uel which it owns from its cash working capital allovarice.
Connecticut Yankee Atomic Power Company, 13-FERC 1 61, M4 (1930).
51/
M. at 65,236.
O@
M
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v,
,,,.-c ww
,r.-
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v-,.---+
+
Docket No. EC9 0 0 0 0, c1 A1 return on equity in the Capacity Interchange Agreements; 12/
and the acquisition premium, fl/
We find that the presiding judge properly decided these issues, and the arguments on exceptions have failed to persuade us that the presiding judge erred.
We will also summarily af firm the presiding judge's decision on the issues as to which no exceptions were taken:
emergency allocation and native load priority under the NH Corridor Proposal; 13/ notice of past tying arrangements by HWP/ ff/
and spinning of f the merged company's transmission assets,11/
As to the remaining issues, we vill rule on several affirm the litigated matters not decided by.the presiding judge, presiding judge with additiona'. discussion in part and reverse the presiding judge in part.
M.
Etatutory Standard Under section 203 (a) of the FPA, fl/ the Commission must approve a proposed merger if the proposed merger "will be Under section 203 (b),
consistent with the public interest."
sf/ the Commission may condition its approval on "such terms and conditions as it finds necessary or appropriate to secure the maintenance of adequate service and proper coordination in the public interest of f acilities subject to the jurisdiction of the commission."
Merger applicants need not show taat a positive benefit to The the public vill result f rom a proposed merger, ff/
applicant must fully disclose all material facts and show af firmatively that the merger is consistent with the public 52/
Id.
The return on equity in the Capacity Interchange Agreements will, however, be updated infra.
e f3/
M. at 65,236.
f3/
154. at 65,228.
Sk/
M. at 65,232.
11/
Id.
f2/
16 U. S. C. S 824b(a) (1988).
11/
16 U. S. C. $ 824b(b) (1988).
l l
f2/
Litah, 47 FERC at 61,7507 Pacific Power & Light Company
- v. FPC, 111 F.2d 1014, 1017 (9th Cir. 1940) (Pacific Power & Licht).
i
Doc)bt No. EC90-10-000, si A1
- 16 interest. 22/
It is sufficient if the oprobablo margar benefits.
add up to substantially more than the costs of the merger." 21/
II.
E,enefits of the Meraer A.
Introduction NU claims that the merger will produce significant benefits for PSNH and its customers, the existing NU companies and their and New England as a whole. 22/
The first and customers, foremost benefit claimed by NU is the resolution Of PSNH's HU also claims that the merged company's attainment bankruptcy.
of single participant status in NEPOOL will save its ratepayers approximately $364 million.
Other monetary benefits claimed by NU amount to approximately $800 million, consisting of:
$527 million in OEM costs from NU's operation of Seabrook; $100 million from improved availability of PSNH's fossil steam generating units; $124 million from reduced administrative and and $39 million from reduced coal purchasing general expenses; costs for PSNH.
An issue common to many of these claimed benefits is whether they should be attributed to the merger even though too benefits are achievable by other means, e.a.,
by contract.
The presiding judge ruled that such benefits should nonetheless be attributed to the merger. 22/
A number of intervenors argue that the presiding judge erred and that such benefits should not be attributed to the nerger.
21/
In support, they cite the U.S. Departm' ant of Justice 's (DOJ) Merger Guidelines, which require rejection of " claims of ef ficiencies if equivalent or comparable savings can reasonably be achieved by the parties through other means." 15/
They also cite the Commission's decision in Souther.1_q,aMD2EDJp_Idison 20/
Eacific Power & Licht, 111 F.2d at 1017, 21/
Ege Ex. 1 at 39-44; Ex. 6 at 27-33; NU Initial Brief at 2-10.
23/
53 FERC at 65,211-13.
New England Cogeneration Associatior Brief on Exceptions at 21/
Principal New England Interve; :rs Brief on Exceptions 55-59; at 13-20 ; Ten Eastern REKVEC Utilities Brief on Exceptions at 24-30, 25/
Ex. 551 at 36.
r
Docket No.=EC90-10-000, et A1.-
- 17 2f/ allowing discovery on alternative means of
~Comnany, l obtaining the claimed merger benefits, and Forthwestern Electric.
22/ where the Commission was "not. impressed" by the
~ Company,
, claims of merger-related savings when the applicants producedL "no
-specific proof" that the claimed sa$,1c,3 "could not be brought consolidation."
- Finally, about by-means other than the proposea the intervenors cite the Supreme Court's interpretation of the Bank Merger Act of 1966 1E/ as requiring merger proponents to show that the merger benefits are not reasonably achievable through other means. 22/
In our view, a claimed benefit should be attributed to the merger even though the benefit could be achieved without the r
merger, jff As we stated in setting this case for hearing:
The Commission.
doec not have to determine whether the disposition is the only technique by which the companies could accomplish the overall objectives of the Federal Power Act.
Rather, the Commission, after analysis of all the relevant factors, need only conclude that, in the particular circumstances, the1 merger is consistent with the-public interest. [g1/)
The FPA is not " hostile" to mergers and does not treat them as
" presumptively harmful." 12/
Nor does the FPA require us to approve mergers only as "a last resort."
Instead, we must weigh 1E/
48 FERC 1 61,207 (1989), aff'c 48 FERC 1 63,008 (1989).
I-i 22/. 5 FPC 312, 318 (1946).
18/
12 U.S.C. 5 1828(c) (1988).
12/
United States v. Third National -Bank of Nashville, 390 U.S.
(1968); United States v. Phillipsburg National 171, 189-90
' Bank and Trust Company, -399 U.S.
350, 372 (1970).
I f
30/
Hearina Order, - 50 FERC at 61,833; Utah, 45 FERC at 61,299; Commonwealth Edison Company, 36 FPC 927, 931 (1966), aff'd.
sub nom. Utility Users-League v.
FPC, 394 F.2d 16 (7th Cir. ), cert. denied, 393 U.S.
953 (1968).
JJf Hearina Order, 50 FERC at 61,833; Kansas City Power & Light l
Company, 53 FERC 1 61,097 at 61,282 n.65 (1990); Southern l~
California Edison Company, 47 FERC 161,196 at 61,672, 2rder L
on rehearino, 49 FERC 1 61,091 (1989).
I E2/
Pacific Power & Licht, 111 F.2d at 1016.
t
,,-g
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y
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,w,,,
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l Docket No. EC9 0 00 0, gi al.
- 18 all of the costs and benefits of proposed mergers and approve those mergers that are " consistent with the public interest."
While this approach differs from the approach taken in the DOJ Merger Guidelines, our statutory role also differs from DOJ's.
The Commission "is not strictly bound by, and not I
empowered tc enforce, the antitrust laws; they are employed to give understandable content to the broad statutory concept of the public interest." 12/
Thus, the Commission is not bound by the DOJ Merger Guidelines and, in fact, has expressly declined to adopt those guidelines.11/
Our conclusion also does not conflict with the Southern California Edison decision cited by the intervenors, since that case involved only an interlocutory appeal of a discovery ruling, where the party opposing discovery had " opened th door" with the testimony of its own witness.11/
To the extent our conclusion here does conflict with the discussion in Northwestern E]ectric, this aspect of that case is overruled in favor of the better-supported approach taken here and in other recent merger decisions.
Finally, the Supreme Court's construction of the Bank Merger The Bank Act of 1966 does not undercut our conclusion here.
Merger Act of 1966, in pertinent part, parallels the antitrust laws by requiring the agency to reject any merger:
(v)hich would result in a monopoly, or which would be in furtherance of any combination or conspiracy to monopolite or to attempt to monopolize the business of banking in any any other part of the United States, or.
proposed merger transaction whose ef fect in e
any section of the country may be substantially to lessen competition, or to tend to create a monopoly, or which in any l
other manner would be in restraint of trade, unless it finds that the anticompetitive ef fects of the proposed transaction are clearly outweighed in the public interest by the probable ef fect of the transaction in r
33/
Utah, 4 5 FERC at 61,28 3 ; Southern California Edison, 47 FERC at 61,674 n.22.
l Ef/
Utilicorp United Inc., 56 FERC 1 61,031, slip op, at 16 n.32 (1991); Central Vermont Public Service Corporation, 53 FERC 3 61,204 at 61,819 (1990).
R5/
Southern California Edison, 48 FERC at 65,014-15.
?
L e
Docket No. EC90-10-000, 2.t A1
- 19 Leeting the convenience and needs of the community to be served.-[f_f/)
The antitrust laws underlying the Bank Merger Act of 1966 are narrower than section 203 of the FPA, since the competition issues addressed by the antitrust laws are only one facet of the-FPA's "public interest" standard.
The "public-interest" under the FPA is not limited to the goals of the antitrust laws and instead is directed primarily to the broader goal of "the orderly production of plentiful supplies of electric energy.
at just and reasonable rates." #2/
Our approach regarding the benefits of _ a proposed merger, though dif ferent f rom the approach taken under the antitrust laws, is proper under section 203, which requires us to approve a proposed acquisition if it is consistent with the public interest.
B.
NEPOOL Savinos Under Section 3.1 of the NEPOOL..greement, PSNH and UU may elect, after the merger, to be treated as a " single participant" in NEPOOL. 31/
According to NU, single participant status would save the merged company approximately $364 million in NEPOOL costs. 33/
These costs would be shifted to other NEPOOL utilities. 9_Q/
This potential cost shift raises two issues.
First, should the Commission allow the merged company to obtain single participant status and thus shif t the 5364 million of costs?
Second, if so, should the Commission recognize the savings ~ to the merged company as a merger-related benefit?
The presiding judge allowed single participant status.
11/
As noted above, we summarily affirm the presiding judge in allowing single participant status.
One matter, however, warrants discussion here.
Certain intervenors argue that allowing single participant status for the merged compa / is-contrary to the decision 'in New Enoland Power Pool Acreerent f.5/
12 U. S. C. 5 1828(c) (1988).
12/
NAACP v. FPC, 425 U.S.
662, 670 (1976).
3R/
Ex. 603 at 10.
9.2/
-Ex.
1 at 41.
9,0/
Ex. 18 at'13, 17; Ex. 15; Ex.
8, columns 3 and 4; Tr. 1428, Q
1857-58, 1862-63, 1865.
11/
53 FERC at 65,213-14.
~
=
Docket No. EC90-10-000, et al. [
D{IEQpL1,12/ where the NEP00L Agroepent was first approved.
specifically, they argue that the liEEQ2L decision requires denial i
of single participant status to utilities, suel as NU and PSNH, that experience their peak loads in different seasons. 12/
We disagrea.
The NEPool Agreement, as initially filed and allowed singic participant status for utilities as approved, ontrolled by a single " person" owning at least 75 percent of the l
/oting shares of each utility.11/
An exception was expressly allowed in the flied agreement for any Vermont utility which elected to be grouped with Votmont Electric Power Company. 22/
This exception vaF approved for essentially two reasonst (1) the
[
verront utilities had long acted as a single contiguous t
integrated electric entity; and (2) since they all experienced their peak loads in winter, single participant Ltatus would not f
give them a lower HEPOOL Capability Responsibility (and 21/
A broader exception was denied, consequent savings).
for a group of muni.:lpal utilities _ (represented by
- however, MMWEC) that was not entitled to single participant status and i
that lacked the two cited attributes of the Vermont utilities, The basis for the denial was that allowing such status for "any group of systems, such as KMWEC, could well be detrimental to the i
functioning of NEPOOL." 12/
The NEPOOL decision, thus, does not stand for the proposition that single participant status is available only to utilities having their peak loads in the same season.
- Instead, another way, indeed the pilcary way, in which utilities may qualify is if they are controlled by a single person with at 12ast 75 percent common ownership.
That is the basis upon which l
UU and PSNH will procumably seek to qualify if the merger is Such status is expressly allowed under the NEPOOL approved.
agreement regardless of when NU cnd PSNH experience their peak
(
- loads, t
The second issue related te si. ale participant status is whether to treat the merged company's NEPOOL savings as a 22/
56 FPC 1567, 1530 (1976), aff'd EMb n922 Hunicipalities of Groton
- 7. PERC, 587 F.2d 1296 (D.C. Cir. 1978).
22/
Principal New England Intervenors Brief on Exceptions at 36-
{
38.
i 21/
NEPOOL, 56 FPC at 1565, 1579-80.
2h/
Id.
t 11/
- 14. at 1580.
All 14
?
l Doc'ct }{o, EC90-10~000, Ct al. A number of intervenors argue timt the llEPOOL savings benefit.
represent a dollcr-for-dollar transfer of costs to other NEPooL members and cannot count As a benefit in determining whether the merger in consistent with the public interest. 23/
'-r T We agree with these intervonors.
The Commission muut consider the effect of these HEPOOL " savings" on all HEPoob 6
members, not just the applicants.
The $364 million saved by the applicants as a single participant in HEPooL will reduce thea Q AsO %.
savings otherwise available to the other HEPOOL members.in determinin such, this cost shift cannot count as a benefit whether the merger is consistent with the public interest.
O-p ~,
This conclusion is not contrary te the decision in EnTd i.
O U
Electric Corporation, 23/ in which the Commission authorized merger between Newport Electric Corporation and Eastern Utl1 1:
4
.7 In Egwpari, the Commission cited the applicante T
- r1 Associates.
$ ' ~ Q claim that the merger benefits included " reduced capacity requirements and lower energy production costs resul?ing rrcy,-, O '
However, while rn r.. A composite load treatment under NEPooL." 193/the Commission cited the applica g,, Ly no finding regarding that claim and instead concluded only that,--.:,':::
"the merger vill not have an adverse ef f ect on operatinfM y
- overall, Z
costs or rate levels." 121/
III. The Ef f ect QD_ Cornet 3.11oD A.
Ihr Cordssion's ReJAQAdbilitin In exercising its public interest responsibilities, the Commission must consider the policies that underlie the antitrust By considering antitrust and anticompetitive statutes. 122/
the Commission serves as a "first line of defense against issues,competitive practices that might later ue the subject of those Ten Eastern REMVEC Utilities Brief on Exceptions at 13-16; PJ./
New England Cogeneration Association Brief on Exceptions at Principal New England Intervenors Brief on Exceptions 59-60; at 4.
9.2/
50 FERC 1 61,382 (1990).
lQD/ M. at 62,171.
19.1/ M. at 62,172.
411 U.S.
747, 758-60 1Q2/ Gulf States Utilities Company v. FPC, (1973) ( Mif States); FPC v. Conway Corporation, 4?6 U.S.
271, 279 (1976).
l l
Docket No. EC90-10-000, gi gl. antitrust proceedings." 121/
Thus, the Commission is obligated to consider possible anticompetitive consequences flowing from a proposed merger, and allegations of anticompetitive conduct may properly be raised in proceedings under section 203 of the FPA. 121/
As noted above, however, the Commission is not strictly bound by the antitrust la'ws; instead, the antitrust laws are merely one f acet of the broad statutory concept of the public interest. 125/
To acet its responsibilities in this proceeding regarding the policies of the antitrust statutes, the Commission focused the parties' attention on "the market power the merged company might acquire as a result of the merger going forward." 195/
Specifically, the commission stated that the " issue to be determined is whether the merged company will have any greater market power than the two companies currently have as separate entities, i.e., whether market power will be enhanced by the merger." 122/
The Commission outlined a four-step analysis for making this determination (1) define the product and geographic markets in which significant market power can be exercised by the merged companyl (2) evaluate the market power the merged company is likely to possess in each relevant product and geographic markett (3) explain how that market power, if it exists, can be exercisedt and (4) describe the likely effects of exercising such market power. (191/)
We will now apply this framework to the evidence that the As discussed below, we affirm the judge's parties submitted.
finding that an unconditioned merger would likely have serious We find that the anticompetitive consequences for New England.
merged company's enhanced control over key transmission interf aces and corridors would allow it to limit access by other 192/ Qul f St ate s, 411 U. S. at 760.
121/ Kansas Power and Light Company v. TPC, 554 T.2d 1178, 1184 (D.C. Cir. 1977); Qulf States, 411 U.S.
at 758-59 125/ Northern Natural Gas Company v. FPC, 399 F.2d 953, 960 (D.C.
Cir. 1968), citino California v. FPC, 369 U.S.
482, 490 (1962).
111/ Hearina_ Order, 50 FERC at 61,834.
192/ M.
191/ U.
1
I Docket No. EC90-10-000, c1 A1,
f New England utilities to important power supply sources that could otherwise compete with NU power supplies.
We find that this would permit the merged company to isolate utilities in Maine, Ve rmont, Eastern REKVEC and other How England subregions from traditional and non-traditional power suppliers located both in and out of New England.
We concur with the judge's finding that this enhanced control over key transmission facilitice would l
expand the merged company's market power in "the years j
immediately following the transaction (the merger) and will continue f or the f oreseeabic future." 121/
We also find that i
the merged company would have increased market power in short-term bulk power markets.
Thus, we conclude that an unconditioned l
i merger would likely have the ef fect of substantially lessening competition within Hsw England and the various subregions
. identified above.
D.
The Eclevant CorPAIIDan for Angspira the Meratt'.n Carpetitive Effects I
The presiding judge concluded that "an unconditioned merger j
would have serious anticompetitive consequences for How England
" 113/
NU disagrees with this conclusion.
111/
NU contends that the presiding judge made the wrong
[
t comparisc'.
NU argues that the presiding judge should have compared.5e competitive situation without the merger to the
'i situation with its " entire merger proposal," 111/ including its General Transmission commitments 111/ and the NH corridor l
Proposal. 111/
NU asserts that the General Transmisulon Commitments and the NH corridor Proposal are pro-competitive and I
argues that these pro-competitive terms must be considered in the first instance in determining the merger's effect on competition.
l 111/
J t\\
192/ $3 FERC at 65,219.
l 112/ 14 t
111/ NU Brief on Exceptions at 7-11.
Eqq alEO New Hampshire i
Brief on Exceptions at 6-8.
i 111/ NU Brief on Exceptions at 16.
j j
111/ Id. at 13. 18.
Ese Ex. 178.
i 113/ Ex. 154.
i 111/ In support, NU cites United States v. Connecticut National i
Bank, 362 F. Supp. 240, 283 (D. Conn. 1973), VAcatt.d on j
other grounds, 418 U.S.
656 (1974); United States v.
Atlantic Richfield company, 297 F. Supp. 1061, 1068-69 (continued...)
r I
i
~_.
,-_-_,_..,.,,,m...
24 -
Docket No. EC90-10-000, et al.
Trial Staf f and other intervenors oppose HU's exception.
i They argue that the merger should be examined without 2]If NU's proposed " conditions" because NU vitness Kalt stated that an unconditioned merger would have no anticompetitive effect.
112/
They also challenge NU's claim that the merger is pro-competitive, arguing that NU's claim is based on mischaracterizations of the evidence, unrealistic assumptions and flawed economic analysis.
We affirm the presiding judge.
We must compare the competitive situation which existed before the merger to the competitive situation which would result from an unconditioned merger in order to establish a baseline for determining whether the merger should be conditioned and, if so, in what ways.
Without such an initial assessment, we cannot determine lla/
whether additional conditions are necessary to mitigate any We find it sufficient, anticompetitive effects of the merger.
and appropriate, to consider NU's proposed transmission commitments in the remedial part of our decision, af ter we determine what, if anything, needs to be remedied.
As shown below, HU's proposed conditions are used as the starting point of our conditioning analysis.
C.
The Relevant Markets We must assess the likely competitive impact of the merger within economically meaningful markets, i.e., markets that could be subject to the exercise of market power.
To do so, we must 111/ (... cont inued)
(S. D. N.Y. 1969), aff'd sub nom. Bartlett v. United States, 4 01 U. S. 986 (1971); and White Consolidated Industrics v.
Whirlpool Corporation, 612 F. Supp. 1009, 1028, 1032, iniunction vacmind, 619 F. Supp. 1022 (H.D. Ohio 1985),
j l
aff'd, 781 T.2d 1224 (6th Cir. 1986).
l 111/ Trial Staf f Brief opposing Exceptions at 7-14.
Esc also Principal New England Intervenors Brief Opposing Exceptions at 3-4, 17-20; Eastern REKVEC Utilities Brief opposing Exceptions at 7; Ten Eastern REMVEC Utilities Brief opposing Exceptions at 6-14; and New England Cogeneration Association Brief opposing Excuptions at 5,'65-75.
Eastern REKVEC Utilities Brief opposing Exceptions at All/ E,0.,
8-9, citina Ex. 520 at 4.
11E/ Ex. 520 at 4.
We have used this same approach in our assessment of other mergers.
Ess Mlah, 45 FERC at 61,283-91; tjill i corp, gypIs, 5 6 FERC 1 61, 03 3.
-..-n-
-,,,ym.y-ym.----
sy,_.
l Dockot No. EC90-10-000, et al. identify the geographic and product markets that are likely to be af fected by the merger.112/
1.
Relevant Ge_caraphic Markets The presiding judge found that the relevant geographic markets are New England and Eastern REMVEC (eastern Massachusetts and Rhode Island).122/
However, in discussing the conditions to be imposed on the merger, the presiding judge stated that {n)orthern utilities are just as threatened by the merger's transmission citrtain as southern ones.
The merger cuts each of f from the other." 121/
Thus, the presiding judge was concerned with How Englat d subregions other than just Eastern REMVEC.
On exceptions,;iv argcea c.at only one relevant geographic market, Eastern REMVL1,.u iduntified on the record. 122/
Trial Staff ergues that '5r*.c are four separate relevant geographic markets -- New 2ngland as a whole a*/d the New England subregions of Eartern Rr*WEC, Maine and Vermont.
Trial Staff asserts that these subregions are important because the merged company may be able to price-discriminate among these New England subregions. 122/
We concur with the presiding judge; the merger's anticompetitive effects would not be limited to Eastern REMVEC.
We find that the whole of New England and the individual subregions of Eastern REMVEC, Maine and Vermont would each likely be affected by the merger and, thus, constitute relevant geographic markets in this case. 123/
The judge's emphasis on Eastern REMVEC appears to stem from his concern that Eastern REMVEC could be highly vulnerable to the Eastern merged company's future exercises of market power.
is the subregion where the demand for bulk power is REMVEC expected to grow the most.
NU's internal studies show that it alS/ Utah, 45 FERC at 61,284 ; Ex. 551.
122/ 53 FERC at 65,215-16.
In the context of this proceeding, the 121/ Id. at 65,2 2 7.
northern utilities are located in Maine, Vermont and New Hampshire; southern utilities, in Massachusetts, Rhode Island and Connecticut.
122/ NU Brief on Exceptions at 2~,-30.
122/ Trial Staf f Brief on Exceptions at 36-38.
121/ Ex. 55 at 52-54.
See alqg Ex. 186 at 5.
j Docket Ho, EC90-10-000, c3 al. expects Eastern REMVEC to be the most promising region for bulk Eastern REKVEC is power sales from its excess capacity. 121/
also one of the most densely populated areas of New England.
Electricity production in Eastern REMVEC is more costly 121/
New York and parts of Canada. 112/
than in Maine, Vermont, Eastern REKVEC has relied on bulk power imports from In the past, these lower-cost areas to moet some of its power supply needs.
In 1986, for example, Eastern REMVEC utilities imported power equivalent to 37 percent of the local load and, by 1988, imports 121/
Eastern REMVEC is equalled 43 percent of local load.
likely to remain a relatively high-cost production area in the As if it is limited to intra-region generation resources.
future Montaup witness Taglianetti testified:
Most utilities in Eastern REMVEC, and certainly Montaup f alls into this category, are basically urban utilities.
Siting power plants in urban areas has proven to be extremely difficult.
A number of projects have been forced to abandon plans to build in the Eastern REKVEC area.
Ecr example, one
[non-utility generator) which had planned NUG to build in Northern Rhode Island has been forced to cancel that project due to local opposition.
That NUG is now considering building in Maine. [123/)
The merged company's enhanced control of Eastern REMVEC interf aces with the rest of New England would allow the merged company to block competing, lover-cost suppliers, thereby forcing utilities in Eastern REMVEC to rely on higher-cost local resources or to purchase f rom the merged company.112/
We find that the presiding judge corre:tly concluded that other New England subregions vould also be vulnerabic to exercises of market power made possibic by NU's increased Neither Maine transmission control resulting f rom the merger.
nor Vermont would be abic to engage in transactions with Eastern RIMVEC or each other without using the merged company's 111/ S ee Ex. 1-1 at 633.
121/Ex. 500 at 17; Ex. 498 at S.
111/ Exs. 498 at 5-6.
121/ Ex. 587, 122/ Ex. 537 at 6-7.
11Q/ Ex. 534 at 10-13.
Docket No. EC90-10-000, it A1 J transmission facilities. 111/
Utilities in Maine would be unable to reach any out-of-state domestic market to buy or sell bulk power without using the Maine / Hew Hampshire interface that will be controlled by NU. 112/
Historically, Maine and Vermont utilities have been active participants in New England markets. 112/
While NU argues on exceptions that Eastern REKVEC is the only relevant market, NU's own economic witness, J.P.
Kalt, testified that
[I)t is possible that the proposed merger could have differential competitive impil..ations, depending upon any limitations that would restrict inter-regional transfers of power capacity.
Exhibit No. (57) illustrates that the natural divisions along which to investigate this question are provided by the boundaries of NU's and PSNH's transmission systems.
These approximately parec1 the region into three arcast Eastern REMVEC (la, eastern Massachusetts and Rhode Island), Maine, and Vermont. [123/)
Therefore, we find that New England, Eastern REMVEC, Maine and Vermont represent relevant geographic markets that could be subject to the exercise of market power by the merged company.
12.5/
2.
Relevant Products The presiding judge identified transmission services and Both NU bulk power as relevant products in this case.111/
and Trial Staf f except to the presiding judge's conclusions.
NU maintains that there is only one relevant product, namely, 121/ Id. ; Ex. 4 49 at 7 2-7 4 ; Ex. 372 at 10.
112/ Ex. 261 at 2 3.
122/ Ex. 4 4 8 at 19-20 ; Ex. 586.
l 11&/ Ex. 55 at 118.
It is appropriate to consider the 12f/ Ex. 569 at 4 8-52.
relevant geographic market as limited to New England and these three subregions because it appears unlikely that existing or new out-of-region suppliers can be a significant competitive influence absent greater transmission transfer capacity.
Id.
liff 53 FERC at 65,214.
l
Dockot No. EC90-10-000, Et al. '
delivered bulk power, undifferentiated by term.112/
NU disagrees that transmission is a separate relevant product.
221/
NU insists that the supply of delivered bulk power and its alternatives, new contingency utility generators (Ucs),
123/ uncommitted and contingency non-utility generators (IPPs/QFs) 112/ and demand side management (DSM), can be easily expanded at current prices, L gt, that the supply of delivered bulk power including these substitutes is highly clastic. 11J/
NU also claims that few, if any, barriers prevent entry into the delivered bulk power market.112/
NU claims that virtually all the expert witnesses in the case agree with its conclusions about the relevant products and that any remaining disagreement-centers on the alternatives.111/
Trial Staf f and several intervonors disagree with NU and say that no agreement was reached on whethers (1) all delivered bulk power is the single relevant product; (2) supply in the product narkets is highly clastic; (3) f ew barriers prevent entry into the product market; or (4) co: petition in bulk power markets is 112/ NU Brief on Exceptions at 29-30, 42-72.
Eq_q & Q How Hampshire Brief on Exceptions at 12-22 and Connecticut Commission Brief on Exceptions at 13-14.
liff NU Brief on Exceptions at 47.
NU asserts that Buckeye Pipe Line Company, Opinion No. 360, 53 FERC 1 61,473 (1990),
holds that transmission cannot be a stand-alone product.
111/ " Contingency" is a term used by NEPOOL to ref er to
" additional resource estimates (from (NEPOOL participants')
contingency plans) that could possibly be brought on line to (although) no detailed meet expected shortages analysis was made of either the feasibility or economics of these resources."
Ex. 55B at 10; Ex. 549 at 63.
These resources "may never be implemented for a variety of reasons."
Ex. 55B at 47, 119/ " Uncommitted" is a term used by NEPOOL to refer to NUGs that are:
(1) planned for installation but are not utility-authorized; and (2) have regulatory approval pending but are not yet under construction.
Ex. 549 at 63; Ex. SSC at 33-34, 60.
111/ NU Brief on Exceptions at 66-72.
141/ Id. at 47.
232/ Id. at 28-29, 45.
Docket No. EC90-10-000, c1 al. (1,e., undif f erentiated by term).13A/
Some of the atemporal intervenors argue that transmission is a separate product because bulk power sellers, in either the short-or the long-term market, cannot substitute any service for transmission.115/
They assert, therciore, that treating transmission services as part of (delivered bulk power) is inadequate; instead, a bundled product transmission must be recognized as a separate product for which there is an independent market. lif/
Trial Staf f and the intervenors also argue that short-term bulk power is a separate product f rom long-term bulk power 112/ because the planning process is imperfect and expansion is discontinuous due to scale economics. 111/
They argue that IPPs/QFs cannot compete in short-term markets because IPPs/QFs are generally committed to long-term contracts. liff They assert that the ability of IPPs/QFs to compete effectively in long-term markets is highly dependent on the availability of 30-36.
Egg 111/ Trial Staf f Brief Opposing Exceptions at 14, also Principal New England Intervenors Brief Opposing Exceptions at 30; Eastern REKVEC Utilities Brief Opposing Exceptions at 23; Ten Eastern REKVEC Utilities Brief Opposing Exceptions at 59; Nov England Cogeneration Association Brief Opposing Exceptions at 8-17, 26, 31.
lA1/ Principal New England Intervonors Brief opposing Exceptions at 30.
Ese alsp Eastern REMVEC Utilities Brief Opposing Exceptions at 23; Ten Eastern REMVEC Utilities Brief Opposing Exceptions at 591 New England Cogeneration Association Brief Opposing Exceptions at 8-17, 26, 31.
lAS/ New England Cogeneration Association Brief opposing Exceptions at 14-15.
132f Trial Staf f defines short-term bulk power as transactions. in capacity and/or energy under contracts with a total duration of five years or less.
Long-term bulk power is defined as transactions under contracts with durations of more than five years.
Egg Ex. 569.
113/ Trial Staf f Brief on Exceptions at 31-36; New England Cogeneration Association Brief Opposing Exceptions at 46; Principal New England Intervenors Brief Opposing Exceptions at 38-41; Ten Eastern REMVEC Utilities Brief Opposing Exceptions at 35-38.
112/ New England Cogeneration Association Brief Opposing Exceptions at 45-46.
l l'
Docket No. EC90-10-000, ci al. transmission access and the regulatory and financial climate.
150/
We agree with the presiding judge's determination that transmission services are a separate relevant product.
Transmission services within the How England region are relevant for products because they can be traded separately and because, there are no substitutes for these many buyers and all sollers,This conclusion is consistent with our analysis of se rvices.
Even im witness r, alt transmission services in Utah. 111/
in the acknowledged that "(c)1early, transmission is a market sense that transactions take place between buyers and sellers of transmission service." 1E2/
While !N is correct that we accepted the delivered price of petroleum products as the relevant price for measuring market power in Duckeye Pine Line, 153/ our finding was based on the facts of that case and does not stand for the proposition that transmission can never be a stand-alone product.
When, as in this case, a proposed merger has quite dif ferent market power implications in generation and transmission markets, we must retain the ficxibility to examine cach separately.
The presiding judge correctly identified the transmission network as a key means of exercising market power in this cace,131/ an important and necessary perspective that vould not be available if delivered bulk power were considered the only relevant product.
We af firm in part and reject in part the presiding judge's determination of relevant bulk power products.
While we agree with the presiding judge that bulk power is a relevant market, we further find (contrary to the presiding judge's decision) that short-and long-term bulk power are separate relevant products in this case.
Long-term and short-term bulk power are not good substitutes for each other. 111/
For example, purchasing a 20-year commitment to meet power needs that exist for a few days 150/ Id. at 4 6-58.
151/ 45 FERC at 61,284.
See Ex. 372 at 44-52; Euckey_e Pi pe Line,
53 FERC at 62,663-64 (product market defined as the transportation of refined petroleum pipeline products).
Jjub/ Ex. 55 at 3 3.
153/ 53 FERC at 62,666.
154/ 53 FERC at 65,216.
155/ Ex. 569 at 7, 25-27; Ex. 574.
Docket No. EC90-10-000, gi gl. or years would be prohibitively expensive. liff Conversely, relying on relatively short-term annual contracts to meet a long-term power requirement is likely to involve excessive risk of In actuality, short-price volatility and availability.112/and long-term arrangements are m substitutes. liff Thus, we find that these two bulk power are the relevant product products (and transmission services) markets in this case.
In theory, short-and long-term power could be supplied by The judge excluded different types of power supply resources.
the following types of resources from the relevant bulk power contingency UGs, uncommitted products on well-reasoned groundstexpansions of DSM programs and major and contingency IPPs/ qts, We affirm the presiding expansions of transmission facilities.These alternatives are not part of judge in these exclusions.
the relevant power products because they are inadequate substitutes for either short-or long-term bulk power liff on this record, we find that all of these alternativen have too long a development period and the prices at which they would become available are too uncertain for them to provide adequate For price-discipline in short-term power markets. 142/
exampic, Mr. Robert Shapiro, the executive director of the Massachusetts Energy Tacilities Siting Council, testified as follows:
It is a difficult and time-consuming process for any entity, utility or non-utility, to site, licence and construct generation projects within Eastern REMVEC.
Projects require a minimum of three years for completion of all phases of development and 11E/ In theory, a buyer might be willing to take the risk of using a lony-term power purchase as a supply source for it could sell short-term power needs if it was certain thatHowever, it any short-term surplus to other utilities.
could not 1. ave this certainty unless there was assured An discussed in Part IV access to other utility buyers.
such access is not assured without transmission
- below, commitments beyond those offered by NU and PSNH.
1f2/ Ex. 56s at 26: Tr. 3684-88; Ex. 524 at 10-12; Ex. 534 at 8-12; Tr. 5272, 5282-86.
111/ Ex. 579 at schedule 4.
liff 53 FERC at 65,216-18.
110/ Ex. 549 at 61-65, 78, 81-86, 96; Ex. 579 at 7-22; Ex. SSE at 6,
19-27.
l Dockot No. EC90-10-000, 21 A1 can take as long as seven years; four to six years is a reasonable range of estimated development times for a typical project of the types being proposed recently. (151/)
In long-term markets, some IpPs/QFs, DSM programs, UGs and new transmission facilities could provide substitutes for purchases from the merged company if they (excluding DSM programs) had assured transmission access; but, we cannot determine the extent of this competitive discipline at this time. 111/
We reject the presiding judge's determination that surplus capacity is a separate relevant product in this case. 111/
Surplus generating capacity is a supply source for short-term bulk power but it is not a relevant product by itself.
Buyers demand short-term power to fulfill various needs, but there is no demand for capacity that is " surplus" as opposed to other capacity available in the market.
Buyers seeking short-term power do not demand " surplus" capacity to the exclusion of other available capacity.
Therefore, there is no market for " surplus" as such and it cannot be a relevant product.
To restate the presiding judge's peanut concession metaphor,111/ there is no separate demand at today's ball game for yesterday's leftover peanuts.
Baseball fana want peanuts and, assuming the peanuts are fresh, the fans do not care whether the peanuts come from inventory (yesterday's lef tovers) or a new shipment.
D.
Market Power 1.
The Mercer's Market Power Effects The presiding judge found that the merger could have substantial anticompetitive effects in the markets for transmission services and bulk power unless it is properly conditioned. 151/
The judge based this conclusion on his determination that the merged company would dominate these markets, thereby gaining substantially increased market power in the relevant products.
Purthermore, the presiding judge found If1/ Ex. 444 at 24.
san AlEQ Tr. 4749.
If2/ Ex. 500 at 15-25: Ex. 534 at 14; Ex. 313 at 64-65; Ex. 444
.at 15-21.
152/ 53 FEnc at 65,215.
11A/ 1$
261/ 14. at 65,219.
e
--...-..c-,,..
.._,----,,.,---._.m..~.m
-_..m-.7, -,, -. _... _ _, _. _ - _
Dockot No. EC90-10-000, etal. its msrket that the merged company would have incentives to use liff power to raise prices or to provide inferior service.
NU and others argue that the presiding judge's conclusions are wrong because he examined the unconditioned merger and because he used the wrong geographic and product markets.
NU claims that it controls as littic as five percent of 112/
the available capacity on transmission interfaces between Eastern REMVEC and the rest of New England and that it does not dominate New England's interfaces with the outside world. lie /
its share of the delivered bulk power Moreover, NU asserts that when IPPs/QFs and DSM are included as substitutco, is
- market, well below the 20 percent dominance standard used by the Commission in EE1 and well under the 35 percent standard in the DOJ Merger Guidelines. 152/
Trial Staf f and many of the intervenors agree with the presiding judge that, to understand the full extent of the merger's anticompetitive ef f ects, one must examine the impact of the merger's combination of transmission facilities and surplus Trial Sta f f and intervenors assert generating capacity. Ils/
that the merger will create a single company with control of 4,100 miles of transmission stretching from the Maine /New central and western Hampshiro border through New Hampshire, Massachusetts and into southern Connecticut. 121/
They state 266/ Id. at 65,214-16, 65,218.
152/ NU Brief on Exceptions at 31-44.
Ecs filra New Hampshire Brief on Exceptions at 9-14.
liff NU Brief on Exceptions at 32-35.
1h2/ 24. at 44-72.
Ecc alEn 122/ Trial Staff Brief opposing Exceptions at 39-44.
Principal New England Intervenors Brief Opposing Exceptions 45-50; Eastern REKVEC Utilities Brief at 4-5, 17, 20-29, Opposing Exceptions at 6, 10-15; Ten Eastern RIKVEC
[
Utilitics Brief opposing Exceptions at 19-38; and New England Cogeneration Association Brief Opposing Exceptions at 7, 19, 23-37.
Principal New England Intervenors Brief Opposing i
121/ Ezgt, The intervenors also assert that NU's 10, 20.
Exceptions at transmission facilities are " essential facilities" as defined by antitrust law.
They urge the Commission to use c
j the essential facilities doctrine as it did in Minh, 45 FERC to order access to transmission services.
at 61,287, Principal New England Intervenors Brief Opposing Exceptions j
(continued...)
l l
i i
i
Docket No. EC90-10-000, c1 A1 that the combined companies will control 80 percent of the transmission capability into Eastern REMVEC 222/ and 60 percent of the transmission capability between New England south of Maine and the rest of the country.122/
They claim that the merged company will own a majority of the key interfaces and corridors in New England. 123/
Moreover, Trial Staf f and intervenors argue that NU will be able to control any expansion of its transmission facilitics because other utilities may not be abic to build transmission lines across NU's territory without NU's permission. 121/
They also assert that it may not be economical for other utilities to duplicate NU's facilities.
11S/
Trial Staff and intervenors also point out that NU's existing generation capacity surplus will increase with its acquisition of PSNH, which also has substantial surplus capacity now that the Seabrook plant is operating. 122/
They argue 121/ (... continued) at 45-50; New England cogeneration Association Brief on Exceptions at 23-24.
122/ Principal New England Intervenors Brict Opposing Exceptions at 23-24.
112/ Id. at 26.
123/ A witness for the Ten Eastern REMVEC Utilities (Curtis K.
Winterfeld) testified that "[kjoy interfaces are those sets of transmission lines over which power flow limits are regularly analyzed and determined by NEPOOL and its participating utilities in order to ensure reliable system operation."
Ex. 416 at 12.
Mr. Winterfeld listed seven key interfaces:
(1) Hydro-Quebec-New England; (2) New York-New England; (3) New Brunswick-New England; (4) Maine-New Hampshire; (5) North-South; (6) CONVEX-REMVEC; and (7)
Eastern REMVEC.
Id.
121/ Principal New England Intervenors Brief Opposing Exceptions at 49.
l 11E/ 14. at 49-50.
122/ Trial staff states that the merger will increase NU's surplus in 1992 from 388 MW to 710 MW, in 1995 from 794 MW to 1,020 MW and in 1998 from 361 to 544 MW.
Trial Staff Brief Opposing Exceptions at 39.
The Principal New England Intervenors argue that NU's own data show that, depending on the year, the merger will bring between 40 and 81 percent of the surplus generating capacity in New England under NU's I
(continued...)
Docket No. Ec90-10-000, c1 A1 that, as a result, the merged company will control more than 65 percent ot New England's surplus capacity in every year from 1994 through the year 2000. 12f/
rurther, they state that during this same period, most other New England utilities, particularly those in Eastern REMVEC, are projected to have littic or no surplus capacity.
In fact, they claim that many utilities are projected to be capacity short during this period.
For exampic, the Principal New England Intervenors argue that New England utilities other than the merged company will have an estimated, aggregate capacity shortfall of 532 MW in 1995. 123/
We will af firm with clarification the presiding judge's findings.
With respect to transmission services, the judge correctly found that there are certain " key transmission f acilities and corridors." lER/
Transmission facilities t
exist in a geographically dispersed network and within this network some lines are more important than others. Ifl/
Therefore, we focus on these strategic or key transmission facilities in assessing the likely competitive effect on transmission services. 112/
t We af firm the presiding judge's conclusion that the merger I
would increase NU's market power over the transmission network throughout New England.
The facilitics that NU will dominate are too corridor from Maine south to the rest of New England, the i
122/ (... continued) i control.
Principal New England Intervenors Brief opposing Exceptions at 27-30.
i i
121/ New England cogeneration Association Brief opposing Exceptions at 27-30.
J79/ Principal New England Intervenors Brief opposing Exceptions l
at 27-30.
112/ 53 FERC at 65,215.
^
111/ For example, the Commission focused on two significant general transmission paths in Utah, 45 FERC at 61,285.
j 112/ Similarly, in i'S icorp, Eugtn, slip op. at
)'J, we found that certain trh.wmission lines constitute " valuable trade corridors."
Such lines are key or strategic facilities in the sense that they are essential contract paths needed by many of the region's buyers to reach important supply sources or by sellers to reach buyers, other transmission facilities that interconnect with a major trade corridor may be equally strategic for specific sellers or buyers because l
they constitute the entry and exit points to the main i
transmission paths.
r
Dockot No. EC90-30-000, ci al. ;
I
. interfaces with interfaces between New England and New York, the l
The merger Quebec and the Eastern REMVEC " curtain." 232/will substantially facility ovnership.
The merged company will own 65 percent of i
I external interfaces compared all the Nes England (south of Maine) interfaces prior i
with NU's ownership of only 32 percent of these The merged company vill own 100 percent to the merger.1Ei/
and of the Maine /New Hampshire interf ace (now controlled by PSNH) control access to the corridor into southern Nov England fror j
After the merger, the company will own 31 Maine. 131/
percent of the corridor connecting New England and Hydro-Que occ
}
And compared to 21 percent prior to tha merger.116/
i finally, af ter the merger, the company's ownership share of the Eastern REMVEC " curtain" increases f rom 40 percent to 80 percent.
i The transmission facilities acquired, when added to 112/
NU's control of 72 percent of the those aircady owned (ctg 2, interface between New York and New England) liff will give NU dominant control over the strategic trading corridors af fecting is over these corridors that utilities and other New England.
It Maine, New Brursvick, New York power producers in Eastern REMVEC, The enhanced f
and Quebec are able to trade with each other.
j control of these facilitics increases NU's market power over transmission services.
Although ownership of transmission in New England was highly f
concentrated bef ore the merger, the merger further reduces Be f ore the opportunities for competitive dealing. LE9/
merger, New England utilities seeking transmission and power ccess to supplies could deal with two separate companies for ufor accose to New NU in the south and west generation supplies, York Power Pool generation renources and PSNH in the w north f or access to Quebec, Maine and New Brunswick resources.
l 1
I 112/ 53 FERC at 65,214-19.
NEPOOL has " external interf aces" with three 111/ Ex. 59 2.
and New neighboring systems -- How York, Hydro-Quebec, j
Brunswick.
Ex. 123 at 115, 119-20.
i 131/ Ex. 592.
Aff/ Id_.
1 112/ Id.
r 112/ Ex. 372 at 21-23, 53-61; Ex. 479 at 7-8.
Docket No. EC90-10-000, et al. Af ter the verger, they will f ace one company. ISQ/
The only other possible provider of similar transmission service, NErCo, has little transmission capacity available for sale. 111/
Before the merger, New England power suppliers competed not only among themselves, but also with lower-cost suppliers in New York, Maine and Canada. 122/
After the merger, a dominant share of the transmission network along all major corridors within and into New England will be controlled by a singic company.122/
Trial Staf f and intervenors discount the value of NEPOOL transmission service as an alternative to the merged firm's transmission service.
We agree.
Transmission service is available on pool transmission facilities (PTF) under the NEPOOL Agreement only if a supply source has been designated as a pool planned unit (PpU) or a pool-planned purchase (e2g2, the Hydro-Quebec energy purchase). 111/
Transmission for non-PPU power or short-term purchases from other utilities is not available on PTT f acilities under the NEPooL Agreement. 111/
Transmission l
for these purchases must be obtained individually from the colling utility and intervening systems. lis/
Therefore, the NEPOOL Agreement does not provide a competing source of transmission service that could mitigate the merged company's enhanced control over ttansmission.122/
With respect to bulk power services, we af firm the presiding judge's conclusion that the merger would give the merged company The supply of market power in the short-term bulk power market.
short-term bulk power consists largely of existing generat ing 19Q/ Ex. 2 61 at 21-2 4 ; Ex. 127; Lxs. 138-145; Ex. 123 at 112-52:
l Ex. 479 at 6-7.
lil/ Ex. 261 at 23.
Egg alsq Ex. 262.
NEPCO vitness Digelow calculated, for example, that the merged con.pany would control 1060 MW (87 percent) of the unused transmission while NEPCO capacity on the New York /New England interf ace, vould control 160 MW (13 percent).
Ex. 262.
i 132/ Ex. 479 at 6.
l 192/ Ex. 59 2.
121/ There are ten PPUs currently operating in NEPOOL and one future unit designated as a PPU.
133/ Ex. 277 at 9.
r 12b) Ex. 524 at 7.
i 7
197/ Ex. 277 at B-9.
e f
I Dockot No. EC90-10-000, ci nl. After the merger, capacity surplus to immediate needs.12f/
NU will control more than 65 per c ent of New England's surplus capacity from 1993 through the year 1998. 122/
NU thus ej);
be able to dominate the supply of short-term bulk power because it will have a dominant share of the excess capacity in New We note that the merged company's ability to exercisc England.
market power in short-term bulk power markets is independent of j
its acquired market power in transmission services.
- However, when the merged company's increased transmission control is it will coupled with its available excess generating capacity, have a substantial sbility and incentive to exercise market power throug1 the combination of short-term bulk power supply and transmission services sales. 12A/
Boston Edison witness Jerrilynne Purdy aptly summarized the combined impact of the merged company's centrol of transmission and surplus generation, stating:
NU/PSNH will control most of the excess generation in New England and thus vill have a clear incentive to compel purchases of NU supply.
NU will also have the capability to discourage Boston Edison from pursuing transactions with non-NU sources due to NU's strategic control over the transmission facilities to the north and west of Boston Edison's service area.
The UU/PSFH transmission monopoly will allos NU to impose terms and conditions on third party transmission services that are so severe that captive utilities, like Boston Edison, will be forced to buy generation f rom NU rather than other sources. [201/)
NU's market power in short-term bulk power markets is mainly the result of its dominant position in surplus generation capacity.
This particular source of market power will dissipate in the future as NU's surplus diminishes.
NU's control of key transmission corridors and interfaces, however, is an independent source of market power.
7xo diminu+. ion of NU's surplus will not reduce the market power NU derives from its control of transmission.
Thus, we also affirm the presiding judge's conclusion that MU will continue to possess market power as long as it continues to control key transmission corridors and 121/ Ex. 520 at 6-7; Ex. 1-I at 638.
112/ Exs. 522, S28, 130, 137.
200/ Ex. 261 at 21-24; Ex. 524 at 1.
221/ Ex. 524 at i.
.. _ _ _ _ _ _ = - _ _ _. _.
I i
Docket No. EC90-10-000, g1 AA. I interf aces that allow it to control both short-and long-term t
222/
Since the presiding judge did not power markets.
analyne short-and long-term bulk power separately, we must clarify that the merged company's market power in the long-term bulk power market is a result of its control of the transmission If the merged company did not network in New England.122/
dominate transmission ser/ ices, buyers could reach and rely on new generating resources, which would then provide buyers with l
The alternatives to purchasing from the merged company. 121/
merged company's enhanced control over key transmission corridors i
is the root of the merger's incremental anticompetitive effects.
)
221/
p 2.
MArbet Concentratlan_Esasures The record contains hundreds of numerical calculations of I
market concentration based on the Herfindahl-!!irschman Index and other measures, and numerous disputes about the The presiding l
(HHI) relative merits of the dif ferent calculations.
judge concluded that "[a)n examination of the disputed numerical devices would serve no useful purpose in the circumstances of l
this case." 2.qs/
5 presfH np judge.
As discussed above, We agree with t 3 i
.n the record based on ownership 4
there is abundant evidenJ l
chares that demonstrates the marged company's enhanced marketThis power over transmi ssier. and short-term bulk power services.
along Vith sne f.on-quantitative evidence discussed
- evidance, in this proceeding.
l suf fices for pt.rp.scs of our analysis l
- above, Thus, we need nce resche the many disputes surrounding the I
various concentration ratios.
While ve used HHIs as an initial r
A 222/ 53 FERC at 65,218.
I 2A2/ Ex. 537 at 6; Ex. 416 at 17; Ex. 261 at 7, 13-23; Ex. 441 at 23-23; Ex. 265 at 9.
\\
LO L/ Ex. 55 at 14 5 ; Ex. 200 at 3-6.
t 1QE/ Egg, g292, Ex. 524 at 21; Ex. 55 at 146-47.
65,219.
In fact, We note that the presiding 225/ 53 FERC at judge, while questioning the usefulness of HHIs himself, relied on various pre-and post-merger single-firm
[
concentration measures of key transmission corridors and interfaces to conclude that the merger vill substantially Egg 53 FERC at 65,214-19.
A single-lessen competition.
i firm concentration ratio is just as much a numerical device as an H111 or a four-firm concentration ratio.
iss Scherer i
and Ross, IQdMS1I1Al_14arket Struc1Mrc_.imd.Jconomis at 71 '14.
j Performanes, Houghton Mif flin company (1990),
i r-
Dockot No. EC90-10-000, 21 al. screen in Mckeye Eine Ling, 2R2/ ve have not adopted HHIs as determinative in reviewing a proposed merger's effect on The issue of whether a firm has market competition. 201/
power cannot be determined on the basis on "any one type of For example, even in hgleye Pictiing, ve evidence. " 2.0.2/
followed up our analysis of HHIs with a " weighing and balancing (of) a number of factors." 212/
Moreover, the calculation of an HHI or any market concentraticn measure zust be grounded upon an informed radtistanding of the institutional, regulatory and structura) t e wi,4 2 L's of the markets that are being examined.
i 211/
E.
h N m;,d,d f,jve__Effeg,tn The presiding judet f ound that the merged company could demand excessive charges for transmission, or deny transmission access altogether, while f avoring its own excess generation at l
The presiding judge found that the merged high prices. 112/
company would have the power to f orce its own ' ext ra goods' on i
buyers, which is especially significant since NU will have the largest block of surplus capacity in Nov England. 212/
its control of Hany intervenors argue that NU vould use transmission and bulk power markets to its advantage. 111/
in che bhort run, NU would be able to limit They argue that, access to alternative suppliers, thereby forcing buyers to purchase transmission and power from NU when less expensive The alternatives vould be available absent the merger. 211/
intervenors argue that UU would also be able to use its control 222/ 53 FERC at 62,663.
221/ UtillERID, supra, s3 ip op, at 16 n.32.
101/ Public Service Corpany of Indiana, Inc. (EE1), 51 FERC
$ 61,367 at 62,205, gEder on reh'a, 52 FERC 5 61,260 (1990).
2J.9/ 53 FERC at 62,663.
RJJ/ Ex. 549 at 20-29; Ex. 195 at 12-19.
212/ 53 FERC at 65,215.
212) 14 45-48.
Egg 111/ Trial Staff Brief Opposing Exceptions at 37-41, Ten Eastern REM A_lE2 and Holyoke Brief opposing Exceptions at 17-22; at 10; Eastern REMVIC Utilities Brief opposing Exceptions at 20-22.
Trial' Staff Brief Opposing Exceptions at 40.
211/ E2g2,
--.m
, Docket No. EC90-10-000, si A1 of transmission to exercise monopsony power over sellers, paying 211/
The intervenors assert them less than the market price.
that this could be especially hard on sellers in Maine and Vermont, where many of the sellers are expected to be located.
211/
In the long run, according to the intervenors, utilities in New England may develop less desirable mixes of generation at higher costs because the locations for new plants will be constrained by NU's transmission control. 211/
The intervenors argue that this result would be especially hard on the Eastern REMVEC utilities because the cost of building and operating generating plants in their region is higher than in the surrounding regions of New England, upstate New York and eastern Canada. 212/
The intervenors argue that NU's past practices demonstrate They how NU would use its augmented market power in the future.
For list a number of complaints about NU's past practices.
they note that NU has no transmission tariffs on file with the Commission and always insists on individually-negotiated
- exacple, They argue that NU has a history of delaying contracts. 221/
its filing of negotiated transmission rates until the buyer has 221/
They lost the opportunity and the will to protest.
assert that NU sometimes requires buyers to agree not to protest or to pledge to pay NU's legal costs if there is a protest.
The intervenors also contend that NU has refused to 222/
follow general industry practices in New Eng]and with respect to discounting multi-system transactions and habit ually provides lower quality service at higher prices than other suppliers of They argue that transmission services in Few England. 222/
NU sots minimum term requirenents on transmission purchases 211/ New England Cogeneration Association Brief opposing Exceptions at 17-18.
Principal New England Intervenors Brief opposing 212/ E.4,,
Exceptions at 27-29, 2Jf/ Id. at 38.
2J1/ Egg, c.c., Ex. 416 at 33-34; Ex. 122.
212/ Ex. 601; Ex.-616.
22J/ Eqq Eastern REMVEC Utilities Initial Brief at 43-45.
122/ Ex. 313 at 28.
222/ Id. at 22, 27-37.
i t
Docket No. EC90-10-000, gi A1 raising the costs of exchanges above their economic value.
The intervenors also claim that QFs and IPPs find it 221/
nearly impossibic to develop generators that depend on transmission access from UU because the quality of service NU will agree to provide is too poor and the exposure to the financial risk of paying for future system improvements is too The intervenors further complain that HU's high. 221/
charges are improperly calculated and that NU has used transmission control to engage in simultaneous buy-sell transactions so as to capture the majority share of the gains from trade. 111/
NU argues that the merger as proposed significantly improves the transmission opportunities for other utilities, especially those utilities in Eastern REHVEC. 222/
NU states that this increased access to transmission will improve the ability of other utilities to make long-term purchases from How Brunswich, as well as f rom NUGs throughout New England. 222/
Concerning NU states that the negotiation of transmission service contracts, it has provided service under more than 100 transmission service contracts in the past and, without exception, service was provided when requested without delay due to NU's policy of first providing service and later negotiating the contract (subject to ultimate commission review). 222/
Finally, NU asserts that, because of its past transmission policies and practices:
o NU is the largest provider of transmission services in New England, pre-merger.112/
No utility in New England has ever been denied o
transmission service by NU in order that NU could sell Its own higher-priced power, and very few cases exist where NU has denied a request f or transmission service for any reason. 211/
221/ Ex. 524 at 15-17.
223/ Ex. 313 at 33, 221/ Ex. 269 at 36-37.
222/ NU Initial Brief at 17.
223/ 16 223/ Ex. 157 at 56.
22&/ Ex. 123 at 169.
111/ Ex. 157 at 6.
Docket No. EC90-10-000, it al. NU routinely sells transmission service to others in o
circumstances where the transmission service is for delivery of wholesale power that is competing directly with NU's power sales. 222/
NU provides or has contracted to provide transmission o
service for approximately 500 MW of NUG capacity located on its system for delivery outside its system and has never denied transmission service to a NUG locating on its system. 211/
i We agree with the presiding judge's conclusions.
An unconditioned merger is likely to harm the public interest by resulting in a higher cost and less ef ficient electric supply in After the merger, RU vould have new means New England. 211/
NU's and added incentives to use its market power.121/
control of key transmission corridors and facilities would allow r
it to control bulk power trado.
Its substantial inventory of excess generating capacity would give NU the incentives to block the sale of competing sources of short-term bulk power services.
To the extent that NU's resources are not the lowest cost resources that would otherwise be available, the results would be higher electricity prices for consumers in many parts of New NU would also have the ability to significantly control England.
the development of new generation resources.
For many utilities, the cheapest generation resources may be located in other For example, as NEpCO witness Bigelow regions. 111/
the best "long-term power supply opportunities would r
testified, be located in Maine and New Brunswick." 212/
The merged t
222/ Tr. 5139-40, 5286-921 Ex. 524C.
~111/ Ex. 123 at 168-70.
111/ 53 FERC at 65,219.
223/ M. at 65,215-19.
one witness presented a comparison of the price 22f/ For example, of capacity currently offered by eleven developers of non-utility generation in Eastern REKVEC with a proposed Canadian project.
The prices are based on levelized, life-at 1990 price levels.
The chart shows a cycle costs, levelized price of approximately 7.5 cents per kWh for the Canadian project while nine of-the eleven non-utility projects in Eastern REMVEC show prices of 8 or more cents The non-utility project, have an estimated price per kWh.
Ex. 416 at 33-range of 7.5 to more than 10 cents per kWh.
i 34; Ev. 422.
1 222/ Ex. 261 at 26.
Dockot No. EC90-10-000, et A14
- 44 company would own all of the transmission linking Maine and New Drunswick with the rest of How England.
NU's enhanced transmission control vould allov it to control the transmission for those new generation resources and thus their development.
To the extent NU f rustrates development of relatively lov~ cost, nov generation resources, the result would be less efficient generaticn patterns that vill contribute to higher electricity costs, to the continuing detriment of Nov England consumers.
in both the short-and the long-term, an anconditioned
- Thus, merger is likely to result in substantial harm to the public interest.
NU'r. Increased ability to af f ect olcetricity narkets in this way persuades us that the merger cannot be approved unless p1 verly conditioned.
Having reached this conclusion, we see no need at this point to decide the merit of the intervenors' allegations that NU's past transmission practices provide additional justification for not approving the merger as proposed.
We must make one final clarification.
The presiding judge found that the merger vould allow NU to command excessive charges for transmission. 221/
Under our rate standards, the merged be allowed to charge unjust or unreasonable company would not The Commission's authority to review raten under a just rates.
and reasonabic standard would necessarily cap these rates at a just and reasonable level.
NU may nonetheless be abic to charge regulated rates f or bulk power services that exceed the rates of other suppliers.
Thus, if NU is permitted to foreclose access to alternative suppliers, utilities that are forced to rely on NU may pay higher prices for power than they otherwise would.
IV.
Condition 2 A.
Disposition of the Mercer Since, as explained above, the proposed merger would have anticompetitive effects, the threshold question for the commission is whether there are countervailing public interest such considerations that outweigh those anticompetitive ef fects, that we should approve the merger as proposed, or whether, absent such countervailing considerations, we should reject the merger or, alternatively, approve the merger subject to conditions that mitigate the anticompetitive effects.
We find that, while there are certain countervailing public interest considerations here, those considerations do notAs noted outweigh the anticompetitive effects identified above.
above, we have summarily af firmed the presiding judge's ruling that the merger will help resolve pSNH's bankruptcy and will also provide substantial savings related to Seabrook O&M, 2Jjf 53 FERC et 65,215.
t
+
e g
,m
,,,... ~ ~,., -.. -.. - -
4
.-m,
- - - - ~-- - _- -_
Dockot Ho, EC90-10-000, gi gl. administrative and general costs and certain other expensos.
However, given the magnitude of increased control over key transmission corridors and interfaces after the merger, and the merged company's ability to significantly influence generation prices and the development of generation resources in a major region of the country, these benefits do not outweigh the merger's anticompetitive effects and do not support approval of the merger as proposed.
Holyoke argues that the merger's anticompetitive ef fects are Holyoke so great that the merger should be disapproved. 222/
asserts that the commission has no duty to save this merger, and Holyoke contends that RU has not met its burden should so hold.
of proving "why the normal remedy of forbidding a merger that is against the public interest should not be imposed." 212/
Holyoke argues that prohibiting such a merger is the " normal remedy," because "[p) reservation of separate competitors with conflicting interests is f ar more likely to stimulate competition than the episodic supervision by an outsider of the behavior of a firm with enhanced market power." 21.1/
We agree with Holyoke that the commission has no duty to impose conditions in order to save a merger that is otherwise In this case, however, the merger vill help anticompetitive.
resolve pSNH's bankruptcy and vill also produce substantial cost Moreover, the transmission savings, as identified above.as modified herein, will adequately commitments offered by NU, The merger's mitigate the anticompetitive effects of the merger.
benefits, and the mitigating offect of the conditions adopted herein, make the merger consistent with the public interest and make conditioned approval of the merger, in our expert judgment, preferable to rejection of the merger.
D.
Etatylgry Authority To Ivoose conditions The Commission's authority to impose conditions on a of the FPA. 212/
In proposed merger derives from section 203 Ulab, the Commission stated that:
[T)he Commission has broad authority under section 203(a) to condition approval of a merger that would not, but for such 229/ Holyoke Brief on Exceptions at 8.
SAC ale 2 Holyoke Brief Opposing Exceptions at 22-20 233/ Holyoke Brief on Exceptions at 8.
Fil/ Holyoke Brief Opposing Exceptions at 24, 2A2/ 16 U.S.C.
$ 824b (1988).
}
l Dockot No. EC90-10-000, 2.1 A1 conditions, be consistent with the public We find that this authority interest.
includes the power to order wheeling for so long as such a condition is necessary to avoid the likely anticompetitive ef fects of a proposed merger, and the tendency of that merger to create a monopoly. (2D /)
However, the commission's conditioning power under section 203(a)
The Cocsission may impose conditions only to the is limited.
extent needed to make a proposed merger consistent with the Thun, in litnh, the Commission imposed public interest. conditions that vore "the minimum necessary" to alleviate the proposed merger's likely anticomp h i.ive effects and to make the 2_U/
proposed merger consistent with the public interest.
The commission has additional authority to impose conditions of the FPA. 2.0/
Section 203(b) states under section 203 (b) in portinent part that the Commission may approve a merger "upon such terms and conditions as it finds necessary or appropriete to secure the maintenance of adequate service and the coordination in the public interest of f acilities subject to the jurisdiction of the Commission."
The Commission in ILLgh held that its
" includes the power to impose authority under section 203 (b) those terms and conditions that are aimed at remedying the
" 2_U/
merger 's likely adverse ef fect on co:tpetition."[s)nction 203(b)'s conditioning To quote the presiding judge, power allows the Commission to order wheeling when necessary to ameliorate the merger's likely anti-competitive ef f ects."
2_All NU argues that, before the Commission can impose conditions under section 203(a) in this case, it must first:
(1) find that is not the merger (including NU's voluntary commitments)specify the ways in and (2) consistent with the public interest; that standard. 2_Of NU argues which the merger fails to meet that its voluntary commitments can be modified only to remedy NU also argues specific merger-related competitive problems.
that its proposed commitments will in fact improve the (footnotes omitted).
2_Q/ litAh, 4 5 FERC at 61,282 2_4_4/ M. at 61,289-90.
2_Q/ 16 U.S.C.
5 B24b(b) (1986).
2_Q/ Iltah, 4 5 FERC at 61,283.
212/ 53 FERC at 65,219.
21S/ NU Brief on Exceptions at 79.
4 l
4 4
-~.--
Docket KO. EC90-17 -000 gi A1 availability of tr asismiunion service, and, thus, render the proposed merger pro-competitive instead of anticompetitive, such that no iurther conditioning is justified.
We need not decide whether NU has properly characterized the Commission's conditioning authority since, even if UU is correct, its stated standard is met in this case.
We find that the propocod merger. includina NU's voluntary cotmitments, is not consistent with the public interest.
Even assuming that NU's transmission commitments Vill improve the transmission service of fered by the applicants, this fact alone would not render the The issue is proposed merger pro-competitive, as claimed by NU.
not simply whether the merged company vill of fer improved transmission service.
NU's argument ignores the other focal point of the anticompetitive analysis:
the merged company's increased market power and incentives to use that power.
- Thus, in our view, the issue is whether the transmission service to be offered sufficiently mitigates the anticompetitive effects of the merged company's increased market power and incentives.
UU's commitments do not adequately mitigate the merger's anticompetitive effects.
The specific deficiencies of NU's commitments are identified below, as well as the specific merger-related probicas justifying modification of NU's commitments.
These specific deficiencies render the proposed merger, even after consideration of NU's commitments, inconsistent with the public interest.
NU also argues that the language of section 203(b) "does not imply any authority to order utilities to wheel power involuntarily. " 212/
NU alternately argues that section 203(b) does not apply in this case because the merging parties operate in a power pool (NEPOOL) that automatically coordinates the operation of the parties' facilities, such that the only transmission issues involve economics, rather than reliability.
NU cites lltah 212/ for the proposition that In support, section 203(b) does not justify imposition of wheeling conditions where the merging parties operate in a power pool. 231/
NU's argument that the Commission cannot require merger applicants to provide transmission service under section 203(b)
Section 20'a (b) states ignores the plain language of the statute.
unambiguously that, in approving a merger, the commission may impose "such terms and conditions as it finds necessary or appropriate to secure the maintenance of adequate service and the coordination in the public interest of f acilities subject to the 232/ Id. at 77.
25_0/ 4 5 FERC at 61,283.
0 Ell / NU Brief on Exceptions at 78.
f
,n
DocV.sc No. EC9 0-10-000, g3 al.
- 48 As long as the Commission jurisdiction of the Commission."and those findings are supported by makes the requisite findings, substantial evidence in the record, the Commission may impose any necessary or appropriate terms and conditions including conditions which obligate the merged company to provide transwission service to competitors on a non-discriminatory If NU does not wish to accept those conditions, basis. 212/
it has the option of foregoing the merger.
the acre existence of a power pool does not render
- Also, section 203(b) inapplicable.
In Utah, the Commission noted that coordination has been achieved through formal power pools -
"provided that menbership is widely available and transmission services readily provided to ef fectuate pool transactions."
The Commission stated that the lack of a region-wide ZEl/
in that case allowed the merged company's strategic power poolover transmission to interfere with the coordination of dominancu jurisdictional facilities by h.ndicapping the operation of a Ting bulk power market. 253/
Thus, the 4
well-funct applicabi y of section 203(b) does not depend on the mere
. a power pool but instead on the effect of the power existence pool in a uring the maintenance of adequate service and the coordina..on of jurisdictional facilities.
When, despite the existence of a power pool, 215/ a proposed merger may af fect the maintenance of adequate service and the coordination of jurisdictional facilities, the Commission may impose "necessary That is so or appropriate" conditions under section 203(b).
for the same reasons stated by the Commission in Qiah:
- here, (W)e ara conditioning our approval of this intEI merger on the Applicants' agreement, a]Ja, that they wheel power for competitors under certain terms and cor.ditions in order to remedy the merger's likely adverse effect (I]f we were to on competition.
approve the merger without such conditions, utilities that compete with the merged 45 FERC at 61,282 (relying in part on section 212/ See Utah, 203(b) to impose transmission conditions where the merged company's control of " strategically located transmission facilities," could be used to " affect the coordination of jurisdictional facilities.")
212/ M. at 61,282.
254/ 45 FERC at 61,283.
211/ Moreover, as discussed above, NEPOOL does not ensure that all sellers in New England will be able to obtain transmission for their products.
l Dockat No. EC9 0 0 0 0, 21 nl. I t
company coald be denicd access to the merged company's strategically located transmission facilities.
This, in turn, could affect the coordination of jurisdictional f acilitias.
[216/)
is applicable here lo the extent nee'ed to avoid Section 203(b) this result.
General Transmission Commitments C.
Under NU's General Transmission Commitment (GTC), NU has voluntarily committed to providing wholesale transmission service NU has for any utility over its existing transmission system.
also committed to building new transmission facilities and interconnections where insufficient transmission capacity exists or where additional f acilities are necessary to alininate a While we transmission constraint on the merged company's system.
support and endorse the general spirit and thrust of the GTC, we in certain respects, vague and lacks the believe that the GTC is, specific detail with which we could find that tha co.smitments fully mitigate the merger's likely anticompetitive effects.
NU has qualified its commitments with b number of Furthermore, conditions which we believe will allow the merged significant entity to exercise considerable market power over transmission.
we will condition our approval of the merger upon Accordingly, NU's acceptance of certain modifications to its GTC.
1.
Existino Transmission Capacity NU has coraitted to provide wheeling service for others over subject to four its transmission system in all circumstances,NU has reserved the right not to provide specific reservations.
wheeling service if NU requires the transmission capacity:
to deliver the output of its generating (1) f acilities to its native load customers; (2) to meet its then-existing contractual commitments to others; (3) for ten years following t... consummation of the merger, to sell to others in NEPOOL the output of existing surplus generation on NU 's system; 25]f and 250/ 45 FERC at 61,282.
NU subsequently revised this priority to As discussed below, 257/ apply to all NEPOOL existing and committed generation.
I
4.
Dockst No.lEc90-lo-000, 31 Al.
- 49 company could be denied access to the. merged
-company's-strategically located transmission facilities.
This, in turn, could affect the coordination of jurisdictional facilities.
[216/)
Secticn 203(b) is applicable here to the extent needed to avoid this result.
C.
General Transmission Commitments Under NU's General Transmission Commitment (GTC), NU has voluntarily committed to providing wholesale transmission service NU has for any utility over its existing transmission system.
also committed to building new transmission facilities and interconnections where-insufficient transmission capacity exists or where additional facilities are.necessary to eliminate a transmission constraint on the merged company's system, While we support and 1 endorse the _ general spirit and' thrust of the GTC, we believe that the GTC is, in certain respects, vague and lacks the specific detail with which we could find that the commitments fully mitigate'the merger's1likely ant' competitive effects.
NU has qualified ~its commitments with a number of Furthermore, significant conditions which we believe will allow the merged entity to exercise considerable market power over transmission.
)
Accordingly, we will. condition our apprcval of the merger upon NU's acceptance of certain modifications to'its GTC.
1.
Existina Transmission - Canagity NU has committed to provide wheeling service for others over its transmission system in all circumstances, subject to four specific; reservations.
NU has reserved the right not to provide wheeling service if NU. requires the transmission capacity:
(1) to deliver the output of its generating -
. facilities to its native load custome' ;
(2) to meet its then-existing cor iac.i.
-commitments-to others; (3) for ten years following the-consummation of the merger, to sell to others in NEPOOL the output of existing surplus generation en NU's system; 2.n/ and 2ffq/ 45'FERC at 61,282.
212/ As discussed below, NU subsequently revised this priority _to apply to alllNEPOOL existing and committed generation.
_.m.__m
.-ms..-a
_--- ~.-
. Docket No. EC90-lO-000,-gi gl.
(4) to purchase power from others for use by its native load customers. 216/
Each of these reservations involves the priority of use that should be accorded native load customers in the face of a constraint that may develop on the merged company's existing The first reservation integrated transmission system. 212/
- was not challenged by the intervenors and does not appear to be We do not believe that a utility exercises market controversial.
power over transmission when it reserves the right to use its transmission system to ensure reliable service to its native load However, additional discussion is warranted on the customers.
other three reservations.
a.
Priority for Settlements NU's General Transmission Commitments require NU to provide wheeling service on its existing transmission f acilities unless those facilities are needed for several specified purposes, including allowing NU to meet its "then-existing contractual commitments to others.
" 210/
To the extent this provision prevents NU from reallocating the use of existing transmission capacity f rom "then-existing contractual subsequent arrangements, and from commitments" to-other, subjecting such " commitments" to incremental cost pricing because of a - subsequent transmission constraint, we find this provision-acceptable in this proceeding.
The Principal New England Intervenors argue that the priority for then-existing contracts should not apply to ctttlements reached as part of this proceeding and that those settlements should not have priority over other transmission requests made "during the pendency of these proceedings."
These intervenors argue that allowing a priority for 211/
NU's settlements could delay or prevent the implementation of a since the utilities receiving regional-transmission arrangement, a settlement-priority would be reluctant to accept a lower The intervenors also-priority under a-regional arrangement.
t 213/ Ex. 178 at 1.
219/ The Commission defines " native load customers" as those franchise or customers on whose behalf NU, by statute, has undertaken the obligation to plan, construct,
- contract, and operate its system to provide reliable service.
21Q/ Id_.
d 211/ Principal New England Intervenors Brief on Exceptions at 73-74.
See Ex. 449 at 83-84: Ex. 477 at 19-21.
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Docket No. EC90-10-000, g1 al. a settlement priority would extend preferences for argue that wheeling service "to a f avored few." 212/
NU argues in reply that giving the settlements reached in this case a lower priority than other settlements is unjustified and inconsistent with the Commission's policy favoring settlements. 151/
NU argues that its settlements with HEPCO and United Illuminating, for exampic, improve the competitiveness of the bulk power markets in New England.
We vill reject the proposal of the Principal New England Inte rvenors.
The two most important settlements in this case are The NEPCO NU's settlements with NEPCO and United Illuminating.
forms the basis for the NH Corridor Proposal, which settlement (as modified herein) we find mitigates to some extent the L
The United merger's potential anticompetitive ef fects.
Illuminating settlement has already been accept ed for filing by the Commission and found not to result in undde discrimination.
211/
The proposal of the Principal New England Intervenors would essentially nullify the key consideration gained by NEPCO settlements.
The Principal and United Illuminating under these New England Intervenors have of fered no compelling argument Thus, we will justifying the negation of these settlements.
reject their exception, b.
Ten-Year Priority for Transmission of Surplus Generation Sales The GTC was originally conditioned provide the transmission of NU's existing surplus generation a ten-year priority over the wheeling of any other generation source.NU amenced the GTC to expand During the course of the proceeding, the surplus generation priority to apply to the wheeling of all_
of NEPOOL's existing or committed generation capacity 211/
rather than only NU's surplus capacity sales.
252/ Principal New England Intervenors Brief on Exceptions at 73.
Attachment at 1.
213/ NU Brief Opposing Exceptions, 52 FERC $ 61,143, reh'a 2ff/ Northeast Utilities Service Company, denied, 53 FERC 1 61,135 (1990).
255/ NU defined such capacity as that specified in the April 1,
Loads and 1990 NEPOOL Forecast Report of Capacity, Energy, Transmission (" CELT Report").
Ege Ex. 159 at Section II NEPOOL Generating Capacity (pages 9-27), Appendix B -
Existing Non-Utility Generators (pages 56-65), Appendix C -
Committed Non-Utility Generators (pages 66-69),Section III (page 29) status codes "U" and "V", and The Hydro-Quebec Project Phases I and II.
,.I
l Docket No. EC90-10-000, 21 A1 The presiding judge rejected NU's proposed ten-year priority for the transmission of surplus generation. ZEL/
The presiding judge found that the merged company's share of the total surplus generation capacity in New England would exceed 65 percent in every year from 1993 through 2000 and would reach as in some of those years. 212/
Therefore, high as 91 percent the presiding judge determined that NU would have " control over the single largest source of surplus capacity in New
[as well as) control over key transmission England f acilities necessary to provide access to alternative sources
" 255/
The presiding judge concluded that NU's dominance over the surplus capacity in the region aggravates the anticompetitive impact of the merger, and could act to displace other sources of power.
Finally, the judge agreed with various intervenors that a surplus capacity priority would not be if NU would simply price its surplus capacity necessary competitively. 2ff/
Both NU and the Connecticut Commission argue on exceptions that the presiding judge's decision f ailed to recognize NU's modification of the ten-year priority to apply to the transmission of all NEPooL existing or committed generating capacity, not just NU's surplus capacity. 229/
NU argues that the presiding judge incorrectly found that the surplus generation priority would displace other power NU explains that the surplus generation priority is supplies.
intended to deny transmission service to a competing seller not in favor of NU's own off-system sLle. 213/
For example, NU claims that if it were competing for a 100 MW generation sale with a non-priority power supplier when only 100 MW ofand the transmission capacity were available on NU's system, that competing supplier obtained the power supply contract, 266/ 53 FERC at 65,225.
212/ During the period of the greatest surplus capacity in New England, from 1992 through 1996, the merged company's share would be 51 percent, 66 percent, 83 percent, 91 percent, and 91 percent, respectively.
Ex. 503, Table 3.
2ff/ 53 FERC at 65,225, citina Ex. 261 at 21.
212/ Ex. 449 at 79.
221/ NU Brief on Exceptions at 86; Connecticut Commission Brief on Exceptions at 9-10.
221/ NU Brief on Exceptions at 87; Ex. 157 at 12-19; Tr. 2662-66.
9 Dock 3t Ho, EC90-10-000, 21 al. l supplier would obtain use of the available transmission capacity. 222/
In contrast, NU claims the priority would operate when both a priority generation source and a non-priority generation source were being wheeled concurrently.
If a transmission constraint then developed, NU states that the non-priority generation source would have a lower economic priority and would be liable for the payment of NEPEX dispatch penalties (i.e., costs associated with NEPEX operating out of economic dispatch), 211/
In defending the need for the ten-year priority, NU states that although its existing transmission system is adequate to deliver the output of its existing generation, problems may be:
created as a result of new generation being installed to serve load somewhere in New England without there being adequate transmission installed to enable that (power) to be delivered along with all existing generation; and that if restrictions develop, that the economic consequences of those restrictions ought to fall upon those who have f ailed to bring to the table suf ficient transmission reinforcements to adequately integrate that new generation into the New England system. [223/)
" considers the transmission priority for existing and NU committed generation to be an integral part of the native load priority and would not relinquish it in the absence of the NU asserts that its voluntary relinquishment merger." 275/
of its original NU-only surplus capacity priority for the first ten years and elimination of the priority entirely thereaf ter constitute significant merger-related concessions. 221/
The Connecticut Commission states that the surplus generating capacity on NU's system was created to meet New England's native load and that denying the surplus generation priority would thus penalize Connecticut ratepayers unfairly.
The connecticut commission also argues that competition 221/
212/ Tr. 2662-66.
111/ NU Brief c? Exceptions at 87 ; Tr. 2665-66.
213/ Tr. 2529-30.
See also Ex. 123 at 175.
223/ NU Brief On Exceptions at 88.
Ils/ Id.
111/ connecticut commission Brief on Exceptions at 13-14.
Dockot No. EC90-10-000, 21 al.
- 54 cannot be harmed because the surplus generation priority does not raise the price of the product above competitive levels and the price of such generation capacity is regulated by the Commission ZZE/
The connecticut commission alleges that elimination of the surplus generation priority would be economically inefficient and would undermine state authority 112/
Trial Staff and various intervenors maintain that the presiding judge properly recognized that NU's modification of the surplus generation priority was a meaningless concession on NU's as NU would still dominate the region's surplus generating
- part, They also note that, since the New England' capacity. 212/
area is expected to have a capacity shortfall by the mid-1990's, the surplus generation priority would almost exclusively benefit NU. 2Hl/
Trial Staff further argues that the surplus generation priority may actually be detrimental to the New England region after 1995 212/
Trial Staff asserts that, if access to the surplus generation priority is approved, transmission service would be more restrictive than under NU's present transmission contracts. 132/
The New England Cogeneration Association disagrees with NU's favor assertion that the surplus generation priority would not its own capacity sales.
The New England Cogeneration Association asserts that a competing supplier's power (not from existing or committed NEPOOL generation) being wheeled on NU's system has a lower economic priority and thus is more likely to be assessed the costs of a NEPEX dispatch penalty.
Accordingly, while NU the alternative might not directly favor its own power sale, supplier's greater chance of incurring NEPEX dispatch penalties 223/ Id. at 19.
129/ Id. at 33
-40.
Eastern REMVEC Utilities Brief Opposing Exceptions at 23 0/ E. q,,
36-37; Ten Eastern REMVEC Utilities Brief Opposing Exceptions at 66-67: Principal New England Intervenors Brief Opposing Exceptions at 59.
Principle New England Intervenors Brief Opposing 2H1/
E.g.,
Exceptions at 58.
232/ Trial Staf f Brief Opposing Exceptions at 56.
113/ Id. at S7.
l Docket No. EC90-10-000, et al. will create a competitive advantage for the NU power sale.
11.4/
The Ten Eastern REMVEC Utilities allege that the surplus generation priority will allow NU to inhibit the development of bulk power supplies by discriminating against new generation, and will discourage NU f rom retiring obsolete generating plants, will ensure that NU does not have to price its surplus generation capacity competitively.111/
They also claim that the surplus generation priority will allow NU to prefer its ovn, less-ef ficient generation over that of competitors.1E1/
We af firm the presiding judge's rejection of the ten-year surplus generation priority.
We find that NU's modification of the surplus generation priority to include all of New England's existing or committed generating capacity is a meaningless concession since, as the presiding judge correctly noted, NU will be the only significant source of surplus generation for the next decade. 282/
We also adopt the presiding judge's finding that the ten-year priority would tend to aggravate the anticompetitive impact The ten-year priority would increase NU's ability of the merger.
to exercise market power in short-term bulk power markets.
By eliminating this ten-year priority, other supplies, including from outside of NEPOOL, should be better able to compete those against NU in such markets, thereby mitigating NU's market power.
the NU describes this priority as allowing it to collectasserts costs associated with a transmission constraint that NU is caused by the wheeling of non-NEPOOL or new generation within He believe that the ten-year priority would allow NU to NEPOOL.
auto =atically deem that a thirc-party wheeling request has
" caused" a transmission constraint and to assess the costs associated with that constraint (e,q., the costs of a NEPEX against the party requesting wheeling.
dispatch penalty)
Therefore, the priority gives NU discretion to indirect 1_y f avor its own power sales through the imposition of constraint-related costs on others.
214/ New England Cogeneration Association Brief Opposing See also Eastern REMVEC Utilities Brief Exceptions at 83.
Ten Eastern REMVEC Utilities opposing Exceptions at 38-39; Brief Opposing Exceptions at 77.
285/ Id. at 71-72.
2Ef/ Ten Eastern REMVEC Utilities Brief opposing Exceptions at 81, citina Utah at 45 FERC at 61,288.
187/ 53 FERC at 65,225.
l Docket No. EC90-10-000, gg gl. Further, NU has neither identified the types of costs or the amount.of costs that it will seek to collect through implementation of this priority, nor specified any facts which would allow us to decide what-party or. parties may be responsible for the incurrence cf-such costs.
Accordingly, as discussed-below, we believe that tbc proper forum to decide who should bear the cost responsibility associated with an existing transmission constraint (or the costs of upgrading a facility to eliminate the constraint) is inLa separate section 205 case based on the particular facts related to that constraint, our finding here is without prejudice to NU proposing a rate mechanism which seeks to re ver costs associated with a particular constraint.
As in any
-lon 205 proceeding, NU will bear the burden of proof to se s as well as the appropriate allocation, support both the amount, of any costs it seeks to recover through a-wholesale transmission rate.
Power Purchases on Behalf of Native Load c.
customers The New York tic lines are NU's main transmission interconnections with New York.
NU states that these lines primarily provide back-up capacity for NU's large nuclear generating units, reducing its need f or generation reserves.
213/
This use of the New York tie lines permits NU to provide substantial amounts (currently 800 MW) of non-firm transmission service over the lines. 212/
NU claims that its interties are made available to NEPOOL at no charge and reduce NEPOOL's total generating capacity requirement.
According to NU, this ability to access reserves from outside NEPOOL saves the pool about -$70 million-por year in addition to millions of dollars of NEPOOL savingsf through economy energy transactions.
219/
Through-the GTC, NU would make available only as much ~ firm transmission capacity as -it determines it -does not need to import economy energy for its native load.
Because NU imports most of its economy energy through.the - New York -tie lines,- NU considers the treatment of these lines critical.
According to NU, "[t]he heart of the-native load priority issue for NU is the ability to use the-capacity over its New York ties to import energy to reduce power production costs. " 221/
ZEE / Ex. 157 at 63,185-86.
282/ Ex. 123 at 172.
22pf Ex. 157 at 63-65.
22J/ NU Brief On Exceptions at 83.
I i
~
l Dockot No. EC90-10-000, gi gl. Trial Staf f and certain intervenors expressed concern that, under the GTC, NU's non-firm service could " bump" others' firm transmission service. 222/
In NU's case-in-chief 111/
and during cross-examination, 233/ NU claimed that once it committed to providing firm transmission service, such firm wheeling would maintain a higher priority than NU's economy evers if the lines became constrained.
NU energy purchases, stated, however, that it would preserve the rights of its native load customers by reserving the transmission capacity it needed to import economy energy and of fering only the remaining capacity for firm transmission service for others.
During the hearing, NU's counsel explained that the transmission capacity needed to import economy energy would be determined based on NU's
" historical use of its New York tie-lines." 111/
The presiding judge found that "[t]here is no legal requirement that a utility equalize its native load customers with all others," and further noted that "[t]he reasonableness of a native load preference is also reflected in the Federal power Act. " 22f/
In addressing the possibility that non-firm transmission service might " bump" firm transmission service, the presiding judge found that firm service would always receive However, the presiding judge rejected NU 's priority. 222/
proposal to allocate capacity for firm service based upon its historical use of the New York tie lines to engage in non-firu purchases on behalf of its native load customers. 211/
The presiding judge found that NU f ailed to adequately explain or to prove the reasonableness of its proposed reservation.
The Connecticut Commission alleges that the presiding judge inconsistently accepted a priority for economy purchases for native load over firm wheeling, yet objected to this same lil/ Trial Staf f Reply Brief at 42 ; Trial Staf f Brief Opposing Exceptions at 53.
222/ Ex. 123 at 176.
111/ Tr. 8181-82, 112/ Tr. 8182.
22f/ 53 FERC at 65,222.
112/ Id. at 65,224.
The presiding judge qNoted NU's counsel as non-firm stating during oral argument that "later economy, purchases or sales do not take priority over (firm service]
This would be so even if the economy purchase was for NU native load customers."
Tr. 8181.
233f 53 FERC at 65,225.
1 l
Dockot No. EC90-10-000, gi al. l NU clains that principle as applied to the New York tie lines.
l af firming the presiding judge on this issue would " create a gaping exception to the native load priority that effectively I
eviscerates it. " n.2/
NU asserts it is not attempting to exclude the New York tic and instead seeks only to preserve lines' capacity from its GTC, NU its native load priority with respect to the tie lines.
claims that the historical use of the New York tio lines vould not be determinative in assessing the remaining capacity Rather, the Actual available for firm transmission."on the basis of objective determination would be made and projected future use of the ties assessments of NU's current to import energy to serve native load customers." 300/
Trial Staf f maintains that NU has f ailed to support any Trial Staff also special treatment for its New York tie lines.
claims that denying firm transmission service on the basis of 301/
potential economic costs shculd not be permitted.
The Eastern REMVEC Utilities contend that NU is attempting indirectly to accord priority to economy purchases made on behalf of its native load customers by withholding firm transmisri.on NU's According to the Eastern REMVEC Utilities, concession that firm transmission will have a higher priority capacity.
than economy energy is meaningless if NU can subjectively decide the amount of firm wheeling service it will make available.
2.01 /
New England Intervenors assert that NU's GT" The Principal firm would be eviscerated if NU vere allowed to withhold transmission capacity for economy transactions, especiallyin prior They also assert that, through the New York tic lines.
proceedings before the Commission, NU has maintained that several of the New York tie lines were primarily built to benefit the not just NU's native load.
entire New England region, Accordingly, they argue that NU should not be permitted to contradict its previous representations. 202/
The Principal in light of NU's increased New England Intervenors argue that,the public interest would be best post-merger market power, D_S/ NU Brief on Exceptions at 85.
200/ Id. at 82.
53-54.
202/ Trial Staf f Brief Opposing Exceptions at 192/ Eastern REMVEC Utilities Brief Opposing Exceptions at 30-31.
303/ Principal New England Intervenors Brief Opposing Exceptions at 54.
Dockot No. EC90-10-000, gi gl. served if the use of these critical transmission interties were not reserved strictly for the benefit of NU's native load customers. 293/
We recognize the historical importance of the New York tic lines for providing reliable and economic service to NU's native as well as to other members of NEPOOL.
NU load customers, witness Schultheis characterized the considerations underlying NU's decision to construct the New York tie lines as follows:
The primary motivation for building these lines was that they enabled NU and other systems to construct a new generation of larger, lower-cost generating facilities that ultimately benefitted all of New England, without compromising reliability or requiring very large operating and installed reserves.
The lines also provided NU with the ability to engage in significant inter-regional bulk benefit power transactions fer its customers' at a time when such transactions were relatively uncommon. (125/]
g the rates paid by NU's native load customers have Purthermore, undisputedly supported the investment costs associated with these lines for years.
Accordingly, we recognize the right of NU and its native-load customers to use the New York ties to obtain what NU terms Furthermore, we do
" legitimate economies of operation." 231/
not believe that NU or its native load customers should have to relinquish this right in order to satisfy requests by third parties desiring firm transmission service over existing transmission facilities at embedded cost rates (ite2, service that does not require the construction of new f acilities).
At the same time, however, we do not believe that third-party in all instances, be subordinated to wheeling requests should, any non-firm purchase NU may wish to make over its New York ties.
The accommodation of the interests of native load customers and third-party wheeling is complex and involves issues of including the priority of initial pricing and priority, allocations of constrained transmission capacity among competing as well as the priority in " bumping" one category of use In for another when constraints develop af ter service has begun.
- uses, 203/ Id. at 57-58.
2.0 5/ Ex. 157 at 184-85.
0 306/ NU Brief On Exceptions at 85.
..~
Docket No. EC90-10-000, it al. resolving these issues, we have sought to equitably balance the interests of-native load customers and the interests of third parties-in securing firm wheeling. across NU's existing transmission system.
Generally, when system constraints occur, firm transmission service should be accorded priority over non-firm cervice, even If if the latter would otherwise benefit native load customers.
firm service is subordinated to non-firm service, firm capacity in nature.
rights have uncertain value and are not truly "fira" As noted above, NU proposed, and the presiding judge accepted, a transmission priority under which existing third-party, firm transmission users would not be bumped by non-firm including NU's own non-firm transactions.
We specifically
- use, affirm this aspect of the initial decision.
However, NU proposed to satisfy. future requests for firm. transmission service only af ter reserving suf ficient transmission capacity on its How York tie lines to import economy energy on behalf of its native load customers.
The judge correctly rejected the set-aside on the grounds that it was imprecise and that NU had not shown it to be reasonable.
In this case, NU witness Schultheis testified that NU built its New York tie lines primarily for reliability purposes.
Accordingly, we believe that it is reasonable.to allow 292/
NU to reserve firm transmission capacity to provide reliable service to its native load customers and to use this capacity for-However, we are unwilling to permit NU to non-firm transactions.
deny _ a request for firm wheeling service based upon a reservation of additional transmission capacity solely for purposes.of engaging in economy trades.
In our opinion, such a reservation would be anticompetitive and would not be associated with
" legitimate economies of operation."
Furthermore, such a set-aside of transmission capacity would permit NU to exercise its significant post-merger market power by refusing to provide wheeling service on existing transmission capacity and requiring l
third' parties:to pay for transmission expansion that may not be E
needed for reliable operation or that may be premature.
Furthermore, the question of whether or not NU should be l'
permitted to set aside a portion of its existing New York tie line capacity'to engage in economy purchases on behalf of its native' load customers.is simply one aspect of the native load priority issue. 1Df equal importance is the question of what pay to obtain firm wheeling service --
price third parties must especially when a wheeling request would require NU to construct 102/ Ex. 157 at 184-85, 188-89.
q
~
/
i l
l Docket No. EC90-10-000, gi gl. We believe that if additional transmission facilities. 221/
firm transmission service is appropriately priced, many of NU's We will native load priority concerns will be alleviated.
address pricing matters below.
Accordingly, given (1) the imprecision of NU's proposed historical set-aside, (2) the possible anticompetitive effects of such a set-aside, and (3) the close relation between this issue and our subsequent discussion of cost responsibility and pricing for transmission upgrades (which we believe will alleviate many of NU's concerns regarding native load priority), we af firm the presiding judge and deny NU's proposal to give higher priority to
-its own non-firm use than to third-party requests for firm wheeling in allocating existing transmission capacity. 222/
however, will NU be required to provide firm third-In no event, party wheeling service out of existing transmission f acilities if reliability of service to native load customers would be adversely affected.
2.
New TI3ansmission capacij;y General Conditionq a.
Under the GTC, NU has also committed to construct new transmission facilities, as necessary, to:
(1) permit new (2) generating facilities to interconnect with its system; provide wheeling service where insufficient transmission capacity exit;ts ; (3) remove transmission constraints; and (4) meet We will construe NU's regional transmission needs under NEPOOL.
We interpret the GTC, as voluntary commitment very strictly.as obligating NU to plan and construct modified by this opinion, its system to ensure the continued reliability of service to NU's existing transmission customers as well as to acet amodate any Furthermore, we bona liste request for firm whcoling service.
will require NU to amend the GTC to allow five years as the maximum period of time within which NU must construct newfor firm wheeling, transmission facilities to satisfy any request As the Commission stated in Qiah:
1 308/ Any rate for firm wheeling service out of existing transmission capacity would reflect a contribution to NU's embedded cost of transmission which, in turn, would reduce the costs borne by NU's native load customers.
202/ While the parties f ocused primarily on NU's economyour holding applies purchases over its New York tie lines,and to all constrained as well to non-firm sales by NU, transmission lines controlled by the merged company, not just the New York tie lines.
~-..
. ~.
- -c.
. Docket No. EC90-10-000, t.t al.,
We believe that five = years is a reasonable -
maximum period of time.for the merged company to'obtain. sufficient additional. transmission-capacity (by-improving and upgrading the:
existing transmission system and/or constructing; pew capacity) to. satisfy all bona-fide requests by other utilities for long-term firm wheeling, as well as its own needs.-(212/)
Numerous witnesses on this record, including NU's own witness.Schultheis, testified' that five years is a reasonable period of time L for NU to plan and build new _ transmission facilities.-lil/
As in-Iltah, we will require NU to use due diligence to provide-firm transmission service sooner than five years. whenever-possible.
JU has undertaken the obligation to ' build new transmission faciiities subject to the following three conditions:
(1). The affected wheeling customers must commit-in advance-to contribute to the costs associated with such construction (including costs associated with use of scarce rights-of-way) and will provide NU reasonable financial assurance _that money willlbe available to pay such costs; e
. ( 2 )-
NU is able feasibly to: construct these additional facilities, consistent with~1ocal andfregional reliability and-siting-considerations, and vith the-orderly and efficient expansion of the exicting transmission grid; and-(3)
NU,E af ter using sreasonable best ef forts,
'is able to obtain all regulatory approvals required yfor' such construction to take place on terms' that do. not. impair the f easibility _
+
of theoproject.111/
!-p WeLfindLthe first' condition reasonable, namely,-requiring-that a wheeling customer provide reasonable' financial. assurance before-NU undertakes' substantial _ investments in new transmission' L
Furthermore, it is substantially E
. facilities for.that-customer.-
11.0_/ _ 4 5 FERC - a t 61, 2 9 4.
at 22-23.
I-JJJ/ Ex. 157 at 62.
gas also Ex. 601 at 34 and Ex. 444
~
212/ Ex. 170 at 8-9.
-t
Docket No. EC90-10-000, 21 AA. ' identical to the obligatien which the Commission imposed in pint on parties requesting firm wheeling service. 2.11/
The second and third conditions deal with the economic, engineering, and regulatory feasibility of building new transmission facilities to eliminate constraints on NU's transmission system.
At issue is whether or not NU may legitimately avoid its obligation to build new transmission facilities because of what it terms " immutable constraints."
We vill address this issue more-fully below.
b.
Innutahle Constraints The presiding judge found NU's native load preference arises cannot be reasonable where a transmission constraint that removed, due to citing, environmental or other regulatory impasse. 111/
The presiding judge found that the proposal to immutable climinate NU's native load priority when faced with for all customers constraints and to provide equivalent treatment Ihe presiding judge was " fraught with difficulties." 315/
reasoned that a utility's holding of a lawful monopoly was linked The judge also to its obligation to serve native load customers.
found that NU's existing transmission facilities were planned, and paid for by its native load customers for their long-
- built, unlike a potential transmission customer who has not term use, yet contributed to the costs of such facilities. 111/
The presiding judge also noted that all utilities in New England favor their own native load and even the Merger Tariff accepts the native load priority in the case of immutable Furthe rmore, the presiding judge found that the constraints.
antitrust laws ' " essential facilities" doctrine did not justify elimination of the native loau priority.
The presiding judge found that, " Utah expressly recognized that the merged company could reserve from its wheeling obligations so much of its capacity as would be necessary to serve native load." lil/
Finally, the presiding judge found "significant legislative 61,294.
In that case, the Commission required a lll/ 45 FERC at party requesting firm transmission service to prof fer
" sufficient security such that the merged company would not financial risk due to non-performance by the l
be at l
requesting party. "
S3,g Algn Efl, 51 FERC at 62,203.
l JJ3/ 53 FERC at 65,222.
l 335] Ig. at 65,221.
1 i
liff Id. at 65,222.
l 112/ Id*
1
l 64 Docket No. EC90-10-000, 31 al.
support" for the native ' cad priority in section 212(a) of the FPA. }lE/
Tne Ten Eastern REMVEC Utilities contend that if the native load priority is allowed, NU will deny transmission access under the guise of " immutable constraints," thus preventing buyers f rom importing competing power supplies and increasing demand for NU's The Ten Eastern REMVEC own surplus generation. 213/
Utilities seek to refine the presiding judge's decision by allcwing NU to prefer native load when f aced with immutable gperating constraints, but otherw3se imposing an absolute obligation to wheel for others, including an ongoing obligation to plan and construct facilities for such wheeling customers.
22d!)
NU asserts that elininating the native load priority would undermine the authority of a state commission to deny transmission siting approval and to ensure that existing transmission capacity is used to reduce the costs to native load customers. 221/
NU also argues that clininating the native load priority may create a disincentive for one state (ennnecticut) to allow transmission siting for a f acility which will uc paid for predominantly by that state's retail ratepayers, while benefitting primarily the residents in another state (Massachusetts). 322/
NU further asserts that New Hampshire and Connecticut have stated that elimination of the native load priority may jeopardize the approval of the merger by these states. 323/
211/ Section 212(a), 16 U.S.C. 5 824k(a) (1983), states in pertinent part:
No order may be issued by the Conmission under section 210 or subsection (a) or (b) of section 211 unless the Commission determines that such order.
will not impair the ability of any electric utility affected by the order to render adequate service to its customers 54-57.
319/ Ten Eastern REMVEC Utilities Brief on Exceptions at 229/ Id. at 60-61, 221/ NU Brief Opposing Exceptions at 45-46.
322/ Id. at 50.
2))f Id. at 47, citing Tr. 2825, 2904, 4359-60.
l
l I
Docket No. Ecco-10-000, et al. The presiding judge found that "NU's choice, to prefer native load when constraints are immutable, is fair, and it strikes a reasonable balance between conflicting interests."
As noted by the presiding judge, even the proposed 223/
Merger Tariff would allow a priority for native load in the face of immutable constraints. 221/
However, if NU's transmission system is constrained such that UU is unable to satisfy a request for firm wheeling service out of existing capacity, NU has committed to build new transmission facilities to alleviate that constraint.
As we stated above, we will construe NU's voluntary commitment very strictly.
If NU fails to satisfy a request for firm transmission service, the party denied wheeling may file a complaint with the Commission.
A complainant must show that:
(1) it made a request for firm transmission service that has not been uct with due diligence, or, in any event, is not expected to be met for five years: (2) it was willing to pay the full cost of the service; and (3) it has provided NU with reasonable financial assurance that money will be available to pay the costs of construction. JJJJ NU will have 30 days to answer the compl aint.
If the basis for NU's answer is that the constraint is immutable, the Commission will convene a technical conference at which the complainant, NU, all affected state commissions and affected customers may make their views knovn, and present evidence, as to:
(1) whether an immutable constraint prevents the construction of new transmission facilities needed to provide the requested service; and (2) if so, the most efficient and equitable allocation of existing transmission capacity on the NU system.
If all affected state commissions agree that there is an immutable constraint, the Commission will accord substantial And, similarly, if all affected state weight to their agreement.
commissions agree on the most efficient and equitable allocation the of existing transmission capacity on the NU system, commission will accord substantial weight to their agreement.
The Commission vill expeditiously render a decision as to whether the constraint is imrutable and, if so, the appropriate allocation of existing capacity.
In no event, however, vill NU be required to provide firm third-party wheeling service out of existing transmission f acilities if reliability of service to native load customers would be adversely affected.
With regard to a complaint that NU has failed to comply with the CTC which involves anything other than the immutable constraint defense, the Commission may set the natter for hearing to investigate the validity of the complaint and to ensure that NU provides service 223/ 53 FERC at 65,222.
_325/ Id.
321/ see Utah, 45 FERC at 61,294, 1
. - ~.
~
l,-
i fDocket No. EC90-10-000,~ tt al. i
$n conformance with the terms of the tariff submitted on 3> q
~
compliance.
32 7n 4
C7 q;)
3.
Transmission Rate Issues m-Rate for Service From Existina Capacit@ 2 FT1 f
C2 ~n ;O t
a.
proposes to submit its trancmission tariff within e%g (rVkg f3 j i
I In contrast, t t In) days af ter the merger is consummated.122/
ES; Merger Tariff contains interim transmission rates to becoma_;far (3)
Co n
ef fective upon the Commission's acceptance of the merger.
T 4
i Condition 4 would require replacement of the-Merger T d
i i
Trial StafffEn days after Commission approval of the merger.the
' ~,- ]
l
. specific terms and conditions of the Merger Tar i
fil [:
, y1 a filing under section 205 221/
t s u ~;re The presiding judge found that no interin tariff or interTS df3
[
rates were necessary. The presiding judge found that allowing 'hh
rr1 l
consummation of-the merger when NU submits its compliance fili l
would " encourage a prompt and fair compliance filing" as NU-could not begin to obtain,the benefits of the merger until it submitted its compliance filing.112/
-Trial Staff and several intervenors except to the presiding
')
They request that~the Commission judge's decision-on this issue.
allow the merger
-adopt-the Merger Tariff or, in the alternative, to be consummated only when the Commission accepts NU's-Trial Staff a compliance filing. 222/
Merger Tariff-would allow the merger to be consummate
-New England immediately upon' approval of-the merger." 22J/
- The Principal New England Intervenors and Ten Eastern REMVEC
{
i 222/ Tr. 7134.
the Merger Tarif f specifies that certain merger filing by l
12E/ However, sections may.be modified only _ under a section 203 l
L NU.
223/ 53 FERC at 65,220-21.
220/ New England -Cogeneration Association.Brief ' on Exceptions at p
City of.Holyoke Gas l' Electric Department Brief on Exceptions 1 at 17; Easterm REKVEC Utilities Brief on 52; Exceptions at 12; Trial Staff Brief:on Exceptions at 75; Principal New England Intervenors -Brief on Exceptions at 64 ;
and Ten Eastern REMVEC Utilities Brief on Exceptions at 41.
221/ Trial Staff Brief On Exceptions at 74-75.
Docket No. EC90-10-000, si A1 Utilities assert that allowing the merger to be consummated filing would allow before the Commission accepts the compliance NU to reap the benefits of the merger before filing an acceptable transmission tarit'f to mitigate the merger's anticompetitive i
etiects. D2]
in setting the merger application for Im notes that, hearing, the Commission stated its intent to resolve this proceeding "as expeditiously as possible" and further stated that it " view [ed) the final conclusion of (PSNH's) emergence from NU bankruptcy as a matter of significant importance." naf argues that delaying the merger's consummation until the Commission accepts the compliance filing would make a prompt resolution of this proceeding impossib1c. nff We belluve that the GTC and the NH Corridor Proposal, as adequately citigate the merger's anticompetitive modified herein, requiring the adoption of the Merger Tarif f.
effects without Trial Staf f stated that the Merger Tarif f would make service We believe available immediately upon approval of the merger.
that the presiding judge accomplished the same result by allowing consummation of the merger when NU submits its compliance filing.
We further believe that delaying the merger's consummation until the Commission accepts im's compliance submittal for filing would be inappropriate given the uncertainty surrounding issues to further litigation in the which may be challenged and subject compliance proceeding and given our commitment to act before the 1991 termination date. LL5/
Merger Agreement's December 31,We believe that NU and PSNH are entitled to a pr At the same time, the intervenors resolution of this proceeding.
are entitled to have service begin as soon as practical, together with a fair resolution of any disputes raised regarding NU's compliance filing.
Accordingly, we believe that it is in the best interests of all parties te allow NU to consummate the We shall also merger when it submits its compliance filing.
require 1m to begin honoring requests for transmission service as modified herein, at that time.
Such under the GTC, transmission service will be provided at either the firm or non-firm transmission rates proposed in im's compliance filing, and without a refund floor.
In reviewing NU's subject to refund, compliance with this opinion, we will hold NU to filing to ensure Principal New England Intervenors Brief on Exceptions at 65; 332/ Ten Eastern REMVEC Utilities Brief on Exceptions at 41-42.
32' Rearina Orde_r, 50 FERC at 61,839-40.
Mjf NU Brief Opposing Exceptions at 81.
31/ Hearino Order, 50 FERC at 61,840.
_ ' - - ~ ' - - - - - _ _ _, _ _.
DockGt No. EC90-10-000, gt al. As NU itself states, "[i)f NU f ails to l
a very high standard.
comply with the letter or spirit of such (Commission) requirement, NU would be subject to summary judgment with respect to any aspect of its compliance filing." 221/
b.
Tje Line and Oooortunity Charagg Core condition 2 states in portinent part The intervenors' "No tic-line adjustment charges or lost opportunftf that:
charges may be included in the costs on which transmission rates are based or otherwise imposed by NU Companies on its transmission customers." 222/
NU does not state that it will charge its transmission customers such costs (as these arebut also does not preclu described below),
Since NU has previously charged such costs to its 223/
and since such charges are expressly transmission customers, the barred under the NH Corridor Proposal but not the GTC, f.ntervenors anticipate that NU may seek to impose such costs on non-Corridor sales.
post-cerger, Tie line adjustment charges are:
(d]esigned to recover the costs of the transmission supplier associated with providing service for a capacity purchase f rom outside NEPOOL.
Such cost increases result f rom an increase in the NEPOOL Capability Responsibility of the provider of such service which is associated with such a purchase. (212/]
According to NU witness Schultheis, transmission capacity on interconnections such as NU's tie lines with New York can be used for importing emergency power from utilities outside of NEPOOL, and this ability lowers the capability Responsibility of NU and Mr. Schultheis states that when all NEPOOL members. 212/
other utilities use NU's New York tie lines to import power, the Capability Responsibility of NU and all NEPOOL members increases for because the New York tie lines are no longer available importing emergency power.
Thus, NU imposes the tio line 336/ NU Brief Opposing Exceptions at 81.
Appendix 222/ Ten Eastern REMVEC Utilities Brief on Exceptions, at 4.
Ene Also Ex. 313 at 24-27; Ex. 601 at 38-39.
223/ Ex. 178; Tr. 4265.
221/ Ex. 154 at 4.
JfR/ Ex. 157 at 63-65.
1
{
l Dockot No. EC90-10-000, gt al. adjustment charge to recover any additional Capability Responsibility costs it incurs because of wheeling over the New York tie lirts.
Lost opportunity charges are:
[djesigned to recover capacity and/or energy savings assumed or estimated to be foregone by the provider of transmission service due to the provider's inability to simultaneously provide transmission service and pursue economic purchases across the transmission system. (lil/)
NU bases such charges on purchases it "could have made but did not make" because of the use of.its transmission system by others. 2A2/
NU states that lost opportunity charges are optional and argues that the charges benefit transmission customers by allowing the customers to avoid interruption at their option. 343/
NU asserts that it currently includes 344/
lost opportunity charges only in its non-firm contracts.
The cresiding judge rejected the proposal to prohibit the tie line and locc opportunity charges. 231/
The presiding judge noted that these charges are currently being litigated in other Commission proceedings involving NU and found no need for still more litigation here.
Instead, the presiding judge conditioned the merger on the merged company's agreeing to accept in this proceeding the Commission's decision in the other proceedings.
NEPCO states on exceptions that it and several other intervanors in this proceeding are not parties to the other NU proceedings. 346/
NEPCO argues that entities (such as NEPCO) that are not parties to the other NU proceedings should have the right to challenge the disputed costs. if the merged company includes them in its compliance filing.
-.3_[1/ Ex. '54 at 3-4, 212/ Ex. 261 at 20; Tr. 4264.
2A3/ Ex. 157 at 100.
344/ Id. at 100.
2f3/ 53 TERC at 65,221.
346/ NEPCO Brief on Exceptions at 16.
Docket No. EC90-10-000, 21 A1 Other intervenors argue that the other NU proceedings do not address the question of whether the anticompetitive ef f ects of the merger must be conditioned by prohibiting such charges.
These intervenors argue that the merged company could 112/
improperly use tie line and lost opportunity chargis "to extract monopoly rents from captive transmission customers." 211/
even if NU's ten-year priority for They posit as an example that, current excess generation capacity is rejected, NU could achieve the same result by charging buyers a " lost opportunity charge" for sales foregone from,its excess capacity.
NU argues in reply that it "would be particularly inappropriate and unf air for the Commission to decide the justness and reasonableness of NU's ' lost opportunity' and ' tie-line adjustment' charges in this case as proposed by some parties." 212/
NU endorses the presiding judge's decision to issues on the " full record being base the outcome of those developed concerning those issues in other ongoing Section 205 The Connecticut Commission, on the other proceedings." 350/ asks the commission to uphold the tio line costs on their
- hand, merits. 151/
In resolving this issue, we will first address the lost NU's lost opportunity charge provides a opportunity charges.
non-firm customer with essentially two options when a transmission path becomes constrained:
accept an interruption in service or reimburse NU for any savings it may forego by not engaging in an economy purchase on behalf of its native load customers in order to continue providing non-firm wheeling NU in these circumstances has no incentive to upgrade service.
the transmission system and eliminate the constraint causing the Also, in the past, NU has not offered to provide firm problem.
transmission service by tariff at a stated cost-based rate -- a service that night mitigate NU's market power in non-firm transmission service if it were a viable alternative for non-firm transmission customers.
Under the conditions imposed here, however, we are requiring its transmission system when necessary to satisfy NU to upgrade requests for firm transmission service and to of fer firm Ten 212/ Eastern REMVEC Utilities Brief on Exceptions at 25-27; 50-53, Eastern REMVEC Utilities Brief on Exceptions at 211/ Eastern REMVEC Utilities Brief on Exceptions at 26.
211/ NU Brief opposing Exceptions at 78.
2:5J1/ 1$.
351/ Connecticut Commission Brief Opposing Exceptions at 63-65.
t Docket No. EC9 0-10-000, g.t al.
- 71 It is transmission service by tarif f at a cost-based rate.
possible that these conditions will suf ficiently mitigate NU's market power over transmission customers so as to render the imposition of lost opportunity charges just and reasonabic for We decline to decide this issue, however, non-firm service.
and other until NU actually seeks to impose such charges, intervenors have had an opportunity to review and respond to NU's At that time, with the details of NU's proposal and proposal.
the focused criticisms of any opposition bef ore us, we will be better able to decide whether NU's lost opportunity charges are just and reasonable for non-firm service. 212/
In Utah, the Commission rejected the applicants' proposal to 252/
In that case, however, charge lost opportunity costu.
the merger applicants sought to apply such charges to firm Here, by contrast, the issue is whether such wheeling service.
charges are appropriate for non-firm wheeling when firm wheeling Moreover, the Commission's is provided without such charges.
action in that case was directed at opportunity cost charges as proposed by Applicants," instead of such charges categorically.
The Commission found "the Applicants' proposal for 213/
determining opportunity costs overly vague and possibly unworkable." 355/
If and when NU files its proposal to we will decide the impose such charges for non-firm service, issue in this case based on the facts presented.
we decline to rule at this time on the tie line Similarly, charges.
The intervenors will have the right to challenge such charges if and when NU seeks to impose them.
NU has not yet filed transmission tarif f s implementing its GTC and has not If stated whether it will seek to recover tie line charges here.
in its tariffs, all the merged company includes such costs affected parties (and not just the parties to NU's other proceedings) vill have the right to challenge such costs, Cost Janronsib_ility__and Pricina for c.
Transnissio M pgrades Under the GTC, NU has voluntarily committed to provide wholesale wheeling service f or any utility over its existing transmission system.
To the extent NU's transmission capacity is inadequate to provide reliable service to native load customers 352/ By that time, we also may h_ve acted in the other NU proceedings involving these issues.
212/ 45 FERC at 61,290, 61,291 n.163.
354/ 1d. at 61,290.
2 53/ Id.
Docket.No. EC90-10-000, 31 31.~
- 72 st for wheeling service, the question
- and also accommodate a _ reque arises of who should bear the cost consequences of-the We recognize that the primary issue of concern to constraint.
the parties:in this proceeding relates to economics, not reliability. 211/
Indeed,-the Oentral controv:rsy in this proceeding has focused upon which party should have to pay the costs of constructing a transmission upgrade to remove a transmission constraint.
While NU commits to provide wheeling service over its existing transmission capacity which temporarily is not needed to serve its native _ load, NU maintains the.t as its native load grows and a particular interface becomes constrained, wheeling customers should have to pay for any_ necessary transmission upgrados.
Specifically, NU advocates that The standard that NU uses is that the wheeling customers must make a PID rata contribution whenever the facilities would not~have been needed hM1 12r the wheeling transfers across a constrained interface.
This means.that NU's native load customers pay for the new facilities they create the need for_and wheeling customers pay for the facilities they create the need for, l252))
The Merger Tariff would eliminate this " native load growth"
~
priority by giving existing firm transmission customers' who obtain service before a constraint develops a higher priority regarding cost responsibility for upgrades than subsequent growth Trial Staf f and the intervenors also object to in native load.
NU's "but-for" cost responsibility test, stating that it presumes
.that wheeling customers will be responsible for all future upgrades. 2kDJ The presiding judge. rejected the Merger Tariff. provision regarding native load priority, noting that the distinction between "old" - and "new" native load was unclear, with little PSNH and many of the intervenors are members of NEPOOL, 25ff-NU, which is a highlyLintegrated power pool.
NEPOOL has established operating procedures to follow in case of emergency and shortage situations'such as transmission constraints to ensure reliability of service -to its members'.-
Ex. 601 at 24.
252/ Ex. 157'at 40.
8118-213/ E.o., Trial Staf f Brief On Exceptions at 70-71; Tr.
8119, 8121.
1
(;.
l i
i
Docket No. EC90-10-000, gl al.
- 73 record evidence on the subject.
The presidint *,udge reasoned that the cost allocation method should not favor either native load customers or wheeling customers.
The presiding judge found that there should be no presumptions as to how the costs of a certain facility should be assigned.
The presiding judge stated that transmission costs should be allocated to those entities responsible for such costs, when feasible. 212/
The presiding judge f ound that NU's "but for" cost allocation test was acceptable if construed and applied in an "even handed and neutral" manner. 212/
Finally, the presiding judge determined that, " future attempts to collect costs for upgrades will, as NU agrees, involve rate filings under section 205 (e.g.
Tr. 8079)." 251/
The presiding judge explained that NU would have the burden of proof and those parties opposing NU's proposed cost assignment would have an opportunity to justify an alternative cost assignment.
Trial Staf f and the intervenors argue that, under NU's native load priority proposal, wheeling customers would always be found responsible for the costs of upgrading transmission facilitics, even if native load growth contributed to (or caused) the constraint.
Trial Staff asserts that the NU and PSNil transmission facilities were not built exclusively to meet the needs of NU's and PSNH's native load customers. 212/
Instead, Trial Staff claims, wholesale firm transmission customers also pay a pro rata share of the costs of those transmission f acilities. 2fl/
According to Trial Staff, NU's proposal could inequitably obligate an existing wheeling customer that is paying a firm rate for transmission service to pay the entire cost of a transmission upgrade which is caused, at least in part, by native load growth.
Trial Staff points to a o
statement by the NEPOOL Executive Committee which notes that with respect to pool transmission facilities, 364/ "the transmission system is planned, approved, built and operated as 212/ 53 FERC at 65,222.
212/ M. a t 65,223.
211/ M.
112/ Ex. 601B at 189; Tr. 6265-66, 252/ M.
364/ Pool transmission f acilities owned by individual NEPOOL participants and rated 69 kV or above constitute the so-called " backbone" transmission facilities within New England.
Ex. 123 at 62.
4 Docket No. EC90-10-000, et al.
- 74 Therefore, Trial Staff asserts an integrated system. " 23 5/
that the reliability and iconomic benefits derived through NEPOOL result from the joint plar ning and operation of all generation and transmission facilitits.
Trial Staff further asserts:
JO)vnership of iNew England] transmission facilities 1.*
cncentrated in ten utilities today and vill be concentrated in nine utilities following the merger.
A continuation of the practice of assigning priority of service to the native loads and existing contracts of transmission owners may either foreclose economic options of other entities or cause such entities to protect their own customers' interests by constructing
- 2ansmission f acilities that are not otherwise needed or in advance of the date when such f acilities vould be needed, l 2.5.h/ )
NU, Nov Hampshire and the Connecticut Commission support the presiding judge's approval of the native load priority.
They assert that a utility's monopoly franchise is granted in exchange for the utility's obligation to serve its native load customers, the native Under this " regulatory compact." they argue, 112/
load priority is universally accepted and applied. 213/
NU nlso argues that Trial Staf f's and intervenors' contentions that transnission facilities in New England are built for the New England region's use is incorrect. 112/
- Rather, "NU
.. has never designed or built its NU. asserts that, transmission f acilities in order to provide transmission service for non-native load customers " 122/
According to New Hampshire, the native load customers have paid for the transmission facilities, including any teoporarily surplus transmission capacity, and will ultimately continue to be responsible for such costs regardless of any temporary use of 15_5/ Ex. 576 at 1, 215/ Ex. 601 at 24.
367/ NU Brief Opposing Exceptions at 45-46, New Hampshire Brief Opposing Exceptions at 47; Ex. 228 at 5-7; Tr. 6351.
213/ New Hampshire Brief opposing Exceptions at 47.
64.
152/ NU Brief Opposing Exceptions at 370/ Ex. 157 at 22.
I
. Dockot No. EC?C-10-000, Ct A1 these facilities by wheeling customers 221/
How Hampshire disputes the relevance of the argument t'.at accling customers New also pay for NU's system costs through wheeling rates.
Hampshire contends that the wheeling customer's financial obligation lasts only as long as its contract for service, while the native load customer's obligation continues indefinitely.
212]
NU and Nov Hampshire maintain that no nexus has been established between the elimination of the native load priority and the mitigation of the alleged increase in market power, all/ and that in H1Ab the Commission stated that transmission conditions had t o be "specifically tailored" to fit the problem being resolved. 22A]
WL sgree with tha presiding judge that questionc of cost responsibility for new transmission facilities built to remove constraints should be " litigated in future proceedings, involving We particularized proposair, filed under section 205." liff as with any other rate proceeding, NU vould further agree that, bear the burden of proof of demonstrating the justness and Purthe rmore, in reasonablonass of its proposed increased rates.
such a proceedjag, opponents to NU's proposal would remain free to demonstrate t'iat the cost responsibility for a particular However, since we have denied NU's upgrade belongu elsewhere. sed set-aside for its non-firm use of the New York tie pr 11:
it is appropriate to indicate why we believe that proper pri 7 may alleviate the concern about usage priorities.
In our view, as a general matter, transmission upgrades necessitated by third-party, firm-transmission use should be paid for by the requesting party and not by native load customers.
While this general principle is easy to enunciate, we cannot pply in all possible future identify now how it woul/
The commission cannot assure customers that circumstances.
obtain firm transmission service from NU that they vill not be held responsible for paying a share of any future upgrades.
Neither can we guarantec UU that the cost of all upgrades vill bc borne by wheeling customers and not native load customers, citina Ex.
111/ New Hampshire Brief opposing Exceptions at 53, 228 at 7-8.
222/ Id. at 54.
t L
222/ Id. at 51, 223/ FU Brief opposing Exceptions at 41, citina Utah, 45 FERC at 61,282.
225/ 53 FERC at 65,223.
l i
l
~ " '
w
, Docket No. EC90-10-000, 31 31 Indeed, the " rolled-in versus incremental" rate issue must be l
evaluated on the specific circumstances of each case.
We v.1 accept NU's proposed "but for" criterion in the same spirit as it was accepted by the presiding judge:
f There is no basis for presumptions or other devir:4-designed to influence the inquiry l
into how the costs of a particular facility
~
should be assigned.
The analysis should be even-handed and neutral.
Mr. Schultheis' test, construed and applied that way, is acceptable. [22&/)
We do not believe that NU's "but for" criterion establishes a i
presumption that third-party use is always responsible for transmission upgrades.
Instead, we construe the criterion to-mean that prospective wheeling customers must share, on a RIS rata basis, the incremontal investment costs incurredLas a result of serving them.-
As the Commission stated in Utah l
Where additional capacity is needed to meet a rates may be designed to
- request, l
specifically assign the cost of that capacity addition to the party requesting service.
We do not preclude the possibility that such costs will subsequently be allocated to other beneficiaries of the additional capacity.
[222/)
We believe that acceptance of NU's "but for" criterion establishes a framework within which NU should be able to manage its transmission commitmentu to others and also accommodate UU's 1
legitimate reliability concerns.
If a firm wheeling request 4
across a particular interface would degrade reliability absent certain upgrades, it is appropriate to consider a wheeling charge that covers such upgrades.
NU's concern for its native-3oad customers is adequately addressed by permitting NU to reserve existing transmission capacity for reliability-purposes combined
-with appropriate application of incremental-cost pricing using for" criterion with regard to transmission upgrades.
its "but This criterion is broad enough, -for example, to accommodate a ratemaking concept in which incremental costs are calculated as the difference in NU't revenue requiremet.ts assuming NU does and 222 1st.
222/ 45.FERC at 61,291 n.163.
, --, ~, - - _ -,,..,. _ - -
. _ _. ~, -..
Docket No. EC90-10-000, gi al.
~ 77 -
Such a does not provide the third-party service. J11/
concept would include the addition of facilities that NU did not require for its own use and also facilities that NU may need in the future but at an earlier date because of a wheeling request.
I The " differential revenue requirements" example is not intended Many others would be to preclude other ratemaking concepts.
consistent with the general f ramework that third parties pay a pro rata share of incremental facilities that would not be needed but for the wheeling request.
)
While the Commission is willing to accept incremental-cost pricing for third-party transmission service, we believe the proper forum to decide the details of cost responsibility In such a case, questions is a separate section 205 rate case.
NU must justify any direct assignments of costs and support any arguments that reliability is degraded by a particular firm No preserption is created by NU's "but transmission service.
f or" criterion that firm whcoling customers always cause the need f or upgrades.
We note that NU has committed to cap transmission customers' responsibility fer the costs of future upgrades to (1) those specific facilitied identified by NU at the time of the wheeling request as needing to be built or upgraded either at the time of the request or in the future; 111/ and I
the maximum dollar amount contained in (2)
UU's initial estimate of a wheeling customer's Er2 rata share of the costs of future upgrades needed to accommodate a request for wheeling service. 181/
While we do not nrejudge the appropriateness of whatever cost-baued methodology NU might propose in future section 205 rate Such a cap we accept NU's cost cap as reasonable.
increases the wheeling customer's certainty about its future
- cases, transmission prices and-is consistent with our willingness to Lncremontal costs as a basis for pricing wheeling service accept I
FERC lla/ This method was accepted by the Commission in ESI, 51
_ Specifically, this approach would be calculated j-as the not differential in the present value of NU's revenue requirements with and without the third-party service.
212/ Tr. 72 64, 8188.
In0/ Tr. 73 06-07, w,== -.
- - = -...
Docket Ho, Ec90-10-000, ci al. that requires construction of nov transmission f acilities.
1EL' However, NU qualified its commitment in cases of significant unforeseen events (e a., a state requirement that all overhead transmission lines be placed underground).
In response to NU's concerno, the judge adopted a 25 percent contingency factor, citing the commission's use of such a factor in nucicar plant decommissioning estimates. JJ2/
We find no support on this record for a 25 percent Rather than considering a fixed contingency contingency factor.
factor, vc believe it would be more appropriate to allow NU to seek recovery through a rate filing where construction costs exceed its original estimate due to major unforeseen events which NU will be held are beyond the merged company's control.
responsibic for producing an accurate initial cost estimate of 212/
We emphasize that the burden of the upgrade costs.
proof in demonstrating both the unexpected nature of the expense and the determination of which customer (s) should bear the associated cost responsibility, vill be upon NU.
Any affected customers would remain free to contest such a showing by NU.
Finally, the presiding judge addressed a number of ancillary issues pertaining to the appropriate rate methodology for pricing transmission service over new transmission f acilities as well as 61,291.
We note that NU's 2f.1/ Eftc als.Q Utah, 4 5 FERC atto estimate the cost of future upgrades and agreement thereby limit a custor.er's increrental cost responsibility applier to prospective requests for transmission service.
We view this initial cost estimate as a prerequisite to any proposal by UU for incremental cost pricing, which means, among other things, that pre-existing transmission service agreements are not subject to incremental cost pricing because of a constraint that may subsequently develop on the merged company's transmission system.
If a party requesting transmission service believes NU's cost estimate to be unreasonabic, it may file a complaint with the commission and sock appropriate relief.
F 1E2/ S3 FERC at 65,224.
.oes not justify " blanket" approval of 2E2/ While the record herea 25 percent contingency factor, the commission l
that NU must take into account reasonable forecasting l
contingencies in estimatir.g the costs of upgrading particular transmission facilities.
_. _ _ ___m.__
Docket No. EC90-20-000, 11 A1 over NU's existing transmission system. 233/
In addition, certain intervenors excepted to the judge's f ailure to require UU i
to include certain rate-related conditions in NU's rate proposal in its compliance filing.115/
The Commission did not set NU's post-merger transmission rates for hearing in this rurthermore, the record evidence in this proceeding. 21f/
Thorofore, we proceeding on these issues is not fully developed.
believe that a determination of the merits of these arguments on this record would be premature.
4.
Duration of service Maximum Duration of Serviqa a.
In its GTC, NU proposes to of fer firm and non-firm service i
by tariff for up to five years and to of fer service by individually-negotiated contracts for longer periods:
NU shall have on file with the FERC a standard form tariff for short-tera (up to five years) wheeling transactions.
All long-term wheeling vill be provided pursuant to r
individually negotiated contracts. (1E2/)
would require NU to of fer service I
The Merger Tarif f, by contrast, for " twenty (20) years or longer by agreement of the parties, except that the term of service shall, at the customer's option, extend at 1 cast as long as the duration of the generation supply commitment of the Customer for the power to be trannmitted."
2hk/
(1) the appropriateness of assessing 213/ These issues-included:-
a customer both a pro-rata charge as well as a base or roll-in rate for transmission service; and (2) the reasonableness of a customer paying for a pro-rata share of a particular upgrade (e.g.,
20 percent of a_upgrado) and being charged additionally on a roll-in basis for the remaining (c.a., 80 percent) portion of such upgrade.
53 FERC at 65,224.
1E2/ For -example, the Principal New England Intervonors, in their Brief On Exceptions at 80, advocate a requirement that the merged company of fer a combined rate or a 50 percent rate discount for multi-system transmission.
4 211/ Hearina order, 50 FERC at 61,836, 231/ Ex. 178 at 7.
Egg also Ex. 123 at 179.
23E/ Egg Ten Eastern RDWEC Utilities Brief on Exceptions, Appendix at 18.
ERA also Ex. 601 at 33, 36-37; Ex. 397 at 12; Ex. 438 at 14.
~.
. _ _ _. _, ~.. ~ _ _ _ _ w
1 Dockot No. EC90-10-000, p1 A1 The presiding judge ruled that the maximum duration of The service under NU's tarif f should be 20 years. 212/
firm presiding judge stated that a " reasonable guarantee of transmission will be essential to discipline the merged company's The presiding judge found that a competitive power." 213/
five-year offer of tariff service would provide insufficient certainty to developers and financiers "who may well be looking at a $450 million investment in a facility with a twenty-year obligation." 221/
The presiding judge held that the evidence justified a maximum duration of 20 years, but no more.
UU argues on exceptions that the 20-year tarif f requirement is unrelated to any competition concern because it does not change the scope of UU's commitment to provide transmission service but only limits NU's ficxibility in designing long-term 222/
NU asserts that case-by-case negotiations arrangements.
are preferabic f or long-term commitments in new entitlements, so that NU can particularly for new generation facilities, perform the necessary studies and tailor the transaction accordingly.
NU argues that sufficient lead time almost always NU states that exists to negotiate such arrangements in advance.
it has never delayed service pending negotiations.
Several intervenors argue on exceptions that the maximum years and duration of service of f ered by tarif f should exceed 20 should continue for the life of the generating unit or the term of the unit power purchase, up to at least 35 years. 122/
They argue that life-of-the-unit contracts are common in the industry and that NU's tariff should provide for them for the cor. tracts of 20 years or less must be same reasons thatIn support, they note that customers can obtain up accommodated.
to 30 years of transmission service under the NH Corridor if needed "to accommodate a firmly committed contract
- Proposal, purchase of power requiring such service." 214/
lES/ 53 FERC et 65,220.
120/ Ld.
12.1/ ld.
222/ NU Brief on Exceptions at 94-95.
122/ Principal New England Intervenors Brief on Exceptions at 63-Ten Eastern REMVEC Utilities Brief on Exceptions at 45-64; 38-22; Eastern REMVEC Utilities Brief on Exceptions at 50; New England Cogeneration Association Brief on Exceptions at 50-52, 294/ Ex. 154 at 3.
l
Docket No. EC90-10-000, c1 al. i They also assert that NU's practice of negotiating contracts on a case-by-case basis creates uncertainty about the terms and availability of transmission, and allows NU to negotiate "take-it-or-leave-it" terms by refusing to file the contract until the Thus, they argue that NU's practice customer accepts NU's terms.
places transmission customers at a competitive disadvantage and is harmful to the puolic interest.
The Eastern REMVEC Utilities further contend that the presiding judge f ailed to specify whether his recommended service duration limit applied to both firm and non-firm service.
They assert that firm and non-firm service should be offered for the same duration, since no difference in duration 1EE/
has been justified and non-firm service is of ten an acceptabic and less expensive option for transmission customers.
The Commission agrees with the presiding judge that a reasonabic availability of transmission is essential to discipline the merged cocpany's increased competitive power and 12f/
to make the merger consistent with the public interest.
"the premerger world of ad hoc As the presiding judge stated, posed serious dif ficulties for transmission negotiations This conclusion is supported by the record, customers." 122/
which comonstrates that NU's practice of case-by-casemakes power pl negotiations:
availability of service cannot be known in advance; 119/
vastes time and creates uncertainties that can kill a deal:
112/ allows a utility to deny transmission access subtly through prolonged contract negotiations; 122/ makes anticompetitive behavior more likely than under a tariff system; 121/ and allows the so)2er to dictate the terms by refusing to file the contract until the customer accepts the soller's In short, terms or agrees not to contest the filing.192/
NU's practice of case by-case negotiations allows it to exercise 19.
__1R5/ Eastern REMVEC Utilities Brief on Exceptions at 396/ Eye 53 FERC at 65,219-20.
121/ Id. at 65,219.
121/ Ex. 265 at 39; Ex. 261 at 19-20; Ex. 381 at 6; Tr. 4258-59' 4262, 4507.
122/ Ex. 2 65 at 39.
192/ Tr. 4 2 59-61.
L91/ Tr. 4263.
AS2/ Tr. 4507, 5019-20; Ex. 261 at 20; Ex. 265 at 39-4 0.
l Docket No. EC90-10-000, gi gl. its market power 1E1/ and to place its transmission customers 121/
The merger vill at a competitive disadvantage.
I substantially expand the transmission system under NU's control and thus enlarge the market in which NU can apply this practice.
This practice must be constrained in order to mitigate the anticompetitive effect of the merger.
The presiding judge found a need for tarif f service for only We find that the evidence supports a 20-year maximum 20 years.
duration, but with a customer's cption to extend service for asNU long as the duration of the customer's power supply contrect.
witness Schultheis testified that the " typical length" of bulk power contracts for NEPook participants is "for as short as one day and for as lona as the life of a acneratina unit." 121/
MEPCO Vitness Bigelow testified that Qualifying Facilities (QFs) and similar projects "need assured service under known terms and conditions for the long-term, coincident with their power A witness presented by Montaup Electric contracts." 121/
service Company testified that transmission buyers need tarif f
" coterminous with the buyers ' power agreemente.. " 122/
The need for transmission service of ten does not end af ter 20 years.
We vill modify the initial decision on this issue in Agf/
order to mitigate the merger's anticompetitive ef f 2 cts against transmission customers needing service for a power supply Accordingly, we vill require NU commitment longer than 20 ' years.
in its merger tarif f on compliance to of fer transmission service for the longer of 20 years or the life of the customer's power supply contract.
Finally, the same durational limit ordered here for firm transmission service vill apply to non-firm transmission service No difference in maximum duration of offered under NU's tariff.
firm and non-firm transmission service has been justified in this since there is no obligation for NU to plan case.
Furthermore, or construct transmission f acilities to accommodate non-firn wheeling requests, we do not see how NU would be harmed by of fering long-term non-firm transmission service.
403/ Ex. 601 at 23.
3.Qf/ Ex. 601B at 123-24.
193/ Ex. 12 3 at 80 (emphasis added).
f_Qs/ Ex. 261 at 18.
407) Ex. 537 at 9.
Appendix 8 (listing several QF projects with Aff/ Egg Ex. 261C, Ex.
initial terms or extension options exceeding 20 years);
397 at 12.
~ _. - _ __. -... -._... _ _ _ _. _. _. _ _ _ _.
l 83 -
Docket No. EC90-10-000,.t1 31 b.
Minimum Duratior. for Non-rirn Service NU proposed a minimum duration of seven days for non-firm service within NEPOOL,1Q1/ and 30 days for service over the New York tie lines.119/
The Herger Tarif f proposed a one-day minimum.,ill/
The presiding judge approved a one-day minimum. 112/
Tbc presiding judge noted the frequency of less-than-seven-day transactions and cited testimony indicating that NU was able to alock up" such transactions for itself by refusing to wheel for The presiding judge stated that NU had offered shorter periods.
no study justifying a seven-day charge for service as short as The presiding judge found that the record supported a one-day.
one-day minimum, particularly in the context of the merged company's increased power. " 113/
We agree with the presiding judge's approval of a one-day find it appropriate to address NU's minimum and his-reasoning but argument that a one-day minimum is unrelated to the competitive ef fect of the merger and is-thus unjustified.11A/
Specifically, we will address how a one-day minimum mitigates a As noted above, NU likely anticompetitive effect of the merger.
of bulk witness Schultheis testified that the _" typical lengtha power contracts for NEPOOL participants is "for as short as one
. " 11.5/
NU itself gains $6-10 million in annual day.
revenues from short-term transactions,115/ some of which last only a couple of days or even hours. M2/
The merged company will be able to of f er a variety of short-term powerA seven-day m sales. 11f/
iQ.9) Tr. 7079.
110/-NU Brief on Exceptions at 89 n.90.
ill/ Eeg Ten Eastern REMVEC Utilities Brief on Exceptions, Appendix at 18 (Merger Tariff at 7).
ill/ 53 FERC at 65,220.
112/ Id.
AL4/ NU Brief on Exceptions - at 88-92.
3.15/ Ex. 12 3 - at 8 0.
ilf/ Tr. 1831.
112/ Tr. 1802.
113/ Ex. 569 at 32.
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Docket No. EC90-10-000, 01 A1 uneconomical for NU's competitors and allows NU, by exercising 1'
its markct power in transmission, to exclude competition for After the merger, NU's market power in these sales. 112/
transmission would extend to a larger system and a broader market; NU would be able to suppress even more competition and The one-day minimum for non-firm gain even more advantage.
service is needed to mitigate this anticompetitive ef fect of the
[
merger.
j.
Vermont Denartment of Public Service 5.
The Principal New England Intervenors request that NU's General Transmission Commitments be. clarified so that the Vermont Department of Public Servico is expressly eligible _ for service.
The Department is aut't.orized under Vermont law to 12R/
represenc the pr.blic in utility matters before the Vermont Public More importantly for present Service Board and this Commission.
purposes,=the-Department also engages in bulk power transactions:
f VDPS also sells substantial quantities of power-to other utilities at wholesale, and Its combined wholesale and retail operations supply nearly-40% of the state's total energy requirements. (121/)
NU witness Schultheis stated during his deposition in this to the extent Vermont law allows the Department proceeding that, service to engage in bulk power transactions, "we would providt Accordingly, we clarify that the l
to the Department." 121/
Department will be eligible for service under the General 4
. Transmission Commitments.
i lD.
"New Hamoshire Corridor Pronosal I'
. The NH Corridor proposal:is the result of a settlement reached on February '24,- 1990 between NU and NEPCO in this proceeding.
NU has incorporated the NH Corricor Proposal as an j.
additional voluntary commitment to the GTC. 122/
i-112/ Ex. 313.at 19,-23-24;-Ex. 524 at 15; Ex. 325 at UI-01; Ex.
386 at 48;_Ex._449 at 48; Ex. 472 at 12-13; Tr. 7092-7100.
1 12R/ Principal New England Intervenors Brief on Exceptions at 69-r 70.
f22/ Vermont-Department of Public Service and Vermont Public g-Service Board motion to intervene at 2-3.
12.2/ Ex. 4 71 at 27.
f 122/-Ex.~154.
f
Docket No. EC90-10-000, 21 gl. The NH Corridor Proposal allows transmission service across the PSNH and NEPCO systems, providing access for buyers in southern New England to reach power suppliers in Canada and Maine.
The NH Corridor Proposal makes 400 MW of existing capacity available 323/ and provides for expansion of the existing Corridor as necessary to accommodate wheeling requests so long as the majority of NEPOOL members support such expansion.
The NH Corridor Proposal allows NU and NEPCO to retain up to 50 percent of the additional capacity resulting from expansions to the corridor.
Corridor service is initially of fered for periods of either ten or 20 years with a ten-year extension available under certain conditions.
Corridor service vill be of fered within three months of the merger's consummation, with binding responses due within three months, but not before July 1, 1991.
Service is to begin approximately two months after responses are received.
If the initial requests for service exceed the capacity of fered, available capacity vill be allocated among those entities submitting responses on a load-ratio basis. ill/
If the Corridor capacity is undersubscribed in the initial of fering, NEPCO has reserved the first right to claim any remaining Corridor capacity on NU's system "above and beyond the 200 MW initially allocated to it." 121/
Any Corridor capacity remaining on either UU or NEPCo's system, which is not subsequently committed by either party for its own system use or for service to others, vill be made available to subscribing parties on a first-come, first-served basis.
The rates for service under the NH Corridor Froposal are to be based on providing firm service at embedded costs.
The ratos will not include any tie-line or lost opportunity cost charges.
NU proposes to file rates for service within 60 days af ter the merger's consummation.
Customers electing service for the initial twenty-year period would be responsible for a portion of the costs of any upgrades needed to expand the Corridor.
Additionally, a customer electing service would be allowed to transfer or assign its transmission rights to other entities.
111/ An additional 40 MW of transmission capacity is provided for transmission service between Maine and PSNH's interconnections with Vermont Yankee for utilities in Vermont and 12 HW of transmission capacity within New Hampshire f or UNITIL and New Hampshire Electric Cooperative.
125/ A load-ratio share vould correspond to each responding utility's annual peak load as a percentage of the total annual peak loads for all utilities requesting Corridor service multiplied by the available capacity.
121/ Ex. 154 at 5.
l
l Docket No. EC90-10-000, et al. 1.
Size of_CorIl2 E Under the ifH Corridor Proposal, NU commits to provide 400 MW of transmission capacity for firm wheeling service across the PSNH system from Maine to interconnection pointu Vith NEPCO.
NEPCO similarly commits to make up to 200 MW of transmission its system capacity available for firm wheeling service acrossbetween NEPCO's int In compensation, NEPCO will have the southern New England.
option to reserve up to 50 percent of the 400 MW made available by itU.
The presiding Judge found the 400 MW of Corridor He transmission capacity to represent a significant commitmL '.
determined that it would be unreasonable to require HU to connit some of that all of PSNH's pre-merger availabic capacity because capacity may be needed to accommodate growth in native load, furthermore, the preciding judge f ound no basis to require NEPCO to provide more transmission capacity than it originally offered. f22/
The presiding judge found, contrary to allegations that the settlement negotiations between NU and NEPCO were unfair, that the bargaining between NU and HEPCO was properly conducted at the resulting size of the Corridor was arm's-length and that The presiding judge concluded that the size of decided fairly.
the Corridor was reasonable in light of the NH Corridor Proposal's potential for increasing the amount of wheeling from northern power suppliers and NU's commitment to exphnd the Corridor if needed. 12Jf The Principal Nea England Intervenors argue that the amount AL/
They Corridor transmission capacity in insufficient.
assert that the 400 MW of Corridor transmission capacity is based of amount of unconnitted transmission solely upon the current capacity on PSNH's system, while PSNH presently provides 30.f of transmission service to others.
4 approximately 740 MW amount of
'1 hey further allege that NU understates the capacity available on the Corridor by excluding capacity which 311/
122/ 53 FERC at 65,226, 428/ 15), at 65,227, 81.
122/ Principal New England Intervenors brief On Exceptions at Eea plsa New England Cogeneration Association Brief On Exceptions at 39.
_430/ Ex. 479 at 15; Ex. 482.
111/ Principal New England Intervenors Brief On Exceptions at 82.
=,
Docket No. EC90-10-000, et al. will become availabic in the future when current tranceission service contracts expire. 122/
The Principal How England Intervenors assert that NU will eventually obtain 948 MW of Corridor capacity,112/ an amount alleged to substantially These intervenors insist exceed NU's load ratio share.121/at a minimum, require NU to provide that the Commission should, 740 MW of transmission capacity, equivalent to PSNH's present They level of transmission service provided to others.121/
also argue that the other entities should be allowed an option to request and participate in Corridor expansions without requiring participation by a majority of HEPOOL participants. ill/
The Eastern REMVEC Utilities and Bangor Hydro-Electric Company / Maine Public Service Company note that any corridor capacity which is not subscribed to within the allotted time 1 12/
These intervonors period will revert to NU and HEPCO.ask the commission to modify the NH this unsubscribed Corridor capacity instead be made that available through the GTC. All/
NU and How Hampshire assert that NU has appropriately reserved only a load-ratio share of the capacity f rom pSUH's transmission system to ensure reliable future service to PSNH's A2S/
NU states that any unsubscribed native load customers.
Corridor capacity will be made available under the GTC. 112/
NU also argues that the purpoce of the NH Corridor Proposal's expansion section is for NU and NEPCO to " support and Icad the expansion process on the Corridor to meet the needs of the Accordingly, NU states that NU and HEPCO are region. " 111/
A22/ ld.
422/ Ex. 269D.
123/ Ex. 313 at 85-86.
121/ Principal How England Intervenors Brief On Execption'; at 63.
436/ Id. at 84.
All/ Ex. 154 at 5.
121/ Bangor-Hydro / Maine Public Service Brief On Exceptions at 15-Eastern REMVEC Utilities Brief On Exceptions at 24.
l 16; New Hampshire brief 122/ NU Brief opposing Exceptions at 84 ;
Opposing Exceptions at 60.
440/ NU Brief opposing Exceptions at 84.
Ailf Ex. 154 at 7-10.
a Docket No. EC90-10-000, et al. not permitted to initiate a corridor expansion without the support of other NEPooL memberu, unless the expansion is needed NU and New to serve NU and NEPCO's native loads. 112/
Hampshire also argue that the NH Corridor Proposal should not bewhose particip modified so as to adversely affect NEPCO, critical to achieving the proposal's benefits.112/
We agree with tne presiding judge that the amount of capacity available for wheeling under the NH Corridor Proposal is UU has committed to make 400 MW of not insignificant.
transmission capacity available for firm transmission service and In addition, HEPCO, who to price such service at embedded costs.is not an applicant in this pro 200 MW of firm transmission service, in exchange for the right to reserve up to half of NU's 400 MW commitment for its own use.
The primary benefit of the NH Corridor Proposal is that it gives which are blocked by UU's post-utilities in Eastern REMVEC, merger " transmission _ curtain," long-term transmission access to powcr supplies in Canada and northern How England over a 12mitte These benefits are largely interface and at embedded costs.
attributable to NEPCO's participation in the NH Corridor Absent this opportunity, Eastern REKVEC utilities Proposal.
would have to separately negotiate wheeling requests with both NU under terms that might not be as advantageous as the and NEPCO, NH Corridor Proposal. f33/
The Commission cannot in this proceeding compel NEPCO to provide more transmission capacity over its system than However, certain intervenors ask the Commission to require NU alone to increase the amount of Corridor transmission that it We believe this is unnecessary for several makes availtble. NU and NEPCO have aircady agreed to physically reasons.
- First, expand the Corridor to accommodate transmission requests beyondif sup the initial capacity made available, In addition, NU has committed that:
of NEPOOL members.
[Tjo the extent any transmission capacity on the PSNH system is not committed to or RU subscribed for under the Corridor Plan, 85-86.
A32/ NU Brief Opposing Exceptions at fj]/ Id. at 83; New Hampshire Brief Opposing Exceptions at 60.
under NEPCO's existing AAA/ NEPCO witness Bigelow explained that,a utility could not receive transm Tariff No.
3, Mr.
service across NEPCO's system on a reserved basis.
Bigelow stated that Corridor service is of a firmness that to its NEPCO has never previously offered except at 27-28.
transmission dependent utilities. Ex. 261 i
l l
fL -- ~
Docket No. EC90-10-000, pt gl.
- 89 has stated that the capacity will be available pursuant to NU's General Transmission Commitments. [111/)
NU's obligation to provide transmission service upon Furthermore, re qu e st, pupra, applies to NU's entire transmission system, including the NH Corridor.
Under the transmission conditions we are adopting, NU cust provide the requested service, independent of the requirements of the NH Corridor Proposal.
Therefore, additional transmission access, beyond the 100 MW already either immediately of f ered, would be made available upon request, from available capacity under the GTC, or, if additional transmission facilities must be built or upgraded, within the time allowed for such construction. 115]
2.
Elig_ih111.t.y As proposed by NU and NEPCO, the NH Corridor Proposal would Rhode Island, and be offered to "all utilities in Massachusetts, as well as certain Vermont and New Hampshire Connecticut,"
utilities. 112/
NU vitness Schultheis explained that the Corridor Proposal is intended:
(P)rimarily to permit utilities in southern New England and Vermont to obtain access to new and existing utility and non-utility sources of generating capacity and/or energy in Canada, Maine and New Hampshire, although the service will be available for south-to-north transactions as well. [A31/1 transmission cepacity on the NH As proposed by NU and NEPCO, Corridor would not be offered to northern New Englend utilities and QFs/IPPs. 449/
The presiding judge ruled on two issues regarding he held that northern New England utilities eligibility.
- First, should be eligible. 159/
The presiding judge found that 445/ NU Brief Opposing Exceptions at 84.
115/ This condition vill not affect the portion of NU's 400 MW capacity available to NEPCO under the NH Corridor Proposal.
4471 Ex. 154 at 6.
448/ Ex. 123 at 158.
l 449/ Id. at 90-91.
Aft] 53 FERC at 65,227.
0
Docket No. EC90-10-000, gt al. northern New England is the most likely location for future non-utility generation and that excluding northern utilities from the NH Corridor could Icave them no assured way to sell power toThe presidin southern New England buyers.in allowing northern buyers to use the NH proposal beneficial The presiding judge stated Corridor to reach southern sellers.
"[m) ore competition for the movement of goods can only benefit the public," and that "[nJorthern utilities are just as that threatened by the merger's transmission curtain as southern ones." Afl/
Second, based on Utah, the presiding judge declined to make QFs eligible under the NH Corridor Propocal and extended eligibility to only those IPPs who qualify as
" utilities" under the FPA.112/
On exceptions, Nov Hampshire and NEPCO both opposeThey eligibility for northern New England utilities.111/
REMVEC utilities to reach northern sellers and that allowing northern sellers to reserve Corridor capacity vill limit the They assert that the opportuni+.ics for Eastern REMVEC utilities.
NH Corridor is already open to northern sellers in the sonne that southern buyers can choose to obtain power from the most They argue that allowing northern efficient northern sollers.
in sales that sellers to reserve corridor capacity may resultNEPCO argues in the alternative inefficient.
would otherwise be that northern sellers should be allowed to participate only through a "second tier" offering of any renaining capacity not taken by southern utilities.
NEPC0 argues that NEPCO also opposes eligibility for IPPs.
giving IPPs control over vital transmission links and participation in decisions to expand Corridor capacity to the long-haul "
have no " obligations to serve and comnitmentbecause the NH Corridor Proposa 454/
NEPCO argues that, allows eligibic utilities to buy from IPPs and allows IPPs to buy corridor transmission service indirectly through brokering, ef ficient IPPs vill be abic to sell their generaticn capacity.
s11owing sellers such as IPPs to reserve NEPCO argues that transmission capacity might result in inef ficient sales by limiting trannmission for more efficient suppliers.
L d.El/ 1.d.
A12/ Id.
HEPCO Brief on 153/ New Hampshire Brief on Exceptions at 23-25:
l Exceptions at 2-3, 10-15.
13.
j ggi/ 1:EPco Erief cn Exceptions at
- - -.. ~ -, - _,, _,,. _ _ _ _,. _
Docket No. EC90-10-000, 21 al.
- 91 The New England Cogeneration Association argues on exceptions that the presiding judge incorrectly excluded QFs from The Association eligibility for Corridor service. Alf/
argues that Utah does not require this result because the Commission expressly limited Einh's holding on QFs to the facts The Association also argues that here, unlike in of that case.
Elah, the relevant market is sufficiently competitive that QFu, even if granted access, will be unable to sell *. heir power at above-market administrative 1y-determined prices.
New Brunswick Power (NB Power) argues on exceptions that the presiding judge failed to expressly grant NB Power access to the NH Corridor.
NB Power notes that, as a foreign corporation, it NB Power may not be a "public utility" as defined in the FPA.
argues that no basis has been shown for granting access for other NB Power northern suppliers while denying access for NB Power.
asserts that such discrimination would be contrary to the United States / Canada Free Trade Agreement.
In briefs opposing exceptions, the Principal New England Intervenors and the Eastern REMVEC Utilities support the presiding judge's decision to allow access for northern utilities but argue, in the alternative, that the Commission should at a minimum implement HEPCO's suggested "second tier" of access for northern utilities. A1E/
We vill affirm the presiding judge's decision to allow access for northern utilities, as modified to reflect NEPCO's proposal of a second-tier offering for northern utilities.
The anticompetitive effects of this merger are not As the presiding All/
limited to the southern New England utilities.
"(n]orthern utilities are just as threatened by judge explained, The merger the cerger's transmission curtain as southern ones.
cuts each off from the other." A33/
Moreover, we see no as here, logic in denying eligibility for northern sellers where, those same sellers may indirectly reserve the same transmission l
AES/ New England Cogeneration Association Brief on Exceptions at 38-50.
Aff/ Principal New England Intervonors Brief opposing Exceptions Eastern REMVEC Utilities Brief opposing at 78, 83; Exceptions at 51.
immediately after the 312/ By "second-tier," we mean *. hat,Corrjdor capacity has been offered utilities for three months, the remaining unsubscribed capacity will be offered to the second-tier utilities for the next three months.
A16/ 53 FERC at 65,227.
i
I I
Docket No. EC90-10-000,,c1 AA. f Any possible inefficiencies caused capacity through brokering.
if at by seller access to corridor capacity could c>ccur only, and all, when transmission on the lui Corridor is constrained, thus should be only short-term in light of the agreement by NU and liEPCO to expand the Corridor.
Any short-term inefficiencies will be prevented by NEPCO's proposal to allow access for northern utilities only through a "second-tier" offoring.
- Thus, we will modify the presiding judge's ruling such that northern utilities vill be eligible to subscribe, but only af ter a first-These tier offering of Corridor capacity to southern utilities.
northern utilities will include HB Power, since we are unaware of any evidence or argument in this proceeding that justifies theexclusio cligibic here.
We vill also af firm the presiding judge's decision to allow Although NEPCO argues that IPPs might disrupt access for IPPs.
NEPCO of f ers no persuasive explanation of why or how this
- NEPOOL, see no rencon to vary f rom the Commission's We would happen.
decision in plaj1 allowing access for IPPs. A12/
however, reverse the presiding judge's denial of We will, access for QFs, based on a subsequent refinement of the Commission's plah decision.
In Western SysMms Power Pool, in AqQ/ the Commission recently authorized QFs to participate a powcr pool trading arrangement if they agreed to waive their PURPA rights to require a utility to buy from them and purchase their QF output at avoided cost.
The waiver, howcVer, applied A similar result is only to cales within the power pool.
appropriate for QF eligibility under the lui Corridor Proposal.
Eligibility will extend to any QF that agrees to waive its PURPA rights to require a utility to buy from it and purchase its QF output at avoided costs.
3.
DgadliDe f or Subggribing The NN Corridor Proposal requires submission of binding requests for transmission service within three months af ter the initial offering date. LEl/
The proposal also requires NU and NEPCO to continue offering any uncommitted transmission 1993. 162/
Trial Staff and the capacity until November 1, 459/ 47 FERC at 61,740-41.
55 FERC 5 55 FERC 5 61,099 at 61,322, p_rdar on reh'a 160/
61,495 (1991).
151/ Ex. 154 at 2.
$9.2) M. at 5.
Docket No. EC90-10-ooo, gg 31 c intervenors proposed to extend the of fering period to May 1, 1995. A12/
r f
The presiding judge approved the proposed extension, 111/ stating that the extended deadline is the same date I
agreed to by NU in its settlement Vith the 18 Vermont Utilities.
[
He also noted that NEPCO did not oppose the extent, ion.
351/
shh/
On exceptions, the Principal How England Intervenors note that the-}m Corridor Proposal allows subscribers to extend their initial ten-or 20-year service term only if the subscriber 1995 (five obtains a firmly committed power supply by October 31, to 15 years before the requested extension). All/
These intervenors argue that the Commission should:-
(1) eliminate the (2) not limit extension to committed power supply requirement; require only "reasonabic notice,"
i I
ten-year periods; and (3) including no substantial notice if the capacity is not o committed.
We will af firm the presiding judge's extension of the subscription deadline but reject the intervenors' additiunal NEPCO is not an applicant in this proceeding and modifications.
J its willingness to of fer an extended term of service only to
- Moreover, i
customers with committed power supplies is reasonabic.
t the other proposed modifications will hamper NEPCO's ability to I
We find no basis for imposing plan its transmission system.
i these additional requirements on NEPCO.
We will, however, require one other modification to the I
As discussed nbove, we vill require a i
subscription deadline.
j second-tier offering of Corridor capacity to northern utilities, The first-tier offering begins with the initial offering date and We will require tne second-tier l
i extends for three montns.
of fering to boain three months af ter the initial of fering date and extend for the three months thereafter, j
i h
i 463/ Ton Eastern REMVEC Utilities Brief on Exceptions, Appendix at 5.
t Af3/ 53 FERC at 65,228-29.
i 111/ Tr. 2540-41; Ex. 123T at 4.
Aff/ NEPCO Initial Brief at 25.
86.
j 467/ Principal New England Intervenors Brief on Exceptions at L
f l
L
= _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ - _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Docket No. EC90-10-000, at Ll. Maxinum Duration of_Servise 4.
The NH Corridor Proposal would expire by its own terms af ter The Principal New England Intervonors suggest instead that servicc under the NH Corridor Proposal should continue f or 30 years.
as long as the merger vould otherwise be anticompetitive.
They ask that the merger be conditioned to require NU 111/
to offer Corridor capacity beyond 30 years, until NU can the Corridor Proposal is no longer necessary to demonstrate that protect the public interest.
We vill reject the Principal New England Interver. ors' They have offered inadequate justification for their proposal.
novel proposal, which would inevitably lead to relltigation of a The substantial part of thir case 30 years from now.
intervenors' proposal vould also lead to excessive uncertainty for transmission planners and parties-to potential transmission arrangements as they avait the outcome of this future litigation.
For these parties, a fixed duration of 30 years vould represent while a duration dependent on future litigation would provide 3 essentially no such certainty until the litigation was finally The public interest vould be better served by a fixed _
decideo.
duration of service than by a duration dependent on the uncertain outcomo of litigation to be conducted 30 years f rom now.
Moreover, the GTC will be applicable.
E.
Ecgional 7,ranmission Arranaccent In its concral Transmission commitments, NU agreed to support the development of a regional transmission program for all of New England:
NU shall support all responsibic ef forts to develop and implement a Nov England regional program concerning access to and oayment for uneeling servi,ces on existing and nov transmission fscilities.
In the event that a regional transpission program is approved by the affected utilities and regulators, which dif f ers f roa or adds to a commitment made by NU herein, such regional program shall roplace and supersede NU's. commitment to the J
extent of such difference or addition.
(469/)
AkR/ 14. at 85.
A12/ Ex. 178 at 9.
l Duckot No. EC90-10-000, gt al. The presiding judge found merit in the idea of a regional (RTA), and videspread support for the transmission arrangement idea among the parties in this proceeding. Ala/
Accordingly, the judge required NU, within six months after consummation of the merger, to submit to NEPOOL for its consideration a draft proposed RTA, prepared af ter consultation with other NEPOOL members, state regulatory bodies, and other potential The judge did not explicitly address transmission customers.
NU's suggestion that the RTA supersede the conditions imposed in this proceeding.
On exceptions, two groups of intervenors support the judge's decision generally but argue that two ancillary requirements are necessary.
First, the Eastern REMVEC Utilities argue that the RTA should supersede the other merger conditions.
They assert that, without this provisinn, requiring NU to submit an RTA to HEPOOL vould allow NU to merely "go through the motions of drafting an RTA," instead of working to achieve a " viable, 121/
They contend that NU nhould be given consensual" RTA.
an incentive to achieve such an RTA, by allowing the removal or replacement of the other conditions imposed here on RU if and when the Commission approves the RTA.
Second, the Ten Eastern REMVEC Utilities argue that NU shculd be required to file its draf t RTA not only with NEPOOL but also with the commission.172/
They assert that such a filing would serve two purposes:
(1) it would ensure compliance it with the requirement that NU produce a draf t RTA; and (2) would give the Commission an. opportunity to inquire into NU's implementation of the other merger conditions, in order to ensure that the conditions were still achieving their intended results.
They argue that such a procedure is akin to the follow-up filings required in ILt.ab.122/
New New Hampshire opposes these exceptions. 474/
Hampshire argues that these intervenors are merely seeking an enhanced bargaining position, not an improved RTA.
New Hampshire asserts that the intervonors' proposals vould allow them to prevent the 2erger by delaying the tangential RTA negotiations, 3,e., to hold the merger hostage as a negotiating tactic.
Ala/ 53 FERC et 65,229-30.
123/ Eastern REMVEC Utilities Brief on Exceptions at 28.
All/ Ten Easterm REKVEC Utilities Brief on Exceptions at 77-79.
All/ 4 5 FERC at 61,303-05.
474/ New Hampshire Brief Opposing Exceptions at 63-64.
Docket No. EC90-10-000, g.t al.,
The Commission will reject the exceptions.
As to the proposal that other merger conditions be removed or replaced by the members of NEpOOL'are free to negotiate and file an the RTA, RTA that would expressly seek to supersede the conditions ordered i
Any such provision of the RTA would, of course, be subject j
here.
to our review and approval.
At this tinie, however, the terms of l
the RTA are unknown and the Commission is thus in no position to l
decide whether the RTA should replace the other merger conditions i
ordered here.
Until we know the terms of the RTA, we cannot decide whether they supplant the need for the other merger l
conditions.
Second, _ we see no benefit in requiring a simultaneous filing of the draf t RTA with the Commission.
There is no reason to suspect that NU.wil1~ not submit the draf t RTA to-NEPOOL.
Moreover, any f ailure by )W to comply with this condition (or any other condition) would in all likelihood be brought quickly to the Commission's_ attention by one or more of the intervenors.
j 1
Nor does the Commission need at this time to provide itself an
(
opportunity to review im's implementation of the merger conditions, since we may order an investigation at any appropriate time.
Finally, the intervenors' - citation to Etah is unpersuasive.
l No proceedings were ordered in that case for the purpose of
_j comprehensively reviewing the~ merged company's implementation of the merger conditions.
Instead, the rate proceedings ordered there were for the much narrower and nore focused purpose of l
ensuring that the merger benefits were reflected in wholesale f
rates as soon as possibic, as well as reviewing the merged company's progress toward implementing single system rates.
While we :nay subsequently decide to fully review IN's implementation of the merger conditions, now is not the time to >
make that decision.
~U.!
h:' C)
C I
~
F.
NEPOOL Voting i
Under the NEPOOL Agreement, NEPOOL members receive voteE'"hnT N NEPOOL's Management Committee based on their annual peak loaQD. @ M i
~ Af firmative action by the Management Committee must be, ch l
4 i?_5/
least 75 percent of the total number of votes ^~ ;,D,*: c-5 g
approved by at Such actions can be vetoed by any two members with 15 476/
- ,:J.' D percent of tho total number of votes or one member with 2b
'T i
percent. 477/
Amendments to the NEPOOL Agreement must be-a...
.T / *
.D-S "1
O '.
1 i
<r
,[]
475/ Ex.~603 at 19.
m r-g l
476/ M.
a.
la 477/ M.
i i
i t
d
1 Docket lio. EC90-lO-000, 2A A1 478/
IN now has about approved by 85 percent of the votes.the votes; the merged company Vill have about 29 22.5 percent of percent. 112/
Several parties argued that the merged company, with its increased market power and the ability to veto action by the Management Committee, would have too~ much power in llEPOOL.
Accordingly, they proposed a condition (Core Condition 7) regarding NU's voting rights, which states in relevant part that:
NU Companies shall not act by exercise of its voting power or otherwise within liEPoOL to prevent, delay or block proposed amendments to the liEPOOL Agreement by which IN Companies' voting power on NEPOOL Committees will be reduced.
}N Companies vill support, without condition, amendments to the NEPOOL Agreement limiting its power in NEPOOL Committees.
IN Companies shall not take or advocate a position at HEPOOL that is contrary to this condition.
NU Companies may oppose any such proposed amendments when filed with the Commission. ( Af_Qf )
Core condition 7 also contains an exception allowing the merged its full, unrestricted voting power whenever company to vote NEPOOL votes on the adoption, amendment or repeal of an RTA.
subject to The presiding judge approved Core Condition 7, condition "will provide stating that the certain modifications, assurance to all HEPOOL members, and will help make some valuable the transaction consistent with the public interest." All/
The judge also noted that IN agreed to similar restrictions under the NH Corridor Proposal. ALj The modifications imposed by the judge altered Core condition 7 such that, intm alin, NU/PSNH's voting strength 23.5 percent; the cannot be reduced below IN's current restriction applies only to votes on the Management Committee; 478/ M. at 204-05.
479/ Ex. 125; Ex. 524 at 33; Ex. 277 at 12-14.
480/ Ten Eastern REMVEC Utilities Brief on Exceptions, Appendix at 6.
Sre.glig Ex. 601 at 28; Ex. 607 at 1; Ex. 477 at 29-34; Ex. 479 at 30-31; Ex. 524 at 37; Tr. 5476-78.
481/ 53 FERC at 65,230.
18.2/ M.
,S e e Ex. 154 at 8.
l
. _-=
l Docket No. EC90-10-000, ci gl.
- 38 the restriction vould not apply to any proposal "concerning" a regional transmission arrangement; and any proposal to limit HU/PSNH's vote must be submitted to the Management Committee within 90 days af ter consummation of the merger.111/
)
NU argues on exceptions that this restriction on its voting power would be discriminatory since it would apply only to NU/PSNH. 3f3/
NU also notes that it had a veto power for five years of existence, and that the New England NEPOOL's first Elcetric System has always had such veto power, but neither party has ever used its veto.
UU argues that the NEPOOL Agreement was approved by the Commission and expressly allows for the 25 percent one-party veto.
UU also asserts that its veto power would matter only if NU opposed an action supported by all 90 of the other NEPOOL members.
According to NU, the restriction would forever keep NU's voting power below 25 percent even if NU's future load growth, apart f rom the merger, vould otherwise entitic UU to a veto power.
Finally, NU argues that the issue of NEPOOL voting was not set for hearing.
Trial Staf f and the intervonors raise several concerns on exceptions. Afj/
They opptse the 90-day deadline imposed by the judge for submissions
',f proposals to NEPOOL to restrict the merged company's voting puwer.
They contend that, without the deadline, Core Condition 7 would be an applicabic only if and when NU/PSNH 's % W r.J power posed prw Oms because of NU/PSNH's conduct within N.iP00L.
Alternatively, they seek a submission deadline of nine months, instead of 90 days, to allow for pre-deadline 1111ng era review of the RTA, arguing that the RTA may relieve the need ice restrictions on NU/PSNH's veto power.
They oppose a requirement that the Maragement Committee vote unaninousiv to lestrict NU/PSNH's vote, a requirement suggested by the presiding judge's statement that the condition would apply only "where all other NEPOOL members theaselves voted to restrict the merged company's voting strength.
" fff/
- Pinally, they argue that the exception allowing the merged company to use its unrcstricted voting power regarding an RTA should apply only to a vote on the " adoption, amendment or repeal" of an RTA, as stated in core condition 7, not to any proposal aconcerning" the RTA.
483/ 53 FERC at 65,230-31.
484/ NU Brief on Exceptions at 98-102.
See also New Hampshire Brief on Exceptions at 29-30.
111/ Trial Staf f Brief on Exceptions at 81-82; Principal New England Intervonors Brief on Exceptions at 87-88 ; Eastern REKVEC Utilities Brief on Exceptions at 29-30.
111/ 53 FERC at 65,230 (emphasis in original).
Dochot No. EC90-10-000, gi al.
- 99 In reply, NU generally opposes the exceptions of Trial Staf f and the interveners but agrees that the initial decision should not be construed to require a unanimous vote to impose a voting restriction. AB2/
With two exceptions (discussed below), we vill affirm the judge's ruling and reasoning.
A restriction on the merged company's veto power is not unduly discriminatory because only NU/PSNH is seeking approval of a merger giving it increased market power and a veto in HEPOOL.
While NU never used the veto it had during HEPOOL's first five years of existence, the merged company vill have dramatically altered market power and incentives compared to NU at that time.
As the judge stated, "that was before the merger.
How the smaller companies are confronting NU/PSNH, with a ' transmission curtain' effectively isolating them, while also controlling surplus capacity."
Moreover, the merged company will remain free to oppose 113/
any voting restriction when it is filed with the commission, and the NEPOOL Management Committee will retain authority in the future to rescind any voting restriction (sub$cet to Commission approval).
We will modify the presiding judge's decision, however, to eliminate the unanimous vote requirement.
The NEPOOL Agreement does not require a unanimous vote for either af firmative action by the Management committee or amendment of the Agreement itself No evidence-has been cited in support of a unanimous vote requirement and NU apparently does not sock such a requirement.
In fact, the presiding judge may not even have intended such a since Core condition 7 contained no such requireme nt requirement, and the judge did not list this point among his modifications.
Regardless, we find no basis for imposing such a requirement.
We will also modify the scope of the RTA exception to the voting restriction so that the exception applica only to votes on the " adoption, amendment or repeal" of an RTA, instead of all votes "concerning" the RTA.
To paraphrase the judge's reasoning on another RTA-related point, the "concerning" limitation cuts too broadly and would invite endless disputes about whether a particular matter does or does not " concern" the RTA.112/
G.
Env Hampshire Electric Cooperative The New Hampshire Electric Cooperative (liH Cooperative) is a wholesale customer of PSNH.
NH Cooperative proposed three AA2/ NU 3rief Opposing Exceptions at 90.
488/ 53 FERC at 65,230.
489/ Id. at 65,231.
4
,,-,.,n..
j l
- 100 -
Docket Ho, EC90-10-000, Et al.
conditions on the proposed merger.
The presiding judge rejected all three conditions. Lu/
We vill af firm with further discussion the judge's rejection of the first condition and, as I
noted above, vill summarily af firm his rejection of the second and third conditions.
f The Nil Cooperative's Condition 1 vould require the merged (1) PSNH's commitments under company's " faithful honoring" of certain seabrook-related agreements between the Nil Cooperative and pSNiit (2) other commitments contained in a settlement term another sheet entered into evidence here as Exhibit 13; or (3) agreement to be negotiated on terms acceptable to the NH Cooperative. 411/
The presiding judge rejected this condition as not merger-related. 412/
The judge stated that "[t)his dispute between involves essentially New Hampshire parties is local in nature,and is being pressed before the New Ha i
intrastate matters, Commission and the New Hampshire state courts." inf The N11 Cooperative excepts to the judge's ruling.114/
The NH Cooperative argues that NU's reorganization plan and the PSNH rate plan do not reflect the full cost owed by PSNH to the The Ni NH Cooperative under the Seabrook-related agreements.
is needed to prevent l
Cooperative asserts that its Condition 1 approval of the merger from hindering the NH Cooperative's The N11 ability to enforce the Seabrook-related agreements.if the merged company does n Cooperative states that, the NH Cooperative may with the Seabrook-related agreements, itself end up in bankruptcy. iM/
The r
We will reject the NH Cooperative's condition 1.
proposed merger vill not af f ect the enf orceability of the j
The enforcement and Seabrook-related agreements. 416/
interpretation of these agreements is being litigated before the i
New Hampshire Commission, the New Hampshire state courts and this e
19/ M.
111/ NH -Cooperative Brief on Exceptions at 2.
l 112/ 53 FERC at 65,231.
19/ M.
314/ NH Cooperative brief on Exceptions at 26-32, f
iM/ We note that the NH Cooperative is now in bankruptcy..
iM/ Ex. 9 at 42 Ex. 400 at 13; }icarino Order, 50 FERC at f
61,836.
'.c 101 -
Dockot No. ECDO-10-000, FA gl.
Our approval of the merger will not affet.t the Commission.
Thus, the NH parties' rights under those agreements. Cooperative's condition 1 is the merger on competition.
H.
Environmental Asses 1 mat Holyoke asks the Commission to conduct a review of the potential environmental impacts of the proposed merger. Lt2/
Holyoke argues that the merger, if approved, vill af feet thecon in a large region.
Holyoke argues that conducting an environmental review of a proposed merger af ter issuance of the initial decision is consistent with the Commission's action in ARA /
Holyoke also EsAthern california Edissn comoany.the need for an environmental review in this asserts that proceeding was not apparent until af ter development of theinitial decision, when it evidentiary record and-issuance of the became clear that W, under its own commitments and under the judge's modifications, would be building new transmisnien facilities.
W argues in reply that Holyoke's request for an NU asserts environmental review should be rejected as untimely.
that Holyoke did not make the request until af ter issuance of the initial decision, even though NU's transmission policies have been a prominent issue since the inception of this proceeding.
NU also arguec that in Etah 19.2/ the commission decided that approval of a merger is not a _ major f ederal action requiring NU acknowledges that an environmental environmental reviev.
review was ' undertaken in Southern _Ralif ornia Edison but argues that the requests for that review were timely and that the Commission had specific information indicating that the proposed merger could have made the already-poor air quality in southern California even worse, We vill reject Holyoke's request for an environmental Approval of the disposition of facilities under sectier.
review.
-203 of the FPA does not generally constitute a major federal action significantly affecting the quality of the huwan.Such activity gen environment.
Thus, mergers are
=
ownership or a change in corporate structure.
l l
l l
~
12]f Holyoke Brief on Exceptions at 20-22.
123] 49 FGC 1 61,091 (1989).
19_2/ 47 F G C at:61,734-36 (1989).
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Docket No. EC90-10-000, 21 A1..
- 102 categorically excluded f rom the requirement to prepare an environmental impact statement. EqQ/
While the Commission required the performanca o'.
a.,
in Southern Ca1 LLQIniA_lY,frJllD. the environmental assessment Commission's decision there was prompted by specliic f actual allegations indicating that "the proposed merger could add hundreds of tons of additional air contaminants to the most In fact, those applicants' polluted air in the Nation." EQl/own filing before a state commission contained opera that could have significantly increased air emissions from the applicants' facilities.
Holyoke has pointed to no similar evidence in this proceeding.
argues that the need for an environmental review
}lolyoke on the transmission policies contained in NU's own rests in part commitments. 192 /
Despite im's early submission of these commitments ac record evidence, EE2/ Holyoke presented no testimony on the need f or an environmentel review and cade no request for such a review e.'ther on the record or in its brief to the presiding judge.
Inst ud, Holyoke presented its request initially in its Brief on Exceptions.
Given Holyoke's argument, any alleged need for an environmental review could and should and certainly before have been apparent to Holyoke long ago,From the beginning of this initial decision.
issuance of the the Commission has stressed the importance of rapidly proceeding, resolving the case. 193/
Delaying the resolution of this case for an environmental review that Holyoke could and should have requesteo long ago (if at all) would be contrary to the public interest.
I.
OnbudErdD Holyoke proposed a condition requiring IN to appoint and compensate an ombudsman f or NU's FERC-jurisdictional customers.
The ctbudsman would be a person experienced in electric 193/
EQQ/ 18 C. F. R. 5 380.4 (a) (16) (1991).
10_1/ 49 FERC at 61,357.
LQ2/ Holyoke Brief on Exceptions at 22 n.28.
192/ Ex. 155: Ex. 178.
EQAf Hearing Order, 50 FERC at 61,834, 61,839-40.
505/ Ex. 376 at 2-3.
Docket No. E C9 0-10-0 0 0, 21 al.
- 103 bulk pover matters who is not a past or present NU cmployee, The appvintment would be for five years. Eq2/
The fu/
not omnadsman vould serve only FERC-jurisdictional customers, retail customers. 523/
The presiding judge approved Holyoke's proposed condition requiring the appointment of an ombudsman IRE /
The judge explained that the selection of the ombudsman would be made by NU, that the amount of compensation wnuld be set by NU and that the appointment could be full-time os part-time, as circumstances warrant.
The judge noted that NU's past transmission practices He stated that, after produced criticisms from its custcmers.
service that NU provides under tr.rif fs (instead of by the merger, individual contract) may also generate complaints.
The judge concluded that an ombudsman can help the merged company to "of fer viable wheeling service to alleviate potential anticompetitive consequences. " 112/
The judge found the appointment of an ombudsman " appropriate to secure maintenance of adequate servicc a
under section 203(b) of the FPA.
NU, the Connecticut Commission and the Eastern REMVEC Utilities filed exceptions. Ell /
They assert that Holyoke's sole argument in support of an ombudsman is based on past in 4U's favor.
disputes on which the Commission has already ruled They argue that the judge of fered no merger-related reason for requiring an ombcdsman and no reason why an ombudsman is needed to make the merger " consistent with the public interest."
They that an ombudsman would be a serious intrusion into also assert the merged company's internal management, could disrupt the verged company's business, and could conflict with state authority to regulate transmission siting and purchased power activities.
They argue that, even without an ombudsman, customers may complair to the Commission when varranted.
They also assert that the judge s ecified i.o procedures or duties for the ombudsman and merely int, sed another layer of bureaucracy at ratepayer expense.
104/ Holyoke Initial Brief at 5; Holyoke Brief Opposing Exceptions at 17-1B n.57.
Epl/ Id.
508/ Id.
529/ 53 FERC at 65,231-32.
51nf & at 65,231.
Connecticut Commission Ell / NU Brief on Exceptions at 102-03 ; Eastern REMVEC Utilities Brief Brief on Exceptions at 50-54; on Exceptions at 31.
l J
Docket No. EC90-10-000, g1 nl.
- 104 -
Holyoke responds that the eppointment of an ombudsman is justified by record evidence demonstrating NU's " onerous, domineering and dilatory" tactics.112/
Holyoke asserts that an ombudsman can mediate disputes generated by such tactics.
Holyoke contends that NU's opposition to an ombudsman says a the issue. 513/
Holyoke also argues that an ombudsman can Holyoke notes that the ombudsman reduce the need for litigation.
need not be unduly costly, since NU may compensate the ombudsman by the day worked.
We will reject Holyoke's proposal to require NU to appoint Customers dissatisfied with NU's service may file an ombudsman.
This complaint complaints with this Commission when varranted.
procedure is a suf ficient means of addressing any jurisdictional The appointment of an disputes between NU and its customers. ombudsman vould establish an u in this proceeding.
justified by the evidence Transnission Dependent Utilitien J.
intervenors argued that the unique dependence of The transmission dependent utilities (TDUs) upon NU or PSNH for financial support transmission service and the TDUs' historical f or NU's or PSNH's transmission system require the imposition of The intervenors a condition specifically addressed to TDUs.
which would require the merged proposed Core Condition 10,
-onpany to of fer each TDU " access to the NU transmission system rights to the use of that sfstem equivalent to those incurred by viu.
exercised by NU itself at a cost equivalent to that NU itself for a comparable service and usage." 111/
The presiding judge found the TDUs " uniquely vulnerable to possible anticompetitive conduct" and " entitled to some measure 515-of protective assurance regarding NU/PSNH's post merger conduct."
rejected Core Condition 10, however. because it would The judge "give the TDUs a higher status than they had bef ore the merger. "
in 111/
Instead, the judge cited the Commission's statement the Hearing Order that the merger will not af fect existing 112/ Holyoke brief Opposing Exceptions at 17-22.
512/ Id. at 19.
Appendix 113/ Ten Eastern REKVEC Utilities Brief on Exceptions, at 8.
See also Ex. 386 at 61-62; Ex. 405 at 16.
515/ 53 FERC at 65,2 3 3.
511/ Jd.
105 -
Dockot No. EC90-10-000, gi gl.
contracts, 511/ noted the ongoing negotiations between NU and and decided "it would be prudent for present purposes the TDUs, simply to maintain the status gun, - the situation which the Commission's order envisions." Elf /
The TDUs argue on exceptions that, despite finding the TDUs uniquely vulnerable to anticompetitive conduct, the judge failed 112/
The TDUs assert to implement a remedy for the TDUs.
that their total dependence upon the'.r principal competitor for essential transmission service raises policy concerns not present with other transmission customers.
They also argue that UU's General Transmission Commitments will harm the TDUs, since NU treated their load growth as native load, but in the past,
- has, will now treat it as incremental load.
The TDUs contend that treating their load growth as incremental load ignores their The TDUs also support for the NU transmission system.
historical the judge wrongly relied on the pending negotiations argue that The TDUs state that, in denying the relief sought by the TDUs.
the if the Commission declines to impose Core Condition 10, Commission should at least order NU to of fer each TDU a
" comprehensive transmission arrangement" comparable to its arrangement with CMEEC, a TDU that settled with NU.
NU and the Connecticut Commission oppose the TDUs' exceptions. 520/
They argue that the merger does not harm the TDUs since they are equally transmission-dependent bef ore and They contend that the TDUs are, in fact, after the merger.
better of f af ter the merger because they will then have enforceable rights against the merged company under the General Transmission C mmitments and the NH Corridor Proposal.
NU states that it is willing to negotiate CMEEC-like Furthermore, so long as such agreements recognize agreements with the TDUs,each TDU's unique characteristics and existing contract TDUs agree to pay a load-ratio share of the merged company's transmission costs.
NU asserts that, to date, only CMEEC has agreed to pay such a rate.
We agree with the Judge's conclusion that the TOUs ate uniquely vulnerable to anticompetitive conduct resulting from the The TDUs are electrically interconnected with only UU or merger.
Ell / Hearina Order, 50 FERC at 61,836.
118/ 53 FERC at 65,233.
Ell / TDUs Brief on Exceptions; Principal New England Intervenors Brief on Exceptions at 70.
Connecticut NU Brief Opposing Exceptions at 75-77; 120/ Commission Brief Opposing Exceptions at 105.
4 Docket No. EC90-10-000, gt al.
- 106 -
The TDUs are entirely dependent on NU or PSim for PSNH 122/
their bulk transmission needs. 122/
Without the merged company's transmission service and f acilities, the TDUs would be unable to engage in any bulk power transactions. 522/
To engage in wholesale power transactions, the TOUs must either trade with or compete against the same company upon whom they These customers depend for all bulk power transmission service.
are indeed " uniquely vulnerable" to the anticompetitive effects of the merger identified above. 12A/
The TDUs are entitled to some level of protection from such anticompetitive effects.
We vill, however, reject Core Condition 10.
The effect of Taken literally, Core Condition 10 Core Condition 10 is unclear.
would give the TOUs a status equivalent not just to NU's native load customers but to NU itself as owner and operator of its transmission system, an unprecedented result.
To the extent the TDUs intended Core Condition 10 to achieve less, they have not language that plainly expresses their goal and we are proposed unwilling to rewrite their proposal to achieve what we can only guess they intended.
We vill instead order the merged company to file a tariff under section 205, concurrent with the filing of the other transmission tariffs ordered here, offering the TDUs a comprehensive arrangement for transmission service comparable to Consistent with NU's the arrangement NU has with CMEEC.
NU may propose to require the TDUs to pay a agreement with CMEEC, NU load-ratio share of the merged company's transmission costs.
committed on the record of this proceeding to of fer the TDUs such an arrangement.
NU's counsel stated that:
[H)U will agree to of fer the TDUs a for use of the NU comprehensive arrangement transmission system comparable to the arrangement it has with CMEEC.
That reflects their proportion of use of the system and they're [ sic) paying a proportionate rate for use of the system. [121/ ]
521/ Ex. 386 at 34; Ex. 381 at 2.
522/ Ex. 386 at 8; Ex. 400 at 10; Ex. 157 at 234, 240-41.
312/ Ex. 409 at 3.
45 FERC at 61,291, 61,293-94 and 48 FERC at 61,182 124/ See Utah, and (TDUs had been " competitively disadvantaged in the past" "the merger would make matters worse").
121/ Tr. 7789-90.
l
(
l Docket No. EC90-10-000, g1 al.
- 107 -
NU witness Schultheis also stated several times that NU is willing to offer the TDUs such an arrangement. 121/
While NU has stated that such arrangements must reflect each this concern TDU's unique characteristics and existing contracts, is insufficiently developed on the record to address these Instead, NU should reflect possible differences at this time.these differences in its proposed tariff as it sees The TDUs may then challenge any proposed tariff provisions they find The Commission, with one exception, will defer inappropriate.
until then all issues about unique characteristics and existing The exception is that we hold at this time that this contracts.
NU and the TDU tariff will not nullify existing TDU contracts.
TDUs will remain bound to their existing contracts.
V.
Rates A.
Capacity Interchance Acreements' Return On Ecuity we will summarily affirm the judge's As noted above, acceptance of Trial Staf f's 13.50 percent return on equity for the capacity Interchange Agreements.
The Commission's policy in determining a rate of return on common equity has been to accept an appropriate equity return, within a zone of reasonableness, based upon test period record However, because the effective period of the rate evidence.
under consideration may extend beyond the test period evidence and the date of the Commission's order, it is appropriate to take into consideration post-record changes in capital market conditions in establishing an equit, return allowance. E22/
Where the rate at issue is "open-ended,"
i,c,,
where no the commission considers the superseding rate has been filed, time period from the ef fective date of the rate up until the date of the Commission decision as equivalent to a locked-in period 123/
A for purposes of updating the equity return allowance.
is then developed, using the separate equity return allowance 126/ Ex. 157 at 118, 239-42; Exs. 123KK - 123NN.
Our adjusted equity return allowance must remain within the 527/ record-based zone of reasonableness.
See, azg2, Boston Edison Company, Opinion No. 299, 42 FERC 1 61,374, reh'a denied, opinion No. 299-A, 43 FERC 1 61,309 (1988), aff'd, Boston Edison Company v. FERC, 885 F.2d 962 (1st Cir. 1989).
Southwestern Public Service Company, opinion No.
523/ See,
e.o.,
379-A, 53 FERC 1 61,084 at 61,240, order on reh'q, Opinion No. 339-B, 53 FERC 1 61,408 (1990).
l 1
l 108 Docket No. EC40-10-000, ni al.
most recent capital cost data available, to be applied prospectively. 522/
Accordingly, we will update the equity return under the Capacity Interchenge Agreements for both periods discussed above.
The first period extends from July 27, 1990, the effective date Capacity Interchange Agreements 52&/ until the date for the The 13.50 percent return on equity, accepted of this Opinion.
was calculated based upon a Discounted Cash Flow (DCF)
- above, methodology using data for the six-month period ending August 31, Federal Reserve Bulletins indicate that during this 1990.
the average yield on ten-year constant maturity U.S.
- period, Treasury bonds was 8.64 percent. Ell /
During the period the rates have been in effect (consisting of the twelve-month period of July 1990 through June 1991) the average yield on ten-year This constant maturity U.S. Treasury bonds was B.35 percent.
represents a 0.33 percent average reduction in yield which, when subtracted f roc the 13.50 percent return on equity accepted results in an adjusted return on equity of 13.17 percent, herein,is within the range of reasonableness recommended by Trial which Staff. 522/
The second period for which we will update the return on equity allowance is prospectively from the date of issuance of this opinion.
The average yield on ten-year constant maturity U.S. Treasury bonds for the most recent six-month period for which data are available is 8.07 percent. 522/
This equates which reduces the to a 0.57 percent average reduction in yield, to 12.93 percent, a rate which equity return f rom 13.50 percent is still within the range of reasonableness supported on this record.
Therefore, for the Capacity Interchange Agreements, we will adopt an adjusted equity return of 13.17 percent for the locked-in period and 12.93 percent prospectively from the issuance date of this opinion.
Pacific Gas and Electric Company, Opinion No. 356, 53 FERC i 329/
61,146 (1990).
529/ 53 FERC at 61,839.
521/ We take of ficial notice of the relevant Federal Reserve Bulletins and Statistical Releases.
522/ Trial Staf f's range of reasonableness for return on equity was 11.61 to 13.55 percent.
Tr. 6648.
533/ January through June 1991.
l
Docket No. EC90-10-000, gt RA.
- 109 -
Seabrook Power Centract's Aeturn On Eaulty B.
As part of the merger, ownership of PSNH's approximately 35.6 percent share of Seabrook will be transferred to North Atlantic, a newly-created subsidiary of NU.
The proposed Seabrook Power Contract governs the sale of Seabrook power by North Atlantic to PSNH.
The contract is a life-of-the-unit power sales agreement under which PSNH will purchase 100 percent The of North Atlantic's share of Seabrook's capacity and energy.
contract allows North Atlantic a 13.75 percent return on equity first Ell / on its $700 million investment in Seabrook during the ten years of the Seabrook Power Contract, pursuant to a cost of service formula rate.
NU states that the negotiated 13.75 return on equity is an essential element of the overall percent reorganization plan for PSNH.
NU argues that a substantial reduction in the return on equity in the Seabrook Power Contract "could render the deal unfinanceable," and thus could be a " deal breaker." 535/
NU submitted no direct evidence in its case in chief to support this figure, 536/ however, NU argues that it the 13.75 percent return on equity is reasonable because proposed to apply this return to an investment of only $700 million, rather than NU's total $2.3 billion investment in PSNH.
NU asserts that in Northeast Utilities Service Company 122/
12R/ the Commission approved the proposed return on equity based, on the fact that NU's formula rate excluded the costs of in pa rt,
certain transmission investment from rate base.
The Trial Staf f presented the only return on equity study on this record, recommending a 13.1 percent return on equity for North Atlantic. 129/
The Trial Staff's proposed rate of return was calculated using the DCF method and a comparable risk analysis.
The Trial Staff used NU as a proxy for North Atlantic and concluded that the proposed 13.75 percent rate of return is excessive, but that a 13.5 percent rate of return would be 534/ NU Initial Brief at 112.
125/ Ex. 6 at 58; Tr. 1946-47; NU Brief Opposing Exceptions at 115.
536/ NU did, however, submit rebuttal testimony (Ex. 207) in response to Trial Staff's rate of return analysis.
122/ NU Brief Opposing Exception at 116-18.
528/ 52 FERC 5 61,097, reh'a denied, 52 FERC 1 61,336 (1990),
petition for rev, filed sub nom. City of Holyoke Gas &
Electric Depar.tment v. FERC, No. 90-1565 (D.C. Cir. Nov. 26, 1990).
S39/ Trial Staff Brief on Exceptions at 89; Tr. at 6648.
29m
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,ea
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.AM, et m
4
>Am44
+-Aa a.=
4*a
_..h4 m
__ 4 110 -
Docket No. EC90-10-000, gh A1 appropriate for NU, 512/
In order to determine the proper rate of return for North Atlantic, the Trial Staf f adjusted the initial calculation downward by 0.4 percent to reflect its assessment that the terms of the Seabrook Power Contract make
-North Atlantic a less risky investment than-NU.
Specifically, Trial Staff argues that North Atlantic is less risky than NU because the Seabrook Power Contract uses a cost-of-service formula Ell / and guarantees payment by PSNH to North Atlantic regardless of whether Seabrook operates. 112/
The presiding judge rejected the Trial Staf f's analysis and instead applied the "end result" test to determine that the proposed 13.75 percent rate of return is just and reasonabic.
In making this determination, the judge accepted RU's 512/
argument that a larger portion of NU's total investment in PSNH could have been assigned to North Atlantic. 511/
In Northeast Utilities Service Coreany, suora, we noted that NU's exclusion of certain f acilities from rate base in part In the instant justified its claimed return on equity. 5A5/
however, Herth Atlantic has not excluded any costs from its
- case, on the evidence in this proceeding, cannot claim a rate base and, rate base larger than the $700 million investment reflected in the Scabrook Power Contract. 546/
As NU's own witness testified, the portion of NU's investment that has not been assigned to North Atlantic, consisting of non-Seabrook assets valued at $808 million and an " acquisition premium" valued at The
$800 million, have been assigned to PSRH itself.112/
Commission's standard ratemaking practice has been to allow a return on rate base, established using original cost investment.
Accordingly, there' is no basis - f or concluding that North Atlantic could have rightfully claimed a larger rate base.
Staf f's range of reasonable returns on equity was 11.61 to 540/
13.55 percent.
Tr. 6648.
511/ Ex. 9 at 28.
542/ Ld. at 34.
543/ 53 FERC at 65,235.
5 A.4. / 1 $.
515/ 52 FERC at 61,485-86.
i 546/ Tr. 1527.
547/ Ex. 9 at 23-24; see also Tr. 1711.
\\
i 111 -
Docket No. EC90-10-000, El al.
In relying on NU's "end result" argument, the judge wrongly ignored the Trial Staf f's analysis of the proper return on We believe that the evidence fully supports the equity.
and conclusion that NU's proposed rate of return is not just reasonable and that Trial Staf f's proposed 13.1 percent return on equity is appropriate.
Trial Staf f's analysis was based on well-established methodology and is fully supported on this record.
In addition, Commission precedent fully supports a downward adjustment to the rate of return of a subsidiary with significant contractual guarantees that make it a less risky investment than its parent. 143/
Trial Staff's calculation of the 0.40 percent reduction to the return on equity to reflect North Atlantic's reduced risk is reasonable and was not contradicted on the record.
In Indiana & Michiaan Power Coreany, the Commission noted that guaranteed cost-of-service f ormula rates reduce risks:
(I & M) Power has a cost-of-service tarif f with its parent, [I & M Electric,) which permits immediate recovery of eny increase in costs, thus limiting its risk and minimizing not only the risk of regulatory lag, but also the risk of disapproval.
It will automatically make its allowed rate of return on equity regardless of whether it delivers the power or not.
The steady stream of revenues f rom such an arrangement provides the company with a very real advantage over those utilities not operating under similar cost-of-service tariffs. (112/)
the Similarly, in Connecticut Yankee Atomic Poyer Company, "the f act that the owners are Co==ission recognized that contractually obligated to purchase the output of Connecticut Yankee's generating f acility clearly reduces the company 's risk. "
550/
Additionally, Trial Staf f notes that the certainty of North Atlantic's guaranteed payments from PSNH is further reinforced by which PSNE's rate agreement with the State of New Hampshire, 281, 40 FERC 1 54 8/ Allegheny Generating Company, Opinion No.
61,117 at 61,318 (1987); South Carolina Generating Company, Inc., Opinion No. 280, 40 FERC 1 61,116 (1987) (Eputh Carolina).
at 61,739 Indiana & Michigan Power Company, 4 FERC 1 61,316 549/
(1978).
See also South Carolina, 40 FERC at 61,311.
550/ 20 FERC 1 61,373 at 61,766 (1982).'
l
Dockot No. EC90-10-000, el gl.
- 112 -
allows PSNH to directly pass Seabrook Power Contract expenses through to retail ratepayers.
Specifically, Trial Staf f explains that:
First, PSNH has been guaranteed 5.5 percent annual increases in retail rates for seven years from January, 1990.
[Ex. 9) at 21, line 14 through page 22, line 13.
Compounded over the seven year period, this constituten a nearly 46 percent increase in retail rates.
Tr. 6732, lines 11 through 17 (Watson).
in Second, the fuel adjustment clause.
PSNH's retail rate schedules will allow it to directly pass to ratepayers its costs under the Seabrook Power Contract.
Ex. 9 at 26, lines 3-20; Ex. 1 at 49, line 19 through page 50, line 2.
Third, the approximately $800 million acquisition premium for PSNH will be amortized and recovered through retail rates.
[f11/ 3 For these reasons, we reject the proposed return on equity and order that the rate instead be set at 13.1 percent.
Consistent with our return on equity updating policy discussed above, the 13.1 percent return on equity for the Seabrook Power Contract must also be updated.
The Seabrook Power Contract was accepted for filing and suspended to become ef fective concurrent with the date the merger is consummated, Therefore, the same prospective subject to refund. 152/
(0.57 percent reduction) used in the Capacity adjustment Interchange Agreements also applies in updating the equity allowance in the Seabrook Power Contract.
Adjusting the 13.1 percent return on equity for North Atlantic results in an updated return on equity of 12.53 percent.
The' Commission orders:
The initial decision is hereby af firmed in part and (A) reversed in part as set forth in the body of this opinion and '
Exceptions to the initial decision not granted in this order.
opinion and order are hereby denied.
(B)
NUSCO's application under section 203 of the FPA seeking approval for PSNH to dispose of all of its jurisdictional f acilities is hereby granted subject to the terms and conditions set forth in the body of this order.
55J/ Trial Staf f Brief on Exceptions at 92.
5.52/ 53 FERC at 61,839.
Docket No. EC90-10-000, at al.
- 113 -
(C)
Within 60 days of the issuance of this order, NUSCO shall make a compliance filing with the Commission, including a statement either accepting or rejecting the terms and conditions set forth above.
However, if any request for rehearing is pending at the expiration of the 60-day period, the filing shall be made within 15 days of the date the Commission disposes of the request (s) for rehearing.
If within the aforementioned period no compliance filing has been made, commission approval shall be deemed denied.
By the Commission.
Commissioner Trabandt cissented in part with a separate statement attached.
Commissioner Terzic concurred with a separate (SEAL) statement attached.
Lois D.
- Cashell, Secretary.
1 l
)
l Northeast Utilities Servico
)
Docket Hos. EC90-10-000 l
t Company
)
ER90-143-000, ER90-144-000, (Re Public Service Company of
)
ER90-145-000 and EL90-9-000 New Hampshire)
)
(Issued August 9, 1991)
TRABANDT, commissioner, dissentino in nart:
Today, the Commission approves a plan for Northeast Utilities (NU) to merge with the Public Service Company of New (PSNH).
I, too, approve the takeover.
I,
- however, Hampshire find the conditions the majority attaches unfounded for a merger I also find the conditions unreasonable for FERC case.
transmission regulation -- which, the more hardened among us realize, this decision really represents.
this order fails because it simply lacks As a merger case, an adequate analysis of the likely anti-competitive impact of the transaction.
As transmission policy this order fares just as poorly.
It augurs a bright future for developers at the expense If the Commission of utilities and their retail customers.
it would tilted much f arther in f avor of third-party wheeling, fall over.
While probably protecting reliability ;*he lights should stay on), the Commission leaves native loao Jj in the air, both as to priority and compensation.
The majority requires an open if at with negotiations barely at the margins, access tariff, My colleagues require NU now also to dispose of its system all.
for up to 35 years or more, and they force the utility to open for QFs and Canadian sellers.
More specifically, I find the following conditions on the merger to lack substantial evidence in the record, to be contrary standard of section to the " consistent with the public interest" of the Federal Power Act and to impose general transmission 203 requirements beyond our authority.
1.
The order, slip op. at 53-54, allows priority over existing capacity for native load reliability, not economy purchases or off-system sales that lower rates for native load.
(See pages 3-5).
2.
The majority, slip op, at 55-60, rejects the 10-year NEPOOL priority NU offered for off-system sales of currentThe order says that this would cre capacity.
I fail to see that third-party requesters must pay for upgrades.
how the priority will always result in third parties paying for upgrades, just possibly more often.
(Ege pages 4-5).
3.
Once service begins, firm third-party wheeling has priority over non-firm (even for native load), slip op. at 64,.
That shortchanges native load.
(Eng page 4).
m.
+
Docket No. EC90-10-000, gt alt 4. 1A technical conference, slip op._at 69-70, will convene to. allocate transmission if NU claims immutable constraints-prevent providing_ requested transmission service.
(See pages 5-14).
5.
The; order, slip op, at-86-87, requires NU to sell transmission for as long as 20 years or the life of the IPP contract, whichever the IPP wants.
The only excuse for this I can see _ is that IPPs need that to survive.
On top of that, the
~
- order, slip; op. at 85-86, effectively rejects negotiation in all cases in favor-of rigid transmission tariff requirements.
To me, 20-years plus negotiation should suffice (since NU committed
^
'itself to negotiate in good f aith).
(Egg page 15).
on the New Hampshire Corridor, allow Canadian 6.
NU must, sellers in, ostensibly because the U.S.-Canada Free Trade Agreement requires;it, slip op, at 95-96.
(See pages 15-16).
7.
The order states, slip op. at 97, that QFs get in if they waive their PURPA rights for the particular transaction, i. e,', the QF mayjnot use-transmission to force-a distant utility to buy at_ avoided: cost.
This still does not answer the question since-.under why1QFs.need anything to keep the market competitive, PURPA, they can always obtain transnission.
(Egg pages 15-16).
- 8. 'The majority, slip op. at 101-104, changes NEPOOL voting by' allowing within 90 days the other members to deny NU its new position.
This results in NEPCO keeping its veto.
(Egg pages 16-17).
9.
Again, the order, slip op..at-110-111, does not allow
. negotiation over individual TDU requirements.- Rather,'NU_mustThe reflect in the tarif f the = individual dif ferences among TDUs, order also leaves existing TDU contracts intact.
(seg pages.14-
- 15). -
10.
The majority, slip op, at 114-116, reduces the rate of return on the Seabrook power contract because with PSNH guaranteeing payment North Atlantic leduced its risk below NU's.
-(See page 24).-
-I express my views in more-detail below on those subjects.
- 1 I.
Six Authors In Search Of A' Character
'The Transmission Task Force and other advocates.of open access in transmission use what we created for Utah Power & Licht Co. (Utah), 4 5 FERC 5 61,095, order on rehearina, 47 FERC 5
~61,209 (1989) as the mold for generic transmission regulation.
Here, the opposite occurs.
The majority applies a preconceived
((
d
-.,,,---,-m-m.v
-r-
j Docket No. EC90-10-000, et als
-3 transmission policy to this individual merger case.
As such, this order represents a twist on the Pirandello play.
In Utah itself, we specifically disavowed making generic policy, 47 FERC at 61,733 ("no inference should be drawn that the transmission access conditions set forth (here) represent Commission policy, to be applied generically in the future, regarding transmission access and pricing").
Today's decision as well.
Therefore, I will have far-reaching consequences, explore the larger question.
This case comes down to transmission: how to allocate the existing system, how to expand it (including who pays for additions) and, in general, who runs the grid.
The current and soon-to-resume debates in Congress about reforming the structure of the electric utility industry must come to grips with these same issues.
This order throws FERC's hat in the ring for the Based on this job of arbiter of the Nation's transmission grid.
order, I would throw the hat right back out.
A.
Nati'/e Load Even utilities otherwise willing to sell transmission must draw a line in the sand.
They must protect their " native load" (the customers within their service territory).
I would repeat 53 FERC i f or emphasis how Judge Nelson der cribed the situation, 63,020 at 65,221-65,222 (1990):
The merging companies' very existences are linked to their obligation to serve native load customers.
That is why they nold lawful monopolies.
Their native load customers have regularly borne the costs of the NU-PSNH facilities.
The future transmission customer, who wants to use those facilities, has not.
The ratepayers of NU and PSNH, who have paid for the fac.'lities through the years, have used them, have planned on them and have relied on them.
NU and PSNH have correspondingly planned for those ratepayers years into the future.
The situation is not unique to NU and PSNH.
Every New England utility favors its own native load.
Nothing in the NEPOOL agreement requires its members to surrender their native load preference, and none do.
The native load issue arises in three contexts.
- First, waen a party initially requests transmission, NU must determine If the whether to take capacity out of the existing system.
capacity sits idle, NU satisfies the request.
If, on the other L
-4 Docket No..EC90-10-000, el al2 hand, NU uses its system, the question arise.s, who takes from the existing system at a lower average system cost, and who pays for additions at a higher incremental cost (the cost of improvements or new facilities)?
NU proposed, slip op. at 53-54, to place ahead of third-party transmission:
1.
native load (for reliability, i.e.,
to keep lights and appliances on);
- 2. existing contractual obligations;
- 3. economy purchases (of cheaper power to lower native load rates) and;
- 4. for 10 years, off-system sales for all NEPOOL utilities (off-system sales allow NU to carn money that goes to reduce native load rates).
The second context in which native load concerns come into play concerns curtailment of service once begun, slip op. at 64-NU-proposed to subordinate third parties using firm service 65.
i Native load would come to firm service on behalf of native load.
first whether for reliability or economy.
4 The third situation arises when a third party requests transmission service for which NU cust build, but an " immutable constraint" prevents the company from constructing the line, as discussed above.
Here, Judge Nelson (53 FERC at 65,221-65,222)
The majority, proposed to allow NU to turn away the third party.
slip op. at 69-70, proposes to call a technical conference (more than a meeting but less than a hearing) with interested states and others and afterward to allocate NU's existing transmission 1
-system.
In all of these instances, I think sound policy compcis the Commission to hold native load harmless.
Reliability for native load would always come first.
I, for one, would provide more in all protection.
I would give priority to economy purchases, cases.
Such native load priority is recognized by the staf f in its proposed merger tariff, at least for reliability; protected by the ALJ's decision; protected by Congress in the Federal Power and universally recognized in systems throughout the United Act; States.
I agree that native load priority encompasses i.D erentiv an economic h
Any oriority is
. reliability and economy.
issue because when the NU system is constrained the outcome is an increased cost to some customer, not a power failure.
?
I Additionally, priority for off-system sales and economy i
purchases for native load benefit is fundamental to economically rational allocation.
The economy purchases and off-system sales in the che financial basis for the ratepayer investment were is not already dedicated to long-term delivery (and capacity that i
If native load ratepayers do not therefore is available).
from the capacity, the utility receives no return on its benefit r
. Docket No. EC90-10-000, el al2 If third-party wheeling customers use the capacity, investment.
If third-native load customers pay more for their electricity.
party customers do not bear the burden of the actual cost of their power investing in reserve capacity (" opportunity costs"),
If native load does not customers have not paid full price.
benefit f rom investing in reserve, host utilities have no incentive to build reserves.
I For the allocation on the initial transmission request, would also agree to liU's proposal for a 10-year priority for off-
~
(Where the system sales over requests on the existing system. issue of who pay it also
- should, Not only does that protect the native loaa, reflects the true cost of the transmission request.
The proposals for incremental pricing for transmission have the same idea in mind.)
As a fall back, I agree with Commissioner Terzic that we should compensate the native load for the higher rates they must Happily, we all agree pay as a result-of transmission requests, purchases necessary to caintain (slip op. at 54, 65 and 70) that native load reliability always prevail.
I appreciate the fact i
the meeting we all agreed to add language to that ef f ect that at complaint proceeding.
" immutable constraint" for the the rest of the Commission rejected Commissioner Unfortunately, Terzic's and my proposal to add priorities for economy purchases Thus, those types of transactions will be and off-system sales. subordination to third-party transmission very much at risk of requests in the FERC allocation (actually re-allocation) process.
the Commission rejected Commissioner Terzic's effort,
- Also, to indicate at least in general that we will which I support, sympathize with NU's efforts to compensate its native load when The staff promised transmission requests create constraints.
i in September we will consider a concrete case in which the i
that issue will arise.
I lcok forward to the debate.
B.
The " Hammer Clause" Peincarnated f
The essence of the majority's transmission conditions is the thinly veiled extension of the long-term conditions from the Utah case.
Recall that in Utah, the Commission included a short-term i
i allocation scheme for any excess transmission capacity on the (the so-called Remaining Existing Capacity merged utility's grid and a long-term' condition not linked to REC.
(REC))
Under that long-term condition (or " Hammer Clause" as it is the merged company is required to f ondly known in some - circles),
displace economy transactions in the future as necessary to satisfy third-party transmission service requests for whichavailable a existing REC is not
)
4 Docket No. EC90-10-000, g1 nix a timely way under specified circumstances.
Interested parties may wish to review my extensive discussion of the legal and policy problems assoc.iated with the Hammer Clause in my partial dissenting coinion, 47 FERC at 61,763-61,770.
For this discussion, it suffices to remember that the Federal Power Act gives us no jurisdiction, as such, to allocate transmissicn capacity, Section 203, under which we may approve mergers requires a direct nexus between what we order and the The merger-induced anti-competitive harm we are trying to cure.
wheeling provisj ens of the federal Power Act similarly rertrain any impulse the Commission might have to manage utilities' grids.
In particular, sections 211 and 212, state explicitly that the Commission may not use the authority Congress granted there to upset existing competitive relationships.
(Even the authors and supporters of bills in various stages of consideration in Congress that would repeal that language express an explicit intention to protect the interests of retail customers of the wheeling utility.)-
The 1989 Transmission Task Force Report later recommended the adoption of a similar-type Nummer Clause as the central feature of a generic transmission policy for the Commission.
As a practical matter, the majority here has donc just that for the with chis New England region of the Nation using the NU system, merger as the vehicle Without any supporting evidence or rationale, the majority that "we will construe NU's blithely announces, _ slip op, at 68, voluntary [ transmission) commitment very strictly," by subjecting the allocation of the existing NU grid to an independent FERC determination in a " Hummer Clause" oroceeding aDV ilac and Ayerv
.t.jy3e NU f ails to satisfy a request for firm transmission service and the requestor files-a couplaint making a specified showing.
After a technical conference convened within 30 days after receipt of the complaint, the Cocnission will expeditiously render a decision as to whether the denial of service was the result of an "immutcble" constraint and, if so, how to allocate l
the existing capacity to achieve "the Lost efficient and equitable allocation" on the NU system.
The complainant, NU, all l
affected state commissions and affected customers could issues of whether participate in the technical conference on the an immutable constraint prevents construction of the required i
i additional transmission _ capacity and how best to re-allecate NU's existing capacity in that event.
The Commission in its determination will accord substantial weight to an agreement by all affected state commissions that there is such an it=utable constraint.
Also, as recommended by the Commission additionally vill Commissioner Terzie and me, i
l
t Docket No. EC90-10-000, el glx,
accord substantial weight to any agreement by all affected state commissions on the 'most "ef ficient cnd equitable" allocation of existing transmission capacity, which, of course, will be the key element of these decisions in the Hammer Clause complaint proceedings.
Thus, the views of the affected state commissions can be of some contemplated significance, to the extent that an agreement among all of them will be accorded substantial weight.
Nevertheless, there should be no misunderstanding that the majority would be bound by such substantial weight for such Ln acreement.
Quite to the cortrary, it now seems clear that the commission staff would adamantly oppose any priority for the native load service in a Commission-ordered re-allocation of existing capacity, apart from, I hope, contracts necessary to maintain native load reliability, even if all af fected state commissions agreed that there should be such a priority for native load services.
Then, the Connission would have to decide how to proceed in the face of such adamant opposition.
The draf t order we discussed at the July 31, 1991 Commiscicn meeting did not include any specific criteria, guidelines, principles, or standards for making the determination on the appropriate allocation of existing capacity, other than the aforementioned " efficient and equitabic" formulation.
Commissioner Terzic and I recommended that we provide more specific principles for such determinations.
For me, even though I oppose the entire Hammer Clause procedure, the addition of these principles vould at least provide a clear refarence frame for the -decisions to be rendered in the conplaint proceedings.
l We recommended the following principles for allocating RU s existing transmission systora:
purchases necessary to maintain reliability ior native 3.
loud customers wil.1 always come first.
Economy purchases that benefit the native load will have 2.
a preference, unless the conplainant agreen to compensate NU in accordance with Principle 3, below.
3..
If a complainant's request for transmission over HU'r L
systen will cause the merged company to f orgo cn economy purchase that would result in a lower rate far native load, the the complainant will pay NU as par t of the transmission rate,
" opportunity cost."
For purposes et this order, we define l
" opportunity cost" for econony purchases as the difference i
between the cost to NU of substitute power (from its own system or other purchase) and the price of the economy purchase if must forco.
NU will credit 'ts cpportunity cost recovery to its native loud customers.
l I
l l
8-Docket No. Ec90-10-000, et al.
Off-system sales.will come chead of a transmission 4,
rcquest,. to the extent the sales reduce native J oad rates, except if the complainant requesting wheeling agrees to pay NU
" opportunity cost."
For these purposes, that cost Will include the portion of the proceeds from the sale NU would have credited to its native load customeru.
NU must provide legal documentation of the lost sale, such as an affidavit or a contract.
NU will make available any remaining capacity to the 5.
complainant for third-party Wheeling.
After considerable discussion at the meeting, the najority whica the Commission agreed to include only the first principle, staff argued was already implied by an earlier section of the order, even though not expressly stated in the Hammer Clause section.
Whatever the explanation, at least the Commission has expressly estabitched such a priority for maintaining reliability for native load customers in any re-allocation cf the existing Given the lack of standards in the original draf t capacity.
order and the trial staff's testimony opposing pliority for native load customers, I consider that additien to be an intent.
iuportant clarification of the majority's the rejection by the majority of the other proposed
- However, principles for the dc+.ermination of priorities in the Hammer Ciause proceedings effectively reverses the decision of the Administrative Law Judge ( ALJ ).
In his Initial Decision, 53 FERC 5 63,020 at 65,221-6S,222, he stated as follows:
(a) Priorities When Constraints Cannot Be Removed Although the merged company is willing to build such upgrades or addit. ions as necessary to rer.ove constraints, siting, environmental, or other regulatory concerns may so=etines preclude such kark.
In that event, prioritj es of access must be established amor.g those demanding.the perged company's facilities.
In the context of this case, the " priorities" dispute involves dollars, not failures of electricity.
The priority " winner" gets cheaper power; no one 1cses electricity.
The merged company would favor its native load customers when an irrerediable constraint produces a conflict between their needs and those of transmission customers.
Some intervenors argue against such a priority, reasoning that concepts of " parity" l
A c
i Docket No.. EC90c 10'-000, p.t al.,. -:
t or " nondiscrimination", require that-transmission customers be allowed to sign on with the mergedicompany and be-treated the same as the' rest of the company's customers.
Under this ~ approach, every customer, native load.or wheeling, would get equivalent treatment, presumably sharing,in all available power.
These intervenors believe that: such an egalitarian service would create more reliable wheeling,_and thus furnish a stronger competitive _ alternative'to NU-PSNH's strength.-
But an approach.which equates wheeling _ with a utility's obligation _ to serve its own retail-customers is fraught with difficulties.
The_-merging companies' very existences are linked to their obligation to serve-
- native - load customers.c That is why they hold lawful monopolies.
Their native; load customers have regularly borne the costs of.
- the4NU-PSMH facilities.
The future
- transmission. customer,:who'vants to use those
,tacilitias, has not.
The ratepayers of NU and?PSNH,- who have' paid for the facilities through the years, have _ used them,.have NU planned on them and have relied on them.
and PSNH have. correspondingly planned for M
'those ratepayers years into the future.
The
~
situation is not! unique to-NU and PSNH.~
- Every-New England utility '.f avors its own native-load.
Nothing in.the NEPOOb agreementf requires :its. members to surrende'r their native. load ' preference, and none do.
Ev2D the crocong.d_intervenor-staf f meraer tariff recoonizes that native load shoulq. preve,11 in -
g
'~
gases : where constraints canopMrs removed-
'r 4
(Tr. -' 814 3-814 7 ).
2here is no legal requirement that a' utilit, equalize;its native loed-customers =
with all others.
The antitrust " essential f acilities doctrine recognizes the -
legitimate primacy of the. company's own-customers.
Even if NU's facilities were
-l
" essential," that-status would not warrant destroying native load preference- (Eng, 9_t;Ah l
'N Power =&
Licht Co.,
45 FERC 1-.61~,095 at p.:
61',287 (1988)).
U3ah :.x}'ressly_ recognized that the merged company could reserve from its wheeling obligatione sn-much of its
+
capacity as would be necessary to serve-i I
- i
-i l
h_n'
=.
.- ~.
g.
')
.[
Docket No. EC90-10-000, 21 A1A q native load (45 TERC at p.61,291).
Egg algg, City of Vernon v. Southern California Ediso.D '
E22, N o.1 CV 83-8127 C.D._ Calif. Aug.:30,
- 1990, - pp. 25-28 ("(r)easonable access' does J
not include that which would-harm Edison's 1
other customers..
Edison is not obligated by'the-antitrust laws to confer-a
' benefit on Vernon at the expense of its own custemers.
Edison's denial of access to o
its transmission' system was motivated by a desire toibenefit-its own customers.
")
.The reasonableness of native load preference is also reflected in the Federa)
Power Act. _Section 21(2)(a) provides that no wheeling order may be entered under sections o'
210 or til unless the Commission determines that such order "will not impair the ability-of any electric utility affected by'the order to render adequate service to its customers."
This provision,.while not bindit' in a section _203 case,-nevertheless' reflects significant legislative approval of-priority for native load, m)'s' choice,-to prefer _ native load when constraints are immutable,-is fair,.and it strikes a reasonable balance between conflicting interests.
(Emphasis added).
Furthermore,- by rejecting the principles proposed. by Commissioner Terzic and me and by ef fectively reversing the ALJ, the majority has ignored the following key points which were well established in the record..
'First, " opportunity costs"; are Dnt monopoly -rent..They are p
laL realL cost '-- the -cost of investing _ in reserve; transmission capacity planned and financed based on these transactions and benefits.
Second,_ third-party _ customers need certainty in prices Land availability, not subsidies.
As long as the costs and priorities.are clear up front they can compete and survive..
. Third, every. time a constraint:arisesLon the system, someone pays
?
Priorities 1only determine what party should be able b
for-power.
- toLavoid_the charges to cover the cost of getting around the _
constraint.
Fourth, _the staf f and-all parties accept' two related Lprinciples:
Native load'has priority for reliability; (1) Prior contracts the utility has' entered into should not (2)
-be abridged.
+
t Docket No. EC90-10-000, g1 alt t It also is noteworthy that at the July 31 meeting I unsuccessfully sought agreement from my colleagues and the commission staf f with the fundamental proposition that, by whatever means existing capacity is re-allocated in the Hammer Clause complaint proceedings, the native load customers should not be forced to suffer higher costs for their service.
In other words, apart from the definitional semantics associated with the term " opportunity cost," any re-allocation of existing capacity will only be equitable and acceptable if native load ratepayers remained financially indif ferent to the re-allocation.
In the
[
alternative, any re-allocation of the existing NU capacity in such a proceeding-would be inequitable and unacceptable if native load customers incurred additional costs as a result of third-party wheeling, opposition on the part of the Commission staff is not surprising since, as discussed below, I am persuaded that the whole object of this exercise (here and in every other case) is to threaten exactly that result; i.e. native load customers will face increased costs unless additional transmission capacity is bui]t to meet all third-party requests for transmission services.
But, I would sincerely hope that the majority will consider further this fundamental prvposition on rehearing of this order and in subsequent cases.
Sadly, once again, the Commission has seized on mandatory transmission access at embedded-cost rates as a vehicle for restructuring the future shape of this electric utility.
Thus far, apart from the recent Technical Conference, the Commission continues to avoid, if not ignore altogether, a more rational transmission pricing policy for a more competitive electric utility industry.
And, by rejecting the additional principles proposed by Co=missioner Terzic and me, the majority refused to consider some formulation of incurred-cost reimbursement for native load ratepayers that would reflect various theories of incremental or opportunity cost pricing in the fact-specific situations on a case-by-case basis.
As a result, there appears to be a continued opposition to any formulation of transmission i
l pricing policy different from embedded cost pricing.
We may know more about opportunity cost pricing in September, as discussed above, but this case points out again why we must address promptly the larger transmission pricing issue as an alternative l
I to or adjunct of the repeated disposition to impose mandatory l
transmission access, as the Department of Energy repeatedly has urged.
It also is significant that the majoriwy rejected Commissioner Terzic's separate proposal to insert the following statement on page 74 of the slip op.:
Although we are not deciding here whether NU's proposal for opportunity cost pricing is p
just and reasonable, generally we support the i
r
?
+.
Dock 2t No. EC90-10-000, et alt notion that opportunity cost pricing for nonfirm service in the absence of market power is appropriate in order to compensata native load customers.
However, we leave for the cases pending before us the precise definition of such opportunity costs.
Apparently, as discussed at the July 31 meeting, we will be presented with a Commission staf f recommendation on the opportunity cost issue in the pending NU dockets (Nos. ER90-373 and ER90-390) in September of this year.
At that time, we will have tha " paper hearing" record in that proceeding as a basis for a decision on the current practices associated with " opportunity pricing in existina NU transmission service agreements.
cost" Thus, we will be addressing the general issue shortly in that However, the potentially separate and distinct issue as context.
to the appropriate standard in Hammer Clause proceedings ultimately will have to await case-by-case decisions in response to specific complaints, in the absence of the general principles proposed by Co=missioner Terzic and me.
For now, at least, the only standard for re-allocation of the existing capacity is "ef ficient and equitable," apart from the priority for contracts necessary for native load reliability added at the July 31 meeting.
A veteran of these debates may recall the theory of primacy of economic ef ficiency, which in the past has been argued as subsuming all equitable considerations, i.e. if it is economically ef ficient, it is by definition also equitable.
A more skeptical view would conclude that that is exactly what the draf ters here intended.
Unfortunately, I do not believe that this is merely another academic or theoretical debate about more abstract transmission As a result of this order, I would fully anticipate that policy.
affected state commissions and FERC will be confronted with a NU, succession of complaints under this Hammer Clause procedure, And probably beginning in the not too distant future.
inevitably, the Commission will be urged by third parties and probab3y the cc= mission staf f to provide a priority for transmission services for non-utility generation over the newly subordinated native lead services and transactions.
That clearly was the result of the Utah Hammer Clause and the essence of the 1989 Transmission Task Force Report.
And, in my personal that just as clearly now is the intended result of the
- judgment, "most efficient and equitable" re-allocation of the existing capacity in the Hammer Clause complaint proceedings.
So, no interested party or af fected state commission should be at all surprised if that is the eventual result in the first of the many likely Hammer Clause proceedings under this order.
i l
1 1
Docket No. EC9 0-10-000, g1 n12
- 13 I have even pondered whether the re-allocation of existing capacity in these Hammer Clause proceedings could include transmission service for retail customers of NU or other utilities, thus facilitating retail wheeling and bypass of NU.
For exar.ple, if an industrial facility sought transmission capacity, what would prevent a Commission majority from granting the request in a Hammer Clause proceeding, especially since in this case, the trial staff advocated that we favor transmission requests over the interests of native load customers?
Similarly, af ter the Utab decision, a municipal system was created primarily to serve a large industrial customer by qualifying for wholesale transmission services required by the Utah order, as could also occur under this order.
Although the ostensible purpose of the Hammer Clause proceeding is to strictly enforce NU's transmission commitments, there appear to be no real limitations on the commission's discretion in making the re-allocation decision, apart from the new principle advocating a priority for native load reliability contracts.
But in a real-world, case-specific, Hammer Clause proceeding, the Commission apparently would have otherwise unconstrained authority to allocate NU's existing transmission capacity as it saw fit at the time.
That is a very dangerous proposition under any ci:: 3umstances.
I also foresee FERC now being affirmatively drawn into the extraordinary technical complexities associated with the reliable operation of the NU system, and, by extension, the NEPOOL systen.
The Commission undoubtedly will have to adjudge the competing technical, economic and operational arguments of complaining parties, NU, NU customers, affected state commissions and other parties in the re-allocation proceedings.
And, as in the merger case itself, the Commission staff probably will be recommending re-allocation schemes that pref er non-utility generation and correspondingly. subordinate native load interest, whenever there is a conflict between the two.
That will be the point when the Commission undoubtedly will be apprised that economic ef ficiency, in fact, subsures equity and the most economically efficient result is an IPP priority to support increased competition in electric markets, despite increased costs for native load ratepayers.
The Hammer Clause procedure here will not be self-executing in any respect, and consequently, the members of the Commission ultimately will be deciding those technical, economic and operational questions on a recurring basis.
Of course, if all the affected state commissions reach an agreement on the appropriate allocation in a particular case, their agreement should be accorded substantial weight under the provision recommended by Commissioner Terzic and me, but the agreement clearly will not be binding nor dispositive.
In the end, this Commission will have the authority to re-allocate the existing system under the highly amorphous "ef ficier.t and equitable"
l Docket No. EC90-10-000, et alt
- 14 standard, subject only to the new priority for the " native load reliability" contracts.
Consequently, I am very concerned about the potential scope and effect of that authority in future cases.
That result of this order, of course, is a mirror reflection of the underlying theory in the Utah case and the 1989 Transmission Task Force Report.
In essence, that result stands for the proposition that FERC would directly and intentionally put at risk economy transactions for native load ratepayers in order to indirectly force jurisdictional state authorities to authorize the siting and construction of additional transmission capacity to satisfy the new requirements of non-utility generation as a "first among equals" class of customers.
Such action would be intended to expedite and solidify the competitive generation sector in the bulk power markets.
Much has been written, by me and others, on this subject (and it will not be j
repeated here), but it is worth noting again in passing that that's what the electric power regulatory game and this merger order are really ali about.
For the previously stated general reasons, as well as the case-specific reasons discussed here, I find that approach highly objectionable.
In the end, the thinly veiled imposition of the Utah Hammer Clause and its operation in the Hammer Clause complaint proceedings should have been rejected by the majority.
- Rather, the Hammer Clause has been imposed here without the thinnest reed of evidentiary support, let alone substantial evidence.
And, it has been imposed for reasons now facially (and perhaps painfully) obvious to all objective analysts, having nothing at all to do with the potential anti-competitive effects of the merger under the Comnonwealth criteria, but rather having everything to do with the IPP priority recommended in the Transmission Task Force Report.
Those readers also interested in proposed legislation now under review in the House Committee on Energy and Commerce may wish to consider how the Commission would be likely to use any new statutory authority enacted by the Congress to protect native load customers.
C.
Tari f f s v.
Necotiations Another important issue in the transmission discussions concerns whether the utility must file a general tariff or may negotiate individual transactions.
Certain parties f avor tarif fs on the grounds that a document on file with FERC guarantees service.
Utilities, even those on the side of open access, oppose tariffs because it builds rigidity into their operations.
As of today, the Commission requires tarif fs.
The maj ority, slip op. at 85-86, held that UU must file an all-purpose transmission tariff and may not negotiate individual deals.
The order, slip op, at 85, claims that, "This conclusion l
l l
i I
Docket No. EC90-10-000, 21 Alt is supported by the record."
The " support" amounts to a word-for-word repetition of the complaints of the Eastern REMVEC intervenors in their Brief on Exceptions.
I recite and comment on them in Section II.
B.
3.
of this opinion.
I only add here one additional thought.
Contradictory, and full of "could" and other terms of conjecture, the rec 4tation belongs more as a chapter in the IPP or Non-Utility Generation
' entry in the Schaum's "Made Easy" series of school books (e.a.,_
Algebra Made Easy) than as a decision the majority supports with substantial evidence.
(Similarly, the majority requires a tariff for TDUs, slip op. at 111. )
The requirement makes it more difficult for utilities to operate their transmission grids.
D. Other Generic Transmission Issues 1.
The majority, slip op, at 86-87, requires NU to provide in its tarif f service for IPPs and similarly situated entities or the that request transmission for a maximum term of 20 years, lif e of the requester's power sales contract, whichever runs lonaer.
NU of fered five years, plus an enforceable promise to negotiate in good faith.
The ALJ, 53 FERC at 65,220, required 20 years (plus negotiation) in_the interest of affording IPPs some certainty.
I see no need to venture beyond the balance the ALJ-struck.
The rationale behind the majority's extension boils down to "the IPPs need it."
To me, that rings hollow.
Like the ban on negotiations, it may make developers' lives easier, but as public policy it harms the electric utility industry.
The utilities cannot uniformly commit that far in advance and we must allow them to adapt to conditions at that time.
An enforceable promise of good faith negotiations suffices to assure that the utility
. will not deliberately pull the plug af ter 20 years._ Again, the majority exalts one sector of the industry, non-utility generators, over sound public policy.
2.
This order, slip op. at 94-97, establishes transmission access for qualifying facilities under the PURPA (QFs) and Canadian sellers.
Making QFs eligible reverses our decision in In Utah we held, 47 FERC at 61,739, "Because transmission Utah.
access is available to any utility than can interconnect with the merged co=pany for the purpose of purchase as well as sales,.
access can be obtained by any such utility for purchases from QFs.
Hence, QFs will have the-same ability to negotiate power contracts (as everyone else)."
I adhere to Utah and the rationale we gave for exclusion.
Even though the District of Columbia Circuit in Environmental Action. Inc., et al.
v.
FERC (Environmental Action), No. 89-1333, et al.,
(D.C. Cir. August 2, 1991) just remanded the issue
l f
Dockot No. EC90-10-000, et alt to us, my point remains valid.
The court, slip op, et 8, 10 spoke (slip op, at 10) in terms of the " consumer welfare point of view enshrined in the antitrust laws."
I speak in terms of transmission policy.
Simply stated, PURPA aircady requires neighboring utilities to purchase QF power or to transmit it to a willing buyer.
QFs already enjoy access.
This gives them more.
Now, they can use the guaranteed purchase as a floor and force transmission for a sale at an even higher price elsewhere.
If the QF has a willing buyer, the purchaser can call f or transmission.
Even if the buyer has too few personnel to arrange the deal, the purchaser need only make o phone call or sign a form and have the seller fill out the details.
The majority counters, slip op, at 97, that in a recent case, Hertern Systems Power Pool (WS PP), 55 FERC $ 61,099 (1991),
we allowed QFs to obtain transmission if they waive their PURPA rights.
I only supported that because the pool agreed.
On rehearing, 55 FERC $ 61,495 (1991) I opposed the " clarification" that went beyond that.
In any event, whatever justified making QFs eligible in WSPP, this action carries a far greater impact.
Here, the majority allows them to displace native load economy.
Morcover, WSPP involved very short-tern sales.
This case concerns transmission of 20 or 35 years or more.
Finally, a word about Canadian sellers.
I disagree with the claim, slip op. at 96, that excluding them would violate the U.S.-Canadian Free Trade Agreement.
This case quite simply has nothing to do with distinctions af firmatively drawn on the basis of national origin.
Rather, it has everything to do with an inf ormed assessment of the likelihood of anti-competitive ef f ects based on substantial evidence in the record.
On that basis, allowing access for Canadian firms here has absolutely nothing to do with our mandate under the Federal Power Act to protect the public interest in the United States.
It helps Canadian firms compete in the U.S. market, but I see the two considerations as completely different.
E.
NEPOOL Votina The majority, slip op. at 101-104, alters NEPOOL procedures to the detriment of NU.
The ALJ pointed out, 53 FERC at 65,230, that the NEPOOL agreement (over which we have jurisdiction outside this merger case) allows utilities with at least 25 percent of the vote to veto pool decisions.
When NEPOOL began, NU and the New England Power Company (NEPCO) both had enough strength to exercise a veto.
NU lost it, leaving only NEPCO.
Adding PSNH's vote will restore NU's position.
Today, acting on shaky ground, the majority clips NU's wings.
The net result of the order is to openly f avor NEPCO over the merged company by 1
Docket No. EC90-10-000, gt alt prese rving, for the foreseeable future, NEPCO's exclusive veto in NEP00L voting.
Ostensibly, if NU could exercise its full voting strength, it could extend its " market power."
Therefore, within the next 90 days NEPOOL members may change the agreement to prohibit NU from adding PSNH's vote to its own (except on matters of adopting, amending and repealing a Regional Transmission Agreement we require NU to file).
I can see through that thin veneer.
For one thing, a NEPOOL veto cannot inherently be anti-competitive.
Our predecessors approved it as part of the pool and the majority permits NEPCO to keep it today.
Further, the merger cannot have made NU's veto anti-competitive, since the transmission conditions the majority imposed supposedly cured that, in any event.
Finally, as we have jurisdiction over NEPOOL anyway, better we address a complaint in a specific factual setting than use a blunderbuss approach that upsets the NEPOOL scheme.
II.
The Stokowski School Of Mercer Iaw All of us Commissioners start from the proposition that section 203 of the Federal Power Act establishes the standard for reviewing the NU-PSNH transaction.
Under that provision, the Commission may approve mergers if we find them consistent with the public interest.
The majority and I also agree that we must apply the law to the specifics of this case.
We disagree on how to go about it.
The majority follows the approach Leopold Stokowski took to the sco) is he conducted.
He found them perhaps inspiring but never controlling.
He insisted on his interpretation, even if the ccmposer wrote something entirely different.
Many find listening to Stokowski uplifting.- Nevertheless, coanoscenti under the influene-of Arturo Toscanini reject that kind of musicology (see Sa hs, Toscanini, 207 (New York 1978) (Stokowcki had trouble leading the NBC Symphony because its musicians resented his "sometimes grotesque tampering with the music he performed.")).
When it comes to our interpretation of our section 203 authority and how to apply it in this case, I prefer Toscanini's approach.
A; The Notes On The Mercer Scale Our adjudications under the Federal Power Act differ from those under the Sherman and Clayton Acts (see e.a.,
Town of Concord v._
Boston Edison Co.,
915 F.2d 17 (1st Cir. 1990);
Cities of Batavia v.
FERC, 672 F.2d 64 (D.C. Cir. 1982)).
We assume a pre-existing monopoly and seek to arrest the spread of l
j i
Docket No. EC90-10-000, et alt anti-competitive behavior.
The antitrust laws sock to prevent nonopoly.
Yet the competitive framework coincidos in both.
Merger law, both under the antitrust laws and section 203, stems from the idea that society must " protect () connetition, not connot i tpIs. "
Ilt p w.n _ S M g _ C o.
v.
U.S 370 U.S.
294, 320 (1962) 2, (Enphasis in original) J rnvironmental ActioD, slip op. St 8.
The law restrains mergers that harm competition.
It allows those that do not, even if competitors suffer.
Moreover, the Supreme Court held that " merger (s) must be functionally viewed, in the conte 4t of (the) particular industry."
370 U.S. at 321-322.
proper analysis, therefore, requires economic information "unigun" to the case at hand (320 U.S. at 322 n.38).
Because the law concerns itself with competition, rather than competitors, we must concentrate on buyers' choices, not sellers' opportunities.
The Co"i c Ocid that decision makers must make a " careful selection c' u a market area in which the coller operates, and to which the p.E manry_,can orac,tiJably turn for supplies."
T3rJa M ggIric Co.-_v.
Nashville Goal Co.,
365 U.S.
320, 327 (1961)
+.phasis added).
In an nutshell:
The contral issue is where does a potential buyer look for potential suppliers of the service -- what is the geographical area in which the buyer han, or in the absence of monopoly would have, a real choice as to i
price and alternative facilities?
This depends on the fac'.s of the market place, taking into account (various) economic l
1 actors.
Maj t ed St ales v.
G r iD110.1.1 C9IAs., 384 U.S.
563, 589 (1966)
(Fortas and Stewart, J.J.,
dissenting).
Finally, while statistics about market share offer useful guidance in certain instances, the court has warned against l
playing a numbers game that confuses means with ends:
9
"(W)hile (a) statistical showing.
would suffice [] to support a finding of
" undue concentration" in the absence of other considerations, the question before us is l
whether (the trial court) was justified in l
finding that other pertinent factors affecting the.
industry and the business l
c l
of the appellee mandated a conclusion that no
[
substantial lessening of competition occurred l
l or was threatened by the acquisition.
I t
~, ~
--,..n-
,.,--,,n n.n.
-n v----~>
Dockot No. EC90-10-000, et alt U.S.
v.
General Dynamics Corp., 415 U.S. 486, 497-498 (1974).
Reviewing this order under these merger concepts, a " rap" fan, let alone an expert in classical music, will find the majority's performance quito Stokowsklan.
The plight of certain types of sellers resounds in the car, even as the word " buyer" appears on the muuic sheet.
(Sometimes, the order explicitly refers to " sellers" as our concern, e.a., slip op. at 33 regarding transmission as a separate product market, while in other places the majority lumps the two together, g g2, slip op, at 39 n.201.)
B.
Eyschonic Fantasticue. Op.lm_11 1.
Reveries,_Passiong I continue to believe, as I stated in my separate opinion to the hearing order, Rortheast Utilities Service Co.. et al.,
50 FERC 5 61,266 at 61,841-61,842 (1990) (Trabandt, Commissioner, concurring), that if push comes to shove, the Bankruptcy court, not this Commission, has jurisdiction over this merger.
Because neither the Bankruptcy Judge nor the parties pressed the issue, it remains dormant (though we should not tempt fate).
I also reiterate (50 FERC at 61,842) that the majority incorrectly compares the merged company to NU and an independent PSNH, when, in fact, the latter has no basis in reality.
The majority considers PSNH emerging f rom bankruptcy only as a benefit, slip op. at 48.
I would use it Ls a starting point for deciding the merger's competitive effects.
All must agree that without money and management f rom NU or another utility, pSNH cannot last long on its own.
Therefore, rather than compare the new NU with separate NU and PSNH, (see slip op. at 40-41) I would look at this merger on the backdrop of a realistic combination of PSNH with other New England utilities.
That way, the Commission can truly measure the competitive impact of the NU takeover.
It also makes f or one way to remove the legal rationale for the harsh transmission conditions tn the order.
2.
A Ball Since the majority voted otherwise when we set the case for hearing, I will go on to explain my differences with the reasoning in the order.
7 have no quarrel with the geographic market the ALJ used.
I daffer with regard to the product market.
In particular, the majority adopts transmission as a completely separcte service.
I find that too broad, y
r
.__y y
Dockot No. EC90-10-000, c1 alt I go along with that only on a case-by-case basis as to certain Transmission Dependent Utilitics (TDUs) (mostly municipal l
entities that form an island within someone else'c grid).
Indeed, because of the TDU situation I very reluctantly agreed in Utah that transmission formed a separate market.
Bat, I never intended that quite case-specific determination to serve as a generic finding or rule for all later merger cases, as it has unfortunately become.
And, as we saw in Section I, this case concerns IPPs, not TDUs.
On the whole, I would use bulk power as the relevant market, with the necessary transmission capacity for delivering the power as an essential and integral element of that market.
The standard for judgment whether to defino a broad or narrow market lies not in whether "' transactions take place between buyers and sellers of transmission,'" slip op. at 34.
Rather, what can buycrs reasonably substitute?
For example, if they freely switch among fruit juice, fruit punch, soda and bottled water, the market becomes soft drinks, rather than one particular variety.
The same holds true here.
Utilities do not buy transmission for its own sake.. Rather, it serves as a means for acquiring and delivering electricity.
Generally, utilities have three means to obtain power: generating the power themselves, buying from someone located on their own grid, and using transmission to purchase supplies from outside the area.
For all but some TDUs, at least generation remains an alternative, if not buying from someone located within the area.
For TDUs owning their own generating plants, transmission exists as but one of the choices.
Only for those TDUs that do not own or cannot build plants and cannot persuade a developer to locate within their service area does transmission stand as a separate market.
Therefore, I find RU's taking control of PSNH's transmission becomes less of an earthshaking event than the majority.
3.
Eppncy In The Country I agree with dividing the short-term f rom the long-term a.
markets.
On the other hand, I find bulk power markets in this case competitive in both.
In the short term, I take judicial notice of the excess capacity New England currently experiences.
I would want to know how much surplus New England has compared to how much the region needs.
That NU will control 65 percent (slip op, at 41) fails to impress me.
Just as in the Genera)_ Dynamics case, percentages only go so far.
For example, if New England needs 200 megawatts and the surplus, exclusive of the combined company comes to 400, NU's share becomes irrelevant.
Docket No. EC90-10-000, el ala. b.
Because of alternate (so-called non-utility and affiliate power producer) generation, I would readily pronounce the long-term market free of anti-competitive merger impact.
In fact, I find astounding the Commission's unwillingness to do so.
The majority today, slip op, at 35-36, holds,"(For) the long ()
term we cannot determine the cytent of compe*.itive discipline (Public Utility Regulatory Policies Act (PURPA) generation, conservation and IPPs can provide)."
The same Commission only last year approved market-based rates for two independent power projects in New England, Dartmouth Power Associates Limited Partnershin, 53 FERC 1 61,117 (1990); and Enron Power Enterprise Corn., 52 FERC 1 61,193 (1990).
In both, the Commission discovered sufficient alternate sources to justify departing f rom traditional rates.
In Dartroulh, 53 FERC at 61,359, the majority relied on QFs to provide the " competitive discipline" over Dartmouth.
The contract ran for 25 years.
The order recited:
The negotiations between Dartmouth and Commonwealth Electric for the first 50 ms were conducted contceperaneously with.
a QF solicitation in which Commonwealth Electric received bids totalling about 12 times the block of capacity (it) sought.
(Furthermore,)
Commonwealth Electric clearly had the QF and Dartmouth proposals available and could weigh the relative advantages of them (sic) against each other.
(For the later increment) taking into account that the Massachusetts QF market remained strong (in 1900) and provided viable alternatives we conclude that post bid negotiations took place in a market where Commonwealth Electric had numerous alternatives That should suffice here.
Even though in 1990 UU and PSNH operated as separate companics, the merger (and combination of their transmission grids) leaves matters the same.
The statute guarantees to QFs transmission rights for their PURPA sales.
NU's acquisition of PSNH leaves PURPA intact.
QFs should have no more trouble acting as alternate sources in the future.
Enron went even further.
There, the majority relied, 52 FERC at 61,170 on the "' contrasting or changing characteristics' in the electric industry" as a whole for its conclusion that New England utilities operate in a competitive environment.
- Indeed,
7 Dockot No. EC90-10-000, gi alt
- 22 the conclusion, ist, relied on cases dealing with transactions in Indiana and Virginia.
I Yet, all of a sudden, doubt sets in.
Has the non-utility generation sector shrunk?
We all-know it has grown in prominence and, according to the Utility Data Institute projections, will become increasingly important in the future.
Why the new i
skepticism?
I can only explain this by citing to a similar phenomenon.
Justice Stewart tried to reconcile Supreme Court merger precedent under the clayton Act.
He concluded, U.S.
v.
Von's Grocerv gnt, 384 U.S.
270, 301 (1966), "The sole consistency that I can find is that
. the Government always wins."
In our jurisprudence the "non-utility generator" invariably takes home the roses.
4.
March To The Scaffol.d similarly, I think the majority too glibly " discount (s) the value of NEPOOL.
as an alternative to (the transmission service of) the merged firm [,)" slip op. at 41.
NEPOOL, the New England Power Pool, basically integrates the operations of its member utilities in generation and sets out rules for the transmission grid.
NEPOOL exists to provide for the needs of its members.
I believe all the New England traditional utilities except one (a municipal) belongs.
That should make REPOOL a realistic choice for a buyer.
l
" Transmission The order concludes otherwise because, id.,
for (non-member) power.
is not available Transmission for those purchases must be obtained individually f rom the selling authority and intervening systems."
Translated, that means NEPOOL would not do for IPP power.
5.
Enear of A Witches' Sabbath For its crescendo, the majority has, in one sentence, slip op. at 48, reversed Utah and instituted a gar ne rule against
- orgers above a certain size.
Of course, if applicants agree to file tariffs providing for open access transmission, " Heaven
- knows, Anything goes" (to borrow from Cole Porter), but I refer to unconditioned proposals.
Even if the majority were correct in its market selections and its conclusion than NU will control a f
" dominant share," the Commission lacks a major underpinning for i
the conditions it imposes.
What chances does the merger bring that harm competition?
[
i l
Ur,like an unregulated industry, electric utility monot t ly remains legal.
Therefore, the conclusions the majority draes regarding the implications of the percentage of transmission NU L
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4 Docket No. EC90-10-000, c3 alt
- 33 will now control, or the inadequacy of restraints on the merged company, provide insufficient support for imposing conditions on the merger.
Section 203 gives us authority only to stop the spread of "artspective anti-competitive effects of the merged Utah Power & Licht Company, Order company's operations.
pn Rehearina, 47 FERC $ 61,209 at 61,758 (1989) (Trabandt, commissioner, dissenting in part) (emphasis in original).
In the Ulmh case, the Commission premised imposing conditions on specific record evidence concerning Utah Power &
found that before the merger Light Company's behavior.
- First, "e
the company "has consistently refused to permit the whcoling of low-cost power across its system.
" 45 FERC at 61,287.
Second, we concluded that "instead of using cheaper energy, (the company) is running generating units it otherwise would not in order avoid (forcing shareholders to carry the costs of those plants,)" 45 TERC at 61,289.
What does the record here show about NU's operations, specifically, its transmission grid?
NU claims, slip op. at 46-47, that: it currently provides more transmission than any other How England utility; it never denied transmission in order to make a sale itself; in fact, it sells transmission for competitors; it allows its system to be a conduit for IpP power g ng outside; and "(in) few cases (has it ever) denied a request or transmission service for any reason (and never for non-utility generation.)"
In opposition, the order recites, slip op. at 45, the Eastern REMVEC intervonors argue that: NU negotiates transmission deals, rather than file a general tariff; the company imposes unreasonabic minimum term requirements; "NU has a history of delaying its filing of negotiated transmission rates until the buyer has lost the opportunity and the will to protest"; NU insists that the customer signing the transmission contract not contest it before FERC; and "(NU) habitually provides lower in quality service at higher prices than other suppliers New England.
Except for the minimum tern question (which the ALJ fixed at one day and we affirm, slip op, at 87), I see nothing remarkabic.
Making allowances for dramatic advocacy, I read the intervenors to say only that NU drives a hard bargain.
(As for not allowing a customer to contest the contract it signed, we have never found fault with that, e,q.,
Pacific Gas & Electric Co.,
44 FERC 5 61,010, order on rehearina, 45 FERC 5 61,061 (1988); Engific Gas
& Electric Co._, 42 FERC 1 61,406, prder on rehearino, 43 FERC i 61,403 (1908).)
The Eastern REMVEC Brief on Exceptions attempts to throw further condemnation at NU.
The intervenors say, (Brief on l
Exceptions at 20-21) that negotiations: "make planning more
(
1 t
Docket No. EC90-10-000, gi alt
- 34 difficult" because the customer "cannot () know" overything in advance; " waste time and create uncertainties that can kill a deal"; give NU a " mechanism" for " attempting to negotiate"
[
unreasonable conditions: "make anti-competitive behavior more situations in likely"; " tend to avoid" regulation; and " promote a
which utilities "offectively" " dictate []" the contract.
[
This inconsistent attack on NU amounts to a plea that the Commission must create for transmission customers a highly favorable business environment: all take and no give.
It smacks of the philosophy of free enterprise advocates who favor it as long as the government guarantees a profit and the risk rests on others.
At bottom, these accusations do not even rise to unproved allegations of past UU conduct.
They reflect unbridled speculation about future NU behavior, t
I reject the intervenors' arguments.
The majority, slip op.
at 48, ducks the question entirely.
"Having reached th[e]
conclusion [that the merger will produce anti-competitive results) we see no need at this point to decide the merit (sic) of intervenors ' allegations that NU's past transmission practice provides.
justification for not approving the merger as proposed."
The discussion, slip op. at 47, leading up to the
" conclusion" mentioned "new means" for UU to act inefficiently.
These "means" turn out to be that the merged company will own more transmission and ;ontrol greater reserves of electricity.
In plain English, NU wa11 grow.
That result, in and of itself, does not require the extreme conditioning in this order under any accepted theory of merger law under the Federal Power Act or more l
general antitrust law.
(on a miscellaneous issue, I disagree with reducing the rate of return on the Seabrook contract, slip op. at 116-117.
Despite the quotation from Conneel.icut Yankee Atsmic Power Co.,
20 FERC i 61,373 (1982), investors value a guaranteed payment only as much as its underpinning.
Here, a single asset, the Seabrook plant, stands behind the payment.
That, to me, makes illogical the conclusion that North Atlantic bears lower risk than NU. )
Under section 203 of the Federal Power Act, I would approve l
l the merger with far more Ionient conditions than the majority imposes.
As I stated at the beginning of this opinion, this j
decision, while cloaked as a merger case, in fact, involves v
primarily transmission policy and how to promote IPPs.
One need only read the conditions the majority places on its approval to see that.
(For example, the majority, slip op. at 96, turns merger law on its head and forces NU to accept transmission requests from northern sellers, even though they can otherwisc I
obtain what they need.)
e
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i Docket No. EC90-10-000, si alt,
III.
Conclusion i
Even as I forcefully disagree with today's action, I realize the.t many both inside and outside the Commission view the outcome of this case as the ticket to a bright future.
For other reasons as well, none of the affected interests may take issue with the resiult.
Perhaps NU will remember Pacificorp's experience with the transmission conditions we placed on its acquisition of Utah Power & Light company and conclude that hardly anyone will come as):ing for access.
Possibly, NU vill accept this as the price for acquiring the Seabrook nuclear plant, and the Bankruptcy Judge may see the conditions as the price for putting PSNH back r
on its feet.
i So, the parties may take this decision in stride and nobody will challenge the Commission in court.
I can understand the ponitions of UU and the Bankruptcy Judge.
I believe mine, as a regulator, differs.
I harbor doubts about the kind of o.<cctric utility industry we have created here.
For legal and practical reasons, I prefer to allow the debate on the electric utility issues in the energy legislation to unfold in Congress this fall, rather than impose a new structure here by regulatory flat in a i
merger.
i I realize that on this vote, I am not in the majority.
Nevertheless, I remain undeterred, and I will continue to oppose such policies which, either blatantly -- as in Utah -- or more veiled -- as here -- subordinate the legitimate interests of native load customers as a matter of policy.
As Dylan Thomas once wrote (D. Thomas, Deaths and Entrances, (1946)),
Do not go i
.. Rage, rage against the df ng gentle into that good night /
of the light."
I dissent in part as to the merger conditions.
A w
Charles A.
Trabandt dM Commissioner i
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l Northeast Utilities Service
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Docket Nos. EC90-10-000, Company
)
ER90-343-000, ER90-144-000, (Re Public Service Company of )
ER90-145-000 and EL90-9-000 New Hampshire)
)
(Issued August 9, 1991)
TERZIC, Commissioner, concurrina:
Initially, I note that my support of this order is based on the facts of this particular case.
I further write to register my disappointment at staff's and my coAleagues' failure to acknowledge the following basic principle involving concepts labeled here " opportunity cost pricing."
I believe recovery of
-opportunity costs are appropriate to compensate native load customers.
For purposes of discussion " opportunity costs" could be defined as:
the costs of any benefits foregone by the transmitting utility when it provides transmission service to a third party.
Moreover, the Commission would not be breaking new ground in adopting this definition, nor would it be inconsistent as a matter of policy to compensate native load customers for the cost of benefits foregone.
In opinion 170; Opinion and Order Approving Just and Reasonable Rates for Generation Adders 1/,
the Commission af firmed an ALJ determination that it was reasonable for a jurisdictional utility to recover revenues foregone from economy energy transactions as a cost of providing emergency power and nondisplacement energy.
The ALJ was quite cicar as to the appropriateness of lost opportunity charges and the intended beneficiaries of such charges.
There can be no question as to the existence of foregone revenues as an item of cost to the supplying utility.
When emergency sales preempt economy sales, the utility's firm customers would receive less revenue for credit to their expenses, even though non-firm energy is provided in both instances.
The foregone revenues are quantifiable and should fully benefit the firm customers at the expense of non-firm customers who receive the emergency service.
The Commission has held that interchange transactions should be made at no cost to the utilitics' full requirements customers.[ footnote omitted]_ Accordingly, the utility supplying the power should be lef t in an equivalent revenue 1/
Ohio Edison Company, Ohio power Company, 23 FERC 5 61,344 (1983).
N' t
{
i 2-Docket Hos. EC90-10-000, ER90-143-000, ER90-144-000, ER90-145-000 and EL90-9-000 position after the emergency sale as that which would have obtained had the economy sale been made (footnote j
omitted). 2/
E While this case centered on economy sales foregone as a result of the provision of emergency service, I believe the principles it sets forth are equally applicable to circumstances where economy purchases are foregono as a result of providing transmission i
l service.-
J Although I realize that we are not deciding here whether j
Northeast Utilities Service Company's proposal for opportunity cost-pricing is just and reasonabic, it is an issue that was
(
presented to us and indeed the order raises and discusses this issue in a number of pages.
Thus I cannot understand the reluctance to generally support or acknowledge the notion that it is appropriate to compensate native load customers when a utility
)
i
-must engage in third party wheeling and as a result forego a benefit to its native load customers.
Certainly, I agree we may l
1 eave for the cases pending before us a more precise definition l
i of such opportunity costs.
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%n Brank3 Terzic
/
Commissioner i
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2/
Ohio Edison Company, Ohio power Company, 15 FERC 5 63,062 at
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65,306 (1981).
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i UNITED STATES OT AMERICA pg Q N TEDERAL ENERGY REGULATORY COMMISSION August 14, 1991 Northeast Utilitics Servics
)
Docket Nos. EC90-10-000 Company
)
ER90-143-000, ER90-144-000, (Re Public Service company
)
ER90-145-000 and EL90 9-000 Nov Hampshire)
)
TO ALL PARTIES:
Attached is Cor_nissioner Trabandt's supplemental statement to the order issued August 9, 1991, in the above referenced proceeding.-
M s h. Y Loin D. Cashell, Secretary.
Northeast Utilitlos Service
)
Docket Nos. EC90-10-000 Company
)
ER90-143-000, ER90-144-0CO, (Re Public Service Company of
)
ER90-145-000 and EL90-9-000 New Hampshire)
)
4 (Issued August 14, 1991)
Sunelement To oeinion of commissi'oner Trabandt:
I argued (slip op. at 5-14) that the transmission re-allocation scheme the majority adopted for Northeast Utilities (NU)'s transmission system neglects the interests of the native load.
Chairman A11 day gave a speech yesterda American Bar Associattun in Atlanta, Georgia,y before the regulation of the electric utility industry.
on the commission's discussed the subject of native load interests in the context ofIn that speech, he transmission access policy.
interest to parties in this case.The following excerpts may be of atten; ion.
I commend them to the readers' A major topic of debate regarding transmission is tue argument that franchised utilities built transmissien capacity to serve their native load customers.
The utility -- the argument goes -- therefore should be able to use any excess capacity on i
its lines to make off-system sales or purchases that would further reduce the rates of those native lead customers. (Discusses how off-system asies work).
Some argue that these types.of transactions, which are non-firm in nature, l
should have priority-over third-party firn i
transmission requests.
In other words, priority of use of the transmission system l
l should always go to_the native load customer l
of the utility that owns the line.
1 At_this point, let me clarify that when l
they say priority-for_ native load customnrs, they aren't talking about using the i
transmission system to directly serve those customers.
There's no question in my mind j
that native load customers should get first I
priority to use the lines to reliably serve their firm power needs.
That's what the commission recently decided in the (HH What is.at issue here goe)s merger-case.
beyond reliability-related use of transmission.
The proponents of these arguments would give higher priority to the transmission owner's non-firm transactions than they would give to third-party firm transactions,~on the basis that it
Dockot No. EC90-10-000, et.ali econceically benefits native load.
In the past, these arguments made sense, i
But today, when we have regional instead of local markets, and when we have an emerging competitive generation market, this is no longer the case.
We should always pro'.act the native load customers on a local basis, to the extent of assuring reliable firm t
service.
But we need to look beyond this and try to maximize the benefits of our i
transmission systems on behalf of all customers in wider, regional markets.
4 It's no longer true that a particular utility's native load customers deserve special treatment, to the detriment of someone else's native load customers.' After all, everybody is somebody's native load customer.
Every third party transmission transhetion is meant to benefit a native load
~
customer somewhere on the interconnected grid.
If we really want to create competitive markets, we have to take a broader perspective.
This means we have to come up with a fair
-way of allocating and pricing existing excess transmission capacity, and providing the right incentives for expansion of new transmission when needed.
(Talks about transmission pricing).
This brings up the issue of what happens if new transmission can't be built.
In other words, as one of our recent merger cases put it, there is-an " immutable constraint" that prevar.ts expansien.
In this n.erger case, the commission put in place a way to-determine-whether there is indeed an immutable constraint and, if so, a way to allocate existing scarce capacity in an efficient and l
equitable manner.
I think the approach we've taken so far at -
the commission is on the right track.
Transmission goes to the highest valued use.
Firn transmission rights take a priurity over non-firm rights.
It holders of firt rights L
want to re-sell or-re-assign the firm capacity for non-firm uses that have a higher i
economic value,-this would be accommodated.
In this way, capacity should go to the highest valued use.
(Remarks of Chairman A11 day at 8-10; emphasin in original).
e.
Docket flo. EC90-10-000, et al.
3-The text cpeaks for itself.
I believe the Chairman's remarks provide a timely and useful data point for assessing the likely results of the transmission re-allocation procedure under various scenarics.
_ffnA A
L CFdries A. Tr'abandt Com:nissioner
.