[Federal Register Volume 62, Number 236 (Tuesday, December 9, 1997)]
[Rules and Regulations]
[Pages 64688-64715]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-31841]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket Nos. RM95-8-003 and RM94-7-004; Order No. 888-B]


Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery of 
Stranded Costs by Public Utilities and Transmitting Utilities

Issued November 25, 1997.
AGENCY: Federal Energy Regulatory Commission, Energy.

ACTION: Final rule; order on rehearing.

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SUMMARY: The Federal Energy Regulatory Commission affirms, with certain 
clarifications, the fundamental calls made in its order on rehearing of 
the final rule in this proceeding. The final rule directed public 
utilities to open their transmission lines to competitors and to offer 
them the same charges and conditions they apply to themselves. The rule 
also gave utilities an opportunity to seek recovery of certain stranded 
costs, i.e., costs that were prudently incurred to serve customers that 
use open access transmission under the final rule to shift to another 
power supplier. The Commission in this order clarifies its position on 
recovery of stranded costs in the case of municipalizations and 
municipal annexations, where customers previously served by a public 
utility become customers of a municipal utility instead.

EFFECTIVE DATE: February 9, 1998.

FOR FURTHER INFORMATION CONTACT:
David D. Withnell (Legal Information--Docket No. RM95-8-003), Office of 
the General Counsel, Federal Energy Regulatory Commission, 888 First 
Street, N.E., Washington, D.C. 20426, (202) 208-2063.
Deborah B. Leahy (Legal Information--Docket No. RM94-7-004), Office of 
the General Counsel, Federal Energy Regulatory Commission, 888 First 
Street, N.E., Washington, D.C. 20426, (202) 208-2039.
Daniel T. Hedberg (Technical Information--Docket No. RM95-8-003), 
Office of Electric Power Regulation, Federal Energy Regulatory 
Commission, 888 First Street, N.E., Washington, D.C. 20426, (202) 208-
0243.
Joseph M. Power (Technical Information--Docket No. RM94-7-004), Office 
of Electric Power Regulation, Federal Energy Regulatory Commission, 888 
First Street, N.E., Washington, D.C. 20426, (202) 208-0243.

SUPPLEMENTARY INFORMATION: In addition to publishing the full text of 
this document in the Federal Register, the Commission also provides all 
interested persons an opportunity to inspect or copy the contents of 
this document during normal business hours in Room 2A, 888 First 
Street, N.E., Washington, D.C. 20426. The complete text on diskette in 
WordPerfect format may be purchased from the Commission's copy 
contractor, La Dorn Systems Corporation. La Dorn Systems Corporation is 
located in the Public Reference Room at 888 First Street, N.E., 
Washington, D.C. 20426.
    The Commission Issuance Posting System (CIPS), an electronic 
bulletin board service, also provides access to the texts of formal 
documents issued by the Commission. CIPS is available at no charge to 
the user. CIPS can be accessed over the Internet by pointing your 
browser to the URL address: http://www.ferc.fed.us. Select the link to 
CIPS. The full text of this document can be viewed, and saved, in ASCII 
format and an entire day's documents can be downloaded in WordPerfect 
6.1 format by searching the miscellaneous file for the last seven days. 
CIPS also may be accessed using a personal computer with a modem by 
dialing 202-208-1397, if dialing locally, or 1-800-856-3920, if dialing 
long distance. To access CIPS, set your communications software to 
19200, 14400, 12000, 9600, 7200, 4800, 2400, or 1200 bps, full duplex, 
no parity, 8 data bits and 1 stop bit. The full text of this order will 
be available on CIPS in ASCII and WordPerfect 6.1 format. CIPS user 
assistance is available at 202-208-2474.

Table of Contents

I. Introduction
II. Public Reporting Burden
III. Background
IV. Discussion
    A. Open Access Issues
    1. Discounting
    2. Reciprocity
    3. Indemnification/Liability
    4. Qualifying Facilities (QF)/Real Power Loss Service
    5. Right of First Refusal/Reservation of Transmission Capacity
6. Energy Imbalance Service
    a. Appropriate bandwidth for small utilities
    b. Settlements establishing a deviation bandwidth or minimum 
imbalance
    7. Transmission Provider ``Taking Service'' Under Its Tariff for 
Power Purchased on Behalf of Bundled Retail Customers
    a. Jurisdiction
    b. Purchases for retail native load

[[Page 64689]]

    8. Indirect Unbundled Retail Transmission in Interstate Commerce
    9. Mobile-Sierra
    10. Tariff Issues
    a. Load served ``behind-the-meter''
    b. Definition of ``Native Load Customers''
    c. Schedule changes
    d. Restriction on making firm sales from designated network 
resources
    e. Reactive Power
    f. Network Operating Agreements
    g. Network customers with loads and resources in multiple 
control areas
    h. Network customer designation of load
    11. Waivers of Order Nos. 888 and 889
    12. Financial Independence of ISO Employees
    13. Distribution Charges
    14. Tight Power Pools
    a. Non-pancaked rates
    b. Coordination transactions
    15. Legal Authority
    16. Ancillary Services
    17. Fair Market Value
    18. Pre-Existing Transmission-Only Contracts
    19. Apportionment of Transmission Revenues For Public Utility 
Holding Companies And Power Pools
    20. Accounting for Transmission Provider's Own Use of Its System
    B. Stranded Cost Issues
    1. Municipal Annexation
    2. Pre-existing Transmission Rights
    3. Load Growth and Excess Capacity
    4. G&T and Distribution Cooperatives
    5. Treatment of Contracts Extended or Renegotiated Without a 
Stranded Cost Provision
    6. Customer Expectations of Continued Service at Below-Market 
Rates
    7. Miscellaneous
V. Environmental Statement
VI. Regulatory Flexibility Act Certification
VII. Information Collection Statement
VIII. Effective Date
Appendix A (List of Petitioners)
Appendix B (Tariff Revision)

    Before Commissioners: James J. Hoecker, Chairman; Vicky A. 
Bailey, and William L. Massey.

I. Introduction

    In this order, the Commission affirms, with certain clarifications, 
the fundamental calls made in Order No. 888-A. \1\
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    \1\ As described further below, the Commission is making one 
revision to the pro forma open access transmission tariff. See infra 
Section IV.A.10.f and Appendix B. Because of this single revision 
and its minor nature, the Commission concludes that it would be 
administratively burdensome to require all public utilities with pro 
forma open access transmission tariffs on file with the Commission 
to submit compliance tariffs to reflect the revision. Accordingly, 
the Commission will amend all pro forma open access transmission 
tariffs currently on file with the Commission to incorporate the 
tariff revision and no tariff compliance filings will be necessary.
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II. Public Reporting Burden

    This order on rehearing issues a minor revision to Order Nos. 888 
and 888-A.\2\ We find, after reviewing this revision, that it does not 
increase or decrease the public reporting burden.
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    \2\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. para. 
31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 (March 
14, 1997), FERC Stats. & Regs. para. 31,048 (1997).
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    Order No. 888 contained an estimated annual public reporting burden 
based on the requirements of the Open Access Final Rule and the 
Stranded Cost Final Rule.\3\ Using the burden estimate contained in 
Order No. 888 as a starting point, we evaluated the public burden 
estimate in light of the revision contained in this order and assessed 
whether the estimate needed revision. We have concluded, given the 
minor nature of the revision, that our estimate of the public reporting 
burden of this order on rehearing remains unchanged from our estimate 
of the public reporting burden contained in Order Nos. 888 and 888-A. 
The Commission has conducted an internal review of this conclusion and 
has assured itself that there is specific, objective support for this 
information burden estimate. Moreover, the Commission has reviewed the 
collection of information required by Order Nos. 888 and 888-A, as 
revised and clarified by this order on rehearing, and has determined 
that the collection of information is necessary and conforms to the 
Commission's plan, as described in Order Nos. 888 and 888-A, for the 
collection, efficient management, and use of the required information.
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    \3\ 61 FR 21540, 21543; FERC Stats. & Regs. para. 31,036 at 
31,638 (1996). In Order No. 888-A, the Commission concluded that its 
estimate of the public reporting burden in that order on rehearing 
remained unchanged from its estimate in Order No. 888. 62 FR 12274, 
12280; FERC Stats. & Regs. para. 31,048 at 30,183 (1997).
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    Persons wishing to comment on the collections of information 
required by Order Nos. 888 and 888-A, as modified by this order on 
rehearing, should direct their comments to the Desk Officer for FERC, 
Office of Management and Budget, Room 3019 NEOB, Washington, D.C. 
20503, phone 202-395-3087, facsimile: 202-395-7285. Comments must be 
filed with the Office of Management and Budget within 30 days of 
publication of this document in the Federal Register. Three copies of 
any comments filed with the Office of Management and Budget also should 
be sent to the following address: Ms. Lois Cashell, Secretary, Federal 
Energy Regulatory Commission, Room 1A, 888 First Street, N.E., 
Washington, D.C. 20426. For further information, contact Michael 
Miller, 202-208-1415.

III. Background

    In Order No. 888, the Commission required all public utilities that 
own, operate or control interstate transmission facilities to offer 
network and point-to-point transmission services (and ancillary 
services) to all eligible buyers and sellers in wholesale bulk power 
markets, and to take transmission service for their own uses under the 
same rates, terms and conditions offered to others. Order No. 888 
required functional separation of the utilities' transmission and power 
marketing functions (also referred to as functional unbundling) and the 
adoption of an electric transmission system information network. To 
implement the requirements of comparable open access transmission, the 
Commission required all public utilities that own, operate or control 
interstate transmission facilities to file open access non-
discriminatory transmission tariffs that contain minimum terms and 
conditions of non-discriminatory transmission service. In Order No. 
888, the Commission established rules for discounting practices, 
provisions governing priority of service and curtailment, and a right 
of first refusal for all firm transmission customers. In addition, 
Order No. 888 conditioned the use of a public utility's open access 
service on the agreement that, in return, it is offered reciprocal 
service by non-public utilities that own or control transmission 
facilities.
    With regard to stranded costs, Order No. 888 gives utilities the 
opportunity to seek to recover legitimate, prudent, and verifiable 
wholesale stranded costs associated with serving customers under 
wholesale requirements contracts executed on or before July 11, 1994 
that do not contain explicit stranded cost provisions, and costs 
associated with serving retail-turned-wholesale customers. The 
opportunity to seek stranded costs is limited to situations in which 
there is a direct nexus between the availability and use of a 
Commission-required transmission tariff and the stranding of the costs. 
The Commission adopted a revenues lost approach for calculating a 
utility's stranded costs, and determined that stranded costs should be 
recovered from the customer that caused the costs to be incurred. The 
Commission decided in Order No. 888 to be the primary forum for 
addressing the recovery of stranded costs caused by retail-turned-
wholesale customers, but not to be the primary forum in cases involving 
existing municipal utilities that annex retail customer service 
territories. Order No. 888 also clarified whether and when the

[[Page 64690]]

Commission may address stranded costs caused by retail wheeling and the 
extent of the Commission's jurisdiction over unbundled retail 
transmission. The Commission determined that the only circumstance in 
which it will entertain requests for the recovery of stranded costs 
caused by unbundled retail wheeling is when the state regulatory 
authority does not have authority under state law to address stranded 
costs when the retail wheeling is required.
    Order No. 888 further addressed the circumstances under which 
utilities and their wholesale customers may seek to modify contracts 
made under the old regulatory regime, taking into account the goals of 
reasonably accelerating customers' ability to benefit from 
competitively priced power and at the same time ensuring the financial 
stability of electric utilities during the transition to competition. 
The Commission determined that pre-existing contracts would continue to 
be honored until such time as they were revised or terminated. The 
Commission also found that those who were operating under pre-existing 
requirements contracts containing Mobile-Sierra clauses would 
nonetheless be allowed to seek reform of the contracts on a case-by-
case basis, and that public utilities would be allowed to file to amend 
their Mobile-Sierra contracts for the limited purpose of providing an 
opportunity to seek recovery of stranded costs, without having to make 
a public interest showing that such cost recovery should be permitted.
    In Order No. 888-A, the Commission reaffirmed its basic 
determinations in Order No. 888, with certain clarifications. For 
example, it revised the discounting requirements to better permit the 
ready identification of discriminatory discounting practices while also 
providing greater discount flexibility, and it clarified several 
aspects of the reciprocity condition. It also clarified that if 
utilities under Mobile-Sierra contracts seek to modify provisions that 
do not relate to stranded costs, they will have the burden of showing 
that the provisions are contrary to the public interest. In addition, 
the Commission reconsidered its decision in Order No. 888 not to be the 
primary forum for determining stranded cost recovery in cases involving 
municipal annexation and concluded that such cases should fall within 
the Commission's province.
    In this order, the Commission affirms, with certain clarifications, 
the fundamental calls made in Order No. 888-A.

IV. Discussion

A. Open Access Issues

1. Discounting
    A number of entities seek rehearing and/or clarification of the 
Commission's modified discounting policy that requires transmission 
providers to offer the same discount over all unconstrained paths to 
the same point of delivery.\4\ Several of these entities assert that 
the Commission's modified policy encourages discriminatory behavior.\5\ 
NRECA and TDU Systems argue that the Commission's policy opens the door 
to customer-by-customer discrimination (including discrimination by the 
transmission provider in favor of its native load customers) because it 
is likely that only one or a few customers would want transmission 
service to a particular delivery point. They also assert that the 
transmission provider unreasonably could discount service on a path 
where it has load, but decline discounts to another delivery point 
halfway along the same path.\6\ They further contend that the 
Commission's new policy ``swings the pendulum too far in the direction 
of allowing price discrimination'' by the transmission monopolist. 
According to TDU Systems, the Commission's policy ``does not confine 
the transmission provider's incentive to give discounts for its own 
transmission uses to those instances, and only those instances, in 
which such discounts are economically justified.'' TDU Systems adds 
that ``the OASIS reporting will be inadequate to remedy discrimination 
in discounting short-term non-firm transmission, since the transactions 
will be over before complaints can even be filed.'' \7\
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    \4\ Arizona, NRECA, TAPS, and TDU Systems. APPA also raises this 
issue, but APPA filed its request for rehearing out-of-time on April 
4, 1997. APPA failed to file its rehearing request within the 30 day 
period required by the Federal Power Act. See 16 U.S.C. 825l(a). 
Accordingly, we will not accept the rehearing request for filing, 
but will accept the pleading as a motion for reconsideration.
    \5\ NRECA, TDU Systems, TAPS and APPA.
    \6\ See also TAPS.
    \7\ TDU Systems at 8-10.
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    TAPS likewise asserts that ``[b]y allowing transmission providers 
to select the delivery points meriting a discount, the Commission is 
encouraging discriminatory behavior that it will be unable to remedy'' 
through an after-the-fact complaint proceeding.\8\ It maintains that 
the Commission's approach ``makes it less likely that transmission 
providers will provide competitors non-firm transmission service at 
rates reflecting the lower quality of the service (if the Commission 
permits non-firm transmission rates to be capped at the firm rate).'' 
\9\ It notes that TAPS members--

    \8\ TAPS at 17.
    \9\ Id. at 18 (footnote omitted).
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have experienced withdrawal of discounts they have enjoyed under the 
Order No. 888 discounting policy and have seen evidence that the 
revised policy will be applied by transmission providers to offer 
discounts to each other, in the hope, expectation, or tacit 
agreement that they will be offered reciprocal discounts on the 
other transmission provider's system when requested, while a 
transmission dependent utility must always pay full freight. [\10\]

    \10\ Id.
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    APPA asserts that the Commission properly required all discount 
negotiations to occur on the OASIS, but erroneously removed the 
requirement that affiliate discounts be offered for all service on 
unconstrained paths. It argues that the Commission ``has failed to 
balance its policy of ending discrimination in wholesale transmission 
services with the objective to send proper price signals to 
transmission providers and customers.'' \11\ Under the Commission's 
modified approach, APPA believes that transmission providers can offer 
discounts on a very selective basis--``public utility transmission 
providers will have the ability to provide discounts to affiliates in 
ways that exclude smaller utilities, including municipal utilities, 
from receiving those same discounts.'' \12\
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    \11\ APPA at 17.
    \12\ Id. at 19.
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    These entities propose several approaches to resolve the 
competitive problems they believe are associated with the Commission's 
modified approach to discounting. NRECA states that the Commission 
should revert to its Order No. 888 policy or require that discounts be 
offered on all unconstrained paths serving all similarly situated 
customers. NRECA and TDU Systems (which supports the second 
alternative) state that the alternative approach could be accomplished 
by requiring discounts on all unconstrained ``posted paths,'' or, if a 
discount is provided within a particular unconstrained area, the 
transmission provider should be required to offer the same discount on 
all unconstrained paths within the same area. Similarly, TAPS states 
that the Commission should revert to its Order No. 888 policy or, at a 
minimum, ``the discounts should be extended to all delivery points in 
the same unconstrained portion of the transmission provider's 
transmission

[[Page 64691]]

system plus other similarly situated customers (from an operational/
cost, rather than competitive, viewpoint).'' \13\ Moreover, APPA states 
that the Commission should revert to Order No. 888 or, in the 
alternative, ``should require uniform discounts across interfaces and 
within control areas, or, at a minimum, within unconstrained zones.'' 
\14\
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    \13\ TAPS at 19.
    \14\ APPA at 20.
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    TAPS adds that the best way to promote efficient transmission usage 
and competitive bulk power markets is ``to set non-firm rates at the 
lowest reasonable rate, in accordance with the Commission's statutory 
mandate * * *. It is unreasonable to rely on discounting, especially 
delivery point-specific discounts, to ensure that customers are not 
charged firm rates for interruptible, low priority, non-firm service.'' 
\15\ It requests that the Commission clarify that it will actively 
exercise its responsibility to ensure that customers are not 
overcharged for non-firm service.
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    \15\ TAPS at 20.
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    Arizona, on the other hand, seeks to narrow the Commission's 
revised discounting policy. It requests that the Commission allow a 
transmission provider to offer varying degrees of discount depending 
upon whether--

    (1) transactions over a particular path alleviate constraints on 
another transmission path, (2) certain transmission paths are loaded 
to a different degree than other paths, and (3) initial discounts 
encourage a sufficient number of transactions. [\16\]

    \16\ Arizona at 4.
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For example, it asserts that ``there could be multiple paths to the 
same delivery point, with each path potentially warranting different 
discounting treatment. A steep discount may be appropriate on one 
unutilized transmission path to encourage counter-wheeling transactions 
that will alleviate constraints on another path into the delivery 
point, whereas a smaller discount (or no discount at all) may be 
appropriate on another unconstrained, but highly valued, path into the 
delivery point.'' \17\
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    \17\ Id. at 5 (footnote omitted).
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    With respect to its second point, Arizona asserts that a 
transmission path with relatively little available transmission 
capability (ATC) deserves a lower discount than a transmission path 
with relatively high ATC. It urges the Commission to clarify ``whether 
a transmission path that has an ATC equal to 80% of [total transmission 
capability (TTC)] should be discounted to the same degree as a 
transmission path that has an ATC equal to only 30% of TTC.'' \18\ As 
to its third point, it seeks clarification that it ``may initially 
offer a steep discount on a transmission path into a particular 
delivery point to encourage transactions, but reduce the discount as 
more and more transactions take place over that path.'' \19\
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    \18\ Id. at 6 n.12.
    \19\ Id. at 6 (footnote omitted).
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    American Electric Power System (AEP) responds to TAPS' assertion 
that transmission providers will only offer discounts to each other as 
evidenced by a printout from AEP's OASIS under which TAPS contends 
``discounts are now available only to delivery points of other 
transmission providers, not those of TDUs.'' \20\ AEP indicates that, 
contrary to TAPS' assertion, it offers discounts to any transmission 
customer that has alternatives to using AEP's transmission system. It 
notes that this is consistent with the Order No. 888-A statement that a 
transmission provider should discount only if necessary to increase 
throughput on its system. It also adds that no customer is being 
charged rates that exceed a just and reasonable, cost-based rate. 
According to AEP, ``[t]o charge customers without alternatives less 
than the cost-based rate would be unduly discriminatory to AEP's native 
load customers who would otherwise have to make up the revenues not 
recovered from such customers.'' \21\ Moreover, because discounting 
must be conducted through the OASIS, AEP declares that there is no 
chance that a transmission provider will use discounting for any 
purpose other than to increase throughput. AEP also opposes TAPS' 
request to establish a price cap for non-firm service below that for 
firm service. It claims that such a change would allow customers on 
largely unconstrained transmission systems such as AEP's to game the 
system by requesting non-firm service priced at a low level with the 
knowledge that the service is essentially the equivalent of firm 
service.
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    \20\ AEP at 3. On April 17, 1997, AEP filed an answer to the 
request for clarification and rehearing of TAPS. In the 
circumstances presented, we will accept the answer notwithstanding 
our general prohibition on allowing answer notwithstanding our 
general prohibition on allowing answers to rehearing requests. See 
18 CFR 385.713(d).
    \21\ Id. at 4 (emphasis in original).
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    Commission Conclusion. We deny the requests for rehearing of our 
discounting policy. In Order No. 888-A, we addressed certain concerns 
raised by various parties on rehearing regarding our prior discounting 
policy and adopted a more balanced approach that would provide 
incentives to transmission providers to operate the transmission grid 
efficiently while ensuring that they do so in a not unduly 
discriminatory manner.\22\ Our balanced approach requires that (1) a 
transmission provider should discount only if necessary to increase 
throughput on its system, (2) any offer of a discount and the details 
of any agreed upon discount transaction must be posted on the OASIS 
(including any negotiation, i.e., any offers and counteroffers, of the 
discount), and (3) a transmission provider must offer the same discount 
for the same time period on all unconstrained paths that go to the same 
point(s) of delivery.
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    \22\ FERC Stats. & Regs. para. 31,048 at 30,274-76.
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    We believe that this approach is a reasonable and workable means to 
permit transmission providers to provide discounts in a not unduly 
discriminatory manner. Transmission providers will not have unnecessary 
restrictions on their ability to increase throughput on their 
transmission systems, which accrues to the benefit of all of their firm 
customers, while OASIS will allow the Commission and other users of the 
system to monitor for instances of unduly discriminatory behavior by 
such transmission providers.\23\
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    \23\ With respect to Arizona's request that a transmission 
provider be allowed to offer varying degrees of discount depending 
on the circumstances, we note that this Rule does not reach that 
level of specificity. A transmission provider is free to implement 
any discounting proposal which it believes can increase throughput 
without doing so in an unduly discriminatory manner, provided that 
the proposal offers the same discount for the same period to all 
eligible customers on all unconstrained paths that go to the same 
point(s) of delivery. However, if challenged on complaint, it should 
be prepared to defend its method. The only alternative is to require 
no discounting, an approach we reject as contrary to firm customers' 
interests and efficient grid use.
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    In this regard, we also disagree that posting of discounts on OASIS 
is inadequate for short-term discounts because the transactions will be 
over before a complaint could be filed. All complaint proceedings occur 
after the fact, but we believe that such proceedings nevertheless act 
as a deterrent to improper behavior. The Commission will not be 
reluctant to impose appropriate sanctions in instances where 
transmission providers engage in unduly discriminatory discounting 
practices. Moreover, any alternative would likely require a preapproval 
process that could, as parties to this proceeding have argued, shut 
down a substantial portion of the hourly transactions in short-term 
markets that depend upon discounted transmission to go forward.
    We see no need at this time to adopt a more restrictive discounting 
policy

[[Page 64692]]

that could hinder a transmission provider's ability to increase 
throughput on its system based solely on allegations that the 
transmission provider may act in an unduly discriminatory manner. The 
opportunity to monitor the discounting behavior of transmission 
providers through OASIS will provide data that will allow the 
Commission to evaluate the adequacy and effectiveness of its 
discounting policy.\24\ Until we see evidence that our discounting 
policy will not work or see patterns of unduly discriminatory 
discounting practices, we will continue the Order No. 888-A discounting 
policy, with the OASIS safeguards in place.
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    \24\ As the market evolves, the Commission may need to take up a 
broad array of transmission pricing issues. It may well develop that 
a long-term solution to any problems raised by discounting requires 
fundamental changes to the transmission pricing methods currently in 
place in the electric industry.
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2. Reciprocity
    Several entities raise a variety of issues with respect to the 
Commission's reciprocity condition. NRECA and TDU Systems request 
clarification that the amendment to section 6 of the pro forma tariff 
that deleted the words ``in interstate commerce'' was intended to 
affect only the reciprocity obligation of foreign transmission 
customers and not the reciprocity obligation of transmission customers 
located in the United States.\25\ They seek clarification that 
transmission customers within the United States need provide reciprocal 
service only on facilities used for the transmission of electric energy 
in interstate commerce and not over facilities used in local 
distribution or only for the transmission of electric energy in 
intrastate commerce.
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    \25\ NRECA at 13-14; TDU Systems at 13-14.
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    Also with respect to section 6 of the pro forma tariff, NEPOOL 
takes issue with the additional language that provides that reciprocity 
applies to ``all parties to a transaction that involves the use of 
transmission service under the Tariff, including the power seller, 
buyer and any intermediary, such as a power marketer.'' \26\ It asserts 
that the breadth of this language could cause New Brunswick Power 
Corporation (New Brunswick), a Canadian utility that has engaged in 
economy and emergency transactions with NEPOOL and made unit sales to 
New England buyers, to cease or reduce sales in New England. According 
to NEPOOL, New Brunswick has indicated a concern that it does not have 
the legal authority to implement a generic open access tariff in New 
Brunswick. Thus, NEPOOL requests that the Commission provide that where 
a seller is simply continuing to make sales in the same manner as it 
did before Order Nos. 888 and 888-A, and is legally unable to provide 
reciprocity, the reciprocity requirement will not be applicable to 
it.\27\
    TAPS takes issue with the Commission's modified ``safe harbor'' 
procedure set forth in Order No. 888-A that permits a non-public 
utility to provide reciprocal service only to the transmission provider 
from whom it receives open access transmission service. TAPS believes 
that the Commission's modification is ``an unnecessary step backwards 
from its expressed aim of remedying past undue discrimination and 
providing non-discriminatory open access.'' \28\ It believes that the 
transmission provider's access to third party systems will be superior 
to that of its customers that support the transmission grid. According 
to TAPS, a customer would be at a disadvantage because it would be 
forced to resort to a filing under section 211. Thus, it asserts that 
the safe harbor should be available only to those that offer open 
access to all eligible wholesale transmission customers. ``At the very 
least, [it argues,] the special protections offered by the safe harbor 
should be available only if the non-jurisdictional utility makes its 
tariff available to the long term customers of the transmission 
provider.'' \29\
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    \26\ NEPOOL at 7.
    \27\ Id. at 7-8.
    \28\ TAPS at 22.
    \29\ Id. at 23 (footnote omitted).
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    RUS seeks rehearing and/or clarification with respect to a number 
of reciprocity related issues. RUS first complains that there is 
confusion regarding the alternatives available to non-public utilities. 
It asserts that in certain places in Order No. 888-A the Commission 
indicates that it will no longer allow bilateral agreements (e.g., 
``Alternatively, bilateral agreements for transmission service provided 
by a public utility will not be permitted.''), but that in other places 
the Commission encourages the use of bilateral agreements (e.g., ``A 
non-public utility may also satisfy reciprocity through bilateral 
agreements with a public utility.''). It also notes that Order No. 888-
A appears to substitute public utility waivers for the alternative of 
bilateral agreements. In any event, however, it argues that

    [p]ublic utilities have no incentive to enter into bilateral 
agreements or to waive the reciprocity requirement for a non-public 
utility that owns transmission. Indeed, these so-called options 
effectively invite public utilities to deny access to non-public 
utilities that have not filed open access tariffs. If a non-public 
utility cannot qualify for a waiver from the Commission, the public 
utility can, by denying a waiver or refusing to enter into a 
bilateral agreement, force the non-public utility to file a 
reciprocal tariff with the Commission. Moreover, requiring a non-
public utility to seek a waiver--whether from the public utility or 
the Commission--is inconsistent with the Commission's assertions 
that the provision of open access by non-public utilities is not 
required, but merely voluntary.\30\

    \30\ RUS at 10-11.
---------------------------------------------------------------------------

    RUS takes issue with the following statement in Order No. 888-A, 
claiming that it mischaracterizes the RUS program and RUS as anti-
competitive:

    With respect to TDU System's assertion that reciprocal service 
should not have to be rendered if it would interfere with RUS loan 
financing, we note that we have already indicated that reciprocal 
service need not be provided if tax-exempt status would be 
jeopardized. If TDU Systems is arguing that we should not require 
reciprocal service if RUS attaches such a condition in its 
regulation of RUS-financed cooperatives, we reject such argument. 
Such cooperatives have the option to seek bilateral service 
agreements. [Order No. 888-A, mimeo at 318].

RUS maintains that it does not place any prohibitions, restrictions, or 
conditions on financing to electric systems based on rendering 
reciprocal service. It states that while the Rural Electrification Act 
places restrictions on RUS financing, it does not prohibit cooperatives 
from obtaining financing for facilities through non-RUS sources.
    RUS seeks clarification that the statement in Order No. 888-A that 
``the seller as well as the buyer in the chain of a transaction 
involving a non-public utility will have to comply with the reciprocity 
condition'' does not mean that if a G&T uses an open access tariff, 
both the G&T and its distribution system are subject to the reciprocity 
provision.
    RUS also states that although the Commission acknowledges that it 
lacks jurisdiction to enforce rates charged by non-public utilities in 
reciprocal open access tariffs and to adjudicate stranded cost claims 
of non-public utilities, the Commission has indicated that if a non-
public utility includes a stranded cost component in a reciprocity 
tariff, ``the Commission will review that stranded cost provision if a 
public utility claims that the stranded cost component, as applied, 
violates the principle of comparability.'' \31\ According to RUS, ``any 
comparability determination with respect to stranded cost or other 
provisions contained in a non-public utility's open access tariff will 
involve the exercise of Commission jurisdiction over a non-public 
utility's open access

[[Page 64693]]

transmission tariff as well as a determination of the legitimacy of the 
non-public utility's stranded cost claims.'' \32\ RUS says that the 
Commission has not indicated that it will apply the comparability 
standard to the transmission rates that rural cooperatives charge 
members and non-members in a manner that will take into account the 
unique characteristics of a cooperative system, the inherent 
differences between members and non-members, and the intended 
beneficiaries of the RE Act.
---------------------------------------------------------------------------

    \31\ Id. at 12.
    \32\ Id.
---------------------------------------------------------------------------

    Commission Conclusion. With respect to NRECA and TDU Systems' 
requested clarification of the deleted words ``in interstate commerce'' 
from section 6 of the pro forma tariff, we reiterate that transmission 
customers in the United States must provide reciprocal transmission 
service ``over facilities used for the transmission of electric energy 
owned, controlled or operated by the Transmission Customer.'' \33\ 
Thus, a transmission customer must provide transmission service over 
all transmission facilities that it owns, controls or operates. This 
includes transmission facilities in both interstate and intrastate 
commerce. Such a customer, however, need not provide reciprocal service 
over facilities used solely in local distribution.
---------------------------------------------------------------------------

    \33\ See FERC Stats. & Regs. at 30,513.
---------------------------------------------------------------------------

    We recently addressed concerns similar to those raised by NEPOOL as 
to the applicability of the reciprocity condition to a Canadian utility 
selling power to a U.S. utility. In an order addressing Ontario Hydro's 
motion for a stay of the reciprocity provision of Order Nos. 888 and 
888-A as those orders apply to transmission-owning foreign entities, we 
explained that the reciprocity condition does not apply

    in circumstances where a Canadian utility sells power to a U.S. 
utility located at the United States/Canada border, title to the 
electric power transfers to the U.S. border utility, and the power 
is then resold by the U.S. border utility to a U.S. customer that 
has no affiliation with, and no contractual or other tie to, the 
Canadian utility. The reciprocity provision thus does not in any way 
affect historical Canadian-United States buy-sell arrangements, 
i.e., those involving sales to U.S. border utilities who then resell 
power to purchasers that have no contractual or other transactional 
link to the Canadian seller. For these types of historical sales, a 
Canadian seller is no worse off under Order Nos. 888 and 888-A than 
it was prior to the orders' issuance. Additionally, Order Nos. 888 
and 888-A do not disrupt any pre-Order No. 888 power sales contracts 
under which Ontario Hydro sells to U.S. utilities, or any pre-Order 
No. 888 transmission contracts under which it purchases transmission 
from U.S. utilities.\34\

    \34\ Order Clarifying Order No. 888 Reciprocity Condition and 
Requesting Additional Information, 79 FERC para. 61,182 at (1997) 
(footnotes omitted); see also Order Denying Motion for Stay, 79 FERC 
para. 61,367 (1997).
---------------------------------------------------------------------------

Thus, Order Nos. 888 and 888-A do not disrupt any existing agreements, 
as defined in those orders, between New Brunswick and any of its U.S. 
customers. Moreover, to the extent any of New Brunswick's transactions 
are buy-sell arrangements of the type described above, such 
transactions also are not affected by Order Nos. 888 and 888-A. 
However, if New Brunswick seeks to sell power under new agreements or 
through new coordination transactions, such transactions are subject to 
Order Nos. 888 and 888-A and New Brunswick would have to agree to 
provide reciprocal open access transmission, unless waived by the U.S. 
public utility or this Commission.
    TAPS' rehearing request with respect to the safe harbor procedure 
was not timely filed. In Order No. 888, the Commission explicitly 
stated that ``we intend that reciprocal service be limited to the 
transmission provider.'' \35\ The Commission also stated, in 
establishing the safe harbor procedure, that ``[w]e are aware that many 
non-public utilities are very willing to offer reciprocal access, and 
that some are willing to provide access to all eligible customers 
through an open access tariff.'' \36\ Thus, it was clear that a non-
public utility could meet reciprocity under the safe harbor procedure 
by agreeing to provide service only to the transmission provider or to 
any eligible customer. Nothing in Order No. 888-A changed this 
approach. The Commission's discussion of the safe harbor procedure in 
Order No. 888-A was limited to Santee Cooper \37\--a company-specific 
case decided subsequent to Order No. 888. The Commission noted that 
while the company in that case chose to offer an open access tariff to 
all eligible customers, ``Order No. 888 provides, as a condition of 
service, that reciprocal access be offered to only those transmission 
providers from whom the non-public utility obtains open-access 
service.'' \38\
---------------------------------------------------------------------------

    \35\ FERC Stats. & Regs. at 31,760.
    \36\ Id. at 31,761.
    \37\ South Carolina Public Service Authority, 75 FERC para. 
61,209 at 61,701 (1996).
    \38\ FERC Stats. & Regs. para. 31,048 at 30,289.
---------------------------------------------------------------------------

    We also disagree with TAPS' assertion that the Commission has taken 
``an unnecessary step backwards from its expressed aim of remedying 
past undue discrimination and providing non-discriminatory open 
access.'' We explicitly stated in Order No. 888 our rationale for 
requiring that reciprocal access be offered only to the transmission 
provider from whom the non-public utility obtains open access service:

    We believe the reciprocity requirement strikes an appropriate 
balance by limiting its application to circumstances in which the 
non-public utility seeks to take advantage of open access on a 
public utility's system.\39\

    \39\ FERC Stats. & Regs. para. 31,036 at 31,762.
---------------------------------------------------------------------------

    With respect to RUS' concerns regarding the availability of 
bilateral agreements, we clarify the distinction between the two 
different circumstances: (1) That of a non-public utility seeking 
transmission service from a public utility, and the requirement imposed 
on the public utility in providing the service; and (2) that of a 
public utility seeking transmission from a non-public utility, and what 
is sufficient for the non-public utility to provide reciprocal 
transmission service. As we stated in Order No. 888-A, if a non-public 
utility seeks service from a public utility, that public utility 
should, except in unusual circumstances, provide the service ``pursuant 
to the open access tariff and not pursuant to separate bilateral 
agreements.'' \40\ On the other hand, if a public utility seeks service 
from a non-public utility through the reciprocity condition, Order No. 
888-A provides that the non-public utility may provide that service 
pursuant to a bilateral agreement to satisfy its reciprocity 
obligation.\41\
---------------------------------------------------------------------------

    \40\ FERC Stats. & Regs. para. 31,048 at 30,285.
    \41\ Id. at 30,289.
---------------------------------------------------------------------------

    We do not agree with RUS that public utilities will have no 
incentive to take service under bilateral agreements or to waive the 
reciprocity condition for non-public utilities. If a public utility 
needs transmission service from a non-public utility to maximize its 
profits or to make sales or purchases on behalf of its native load, 
then it should not care whether it takes service from the non-public 
utility under a bilateral agreement or an open access tariff. However, 
we recognize that even if the public utility does not need transmission 
service from a non-public utility, it may use the reciprocity condition 
as a reason to deny transmission service. But this is no different from 
the situation non-public utilities were in prior to the issuance of 
Order No. 888 when utilities could outright deny any transmission 
service. In that situation, the only recourse for the non-public 
utility was to file a request for service under section 211. The same 
is true post-Order No. 888.\42\
---------------------------------------------------------------------------

    \42\ Of course, the flip side is equally true. If a public 
utility seeks service from a non-public utility, the only way it may 
be able to seek such service is by filing a section 211 application.

---------------------------------------------------------------------------

[[Page 64694]]

    In any event, should a public utility refuse to provide 
transmission service based on a claim that the non-public utility 
requesting transmission service is not willing to provide reciprocal 
service, the non-public utility may always file a transmission tariff 
under the safe harbor procedure. We do not see this as any burden as 
the Commission has made available for interested entities a complete 
open access tariff that would require little modification to file.\43\ 
Moreover, as we have explained, this reciprocal tariff, filed under the 
safe harbor procedure, need only be made available to the public 
utility (or utilities) from whom the non-public utility obtains open 
access transmission service. Further, if, as RUS seems to imply, the 
cooperatives do not want to provide any service, that is fundamentally 
at odds with the basic reciprocity provision and the fairness/
competition concepts that underlie it.
---------------------------------------------------------------------------

    \43\ We note that since issuance of Order No. 888, ten non-
public utilities have filed reciprocity tariffs, including 
cooperatives.
---------------------------------------------------------------------------

    We also reject RUS' argument that requiring a non-public utility to 
seek a waiver is inconsistent with the Commission's assertion that the 
reciprocity condition is voluntary. First, we did not require that non-
public utilities seek a waiver, but merely provided a waiver as an 
option for them to pursue. Moreover, the waiver option (from the public 
utility or the Commission) is available only if a non-public utility 
voluntarily chooses to request open access transmission service from a 
public utility. As we explained in Order No. 888-A:

    we are not requiring non-public utilities to provide 
transmission access. Instead, we are conditioning the use of public 
utility open access tariffs, by all customers including non-public 
utilities, on an agreement to offer comparable (not unduly 
discriminatory) services in return.\44\
---------------------------------------------------------------------------

    \44\ FERC Stats. & Regs. para. 31,048 at 30,285 (emphasis in 
original).

    We will clarify for RUS that the Commission's statement that ``the 
seller as well as the buyer in the chain of a transaction involving a 
non-public utility will have to comply with the reciprocity condition'' 
does not apply to member distribution cooperatives when their G&T 
cooperative obtains open access transmission service. We did not intend 
this statement to change our position with respect to cooperatives and 
---------------------------------------------------------------------------
reaffirm our prior pronouncement that

    If a G&T cooperative seeks open access transmission service from 
the transmission provider, then only the G&T cooperative, and not 
its member distribution cooperatives, should be required to offer 
transmission service.\45\
---------------------------------------------------------------------------

    \45\ Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 
30,286. We note that this does not prevent an eligible entity from 
filing a section 211 request with a ``distribution'' cooperative.

    Finally, we disagree with RUS' claim that ``any comparability 
determination with respect to stranded cost or other provisions 
contained in a non-public utility's open access tariff will involve the 
exercise of Commission jurisdiction over a non-public utility's open 
access transmission tariff as well as a determination of the legitimacy 
of the non-public utility's stranded cost claims.'' \46\ In Order No. 
888-A, the Commission explained that a non-public utility that chooses 
voluntarily to offer an open access tariff for purposes of 
demonstrating that it meets the reciprocity condition can include a 
stranded cost provision in its tariff, but adjudication of any stranded 
cost claims under that tariff would not be subject to our jurisdiction. 
We said that although we would not determine the rate of a non-public 
utility (including the stranded cost component of the rate), ``we would 
review a public utility's claim that it is entitled to deny service to 
a non-public utility because the stranded cost component of the non-
public utility's transmission rate is being applied in a way that 
violates the principle of comparability.'' \47\ In reviewing a public 
utility's claims that a non-public utility is applying its stranded 
cost provision in a non-comparable (or discriminatory) manner, we would 
not be exercising jurisdiction over the non-public utility or its 
rates. We simply would be enforcing the reciprocity condition. As we 
said in Order No. 888-A, ``[i]t would not be in the public interest to 
allow a non-public utility to take non-discriminatory transmission 
service from a public utility at the same time it refuses to provide 
comparable service to the public utility.'' \48\
---------------------------------------------------------------------------

    \46\ RUS at 12.
    \47\ Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 30,364 
n.527.
    \48\ Id. at 30,285.
---------------------------------------------------------------------------

3. Indemnification/Liability
    Several petitioners argue that the Commission erroneously 
established a new standard of liability for transmission providers--
simple negligence--that is contrary to the weight of authority in 
states across the country.\49\ They claim that the Commission's 
standard would expose transmission providers and their native load 
customers to potentially enormous liability, including large 
consequential damage awards.\50\ EEI also argues that the Commission 
has made no finding that a change in the standard is needed to remedy 
alleged undue discrimination nor, it argues, has the Commission 
demonstrated any reason to change the liability standard. According to 
EEI, the proper standard is ``gross negligence.''
---------------------------------------------------------------------------

    \49\ See KCPL and Coalition for Economic Competition. EEI also 
raises this issue, but EEI filed its request for rehearing out-of-
time on April 4, 1997 with a request that the Commission accept the 
rehearing request because it has occurred at the very start of the 
proceeding, no response is required by any other party and there 
will be no prejudice to any other party. EEI failed to file its 
rehearing request within the 30 day period required by the Federal 
Power Act. See 16 U.S.C. 825l(a). Accordingly, we will not accept 
the rehearing request for filing, but will accept the pleading as a 
motion for reconsideration.
    \50\ See Coalition for Economic Competition, EEI.
---------------------------------------------------------------------------

    Similarly, Puget argues that the Commission erroneously refuses to 
allow the express exclusion of consequential and indirect damages. It 
argues that the exception language in section 10.2 of the pro forma 
tariff (``except in cases of negligence or intentional wrongdoing by 
the Transmission Provider'') should be changed to ``except in cases of 
and to the extent of comparative or contributory negligence or 
intentional wrongdoing by the Transmission Provider.'' It further 
argues that Order No. 888 should be revised to exclude liability for 
special, incidental, consequential or indirect damages.
    Coalition for Economic Competition states that the Commission 
erroneously relied upon a gas decision as a basis for adopting an 
ordinary negligence standard. It asserts that the characteristics of 
gas and electric service and the risks associated with each are very 
different: (1) the wires for electric transmission are located above 
ground and more susceptible to outages than buried pipelines and (2) 
the electric grid is more complex, with the potential for a single 
problem to affect a significant number of customers over a large 
geographic area. Thus, it argues, electric transmission providers face 
a much greater exposure to liability than gas transporters.
    EEI and KCPL request that the Commission clarify whether states 
have authority to establish the scope of a utility's liability in 
providing federally mandated transmission service, as provided for in 
Order No. 888-A. Because of some uncertainty on this issue and the fact 
that 25 states do not have reported decisions on the issue, EEI 
indicates that there is likely to be significant litigation, which may 
lead to uncertainty between the parties to the

[[Page 64695]]

interstate service transaction. If the Commission determines that 
states do not have authority, EEI and KCPL assert that the Commission 
should establish a rule of liability based on a standard of gross 
negligence. If the Commission determines that states do have the 
authority to establish the scope of a transmission provider's 
liability, EEI, as well as KCPL, assert that the Commission ``should 
clarify that states are preempted from attaching liability to actions 
taken by a transmission provider in compliance with the provisions of 
its filed pro forma tariff'' and ``should make an affirmative statement 
that it is expressing no opinion on whether a transmission provider 
should be liable, for public policy reasons, for acts of ordinary 
negligence.'' \51\
---------------------------------------------------------------------------

    \51\ EEI at 7; KCPL at 7-8.
---------------------------------------------------------------------------

    Coalition for Economic Competition further maintains that

    while the Commission directs transmission providers to rely on 
state law for protection against liability, it ignores the policies 
established at the state level which already address the issue. As a 
result, FERC is reallocating the risks associated with the 
transmission of electricity. To the extent that reallocation forces 
utilities to experience an additional financial burden, captive 
customers will be forced to pay more--more than the parties agreed 
would be their fair share. [\52\]

    \52\ Coalition for Economic Competition at 7.
---------------------------------------------------------------------------

Furthermore, Coalition for Economic Competition states that case law 
may not protect the utility and its captive customers from the costs 
associated with the reallocation of risk:

    Frequently, the outcome of a case is closely related to any 
applicable tariff language that embodies that state's public policy 
as set by its regulatory commission. If the pro forma liability 
provision differs from the standards used in a particular state, the 
applicability and usefulness of that state's prior court decisions 
is unclear. [\53\]

    \53\ Id. at 8.
---------------------------------------------------------------------------

    Coalition for Economic Competition also asserts that the Commission 
appears to be sending contradictory signals, citing a recent decision 
(New York State Electric & Gas Corporation, 78 FERC para. 61,114 
(1997)) in which the Commission rejected a provision in an open access 
tariff that acted as a choice of law provision. It argues that issues 
involving which jurisdiction provides the most appropriate forum, and 
which law should apply, are likely to be contested issues. In sum, 
Coalition for Economic Competition states that ``the Commission's 
reliance on state law leaves a wide open gap in which the outcome of 
potential claims is completely unknown, and the risk to which 
transmission providers are exposed is increased even more.'' \54\
---------------------------------------------------------------------------

    \54\ Id. at 9.
---------------------------------------------------------------------------

    Commission Conclusion. The tariff provisions on Force Majeure and 
Indemnification, as clarified in Order No. 888-A, provide certain 
limited protections to the transmission provider as well as its 
customers, when they faithfully attempt to carry out their duties under 
the tariff. The petitioners want the Commission to extend these limited 
protections to other situations or otherwise set forth definitive rules 
on liability in various situations that might arise under the tariff. 
We believe that the tariff provisions strike the right balance, and we 
will not here attempt to define the consequences of every conceivable 
breach that might occur under the tariff. Nor will we use the tariff, 
as some appear to want us to do, as an instrument for defining 
exclusive and preemptive federal laws for liability for all damages 
that might arise from the operation of the transmission system.
    The Force Majeure provision of the tariff, in its essence, provides 
that neither the transmission provider nor the customer will be liable 
to the other when they behave in all respects properly, but 
unpredictable and uncontrollable force majeure events prevent 
compliance with the tariff. The Indemnification provision of the 
tariff, in its essence, provides that when the transmission provider 
behaves in all respects properly, the customer will indemnify the 
transmission provider from claims of damage to third parties arising 
from the service provided under the tariff. Under the terms of the 
tariff, the transmission provider may not rely on the protections 
provided by the Force Majeure clause or the Indemnification Clause for 
acts or omissions that are the product of negligence or intentional 
wrongdoing. Likewise, the customer may not rely on the protections 
provided by the Force Majeure clause for acts or omissions that are the 
product of negligence or intentional wrongdoing.
    Contrary to the contention of EEI, the Force Majeure and 
Indemnification provisions do not establish a new simple negligence 
standard of liability for transmission providers. As we explained in 
Order No. 888-A, the issue of whether liability will attach to certain 
acts or omissions by a transmission provider is a different question 
from whether a customer should be obligated to indemnify the 
transmission provider in such circumstances.\55\ In Order Nos. 888 and 
888-A, the Commission has made no finding and expressed no opinion 
concerning whether a transmission provider should be held liable for 
damages to third parties arising from the transmission provider's acts 
or omissions of simple negligence, and the tariff language should not 
be construed as preempting the appropriate tribunal's consideration of 
whether liability should attach for acts or omissions of the 
transmission provider that injure third parties.
---------------------------------------------------------------------------

    \55\ FERC Stats. & Regs. para. 31,048 at 30,301.
---------------------------------------------------------------------------

    While the Commission has not established an exclusive and 
preemptive liability standard for electric utilities, EEI and the 
Coalition for Economic Competition would have us do so. They seek 
exculpatory language in the tariff that would protect the transmission 
provider from liability in all cases, except where gross negligence has 
been shown. Both acknowledge in their rehearing requests that such an 
exculpatory standard would in some regions alter the current liability 
standards, citing a study which concludes that 25 states have addressed 
the issue, with 21 of the 25 finding a gross negligence standard 
appropriate. Both argue that the Commission could eliminate potential 
uncertainties and conflicts among tribunals by determining a 
comprehensive and exclusive federal standard that accords with the 
determinations of the majority of states that have addressed this 
issue. EEI and KCP&L also question whether reference to state law is 
appropriate at all, suggesting that the Commission must develop a 
comprehensive federal standard of liability for service under the 
tariffs. We do not believe that such a determination is necessary or 
appropriate at this time.
    First, we note that there is no question that the Commission has 
exclusive jurisdiction to determine the reasonableness of rates, terms, 
and conditions for the transmission of electric energy in interstate 
commerce.\56\ Moreover, it is clear that state tribunals may not 
second-guess or collaterally attack Commission determinations of the 
reasonableness of filed rates, terms, and conditions.\57\ On the other 
hand, it is likewise clear that the Commission's jurisdiction to 
consider disputes arising under jurisdictional tariffs does not as a 
matter of law preclude state courts from also entertaining such 
disputes in the

[[Page 64696]]

appropriate circumstances.\58\ In determining whether the Commission 
will exercise jurisdiction in such cases, the Commission is guided by 
the principles set forth in Arkansas Louisiana Gas Company v. Hall.\59\ 
Application of these principles suggests the possibility that tribunals 
other than the Commission may be called upon to adjudicate disputes 
arising from service under the tariff.
---------------------------------------------------------------------------

    \56\ 16 U.S.C. 824b; see, e.g., Nantahala Power & Light Company 
v. Thornburg, 476 U.S. 953, 963-66 (1986); FPC v. Southern 
California Edison Company, 376 U.S. 205 (1964); Public Utilities 
Commission v. Attleboro Steam & Electric Company, 273 U.S. 83 
(1927).
    \57\ See, e.g., Mississippi Power & Light Company v. Mississippi 
ex rel Moore, 487 U.S. 354, 374-75 (1988); Gulf States Utilities 
Company v. Alabama Power Company, 824 F.2d 1465, 1471-72, amended, 
831 F.2d 557 (5th Cir. 1987).
    \58\See, e.g., Pan American Petroleum Corporation v. Superior 
Court of Delaware, 366 U.S. 656, 662, 666 (1961).
    \59\ 7 FERC para. 61,175, reh'g denied, 8 FERC para. 61,031 
(1979).
---------------------------------------------------------------------------

    With that background, the concerns expressed by EEI and KCP&L 
concerning the need for a uniform federal liability standard closely 
resemble the concerns addressed by the court in United Gas Pipe Line 
Company v. FERC.\60\ In that case, the Commission had approved a tariff 
that limited a pipeline's liability to claims of ``negligence, bad 
faith, fault or wilful misconduct'' and the pipeline appealed, arguing 
that a uniform standard of liability should be established that was 
more protective of the pipeline. The court rejected the claim that 
there was a need for a uniform federal standard more favorable to the 
pipeline. As the court explained, ``uniformity of result is needed only 
to protect the federal interest, that is, only to exculpate [the 
pipeline] from contract liability in all cases not based on [the 
pipeline's] fault. Uniformity of exculpation beyond those cases is not 
a matter of federal concern'' because in such instances ``liability 
flows only from [the pipeline's] mismanagement.''\61\ This same 
reasoning applies here. It is appropriate for the Commission to protect 
the transmission provider through the tariff provisions on Force 
Majeure and Indemnification from damages or liability that may occur 
when the transmission provider provides service without negligence, but 
to leave the determination of liability in other instances to other 
proceedings.\62\
---------------------------------------------------------------------------

    \60\ 824 F.2d 417 (5th Cir. 1987).
    \61\ 824 F.2d 427.
    \62\ Some of the rehearing requests concerning indemnification/
liability raise issues that previously were raised on rehearing of 
Order No. 888 and were addressed by the Commission in Order No. 888-
A. See Coalition for Economic Competition argument that the 
circumstances of electric transmission require a different result 
than the gas pipeline cases and Puget arguments that the negligence 
language of the indemnification provision should be changed to 
reference comparative or contributory negligence and that the tariff 
should exclude transmission provider liability for special, 
incidental, consequential, or indirect damages. The Commission will 
not further address such issues in this proceeding.
---------------------------------------------------------------------------

4. Qualifying Facilities (QF)/Real Power Loss Service
    NIMO and EEI \63\ seek rehearing of the Commission's clarification 
in Order No. 888-A that a

    \63\ As discussed above, EEI filed its request for rehearing 
out-of-time. Accordingly, we are treating EEI's pleading as a motion 
for reconsideration.
---------------------------------------------------------------------------

    QF arrangement for the receipt of Real Power Loss Service or 
ancillary services from the transmission provider or a third party 
for the purpose of completing a transmission transaction is not a 
sale-for-resale of power by a QF transmission customer that would 
violate our QF rules.\64\

    \64\ FERC Stats. & Regs. para. 31,048 at 30,237 (1997). See also 
Puget.
---------------------------------------------------------------------------

    NIMO argues that the Commission's clarification is inconsistent 
with the criteria for QF status under sections 3(17) and 3(18) of the 
FPA and the Commission's precedent. NIMO argues that the Commission has 
decided that a QF can only sell the net output of its facility without 
losing QF status. According to NIMO, allowing QFs to purchase Real 
Power Loss Service will result in QFs selling in excess of their net 
output at avoided cost.\65\
---------------------------------------------------------------------------

    \65\ On April 21, 1997, Granite State Hydropower Association 
filed an answer to NIMO's rehearing request arguing that gross sales 
are permissible for QFs. In the circumstances presented, we will 
accept the answer notwithstanding our general prohibition on 
allowing answers to rehearing requests. See 18 CFR 385.713(d).
---------------------------------------------------------------------------

    Finally, NIMO argues that if the Commission wishes to allow QFs to 
purchase power to compensate for line losses from third parties, and to 
include such power in their sales, it must do so only after a 
rulemaking in which it has noticed its intention to amend its QF 
regulations.\66\
---------------------------------------------------------------------------

    \66\ EEI supports NIMO's arguments.
---------------------------------------------------------------------------

    Commission Conclusion. As a preliminary matter, we reject NIMO's 
argument that the Commission could only grant the clarification 
provided in Order No. 888-A after a rulemaking in which it noticed its 
intent to amend its QF regulations. All of the QF cases cited by NIMO 
in its rehearing request involve the Commission clarifying its rules in 
case-specific situations. For example, in Occidental Geothermal, Inc. 
(Occidental), the Commission was required to define the term ``power 
production capacity'' of a facility as that term was used in 18 CFR 
292.204(a).\67\ The Commission did so without issuing a notice of 
proposed rulemaking and seeking comments.
---------------------------------------------------------------------------

    \67\ 17 FERC para.61,231 (1981).
---------------------------------------------------------------------------

    Moreover, the issue raised by NIMO and EEI is whether the 
Commission's clarification would result in a facility losing QF status, 
as defined in sections 3(17) and 3(18) of the FPA. The Conference 
Report on PURPA provides:

    The new paragraphs 17(C) and 18(B) of the definitions provide 
that the Commission shall determine, by rule, on a case-by-case 
basis, or otherwise, that a small power production facility or a 
cogeneration facility is a qualifying small power production 
facility or cogeneration facility, as the case may be.[\68\]
---------------------------------------------------------------------------

    \68\ H.R. Rep. No. 95-1750, Public Utility Regulatory Policies 
Act, 95th Cong. 2d Sess. 89 (1978) (emphasis added). See also 
Turners Falls Limited Partnership, 55 FERC para.61,487 at 62,670 
n.33 (1991) (Turners Falls).
---------------------------------------------------------------------------

Accordingly, NIMO's argument that the Commission has improperly amended 
its PURPA regulations is wrong.
    The substantive issue raised on rehearing is an issue of first 
impression.\69\ In Occidental, Turners Falls, as well as in Power 
Developers, Inc.,\70\ Malacha Power Project, Inc. (Malacha),\71\ and 
Pentech Papers, Inc.,\72\ the Commission found that QFs were permitted 
to sell only the net output of their power production facilities as 
measured at the point of interconnection with the electric utility to 
which they were interconnected. The Commission did not decide the 
question of whether ``the receipt of Real Power Loss Service or 
ancillary services from the transmission provider or a third party for 
the purpose of completing a transmission transaction'' would be a sale-
for-resale of power by a QF that would violate the Commission's QF 
rules.
---------------------------------------------------------------------------

    \69\ We note that other aspects of the ``net/gross'' issue are 
pending before the Commission in separate proceedings and will be 
addressed by the Commission in subsequent orders. See Connecticut 
Valley Electric Company, Inc. v. Wheelabrator Claremont Company, 
L.P., et al. (Docket Nos. EL94-10-000 and QF86-177-001); Carolina 
Power & Light Company v. Stone Container Corporation (Docket Nos. 
EL94-62-000 and QF85-102-005); and Niagara Mohawk Power Company v. 
Penntech Papers, Inc. (Docket Nos. EL96-1-000 and QF86-722-003).
    \70\ 32 FERC para.61,101 (1985).
    \71\ 41 FERC para.61,350 (1987).
    \72\ 48 FERC para.61,120 (1989).
---------------------------------------------------------------------------

    At first glance, it would appear that Real Power Loss Service and 
ancillary services fall within the definition of ``supplementary 
power'' as defined in 18 CFR 292.101(b)(8).\73\ If this were in fact 
the case, the precedent cited above would be relevant because 
supplementary power would be subtracted from gross output to determine 
the net output available for sale and, pursuant to Turner Falls, any 
sale in excess of the net output would result in a loss of QF status. 
However, if Real Power Loss Service and ancillary services are part of 
the costs of transmission, they are not covered

[[Page 64697]]

under the definition of ``supplementary power.''
---------------------------------------------------------------------------

    \73\ Supplementary power is defined as ``electric energy or 
capacity supplied by an electric utility, regularly used by a 
qualifying facility in addition to that which the facility generates 
itself.''
---------------------------------------------------------------------------

    As the Commission explained in its Notice of Proposed Rulemaking, 
Small Power Production and Cogeneration-Rates and Exemptions:

    The costs of transmission are not a part of the rate which an 
electric utility to which energy is transmitted is obligated to pay 
the qualifying facility. These costs are part of the costs of 
interconnection, and are the responsibility of the qualifying 
facility * * *. The electric utility to which the electric energy is 
transmitted has the obligation to purchase the energy at a rate 
which reflects the costs that it can avoid as a result of making 
such a purchase.\74\
---------------------------------------------------------------------------

    \74\ FERC Stats. & Regs., Proposed Regulations 1977-1981, 
para.32,039 at 32,437 (1979). See also id. at 32,447 (costs of 
transmission constitute interconnection costs and must be borne by 
QF unless transmitting utility agrees to share them).
---------------------------------------------------------------------------

    This view was adopted by the Commission in Order No. 69, Small 
Power Production and Cogeneration Facilities, Regulations Implementing 
Section 210 of the Public Utility Regulatory Policies Act of 1978.\75\ 
There the Commission defined ```interconnection costs' as the 
reasonable costs of * * * transmission * * *.''\76\ It is also 
consistent with the Commission's findings in 18 CFR 292.303(d) that if 
a QF transmits its output to an electric utility with which it is not 
interconnected, the rate for the purchase of such energy ``shall not 
include any charges for transmission.'' Thus, all that remains is to 
determine whether Real Power Loss Service and ancillary services are 
part of the costs of transmission.
---------------------------------------------------------------------------

    \75\ FERC Stats. & Regs., Regulations Preambles 1977-1981, 
para.30,128 (1980).
    \76\ Id. at 30,866. See also 18 CFR 292.101(b)(7).
---------------------------------------------------------------------------

    Ancillary services as defined in Order Nos. 888 and 888-A are part 
of the costs of transmission services. In Order No. 888, we defined 
ancillary services as those services ``that must be offered with basic 
transmission service under an open access transmission tariff.''\77\ We 
noted that these services are those ``needed to accomplish transmission 
service while maintaining reliability within and among control areas 
affected by the transmission service.''\78\ Thus, there is no question 
that ancillary services are part of the cost of transmission and 
therefore are included among the interconnection costs a QF is 
responsible for.
---------------------------------------------------------------------------

    \77\ FERC Stats. & Regs., para.31,036 at 31,705 (footnote 
omitted).
    \78\ Id.
---------------------------------------------------------------------------

    Real Power Loss Service is an interconnected operations 
service.\79\ It is thus not a service which a transmission provider is 
required to provide under its open access transmission tariff. 
Nevertheless, the Commission recognized that a transmission customer 
must make provisions for Real Power Loss. As the Commission noted, a 
customer ``cannot take basic transmission service without such a 
provision.''\80\ As a result, we find that Real Power Loss Service is 
also a part of the cost of transmission and included among the 
interconnection costs a QF is responsible for.
---------------------------------------------------------------------------

    \79\ Id. at 31,709.
    \80\ Id.
---------------------------------------------------------------------------

    Consistent with 18 CFR 292.303(d), however, a QF purchasing Real 
Power Loss Service shall have its purchase rate adjusted up or down 
consistent with 18 CFR 292.304(e)(4).\81\ In other words, while a QF 
can never sell more power than its net output at its point of 
interconnection with the grid, its location in relation to its 
purchaser (and thus its losses) may be relevant in the calculation of 
the avoided cost which it is entitled for the power it does deliver to 
its electric utility purchaser. However, as explained above, the 
receipt of Real Power Loss Service or ancillary services is not a sale-
for-resale of power. Rather, they are part of the costs of transmission 
which the QF must bear, in the absence of an agreement to share such 
costs with the transmitting utility.
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    \81\ In Order No. 69, the Commission noted:
    Subparagraph (4) addresses the costs or savings resulting from 
line losses. An appropriate rate for purchases from a qualifying 
facility should reflect the cost savings actually accruing to the 
electric utility. If energy produced from a qualifying facility 
undergoes line losses such that the delivered power is not 
equivalent to the power that would have been delivered from the 
source of power it replaces, then the qualifying facility should not 
be reimbursed for the difference in losses. If the load served by 
the qualifying facility is closer to the qualifying facility than it 
is to the utility, it is possible that there may be net savings 
resulting from reduced line losses. In such cases, the rates should 
be adjusted upwards.
    Order No. 69 at 30,885-86.
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5. Right Of First Refusal/Reservation Of Transmission Capacity
    NRECA, TDU Systems and TAPS seek clarification that the rights of 
network customers to reserve capacity to serve their own retail load 
are comparable to a transmission provider's right to reserve 
transmission capacity for its retail native load. They point to 
language in Order No. 888-A that supports their interpretation, but 
note that other language concerning the Right of First Refusal (ROFR) 
mechanism seems to provide an advantage to transmission providers in 
serving their retail native load.
    NRECA and TDU Systems argue that the Commission improperly allows a 
transmission provider to reserve capacity as needed to serve its 
existing native load customers, but the cooperative wholesale power or 
firm transmission customer has only a right of first refusal that 
requires it to match competing bids, which exposes it to matching an 
incremental rate or opportunity cost rate capped at the cost of system 
expansion. They assert that ``[t]o the extent the transmission provider 
is able to continue to provide service to its retail native load at 
average embedded transmission costs, so too should the network customer 
have the right to continued service at average embedded-cost rates, 
rather than at incremental-cost rates or opportunity-cost rates capped 
only at the cost of system expansion.'' \82\ TDU Systems requests that 
the Commission clarify that
---------------------------------------------------------------------------

    \82\ TDU Systems at 6; NRECA at 5.

    the ROFR provisions allow an existing network customer to 
continue to reserve transmission capacity at rates that remain 
comparable to the transmission provider's service to its retail 
native load.\83\
---------------------------------------------------------------------------

    \83\ TDU Systems at 7.

---------------------------------------------------------------------------
Similarly, NRECA requests the Commission to clarify that

    firm transmission customers for which the transmission provider 
has a planning requirement are on an equal footing with the 
transmission provider's retail load in reserving transmission 
capacity. The Commission accordingly should clarify that the ROFR 
provisions allow existing firm transmission customers for which the 
transmission provider has a planning requirement to continue to 
reserve their existing transmission capacity at rates that remain 
comparable to the transmission provider's existing service to its 
retail native load.\84\
---------------------------------------------------------------------------

    \84\ NRECA at 7.

---------------------------------------------------------------------------
TAPS asks the Commission to clarify that

    its discussion of the rights of a transmission provider to 
reserve and reclaim capacity needed for native load growth apply 
with equal force to capacity needed for network customers for which 
the transmission provider is equally responsible for planning its 
system. The Commission should also clarify that the transmission 
provider's reclamation/reservation right cannot be used to withdraw 
capacity currently or reasonably forecasted to be used by a network 
customer.\85\
---------------------------------------------------------------------------

    \85\ TAPS at 33.

    TDU Systems further requests that the Commission clarify the rate 
an existing transmission customer would have to match to retain its 
reservation priority. It requests that the Commission clarify that the 
customer need match only the undiscounted tariff rate of general 
applicability and not the highest rate the transmission provider is 
then collecting

[[Page 64698]]

from any customer, i.e., an incremental rate based on an upgrade for a 
particular customer.
    Commission Conclusion. In Order No. 888-A, we addressed concerns 
raised by transmission providers that the right of first refusal may 
prohibit them from recalling capacity needed for native load growth, by 
clarifying that the transmission provider may reserve existing capacity 
for retail native load growth. While the Commission's conclusion in 
Order No. 888-A, in the context of the treatment of retail native load, 
is correct, a transmission provider may also reserve existing capacity 
for both its own wholesale native load growth and network customers' 
load growth. As the Commission originally explained in Order No. 888:

    public utilities may reserve existing transmission capacity 
needed for native load growth and network transmission customer load 
growth reasonably forecasted within the utility's current planning 
horizon.\86\

    \86\ FERC Stats. & Regs. para. 31,036 at 31,694 (emphasis 
added).
---------------------------------------------------------------------------

Accordingly, in order to allay the concerns of NRECA, TDU Systems and 
TAPS, we clarify that network transmission customers are afforded the 
same treatment as the transmission provider on behalf of native load 
(retail and wholesale requirements customers) in terms of the 
reservation of existing transmission capacity by the transmission 
provider.
    Regarding NRECA's and TDU Systems' allegation that a transmission 
provider's right to reserve existing transmission capacity for its 
retail native load is superior to a firm transmission customer's right 
of first refusal, we note that it is not clear if NRECA and TDU 
Systems' argument pertains to network transmission customers or to 
point-to-point transmission customers. The right of a transmission 
provider to reserve existing transmission capacity on behalf of network 
transmission customers is discussed above. The reservation priority of 
transmission capacity for point-to-point transmission customers is 
different because point-to-point transmission customers do not 
undertake the same payment obligation as either network transmission 
customers or the transmission provider on behalf of native load 
customers. As the Commission explained in Order No. 888-A in the 
context of reservation of existing capacity:

    We note that network service is founded on the notion that the 
transmission provider has a duty to plan and construct the 
transmission system to meet the present and future needs of its 
native load and, by comparability, its third-party network 
customers. In return, the native load and third-party network 
customers must pay all of the system's fixed costs that are not 
covered by the proceeds of point-to-point service. This means that 
native load and third-party network customers bear ultimate 
responsibility for the costs of both the capacity that they use and 
any capacity that is not reserved by point-to-point customers. In 
this regard, native load and third-party network customers face a 
payment risk that point-to-point customers generally do not 
face.\87\
---------------------------------------------------------------------------

    \87\ FERC Stats. & Regs. para. 31,048 at 30,220.

    Additionally, we note that a firm transmission customer may always 
elect to take network transmission service in lieu of point-to-point 
transmission service, thereby obtaining rights to reserve existing 
transmission capacity that are comparable to the rights of other 
network customers and the transmission provider on behalf of native 
load.
    Furthermore, unless prohibited by the terms of the existing 
transmission customer's contract, there is nothing to prevent an 
existing point-to-point transmission customer from seeking to extend 
the term of its contract. An existing transmission customer may also 
enter into an additional agreement for point-to-point transmission 
service and reassign such capacity until needed or choose a service 
commencement date concurrent with the termination of its existing 
contract.
    TDU Systems asserts that Order No. 888-A ``leaves unresolved 
whether the customer must pay the undiscounted rate of general 
applicability for tariff service at the time of conversion or the 
highest rate the transmission provider is then collecting from any 
customer,'' such as an incremental cost-based rate.\88\ We clarify that 
the right of first refusal does not require an existing transmission 
customer to match the highest rate the transmission provider is then 
collecting from any customer. The highest rate collected from any 
customer may involve a different service than that service received by 
the existing customer, which may result in an inappropriate comparison. 
In this regard, the Commission stated in Order No. 888-A that the 
purpose of the right of first refusal is to be a tie-breaker and, 
therefore, the competing requests should be substantially the same in 
all respects.\89\ Accordingly, we clarify that the existing 
transmission customer exercising its right of first refusal will be 
required to match the term of service requested by another potential 
customer and may be required to pay the transmission provider's maximum 
filed transmission rate. However, the rate must be for substantially 
similar service of equal or greater duration.
---------------------------------------------------------------------------

    \88\ TDU Systems at 8.
    \89\ FERC Stats. & Regs. para. 31,048 at 30,197.
---------------------------------------------------------------------------

    TDU Systems also asks whether the maximum rate that a customer must 
match in exercising its right of first refusal would include an 
incremental cost-based rate for an upgrade to a competing customer or 
if the customer is required to match only the undiscounted tariff rate 
of general applicability. The right of first refusal is predicated on 
an existing customer continuing to use its transmission rights in the 
existing transmission system. The right of first refusal acts as a 
tiebreaker to determine whether the competing eligible customer or the 
existing transmission customer gets the existing transmission capacity. 
Accordingly, the maximum rate for such existing transmission capacity 
would be the just and reasonable transmission rate on file at the time 
the customer exercises its right of first refusal.\90\
---------------------------------------------------------------------------

    \90\ Depending on the rate design on file for the existing 
capacity, a customer exercising its right of first refusal could 
face an average embedded cost-based rate, an incremental cost-based 
rate, a flow-based rate, a zonal rate, or any other rate design that 
the Commission may have approved under section 205 of the FPA.
---------------------------------------------------------------------------

    In conclusion, we believe that we have struck an appropriate 
balance between our goals of: (1) Protecting the rights of retail and 
wholesale native loads and network customers by allowing the 
transmission provider to reserve existing transmission capacity for 
their projected load growth and (2) providing existing firm 
transmission customers with a priority over new requests for firm 
transmission service to continue receiving transmission service from 
existing transmission capacity when there is insufficient existing 
capacity available to accommodate all requests for transmission 
service.
6. Energy Imbalance Service
    a. Appropriate bandwidth for small utilities. APPA argues that the 
Commission's revision in Order No. 888-A to the deviation bandwidth did 
not go far enough and does not address the requirements of all small 
utilities, i.e., utilities that sell no more than 4 million MWh 
annually.\91\ It asserts that the Commission has adequately remedied 
the problem for those small utilities serving load with a peak demand 
of less than 20 MW, but not for those utilities serving loads with 
greater peak demands.
---------------------------------------------------------------------------

    \91\ APPA at 21-23 (citing Blue Creek Hydro, Inc., 77 FERC para. 
61,232 at 61,941 (1996), in which the Commission used the 4 million 
Mwh level for determining small utilities eligible for waiver of the 
requirements of Order No. 889).
---------------------------------------------------------------------------

    To remedy the problem, APPA asks the Commission to revise the 
minimum

[[Page 64699]]

bandwidth to provide a minimum deviation bandwidth of 2 MW for 
utilities serving load with a peak demand of less than 20 MW, 5 MW for 
utilities serving load less than 100 MW, and 7.5 MW for all other small 
utilities.
    Commission Conclusion. We deny APPA's motion for 
reconsideration.\92\ As the Commission explained in Order No. 888-A, 
the deviation bandwidth was developed ``to promote good scheduling 
practices by transmission customers. It is important that the 
implementation of each scheduled transaction not overly burden 
others.'' \93\ The Commission reaffirmed its use of the 1.5 percent 
energy imbalance bandwidth as ``consistent with what the industry has 
been using as a standard and is as close to an industry standard as 
anyone can set at this time.'' \94\ However, the Commission recognized 
the needs of small customers and raised the minimum energy imbalance 
from one megawatthour per hour to two megawatthours per hour. In doing 
so, the Commission sought to balance its primary goal of promoting good 
scheduling practices with its commitment to provide as much relief as 
possible to small customers. Larger minimum deviation bandwidths, as 
proposed by APPA, could only unnecessarily jeopardize this balance at 
the expense of good scheduling practices.
---------------------------------------------------------------------------

    \92\ As discussed above, APPA filed its request for rehearing 
out-of-time. Accordingly, we are treating APPA's pleading as a 
motion for reconsideration.
    \93\ FERC Stats. & Regs. para. 31,048 at 30,232.
    \94\ Id. at 30,232.
---------------------------------------------------------------------------

    Moreover, in Order No. 888-A, the Commission provided all 
customers, including small customers, further options to deal with any 
difficulties that may be experienced as the result of the minimum 
deviation bandwidth set forth in Order No. 888-A:

    To help customers with the difficulty of forecasting loads far 
in advance of the hour, the Final Rule pro forma tariff permits 
schedule changes up to twenty minutes before the hour at no charge. 
By updating its schedule before the hour begins, a transmission 
customer should be able to reduce or avoid energy imbalance and 
associated charges. However, we will allow the transmitting utility 
and the customer to negotiate and file another bandwidth more 
flexible to the customer, subject to a requirement that the same 
bandwidth be made available on a not unduly discriminatory 
basis.\95\

    \95\ Id.
---------------------------------------------------------------------------

APPA has simply not shown that the minimum deviation or the procedures 
to reduce or avoid energy imbalance charges or to negotiate another 
bandwidth do not provide adequate relief for small customers. Nor has 
APPA shown that larger bandwidths could be implemented without unduly 
undermining good scheduling practices.
    b. Settlements establishing a deviation bandwidth or minimum 
imbalance. TDU Systems states that Order No. 888-A allows a 
transmission provider and a customer to negotiate and file another 
bandwidth more flexible to the customer on a not unduly discriminatory 
basis, but if a settlement was approved subject to the outcome of Order 
No. 888, it must be revised in the subsequent compliance filing to 
reflect the language in the pro forma tariff. Accordingly, TDU Systems 
seeks clarification that if such a settlement contains a bandwidth 
above 1.5% or a minimum imbalance above 2 MW, those amounts need not be 
revised downward to conform to the pro forma tariff.\96\
---------------------------------------------------------------------------

    \96\ TDU Systems at 12-13.
---------------------------------------------------------------------------

    Commission Conclusion. We will not grant the clarification sought 
by TDU Systems. In Order No. 888-A, we explicitly stated that

    service provided pursuant to a settlement that was expressly 
approved subject to the outcome of Order No. 888 on non-rate terms 
and conditions must be revised in the subsequent compliance filing 
to reflect the language contained in the pro forma tariff.\97\
---------------------------------------------------------------------------

    \97\ FERC Stats. & Regs. para. 31,048 at 30,233.

    This is consistent with our desire to have all public utilities at 
the same starting line as open access is implemented in the electric 
---------------------------------------------------------------------------
industry:

    By initially requiring a standardized tariff, we intend to 
foster broad access across multiple systems under standardized terms 
and conditions.\98\
---------------------------------------------------------------------------

    \98\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,734.

    However, as we also recognized, ``public utilities are free to file 
under section 205 to revise the tariffs (e.g., to reflect various 
settlement provisions) and customers are free to pursue changes under 
section 206.'' \99\ Thus, the settlement discussed by TDU Systems must 
be revised to conform to the pro forma tariff, but the public utility 
transmission provider to the settlement may then make another filing 
with the Commission to seek a change to the bandwidth contained in the 
pro forma tariff.
---------------------------------------------------------------------------

    \99\ Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 30,234 
(footnote omitted).
---------------------------------------------------------------------------

7. Transmission Provider ``Taking Service'' Under Its Tariff for Power 
Purchased on Behalf of Bundled Retail Customers
    a. Jurisdiction. IL Com states that the Commission agreed with IL 
Com's jurisdictional arguments on rehearing of Order No. 888 and made 
the following appropriate clarifications in Order No. 888-A:

    In a situation in which a transmission provider purchases power 
on behalf of its retail native load customers, the Commission [FERC] 
does not have jurisdiction over the transmission of the purchased 
power to the bundled retail customers insofar as the transmission 
takes place over such transmission provider's facilities. [quoting 
Order No. 888-A at 117-18 (emphasis added)].
* * * * *
    [The Commission] does have jurisdiction over transmission 
service associated with sales to any person for resale, and such 
transmission must be taken under the transmission provider's pro 
forma tariff. [quoting Order No. 888-A at 118 (emphasis 
added)].\100\

    \100\ IL Com at 8.
---------------------------------------------------------------------------

However, IL Com argues that the Commission

    nevertheless neglected to revise Sec. 35.28(c)(2) and 
Sec. 35.28(c)(2)(i) to incorporate these clarifications into the 
Rule. Therefore, [IL Com] reiterates its request that the words 
``for sale for resale'' be inserted into the Rule after the word 
``purchases'' in Sec. 35.28(c)(2) and ``purchase'' in 
Sec. 35.28(c)(2)(i) to codify the Order 888-A clarification 
concerning the extent of required power purchase unbundling.\101\

    \101\ Id. at 8-9.
---------------------------------------------------------------------------

    CCEM, however, argues that the Commission's disclaimer of 
jurisdiction over the transmission in interstate commerce of purchased 
power headed for retail customers is contrary to the FPA's assertion of 
jurisdiction over all transmission of electric energy in interstate 
commerce.\102\ It states that
---------------------------------------------------------------------------

    \102\ CCEM at 2-6.

    [t]he Commission has already embraced the proposition that it 
has the statutory authority and mandate to require utilities to 
adopt tariffs that will ensure all market participants comparable 
access to transmission services. It must now extend that authority 
---------------------------------------------------------------------------
and mandate to apply to all transmission service.\103\

    \103\ Id. at 4.
---------------------------------------------------------------------------

CCEM further argues that the Commission's failure to assert 
jurisdiction over interstate transmission of purchased power to retail 
customers is contrary to precedent under the Natural Gas Act 
(NGA).\104\ It cites to Mississippi River Transmission Corp. v. FERC, 
969 F.2d 1215 (D.C. Cir. 1992), stating that the court affirmed the 
Commission's interpretation of NGA section 1(b) as authorizing the 
Commission to regulate the price of natural gas transportation service 
that

[[Page 64700]]

MRT provided in support of certain firm direct sales.
---------------------------------------------------------------------------

    \104\ Id. at 4-6 (citing Mississippi River Transmission Corp. v. 
FERC, 969 F.2d 1215 (D.C. Cir. 1992)).
---------------------------------------------------------------------------

    If the Commission does not grant rehearing as requested by CCEM, 
CCEM argues that ``the Commission should nevertheless clarify that its 
jurisdictional disclaimer does not extend to power pool transmission 
services.'' \105\ It asserts that because pools themselves do not have 
native load and do not purchase power on behalf of native load, ``when 
a public utility takes poolwide service to transmit purchased power, it 
should be required to take that service on an unbundled basis pursuant 
to the power pool's open-access tariff.'' \106\ In this regard, it 
states that it is ``aware that certain public utilities claim that the 
Commission's disclaimer of jurisdiction extends to their uses of 
poolwide transmission service to transmit purchased power to their 
captive, native loads.'' \107\
---------------------------------------------------------------------------

    \105\ Id. at 6.
    \106\ Id.
    \107\ Id.
---------------------------------------------------------------------------

    CCEM further argues that the Commission's failure to require that 
all transmission service be taken under an open access tariff is 
arbitrary and irreconcilable with the Commission's concurrent 
determination in connection with the rules pertaining to stranded cost 
recovery that it has jurisdiction over the rates, terms and conditions 
of unbundled interstate transmission services by public utilities to 
retail customers, and that it has the authority to address retail 
stranded costs through its jurisdiction over such services. It adds 
that experience from restructuring the natural gas industry (Order Nos. 
436 and 636) shows the need to unbundle and separately regulate 
transmission provided in connection with retail service.
    Commission Conclusion. CCEM's arguments with respect to the 
Commission's disclaimer of jurisdiction over bundled retail 
transmission are the same arguments it raised on rehearing of Order No. 
888 (and were addressed by the Commission) \108\ or should have raised 
on rehearing of Order No. 888. We will not accept CCEM's invitation to 
further address this issue.
---------------------------------------------------------------------------

    \108\ FERC Stats. & Regs. para. 31,048 at 30,225-26.
---------------------------------------------------------------------------

    In response to CCEM's request for clarification regarding power 
pool transactions, we note that all power pool transactions must be 
taken under the terms of the pool-wide pro forma tariffs that were 
filed on compliance to Order No. 888.\109\ The appropriateness of the 
terms and conditions contained in those pool-wide pro forma tariffs 
will be addressed on a case-by-case basis when the Commission addresses 
the merits of the various pools' compliance filings.
---------------------------------------------------------------------------

    \109\ See MidContinent Area Power Pool, et al., 78 FERC para. 
61,203 (1997) (Order Accepting for Filing and Suspending Proposed 
Pool-Wide and Single-System Holding Company Open Access Transmission 
Tariffs and Revised Tariffs, and Deferring Further Action), reh'g 
pending.
---------------------------------------------------------------------------

    Finally, we deny IL Com's request to modify sections 35.28(c)(2) 
and 35.28(c)(2)(i) of the Commission's regulations. The additional 
language proposed by IL Com simply will not work. As we describe in 
more detail in section 7.b below, it is not possible, as a practical 
matter, to divide a single power purchase made on behalf of both 
wholesale and retail native load such that the transmission provider 
takes service under the terms and conditions of the pro forma open 
access transmission tariff for the wholesale part of the purchase and 
under the terms and conditions of a different tariff for the retail 
part. Thus, the entire purchase transaction must be undertaken pursuant 
to the terms and conditions of the pro forma open access transmission 
tariff. The language proposed by IL Com does not recognize the 
indivisible nature of single power purchases made on behalf of both 
wholesale and retail native load.
    b. Purchases for retail native load. TAPS argues that the 
Commission significantly contracts its functional unbundling 
requirement and the associated Standards of Conduct ``by exempting from 
functional unbundling all use by a transmitting utility of its own 
transmission system to serve bundled retail native load.'' \110\ By 
exempting a key aspect of the transmission provider's activities in 
wholesale markets from the open access rules, TAPS asserts, 
comparability is destroyed and the market is severely distorted. It 
emphasizes that

    \110\ TAPS at 4 and 6-14.
---------------------------------------------------------------------------

    because of the interdependence, elasticity and fungibility of 
purchases on behalf of unbundled retail load with the transmission 
provider's other wholesale marketing activities, there is little, if 
anything, left of functional unbundling.\111\

    \111\ Id. at 5.
---------------------------------------------------------------------------

TAPS states that Order No. 888-A leaves unclear issues critical to 
comparability, ``such as request procedures and priority for usage of 
limited interface capability applicable to the transmission provider's 
use of transmission for economy imports for retail bundled load.'' 
\112\ It argues that without clearly established rules that put the 
transmission provider in the same position as network customers, the 
transmission provider will have a competitive advantage.
---------------------------------------------------------------------------

    \112\ Id. at 9.
---------------------------------------------------------------------------

    TAPS further argues that the Commission's approach defeats the 
Commission's Standards of Conduct and allows transmission provider 
employees involved in the transmission function to ``share operational 
and reliability information with employees engaged in making economic 
and other purchases for retail bundled load on a preferential basis as 
compared with other transmission customers or the transmission 
provider's `wholesale' merchant function.'' \113\ Further, it asserts 
that the Commission's approach to functional unbundling will encourage 
a transmission provider to retain its preferential access to 
transmission service and information and discourage it from joining an 
ISO, under which it would lose its preferential treatment.
---------------------------------------------------------------------------

    \113\ Id. at 10-11.
---------------------------------------------------------------------------

    TAPS concludes by arguing that ``[c]ontrary to the Commission's 
suggestion, constriction of functional unbundling is not required by 
limitations on the Commission's jurisdiction.'' \114\ It asserts that 
the Commission has provided no support for its position and adds that 
the Commission's position cannot be reconciled with its treatment of 
transmission agreements between jurisdictional and non-jurisdictional 
entities whereby the Commission stated that its authority over a 
jurisdictional contract involving a public utility cannot be impaired 
by virtue of the fact that the other party is non-jurisdictional.
---------------------------------------------------------------------------

    \114\ Id. at 14.
---------------------------------------------------------------------------

    Commission Conclusion. While we have reiterated our view that the 
Commission does not have jurisdiction over the rates, terms and 
conditions of bundled retail service, based on the comments received on 
rehearing, we believe certain clarifications need to be made. As a 
practical matter, we do not believe that it is possible to divide a 
single power purchase made on behalf of both wholesale and retail 
native load such that the transmission provider takes service under the 
open access non-rate terms and conditions for the part of the purchase 
that goes to wholesale native load, but takes service under different 
terms and conditions for the part of the purchase that goes to retail 
native load. Because the power purchase transaction (including the 
delivery across the transmission provider's system to both wholesale 
and retail customers) is indivisible, and because the transmission of 
the purchased power to the wholesale native load customer must be done

[[Page 64701]]

pursuant to the open access tariff, this means that the entire 
transaction de facto must be pursuant to the non-rate terms and 
conditions of the tariff.
    Concerning the Standards of Conduct requirement that public 
utilities separate their wholesale power marketing functions from their 
transmission operations, the Commission did not require separation of 
the retail power marketing function because the state has jurisdiction 
over retail power marketing and over bundled retail transmission. 
However, here too we believe further clarification is necessary. First, 
the public utility has no choice pursuant to Order Nos. 888 and 888-A 
but to separate its wholesale power marketing function (including power 
purchase transactions made by the marketing function on behalf of 
wholesale native load) from the transmission operations function. This 
means that those persons in the company that are involved in wholesale 
power purchases as well as wholesale sales cannot interact with the 
transmission personnel other than through the OASIS. Thus, to the 
extent they are making purchases on behalf of wholesale as well as 
bundled retail native load as part of a single purchase, they will have 
to abide by the separation of function requirement. As discussed above, 
such a purchase is not divisible. Additionally, it is conceivable that 
there could be a separate retail marketing function for native load and 
a separate wholesale marketing function for native load. If a challenge 
is made to the way a utility organizes its functions, then the utility 
bears the burden of demonstrating that it is maintaining a separate 
staff to perform retail marketing functions. Furthermore, in such 
cases, it would clearly be inappropriate for the retail staff to share 
transmission information with the wholesale marketing staff.
8. Indirect Unbundled Retail Transmission in Interstate Commerce
    Referencing the Commission's conclusion that section 212(h) does 
not prohibit the Commission from ordering public utilities to provide 
indirect unbundled retail transmission in interstate commerce, BPA 
states that it appears that the Commission intended to clarify its 
jurisdiction to order retail transmission in certain limited, 
interstate situations--namely, to ensure that state initiatives would 
not be frustrated by the failure of neighboring states to undertake 
similar initiatives. Where a state has not mandated retail access, but 
a local utility agrees to provide retail access,\115\ BPA argues that 
it should not be required to distribute another supplier's power to its 
customers.
---------------------------------------------------------------------------

    \115\ See also Puget at 27.
---------------------------------------------------------------------------

    BPA also argues that section 212(h)(2) prohibits orders requiring 
``indirect retail transmission.'' It declares that the Commission 
ignored section 212(h)(2), which it asserts prohibits orders requiring 
indirect retail transmission. BPA contends that, if it and other 
transmitting utilities are required to provide indirect retail 
transmission, BPA's ability to meet its statutory obligation to recover 
all of the costs of the Federal Columbia River Power System and the 
Commission's ability to meet its statutory obligation to ensure that 
BPA's rates are sufficient to assure repayment of the federal 
investment in the power system will be placed at risk.
    Commission Conclusion. We disagree with BPA that we ignored section 
212(h)(2) in concluding that we have the authority to order indirect 
retail transmission in interstate commerce to accommodate retail access 
programs ordered by a state or voluntary retail delivery by the local 
utility. We clarify that while section 212(h)(2) may limit the 
Commission in certain circumstances, as a general matter, we believe we 
can order indirect interstate transmission services necessary to 
accommodate direct retail access programs that are state ordered or 
voluntary. Clearly, whether section 212(h) would prohibit the 
Commission from ordering transmission in a particular circumstance 
would depend upon the facts presented, including who the transmission 
requestor is, who the seller of energy is, and who is transmitting or 
delivering the energy and over what facilities. If parties wish to 
raise section 212(h)(2) in a particular case, they may do so; however, 
we do not believe Congress intended section 212(h)(2) to be used as a 
competitive shield against state-ordered retail access programs or 
voluntary retail access by local utilities.\116\
---------------------------------------------------------------------------

    \116\ BPA's arguments that requiring indirect retail wheeling 
may put at risk its ability to meet its statutory obligation to 
recover all of the costs of the Federal Columbia River Power System 
and the Commission's ability to meet its statutory obligation to 
ensure that BPA's rates are sufficient to assure repayment of the 
federal investment in the power system are speculative and more 
appropriately addressed in a fact-specific proceeding if and when 
this possible risk may arise. Moreover, BPA may propose appropriate 
stranded cost provisions.
---------------------------------------------------------------------------

9. Mobile-Sierra
    Met Ed objects to what it describes as the Commission's asymmetric 
treatment of customers and suppliers in Order No. 888-A. First, it 
argues that the existence of uneven bargaining power prior to Order No. 
888 (that is referred to in Order No. 888-A) does not provide a 
rational basis for imposing different standards for customer-initiated 
and supplier-initiated requests for modification of existing contracts. 
It says that the Commission does not identify the specific manner in 
which existing wholesale contracts would lose their just and reasonable 
character due to changes in the electric industry. ``Just as 
competitive wholesale markets may present opportunities to buyers that 
are less costly than existing contracts, they may also give sellers 
greater opportunities to reach new buyers who would be willing to pay 
more than customers under existing below-cost contracts. If the 
Commission's initiatives to expand wholesale markets provide a rational 
basis for making it easier for buyers to modify existing contracts, 
then these initiatives equally provide a basis to ease the burden on 
sellers.''\117\
---------------------------------------------------------------------------

    \117\ Met Ed at 6.
---------------------------------------------------------------------------

    Second, Met Ed argues that because the existence of uneven 
bargaining power was not universal, it cannot provide the basis for a 
uniform refusal to apply a just and reasonable standard in evaluating 
all supplier-initiated requests for modification (other than of 
stranded cost provisions). ``The Commission cannot properly distinguish 
customers from suppliers based on a premise that is only true in the 
`majority' of the cases, particularly when the Commission has the 
ability to make the appropriate determination on a case-by-case 
basis.''\118\
---------------------------------------------------------------------------

    \118\ Id. at 7.
---------------------------------------------------------------------------

    Third, Met Ed says that the Commission's distinction between 
customers and suppliers is not rationally related to the purpose of 
Order No. 888. It contends that broad competition is not furthered by a 
policy that would hold suppliers, but not customers, to the terms of 
existing unfavorable contracts. Met Ed states that ending the subsidies 
reflected in long-term below-cost contracts promotes the most efficient 
use of power supply resources. According to Met Ed, Order No. 888-A's 
treatment of existing contracts will exacerbate stranded costs (a 
utility would not be able to obtain relief from a wholesale contract 
that does not cover its costs, while a customer under another contract 
could obtain a modification or termination of the contract). ``Even if 
the Commission persists in its conclusion that it can reasonably 
distinguish requests for modifications by customers from those by 
utilities because existing contracts

[[Page 64702]]

reflect one sided bargaining, it should clarify that it will not make 
such a distinction when customers had other options at the time the 
contracts were executed.''\119\
---------------------------------------------------------------------------

    \119\ Id. at 10.
---------------------------------------------------------------------------

    Commission Conclusion. Met Ed has not raised issues not previously 
addressed by the Commission. Concerning its argument that uneven 
bargaining power was not universal, Order No. 888 clearly recognized 
that this was the case.\120\ However, we clarify that, in determining 
whether to modify an existing contract, we will look at, among other 
things, whether a customer had other supply options available to it at 
the time it negotiated its existing contract. We agree with Met Ed that 
the existence of uneven bargaining power may not have been 
``universal'' and clarify that utilities are free to present to the 
Commission, on a case-by-case basis, arguments that their contracts are 
no longer in the public interest or just and reasonable, and therefore 
should be modified.
---------------------------------------------------------------------------

    \120\ See, e.g., FERC Stats. & Reg para. 31,048 at 30,193.
---------------------------------------------------------------------------

10. Tariff Issues
    a. Load served ``behind-the-meter.'' Central Maine states that the 
Commission required all of a wholesale network customer's load 
``behind-the-meter'' to be included in its load-ratio share. It 
asserts, however, that the Commission ``failed to state whether the 
utility also must include all of a retail customer's load `behind-the-
meter' in computing the load-ratio share.'' \121\ It indicates that it 
is concerned that it cannot identify the ``behind-the-meter'' 
generation that its retail customers own and operate. Central Maine 
maintains that ``[o]nly if the utility invests significant effort and 
incurs substantial expense to install metering technology will it have 
the ability to monitor its retail customers.'' \122\ In any event,

    \121\ Central Maine at 2.
    \122\ Id. at 3.
---------------------------------------------------------------------------

    Central Maine believes that the Commission did not intend to 
require utilities to determine their retail customers ``behind-the-
meter'' load when calculating network customers' load-ratio shares. 
Moreover, the Commission cannot require a non-jurisdictional 
wholesale customer to determine its retail customers ``behind-the-
meter'' load. Thus, if FERC required jurisdictional companies to 
make such a determination, the load-ratio share of network non-
jurisdictional wholesale customers would always be understated. The 
Commission should clarify Order No. 888-A so that it is clear that 
utilities are not required to meter retail customer's ``behind-the-
meter'' load.\123\

    \123\ Id.
---------------------------------------------------------------------------

    Commission Conclusion. Central Maine's concern regarding the 
identification of a retail customer's ``behind-the-meter'' generation 
and load is unclear. The Commission's discussion in Order Nos. 888 and 
888-A regarding the treatment of behind-the-meter generation and load 
specifically pertained to an individual network customer's designated 
network generation and load. If Central Maine's concern pertains to the 
calculation of a transmission provider's total network load, including 
the load of the transmission provider's retail native load customers, 
such an inquiry is beyond the scope of Order Nos. 888 and 888-A and 
should be addressed on a case-by-case basis.
    b. Definition of ``Native Load Customers.'' Dairyland argues that 
the definition of ``Native Load Customers'' in section 1.19 of the pro 
forma tariff is limited to wholesale and retail power customers and 
``could be read not to encompass the native loads of parties to 
transmission joint use and construction agreements but who are not 
power customers of the Transmission Provider.'' \124\ It proposes that 
the following clause be added to the end of section 1.19: ``including 
obligations arising from transmission joint use agreements in effect as 
of July 9, 1996.'' \125\ Dairyland argues that the Commission should 
recognize these agreements and modify the definition so that 
``transmission facilities constructed and operated to meet the reliable 
electric needs of each party's native load customers are treated 
comparably, without regard to whether either party is or is not a 
`power' customer of the other.'' \126\ It further indicates that its 
primary concern in seeking this modification is in terms of priority 
under the pro forma tariff for curtailment and reservations and 
believes that its status and rights are unclear.
---------------------------------------------------------------------------

    \124\ Dairyland at 4 (emphasis in original).
    \125\ Dairyland notes that it filed a supplemental rehearing 
request on this issue that the Commission accepted as a motion for 
reconsideration. It asserts that the Commission did not address its 
issue in Order No. 888-A, but instead described the arguments as 
being similar to an argument it rejected that joint planning is a 
sufficient criterion to be considered a ``Native Load Customer'' and 
that construction and operation by the transmission provider should 
not be necessary for native load status to be conferred.
    \126\ Id. at 6.
---------------------------------------------------------------------------

    Commission Conclusion. We believe that Dairyland's argument is 
misplaced and deny its request for rehearing. In Allegheny Power 
Systems, Inc., et al.,\127\ we found that Dairyland's joint use 
agreements ``are in the nature of bilateral transmission agreements and 
are not superseded or otherwise affected by Interstate Power's 
compliance tariff. Thus, any changes to the definition of `native load 
customers' are not necessary.'' \128\ Accordingly, any change to the 
definition of native load customers contained in the pro forma tariff 
would have no affect on Dairyland's joint use agreements.
---------------------------------------------------------------------------

    \127\ 80 FERC para. 61,143 at 61,555 (1997).
    \128\ We further note that Interstate Power Company did not file 
on December 31, 1996, as provided in Order No. 888, to modify its 
joint use agreements with Dairyland. See 18 CFR 35.28(c)(1)(iii). 
Thus, those agreements must not prohibit transmission over the 
facilities to third parties and, accordingly, remain in effect as 
existing bilateral transmission agreements.
---------------------------------------------------------------------------

    We also note that Dairyland has stated that under its joint use 
agreement ``the native loads of Dairyland and the native loads of the 
public utility party to the agreement were to be treated comparably in 
terms of transmission service utilizing the transmission facilities.'' 
\129\ Thus, Dairyland already is obtaining the comparable treatment 
that it is apparently seeking through its proposal to change the 
definition of native load contained in the pro forma tariff.
---------------------------------------------------------------------------

    \129\ Dairyland at 6.
---------------------------------------------------------------------------

    c. Schedule changes. NRECA states that Order No. 888-A provided 
that schedule changes for firm point-to-point service were not limited 
up to twenty minutes before the start of each clock hour, but could be 
set at a reasonable time limitation that is generally accepted in the 
region and consistently adhered to by the transmission provider. NRECA 
requests rehearing to not only permit, but also to require, scheduling 
changes during emergency conditions.\130\ It asserts that the 
Commission should make this revision consistent with the language of 
section 30.4 of the pro forma tariff that permits network resources to 
be rescheduled in response to an emergency or other unforeseen 
condition. In any event, if ``schedule changes are not permissible in 
such situations, at least any associated penalties, e.g., punitive 
charges for energy imbalances exceeding the 1.5% `deadband,' should be 
waived.'' \131\
---------------------------------------------------------------------------

    \130\ See also TAPS at 35-36; TDU Systems at 24-25.
    \131\ NRECA at 16; see also TAPS at 36-37.
---------------------------------------------------------------------------

    Commission Conclusion. We deny NRECA's rehearing request to require 
transmission providers to make schedule changes requested by customers 
during emergency conditions. It is the responsibility of transmission 
customers to make arrangements for emergencies, such as operating 
reserves for the loss of a power supplier's generation source. If an 
emergency

[[Page 64703]]

arises, a transmission provider should not be required to accept a 
customer-requested schedule change, though we would expect the 
transmission provider to permit a schedule change to the extent 
possible. Granting NRECA's request would ignore the fact that requiring 
the transmission provider to accept a requested scheduling change may 
not be consistent with maintaining system reliability.
    Moreover, an emergency situation does not automatically cause a 
customer to use Energy Imbalance Service or to pay a penalty. For 
example, if a customer resource becomes unavailable due to an emergency 
situation, but is replaced by an equivalent amount of reserves, the 
customer would remain in balance if its load meets the schedule.\132\ 
However, if the emergency is the cause of the customer's energy 
imbalance, that is, the transmission provider is unable to deliver the 
scheduled energy, the customer should not be responsible for paying an 
Energy Imbalance Service penalty.
---------------------------------------------------------------------------

    \132\ See Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 
30,233 (emergency situations caused by loss or failure of facilities 
should be addressed in the transmission customer's service agreement 
(or the generation supplier's separate interconnection agreement) 
and not as part of Energy Imbalance Service).
---------------------------------------------------------------------------

    d. Restriction on making firm sales from designated network 
resources. NRECA argues that section 30.4 of the pro forma tariff 
unreasonably restricts network customers' ability to make firm sales 
from their generation and that similar restrictions do not apply to 
transmission providers' own generation resources.\133\ It asserts that 
this restriction on network customers ``is unnecessarily limiting both 
the number of competitors and the array of generation products 
available, as well as skewing the market in favor of generation sales 
by incumbent public utility transmission providers.'' \134\ If the 
Commission does not change its position, NRECA states that the 
Commission should at least provide network customers greater 
flexibility in designating network resources under section 30.1 of the 
pro forma tariff:

    \133\ See also TDU Systems at 18-21.
    \134\ NRECA at 17; see also Dairyland at 8.
---------------------------------------------------------------------------

    the Commission should at least grant network customers the 
ability to designate network resources over shorter time periods 
(e.g., one month) or permit the network customer to designate its 
network resources in a manner that varies by season or by month to 
track projected variations in network loads plus reserve 
requirements. This would provide network customers more flexibility 
in using their network resources to make firm off-peak sales to 
loads other than their network loads when it makes economic sense to 
do so, while still ensuring that adequate resources are committed to 
meet the network load and reserve requirements of the period.\135\

    \135\ NRECA at 18.
---------------------------------------------------------------------------

    TDU Systems adds that if the Commission does not change its 
position, ``transmitting utilities should be required to designate 
their network resources, and those resources, too, should be restricted 
to serving the transmitting utilities' network loads.''\136\
---------------------------------------------------------------------------

    \136\ TDU Systems at 21.
---------------------------------------------------------------------------

    Commission Conclusion. We disagree with NRECA, as well as TDU 
Systems, that the restrictions set forth in section 30.4 of the pro 
forma tariff do not also apply to a transmission provider's own 
generation resources. In Order No. 888, we explicitly stated that

    a transmission provider taking network service to serve network 
load under the tariff also is required to designate its resources 
and is subject to the same limitations required of any other network 
customer.\137\

    \137\ FERC Stats. & Regs. para. 31,036 at 31,753-54.
---------------------------------------------------------------------------

    In addition, we note that, contrary to NRECA's assertion, the pro 
forma tariff does not prevent network customers from designating 
network resources over shorter time periods or in a manner that varies 
by season or by month. It only prohibits network customers from making 
sales from designated network resources. The purpose of the prohibition 
is to ensure that such resources are available to meet the network 
customer's network load on a non-interruptible basis. Sections 30.2 and 
30.3 of the pro forma tariff already provide network customers with a 
significant level of flexibility. Specifically, a network customer that 
seeks to engage in firm sales from its current designated network 
resources may terminate the generating resource (or a portion of it) as 
a network resource and request, as set forth in section 29 of the pro 
forma tariff, that the same generation resource be designated as a 
network resource effective with the end of its power sale. We note that 
network customers, as well as the transmission provider's merchant 
function, must obtain point-to-point transmission service for off-
system sales.
    e. Reactive Power. NY Com states that under Order No. 888-A ``a 
transmission customer may satisfy part of its obligation [to supply 
reactive power service] through self-provision or purchases from 
generating facilities under the control of the control area operator.'' 
\138\ It requests clarification that the phrase ``under the control of 
the control area operator'' refers only to generators with continuously 
operating automatic voltage control (AVC). NY Com argues that units 
that do not have AVC and operate ``flat out'' do not support 
reliability and increase operating difficulty and inflict higher costs 
because system operators need to monitor local voltage levels and 
anticipate changing reactive support requirements.
---------------------------------------------------------------------------

    \138\ NY Com at 15-16.
---------------------------------------------------------------------------

    The Independent Power Producers of New York, Inc. (NY IPPs) 
responds to NY Com's request that only generators with continuously 
operating AVC be allowed to self supply reactive power.\139\ It asserts 
that ``[t]here is no reason to suppose that the Commission intended 
that suppliers of reactive power without AVC should not receive credit 
for the service they render.''\140\ It claims that NY Com's assertion 
that generators that do not have AVC and operate flat out cannot supply 
reactive power without inflicting higher costs on the system ``shows a 
fundamental misunderstanding of the operations of an electric 
generator.'' \141\ It maintains that

    \139\ On April 11, 1997, NY IPPs filed an answer to the request 
for clarification of NY Com. In the circumstances presented, we will 
accept the answer notwithstanding our general prohibition on 
allowing answers to rehearing requests. See 18 CFR 385.713(d).
    \140\ NY IPPs at 3.
    \141\ Id.
---------------------------------------------------------------------------

    [t]he ability to provide reactive support at full power output 
without imposing higher system costs has nothing to do with whether 
a generator has AVC. Rather, the ability to provide reactive power 
support stems from the design of the generator itself, specifically 
the rating of the rotor and stator windings. The NYPSC's assertion 
that providing reactive support manually ``increases operating 
difficulty and inflicts higher costs because system operators need 
to actively monitor local voltage levels, and anticipate changing 
local voltage levels'' is both unsupported and irrelevant.[\142\]

    \142\ Id. at 3-4.
---------------------------------------------------------------------------

Moreover, it asserts that ``[t]o the extent that generators with AVC 
that self provide reactive support render a more valuable service than 
those that self provide reactive support without AVC, they should be 
credited accordingly--but that does not mean that generators without 
AVC should not be credited at all for self providing reactive 
support.'' \143\ In addition, NY IPPs responds to NY Com's assertion 
that it has discouraged the practice of manual voltage support by 
requiring non-utility generators to either use AVC or pay a fee based 
on the absorption of reactive power. It states that NY Com's 
requirement ``that non-utility generators pay a utility when the 
generator absorbs reactive power at the utilities' request is

[[Page 64704]]

currently the subject of litigation in the United States District Court 
for the Northern District of New York.'' \144\
---------------------------------------------------------------------------

    \143\ Id. at 4.
    \144\ Id. (emphasis in original).
---------------------------------------------------------------------------

    TAPS is concerned that without specific tariff language some 
transmission providers will try to deny reactive power credits to 
transmission customers that should otherwise receive such credits. It 
suggests that the following language should be added to the pro forma 
tariff:

    The service agreement of the transmission customer that can 
supply at least a part of the reactive service it requires, either 
through self-supply or purchases from a third party, shall specify 
the generating sources made available by the transmission customer 
that provide reactive support.[\145\]

    \145\ TAPS at 28.
---------------------------------------------------------------------------

    TAPS also asks the Commission to clarify that the phrase ``under 
the control of the control area operator'' refers to ``the reactive 
production or absorption capability of the generator and not 
necessarily to the generator's ability to produce real power.'' \146\ 
It states that

    \146\ Id. at 29.
---------------------------------------------------------------------------

    while a generator's real power output may be on automatic 
generation control (AGC) and dispatched economically, its reactive 
power output usually is not on automatic control or dispatched on a 
moment-by-moment basis. Rather, the plant operator separately 
regulates the output of the two kinds of power. As a result, a 
customer can give the control area operator the ability to rely upon 
the customer's generation to produce or absorb reactive power 
independent of control over the unit's real power output, for 
example, by the customer's setting its generator's voltage regulator 
to respond to the needs of the control area as established by the 
control area operator. Thus, the Commission's statement that ``a 
customer who controls generating units equipped with automatic 
voltage control equipment may be able to use those units to help 
control the voltage locally and reduce the reactive power 
requirement of the transaction,'' (Order No. 888-A at 150-51) should 
not be read to require that the entire generating unit be under the 
control area operator's control.[\147\]

    \147\ Id. at 30.
---------------------------------------------------------------------------

    Furthermore, TAPS argues that comparable standards should be 
applied to customer-owned and transmission provider facilities. ``The 
control area operator should not be permitted to refuse the offer of a 
customer to turn over to the control area operator the control of the 
reactive capabilities of the customer's generating facilities.'' \148\ 
Moreover, it asserts that ``[i]f the control area operator is able to 
rely upon its own or its customer's facilities to produce or absorb 
reactive power, then rate base treatment or credits, respectively, are 
appropriate.'' \149\
---------------------------------------------------------------------------

    \148\ Id.
    \149\ Id.
---------------------------------------------------------------------------

    Commission Conclusion. We do not agree with NY Com's assertion that 
the phrase ``generating facilities under the control of the control 
area operator'' refers only to generators with AVC. We clarify that 
what is ``under the control of the control area operator'' in Schedule 
2 of the pro forma tariff is the reactive production and absorption 
capability of the generator and not the generator's ability to produce 
real power. With regard to the dispute between NY Com and NY IPPs 
concerning the appropriate reduction in charges for Reactive Supply and 
Voltage Controls from Generation Sources Service, we find that this 
dispute is fact-specific and beyond the scope of this proceeding.
    There is no need to add the specific language to the pro forma 
tariff as requested by TAPS. As stated in Order No. 888-A, the 
Commission specifically requires that a transmission customer's service 
agreement specify all reactive supply arrangements, including the 
generating resources made available by the transmission customer that 
provide reactive support.
    In response to TAPs' other concern, we note that Order No. 888 
requires that a transmission customer obtain or provide ancillary 
services for its transactions. We do not intend that requirement to 
provide a means for a generation owner to compel a transmission 
provider to purchase services it may not need. As we stated in Order 
No. 888-A, a third party may offer ancillary services voluntarily to 
other customers if technology permits. However, simply supplying some 
duplicative ancillary services (e.g., providing reactive power at low 
load periods or providing it at a location where it is not needed) in 
ways that do not reduce the ancillary services costs of the 
transmission provider or that are not coordinated with the control area 
operator does not qualify for a reduced charge.
    f. Network Operating Agreements. TAPS asks that section 29.1 of the 
pro forma tariff be modified to permit a network customer to request 
that a network operating agreement be filed on an unexecuted basis, 
just as it may request a network service agreement to be filed on an 
unexecuted basis. It asserts that this would ``permit service to 
commence, pending resolution of disputed matters, and would reduce the 
ability of the transmission provider to use the network operating 
agreement as a competitive tool.'' \150\
---------------------------------------------------------------------------

    \150\ Id. at 34.
---------------------------------------------------------------------------

    Commission Conclusion. In Order No. 888-A, in response to TAPS' 
argument that to avoid improper use of operating agreements by 
transmission providers the Commission should either permit network 
operating agreements to be filed in unexecuted form or include a 
network operating agreement as part of the pro forma tariff, we 
rejected mandating a particular network operating agreement but 
indicated that

    If a transmission provider wishes to include a generic form of 
network operating agreement in its pro forma tariff (to be modified 
as required and as mutually agreed to on a customer-specific basis), 
it may propose to do so in a section 205 filing or it may file an 
unexecuted network operating agreement in a section 205 filing.
    To the extent a customer believes a transmission provider is 
engaging in unduly discriminatory practices via the network 
operating agreement, the customer may file a section 206 complaint 
with the Commission.\151\
---------------------------------------------------------------------------

    \151\ FERC Stats. & Regs. para. 31,048 at 30,325.

On rehearing, TAPS points out that our approach would still permit a 
transmission provider to delay the commencement of service. We 
recognize this and will permit a network customer to request that a 
network operating agreement be filed on an unexecuted basis, just as we 
have allowed a network customer to request that a network service 
agreement be filed on an unexecuted basis. Accordingly, we will modify 
section 29.1 of the pro forma tariff by adding the following language 
to the end of section 29.1: ``, or requests in writing that the 
Transmission Provider file a proposed unexecuted Network Operating 
Agreement.'' \152\
---------------------------------------------------------------------------

    \152\ See Appendix B and note 1 supra.
---------------------------------------------------------------------------

    g. Network customers with loads and resources in multiple control 
areas. TDU Systems argues that Order No. 888-A does not respond to its 
``core contention that network service under the pro forma tariff does 
not provide them comparable service.'' \153\ It argues that

    \153\ TDU Systems at 15.
---------------------------------------------------------------------------

    [r]equiring the network customer to assign a designated network 
resource to a single control area, and arbitrarily limiting the 
ability of a network customer to schedule the output of network 
resources between and among control areas by limiting the output of 
those resources to network load in a single control area, 
effectively prevents the network customer from operating an 
integrated system.\154\
---------------------------------------------------------------------------

    \154\ Id.

Thus, it requests that the Commission ``rule that TDU systems with 
loads and resources in multiple control areas may

[[Page 64705]]

designate as Network Resources for each control area the totality of 
their resources that meet the owned, purchased, or leased requirement 
of section 1.25 of the tariff.'' \155\
---------------------------------------------------------------------------

    \155\ Id. at 18.
---------------------------------------------------------------------------

    TDU Systems further asserts that a network customer can integrate 
loads and resources in multiple control areas only by purchasing 
network service in each control area and point-to-point service for 
transmission between the control areas. Thus, it argues,

    [A]bsent a regional network tariff, the Commission should 
require the provision of service to network customers with loads and 
resources located on multiple systems under a rate that recovers the 
customer's load ratio share--but no more--of the transmission 
owners' collective transmission investment in the control areas that 
the customer straddles.\156\
---------------------------------------------------------------------------

    \156\ TAPS at 18 n.36.

    Commission Conclusion. We disagree with TDU Systems that network 
service under the pro forma tariff does not provide network customers 
with comparable service. Significantly, a network customer with 
resources and loads in multiple control areas is simply not similarly 
situated to a transmission provider serving native load located 
entirely within the transmission provider's single control area. Unlike 
a transmission provider serving load entirely within a single control 
area, a network customer with resources and loads in multiple control 
areas must not only integrate its resources and loads within the 
individual control areas, but must also arrange transmission services 
(network or point-to-point) for transactions occurring between and 
among the multiple control areas in which it seeks to transact 
business. However, we emphasize that if a transmission provider has 
resources and loads in multiple control areas, it must treat network 
customers that also have resources and loads in multiple control areas 
on a comparable basis.
    In this regard, we also disagree with TDU Systems' assertion that 
we have required a network customer to assign a designated network 
resource to a single control area and limit the scheduling of such 
resources to serve load in a single control area. Tariff sections 30.6 
and 31.3 allow for the designation of both network resources and 
network loads that are not physically interconnected with the 
transmission provider. Under the pro forma tariff, a network customer 
that seeks network service for all of its loads in multiple control 
areas may designate all such loads as network loads.\157\ By 
designating all of its loads as network loads, such network customer 
will receive comparable service in each control area and will have the 
ability to schedule the output of network resources between and among 
control areas, just as a transmission provider or other network 
customer would need to do to serve load in an adjacent control area.
---------------------------------------------------------------------------

    \157\ Alternatively, a network customer with resources and load 
in multiple control areas may elect to designate only such load that 
is located in a single control area as its designated network load 
and separately arrange for transmission service (e.g., point-to-
point service) to serve load in adjacent control areas from 
generation resources located in the control area in which it 
designated its network load. Here too the network customer would be 
receiving comparable transmission service because a transmission 
provider or any other network customer seeking to serve load in an 
adjacent control area would also have to arrange for point-to-point 
transmission service to make the service possible.
---------------------------------------------------------------------------

    TDU Systems is concerned with the rates it must pay to the various 
control area operators to integrate its resources and loads. In 
rejecting TDU Systems' virtually identical argument in Order No. 888-A, 
we explained:

    Because the additional transmission service to non-designated 
network load outside of the transmission provider's control area is 
a service for which the transmission provider must separately plan 
and operate its system beyond what is required to provide service to 
the customer's designated network load, it is appropriate to have an 
additional charge associated with the additional service.\158\
---------------------------------------------------------------------------

    \158\ FERC Stats. & Regs. para. 31,048 at 30,255.
---------------------------------------------------------------------------

    h. Network customer designation of load. TDU Systems asks the 
Commission to clarify that open access transmission providers must 
credit or eliminate double charges arising from the inability of 
network customers to designate less than all of the load at a delivery 
point as network load. TDU Systems asks the Commission to make the 
following points clear:

    first, there will be no double recovery of either transmission 
costs or ancillary costs that are being recovered in the existing 
bundled generation supply agreement; second, as the Commission 
properly noted in requiring the unbundling of bilateral economy 
energy coordination transactions, the transmission provider will not 
be permitted to recover more under the new arrangement for those 
(transmission and ancillary) services than it does under the 
existing bundled generation supply agreement; and third, the 
transmission provider is required to achieve these results by using 
one of the alternatives stated in Order No. 888-A at the 
transmission customer's election or by an alternative arrangement 
agreed upon by the customer.\159\

    \159\ TDU Systems at 23.
---------------------------------------------------------------------------

It concludes that ``[i]f the Commission relegates the customer to a 
section 206 complaint proceeding, it has reversed the burden of proof 
on the transmission provider to show that its increased rate is just 
and reasonable.''
    Commission Conclusion. As noted by TDU Systems, we stated in Order 
No. 888-A that

    the Commission did not intend for a transmission provider to 
receive two payments for providing service to the same portion of a 
transmission customer's load. Any such double recovery is 
unacceptable and inconsistent with cost causation principles.\160\

    \160\ FERC Stats. 7 Regs. para. 31,048 at 30,261-62.
---------------------------------------------------------------------------

We intended this language to apply broadly and, accordingly, clarify 
that it applies to transmission costs and ancillary costs. Moreover, 
while we expect transmission providers to design rates that will avoid 
double recovery of such transmission costs or ancillary costs, we 
believe that this is a fact-specific issue that is appropriately 
addressed on a case-by-case basis.\161\ Finally, while we indicated in 
Order No. 888-A that a transmission customer may file a complaint under 
section 206 with the Commission to address any claims of double 
recovery, the transmission customer would most likely raise this issue 
in the section 205 proceeding in which the transmission provider files 
to initiate the particular service with the transmission customer. 
Indeed, it would be in such a section 205 proceeding in which this 
transitional problem would first arise and the transmission customer 
would first have the opportunity to challenge any possible double 
recovery.
---------------------------------------------------------------------------

    \161\ In this regard, we will not mandate that a transmission 
provider accept a customer-specified approach to resolving any 
double recovery concerns.
---------------------------------------------------------------------------

11. Waivers of Order Nos. 888 and 889
    NRECA states that the Commission's policy on waivers of Order Nos. 
888 and 889 provides that such waivers terminate upon a request for 
service or a complaint. It argues that permitting the termination of a 
waiver upon a complaint improperly subjects the utility to baseless 
complaints and significantly diminishes the value of the waiver. It 
asserts that a waiver of Order No. 889 should terminate only upon a 
finding by the Commission that there is a valid basis for the 
complaint.\162\ Similarly, it asserts that a waiver of Order No. 888 
should terminate ``only upon a Commission order finding that, in light 
of changed circumstances or new evidence, the waiver should not be

[[Page 64706]]

continued and the utility should be required to file the pro forma 
tariff.'' \163\
---------------------------------------------------------------------------

    \162\ See also TDU Systems at 10-12 (raising similar arguments 
with respect to waivers of Order No. 889).
    \163\ NRECA at 12.
---------------------------------------------------------------------------

    Commission Conclusion. NRECA's request for rehearing with respect 
to the termination of a waiver of Order No. 888 should have been raised 
on rehearing of Order No. 888, which first established that a waiver 
would be granted if, among other things, the utility ``commits to file 
an open access tariff within 60 days of a request to use its facilities 
and to comply with the rule in all other ways.'' \164\ Nothing set 
forth in Order No. 888-A changed this requirement. Accordingly, NRECA's 
request for rehearing was not timely filed.
---------------------------------------------------------------------------

    \164\ FERC Stats. & Regs. para. 31,036 at 31,853.
---------------------------------------------------------------------------

    However, we note that the Commission, in a recent order modifying 
the circumstances under which a waiver of Order No. 889 \165\ will be 
revoked,\166\ addressed this very issue:
---------------------------------------------------------------------------

    \165\ Open Access Same-Time Information System and Standards of 
Conduct, Final Rule, Order No. 889, 61 FR 21737 (May 10, 1996), FERC 
Stats. & Regs. para. 31,035 (1996), order on reh'g, Order No. 889-A, 
62 FR 12484 (March 14, 1997), FERC Stats. & Regs. para. 31,049 
(1997), order on reh'g, Order No. 889-B, published elsewhere in this 
issue of the Federal Register, FERC Stats. & Regs. para. ________ 
(1997).
    \166\ NRECA's request with respect to the revocation of waivers 
of Order No. 889 is addressed in Order No. 889-B, which is being 
issued concurrently with this Order. In Order No. 889-B, the 
Commission notes that in Central Minnesota Municipal Power Agency, 
et al., 79 FERC para. 61,260 (1997) (Central Minnesota), it already 
has revised its approach concerning the revocation of waivers of 
Order No. 889 to provide that such waivers will remain effective 
until the Commission takes action in response to a complaint, rather 
than until 60 days after a complaint to the Commission.

    we will not, however, alter our determination that a utility 
that has been granted waiver of Order No. 888 is required to file a 
pro forma tariff within 60 days after it receives a request for 
transmission service and must comply with any additional 
requirements that are effective on the date of the request. The 
filing with the Commission of a pro forma tariff places 
significantly less burden on a utility than does full compliance 
with Order No. 889, and we continue to believe that 60 days from 
receipt of a request for service provides sufficient time for such 
compliance.\167\
---------------------------------------------------------------------------

    \167\ Central Minnesota, 79 FERC at 62,127 (1997).
---------------------------------------------------------------------------

12. Financial Independence of ISO Employees
    NEPOOL expresses concern that the requirement in Order No. 888-A 
that ISO employees sever all financial ties ``can be interpreted to 
foreclose the Commission from even considering the merits of provisions 
for ownership of securities by ISO employees contained in NEPOOL's ISO 
proposal that is now pending before the Commission in Docket Nos. OA97-
237-000 and ER97-1079-000.'' \168\ It contends that severance of all 
financial ties would impose an economic hardship on certain NEPOOL 
employees in pension and stock ownership plans of market participants 
through the years. In particular, it notes that many of the existing 
NEPOOL staff have accumulated Northeast Utilities stock in their 
pension or other employee benefit plans, but that the market price of 
that stock has recently declined significantly. However, NEPOOL has 
required ISO employees to divest themselves of such securities in 
excess of $50,000 within six months of their employment by the ISO. 
Thus, NEPOOL requests that the Commission clarify that it could waive 
the requirement that ISO employees sever all financial ties with market 
participants in compelling circumstances or clarify the acceptable 
length of a transition period during which they may continue to hold 
such securities.
---------------------------------------------------------------------------

    \168\ NEPOOL at 2.
---------------------------------------------------------------------------

    Commission Conclusion. In a recent order conditionally authorizing 
the establishment of an ISO by NEPOOL, the Commission specifically 
addressed the concerns raised here by NEPOOL.\169\ The Commission 
rejected NEPOOL's proposal to allow employees to possess securities of 
market participants as long as the value does not exceed $50,000. The 
Commission reaffirmed its strong commitment, set forth in Order Nos. 
888 and 888-A, to ensure that an ISO is truly independent and that 
employees of an ISO are financially independent of market participants. 
However, the Commission recognized, as it had in Order No. 888-A, that 
there may be a need for flexibility with respect to the length of a 
transition period and that this matter is best addressed on a case-by-
case basis.
---------------------------------------------------------------------------

    \169\ New England Power Pool, 79 FERC para. 61,374 (1997), reh'g 
pending.
---------------------------------------------------------------------------

13. Distribution Charges
    NY Com seeks clarification of the Commission's statement that a 
utility is free to include a ``distribution charge'' in a customer's 
service agreement and/or the network customer's network operating 
agreement.\170\ In particular, it requests that the Commission clarify 
that it did not intend to preempt state jurisdiction, but rather that 
when a term, condition or rate is required for local distribution 
service, the state determination will apply. It asserts that such a 
clarification would avoid forum shopping that would otherwise occur. In 
the alternative, it requests rehearing, arguing that the Federal Power 
Act, its legislative history and case law all dictate against 
Commission jurisdiction over local distribution.
---------------------------------------------------------------------------

    \170\ NY Com at 5-12.
---------------------------------------------------------------------------

    Commission Conclusion. We clarify, as requested by NY Com, that 
when a term, condition or rate is required for local distribution 
service the state determination applies. We reiterate that we believe 
there is always a local distribution service element of a retail 
transaction, through which the state may impose charges on the retail 
customer. We also reiterate, however, that where a public utility is 
delivering unbundled energy to a supplier that then resells the energy 
to an end-user, the Commission has exclusive jurisdiction over the 
public utility's facilities used to effect the transaction without 
regard to their being labeled ``transmission,'' ``distribution,'' or 
``local distribution.'' \171\ Moreover, where a public utility is 
delivering unbundled energy from a third-party supplier directly to an 
end user, the particular facts of the case will determine which of the 
facilities are FERC-jurisdictional transmission facilities and which 
are state-jurisdictional local distribution facilities.\172\
---------------------------------------------------------------------------

    \171\ See Order No. 888, FERC Stats. & Regs. para. 31,036 at 
31,969 (Appendix G) and Allegheny Power System, Inc., et al., 80 
FERC para. 61,143 at 61,551-52 (1997).
    \172\ See Order No. 888, FERC Stats. & Regs. para. 31,036 at 
31,969.
---------------------------------------------------------------------------

14. Tight Power Pools
    a. Non-pancaked rates. NY Com seeks clarification of the following 
statement in Order No. 888-A:

    Order No. 888 does not require a non-pancaked rate structure 
unless a non-pancaked rate structure is available to pool members. 
Although the Commission has encouraged the industry to reform 
transmission pricing, the Commission's current policy does not 
mandate a specific transmission rate structure.\173\
---------------------------------------------------------------------------

    \173\ NY Com at 12.

It argues that this statement conflicts with other statements that 
``require power pools to file joint pool-wide tariffs and to offer all 
transmission services that they are capable of providing.'' \174\ NY 
Com asks that the Commission clarify that utility members of tight 
power pools must provide transmission service jointly under a single 
tariff. It states that this is the best way to eliminate undue 
discrimination. It argues that tight power pools must provide, pursuant 
to prior Commission orders, all transmission services that they are 
reasonably capable of providing and must file joint tariffs to provide

[[Page 64707]]

transmission service on a pool-wide basis.
---------------------------------------------------------------------------

    \174\ Id. at 13 (emphasis in original).
---------------------------------------------------------------------------

    Commission Conclusion. NY Com appears to be confusing services that 
a power pool is capable of providing with pricing methodologies that a 
power pool may elect to use. While the Commission required that by 
December 31, 1996 all pool transactions be taken under a joint pool-
wide tariff on file with the Commission, the Commission did not mandate 
a specific transmission rate structure for such tariff.\175\ As we 
stated in Order No. 888-A, the primary goal for pooling arrangements is 
to ensure comparability regarding transmission services offered on a 
pool-wide basis. Thus, comparability is achieved if the same service is 
provided at the same or comparable rate to both pool and non-pool 
members.\176\
---------------------------------------------------------------------------

    \175\ However, as explained in Order No. 888-A, the Commission 
did require that all transmission rate proposals filed in compliance 
with Order Nos. 888 and 888-A be cost based and meet the standard 
for conforming proposals set out in the Commission's Transmission 
Pricing Policy Statement. See 18 CFR 2.22.
    \176\ Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 
31,728.
---------------------------------------------------------------------------

    b. Coordination transactions. Otter Tail requests that the 
Commission clarify the following statement in Order No. 888-A:

    We do not find it to be unduly discriminatory to provide some 
pool-wide transmission services to members under a pooling agreement 
and to provide other transmission services to members under the 
individual tariff of each member, as long as members and non-members 
have access to the same transmission services on a comparable basis 
and pay the same or a comparable rate for transmission.\177\
---------------------------------------------------------------------------

    \177\ Otter Tail at 3 (emphasis added by Otter Tail).
---------------------------------------------------------------------------

It asks the Commission to clarify that this statement

Is meant only to indicate that in the case of different services, 
one service (e.g., wholesale transactions) can be offered to all 
potential customers under the pool tariff, but another service 
(e.g., ancillary services) may not be offered to any customers under 
the pool tariff. Otter Tail specifically requests that the 
Commission clarify that where the same service is involved, pools 
cannot discriminate against certain transactions based solely on the 
transaction's duration, that is, pool-wide tariffs cannot exclude 
longer term transactions but include short-term 
transactions.\178\

    \178\ Id. at 4 (emphasis in original).
---------------------------------------------------------------------------

In its case, Otter Tail is concerned that MAPP limits coordination 
transactions under the pool to those with a duration of two years or 
less and thereby prevents any longer term service from using the pool 
tariff. It argues that MAPP's tariff does not comply with Order No. 888 
because it does not offer pool-wide service for all coordination 
transactions, regardless of duration. Otter Tail further argues that 
excluding the benefits of pool-wide service for coordination 
transactions based only on the length of term is contrary to, and 
incompatible with, Congress' and the Commission's goal to promote 
competition at the generation level and permits pools to exercise 
market power.
    Commission Conclusion. We disagree with Otter Tail. As we stated in 
Order No. 888-A, the primary goal of Order No. 888's requirements for 
pooling arrangements, including ``loose'' pools, such as MAPP, is to 
ensure comparability regarding transmission services that are offered 
on a pool-wide basis.\179\ In the case of the MAPP agreement, pool 
transactions are limited to periods not to exceed two years for all 
members.\180\ Comparability is achieved if all parties, both pool 
members and non-pool members, are treated in a non-discriminatory 
fashion as to access to transmission services, the types of 
transmission services and the rates paid for such transmission 
services.
---------------------------------------------------------------------------

    \179\ FERC Stats, & Regs. para. 31,048 at 31,241.
    \180\ Mid-Continent Area Power Pool Rate Schedule, FERC No. 5.
---------------------------------------------------------------------------

    In addition, Order No. 888 requires loose pools to take service 
under a joint pool-wide tariff for all pool transactions.\181\ If 
transactions of more than two years in duration are not pool 
transactions, then transmission for those transactions need not be 
pursuant to the pool-wide tariff, and instead would be provided 
pursuant to the individual companies' pro forma tariffs. This is 
consistent with our finding in Order No. 888-A that we will not require 
pool members to offer transmission services to third parties that the 
pool members do not provide to themselves on a poolwide basis.\182\
---------------------------------------------------------------------------

    \181\ FERC Stats. & Regs. para. 31,036 at 31,728.
    \182\ See FERC Stats. & Regs. para. 31,048 at 30,241.
---------------------------------------------------------------------------

15. Legal Authority
    Puget states that the Commission does not have the legal authority 
to require public utilities to file open access tariffs and argues that 
Order No. 888 does not contain any specific finding that any rate, term 
or condition of Puget's tariff is unjust, unreasonable or unduly 
discriminatory or preferential.
    Commission Conclusion. The Commission set forth its legal authority 
to require public utilities to file open access tariffs in Order No. 
888. Puget's request for rehearing with respect to this issue should 
have been raised on rehearing of Order No. 888 and therefore was not 
timely filed.\183\
---------------------------------------------------------------------------

    \183\ We note that Puget filed a rehearing request of Order No. 
888, but did not challenge the Commission's authority to require 
public utilities to file open accesss tariffs.
---------------------------------------------------------------------------

16. Ancillary Services
    Puget argues that ancillary services such as reactive power and 
voltage control cannot be considered merely ancillary to the provision 
of transmission service, but are significant generation services that 
should be subject to market rates. Puget asserts that ``[i]t is wholly 
inappropriate for the Commission to provide for the sale of power as an 
ancillary service under the pro forma tariff; instead, utilities such 
as [Puget] should be compensated for the sale of such power at market 
based rates.'' \184\ It argues that the Commission ``must recognize 
that ancillary services are generation related and should be priced at 
market in order to be consistent.'' \185\
---------------------------------------------------------------------------

    \184\ Puget at 18.
    \185\ Id. at 19.
---------------------------------------------------------------------------

    Commission Conclusion. Puget raises issues that were previously 
addressed in Order No. 888. In that order the Commission determined 
that ancillary services are transmission related and indicated that 
market-based pricing for ancillary services would be addressed on a 
case-by-case basis. Puget's request for rehearing with respect to these 
issues should have been raised on rehearing of Order No. 888 and 
therefore was not timely filed.
17. Fair Market Value
    Puget argues that Order No. 888-A improperly shuts the door on the 
pricing of transmission property at fair market value. Citing footnote 
261 of Order No. 888-A,\186\ Puget asserts that the Commission changed 
its policy from Order No. 888 and claims that in Order No. 888-A ``the 
Commission ruled that each utility is now expressly limited by the 
transmission pricing policy to charging only embedded costs for 
existing transmission facilities to competitors and others even though 
rates for generation assets are priced at market.'' \187\ Puget argues 
that Order No. 888-A achieves ``the effect of a condemnation by forcing 
[Puget] and other integrated electric utilities to allow competitors to 
use private utility property, but at less than fair market value.'' 
\188\ Puget further argues that the Constitution ``does not permit the 
taking of private property of one citizen to

[[Page 64708]]

benefit competitors or other private citizens.'' It contends that

    \186\ Footnote 261, which is in the section entitled Opportunity 
Cost Pricing, provides in relevant part that ``[u]nder the 
Commission's transmission pricing policy, utilities are limited to 
charging the higher of embedded costs or opportunity/incremental 
costs.''
    \187\ Puget at 21.
    \188\ Id. at 21-22.
---------------------------------------------------------------------------

    [T]he voluntary provision of transmission service to 
noncompetitors in an entirely cost-based integrated system is not 
the same as a forced provision of service and use of property by a 
competitor under a new set of regulations treating generation at 
market rates.\189\

    \189\ Id. at 26.
---------------------------------------------------------------------------

Puget goes on to argue that

    Order 888 erroneously asserts that there ``simply cannot be an 
unconstitutional taking of property when public utilities continue 
to have the right to file for and receive rates that provide them a 
reasonable opportunity to recover their prudently incurred costs.'' 
62 Fed. Reg. at 12,433. For example, by illegally requiring 
unbundling of generation assets at market without at the same time 
providing for utility recovery of the fair market value of its 
transmission property, the Commission is attempting to deprive 
public utilities of fair market value compensation.\190\

    \190\ Id.
---------------------------------------------------------------------------

In conclusion, Puget declares that ``[t]he Commission cannot create a 
situation in which generation is sold at a new market-based rate and 
transmission is limited to an old historic embedded-cost rate. Neither 
the Constitution nor the FPA will permit such a result.'' \191\
---------------------------------------------------------------------------

    \191\ Id. at 27.
---------------------------------------------------------------------------

    Commission Conclusion. We reject Puget's rehearing request. Puget 
makes a far-ranging argument that Order No. 888-A improperly shuts the 
door on the pricing of transmission property at fair market value. It 
bases its argument entirely on a single footnote in Order No. 888-A 
that has been taken completely out of context. The footnote in Order 
No. 888-A cited by Puget merely recites the Commission's longstanding 
policy as to opportunity cost pricing.\192\ Indeed, in the sentence to 
which that footnote is attached, the Commission explicitly stated that 
it ``does not believe that any changes are necessary to its policy on 
opportunity cost recovery.'' \193\ Moreover, the entire discussion to 
which that footnote applies is in a section entitled ``Opportunity Cost 
Pricing.'' \194\
---------------------------------------------------------------------------

    \192\  See Order No. 888, FERC Stats. & Regs. para. 31,036 at 
31,739-40; Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 
30,263-66.
    \193\ Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 
30,625.
    \194\ Id. at 30,263.
---------------------------------------------------------------------------

18. Pre-Existing Transmission-Only Contracts
    Soyland argues that the Commission's Mobile-Sierra findings must 
apply not only to wholesale requirements contracts but also to 
unbundled transmission-only contracts. It asserts that ``[t]here is no 
legitimate reason to deny unbundled, transmission-only customers timely 
and meaningful access to the open access regime and competitive markets 
on the same terms as requirements customers.'' \195\ It contends that 
it faced the same problem as requirements customers--``use of 
transmission monopoly power to force a purchase of power as a condition 
to getting transmission access to deliver owned resources from off-
system.'' \196\
---------------------------------------------------------------------------

    \195\ Soyland at 8.
    \196\ Id.
---------------------------------------------------------------------------

    Moreover, it asserts that the Commission has not explained how or 
why requirements contracts and transmission-only contracts should be 
treated differently as a result of the past and continuing changes in 
the industry. Soyland further states that utilities had the upper hand 
over ``customers who executed unbundled transmission and power supply 
contracts simultaneously; together, such contracts are the functional 
equivalent of bundled partial requirements contracts, and should not be 
subject to a different standard for contract reform.'' \197\
---------------------------------------------------------------------------

    \197\ Id. at 10.
---------------------------------------------------------------------------

    Commission Conclusion. Soyland's rehearing request addresses an 
issue that should have been raised on rehearing of Order No. 888. In 
that order, the Commission explicitly indicated that customers under 
requirements contracts executed on or before July 11, 1994 that 
contained Mobile-Sierra clauses should have the opportunity to 
demonstrate that their contracts no longer are just and 
reasonable.\198\ Soyland's opportunity to request that we expand the 
scope of the contracts covered to include unbundled transmission-only 
contracts was on rehearing of Order No. 888.\199\ Accordingly, 
Soyland's request for rehearing with respect to this issue was not 
timely filed.
---------------------------------------------------------------------------

    \198\ FERC Stats. & Regs. para.31,036 at 31,664.
    \199\ In this regard, we note that other entities did file 
rehearing requests of Order No. 888 seeking to expand the scope of 
the contracts covered by the Commission's Mobile-Sierra findings. 
See Order No. 888-A, FERC Stats. & Regs. para.31,048 at 30,190-91.
---------------------------------------------------------------------------

19. Apportionment of Transmission Revenues for Public Utility Holding 
Companies and Power Pools
    TDU Systems asks the Commission to clarify that the ``apportionment 
of credits for customer transmission facilities among the operating 
companies of a utility holding company or in power pools should be 
subject to Commission approval.'' TDU Systems states that the method of 
crediting transmission customers for operating companies' uses of their 
own and each other's transmission facilities in setting transmission 
rates must meet the Commission's comparability standards and should not 
be filed on a unilateral basis. Similarly, it requests that customer 
credits for pool participants' use of their own and each other's 
transmission facilities should be subject to Commission review in 
approving the pool's transmission rates and tariff terms and 
conditions.\200\
---------------------------------------------------------------------------

    \200\ TDU Systems at 33-34.
---------------------------------------------------------------------------

    Commission Conclusion. TDU Systems' rehearing request addresses 
issues that should have been raised on rehearing of Order No. 888. In 
Order No. 888, the Commission stated that credits for customer-owned 
facilities should be addressed on a case-by-case basis.\201\ 
Accordingly, TDU Systems' request for rehearing with respect to these 
issues was not timely filed.
---------------------------------------------------------------------------

    \201\ See FERC Stats. & Regs. para.31,036 at 31,742.
---------------------------------------------------------------------------

20. Accounting for Transmission Provider's Own Use of Its System
    TDU Systems argues that the Commission's requirement that a 
transmission provider's methodology to credit customers for the 
transmission provider's off-system sales be addressed in compliance 
filings and will depend on the rate design is insufficient.\202\ It 
argues that this ignores that

    \202\ TDU Systems at 34-35.
---------------------------------------------------------------------------

    Comparability has a time dimension, requiring the prompt 
crediting of such charges if they are not automatically accounted 
for in the rate design. Thus, the order fails to address whether a 
new kind of rate mechanism is needed if comparability is to be 
ensured on an ongoing basis under open-access transmission, just as 
the Commission years ago approved the use of fuel-adjustment clauses 
to deal with more volatile fuel prices. Requiring parties to resolve 
this issue in individual compliance filings does not address this 
generic problem. The Commission should provide more guidance to 
public utilities as to what crediting mechanisms are necessary if 
comparability is to be achieved.\203\

    \203\ Id. at 34-35.
---------------------------------------------------------------------------

    Commission Conclusion. In Order No. 888-A, the Commission explained 
that an automatic pass-through mechanism for revenue credits raises a 
number of potential problems including: ``(1) use of estimates versus 
actuals; (2) the appropriate time period to be utilized and (3) firm 
versus non-firm distinctions.'' \204\ The Commission further noted that 
the appropriate treatment of revenue credits for off-system sales is 
dependent on the rate design used by a transmission provider and 
concluded that this issue is not appropriately resolved on a generic 
basis. Despite these identified problems, TDU Systems continues to 
request that

[[Page 64709]]

the Commission adopt an automatic revenue credit mechanism without 
attempting to address such problems or proposing an appropriate 
mechanism to accomplish its request.
---------------------------------------------------------------------------

    \204\ FERC Stats. & Regs. para.31,048 at 30,310.
---------------------------------------------------------------------------

    To bolster its proposal, TDU Systems claims that automatic 
treatment of revenue credits is comparable to the Commission treatment 
of fuel charges through the use of an automatic fuel adjustment charge. 
We disagree. An automatic fuel cost adjustment clause was determined to 
be appropriate because of the unpredictability of fuel prices.\205\ TDU 
Systems has not demonstrated that revenue credits warrant the same 
treatment.\206\
---------------------------------------------------------------------------

    \205\ See Treatment of Purchased Power in the Fuel Cost 
Adjustment Clause for Electric Utilities, FERC Stats. & Regs. 
para.30,524 at 30,800 (1983).
    \206\ In Pennsylvania-New Jersey-Maryland Interconnection, et 
al., 81 FERC para.________ (1997), issued concurrently with this 
order on rehearing, the Commission made an exception to its general 
approach to revenue credits and allowed monthly crediting of non-
firm transmission revenues. However, this was done in the context of 
a major restructuring of a tight power pool.
---------------------------------------------------------------------------

    Moreover, TDU Systems has not demonstrated that the lack of an 
automatic credit mechanism is likely to result in unjust and 
unreasonable rates. For example, the Commission's traditional means of 
accounting for transmission revenues from non-firm uses of the 
transmission system is to reflect a representative level of revenue 
credits (based on historical and/or projected revenue levels) in each 
rate case, which has the effect of lowering the transmission rate for 
all firm transmission users.\207\ TDU Systems has not shown why a 
similar rate case approach to revenue credits (as opposed to an 
automatic credit mechanism) is not appropriate, particularly for all 
transmission providers. In any event, we would anticipate little or no 
difference between the results of an automatic revenue credit mechanism 
and our traditional approach and TDU Systems has not shown otherwise.
---------------------------------------------------------------------------

    \207\ See, e.g., Pennsylvania Power Company, 26 FERC para.61,354 
at 61,781 (1984).
---------------------------------------------------------------------------

    Finally, TDU Systems' proposal is one-sided in that it would only 
require the automatic passthrough of revenues from the transmission 
provider's use of the transmission system for off-system sales. As the 
Commission stated in Order No. 888-A,

    revenue from the transmission component of all off-system uses 
of the transmission system (whether by the transmission provider or 
a transmission customer) must be treated on a comparable basis, 
whether through rate design or through revenue credits.\208\
---------------------------------------------------------------------------

    \208\ FERC Stats. & Regs. para.31,048 at 30,310 (emphasis 
added).
---------------------------------------------------------------------------

B. Stranded Cost Issues \209\

1. Municipal Annexation
    In  Order No. 888, the Commission decided that it would not be the 
primary forum for stranded cost recovery in situations in which an 
existing municipal utility annexes territory served by another utility 
or otherwise expands its service territory.\210\ In Order No. 888-A, 
the Commission reconsidered this decision and concluded that it would 
be the primary forum for stranded cost recovery in a discrete set of 
municipal annexation cases, namely, those involving existing municipal 
utilities that annex retail customer service territories and, through 
the availability of Commission-required transmission access, use the 
transmission system of the annexed customers' former supplier to access 
new suppliers to serve the annexed load.\211\
---------------------------------------------------------------------------

    \209\ Some of the rehearing requests raise issues that 
previously were raised on rehearing of Order No. 888 and were 
addressed by the Commission in Order No. 888-A. The Commission will 
not further address such issues in this proceeding. For example, 
Puget repeats some of the same arguments that it raised in its 
request for rehearing of Order No. 888 concerning the federal causes 
of stranded costs, the Commission's alleged abdication of its legal 
authority to ensure recovery of stranded costs associated with 
bypass and retail wheeling, the application of the reasonable 
expectation test to departing retail customers, and the Commission's 
failure to include deferred costs in the revenues lost formula. The 
Commission addressed these concerns in Order No. 888-A. See FERC 
Stats. & Regs. para.31,048 at 30,358-62, 30,424, 30,426-27. TDU 
Systems reiterates its objection to the Commission's elimination of 
the section 35.15 prior notice of termination requirement for power 
sales contracts executed after July 9, 1996 that terminate by their 
own terms. The Commission addressed TDU Systems' concerns in this 
regard in Order No. 888-A. See FERC Stats. & Regs. para.31,048 at 
30,392, 30,393-94.
    \210\ FERC Stats. & Regs. para.31,036 at 31,818.
    \211\ FERC Stats. & Regs. para.31,048 at 30,408-09.
---------------------------------------------------------------------------

    A number of petitioners seek rehearing or reconsideration \212\ of 
the Commission's decision in Order No. 888-A to be the primary forum 
for stranded cost recovery in the case of municipal annexations.\213\ 
Some oppose this decision for the same reasons that they opposed the 
Commission's decision to be the primary forum for stranded cost 
recovery in the case of new municipal utilities. For example, some 
entities argue that the Commission does not have any authority with 
respect to costs in retail rate base that may be stranded as a result 
of the annexation of electric service territory by a municipal 
utility.\214\ A number of petitioners also contend that municipal 
annexation occurs pursuant to state or local law, not federal law, and 
that every facet of municipal annexation, including compensation and 
valuation, is governed by state or local authorities.\215\
---------------------------------------------------------------------------

    \212\ As discussed above, APPA filed its request for rehearing 
out-of-time. Accordingly, we are treating APPA's pleading as a 
motion for reconsideration.
    \213\ See APPA, CAMU, IL Com, NARUC, TAPS. TDU Systems, on the 
other hand, argues that the Commission should permit non-public 
utilities providing reciprocal transmission service to recover 
stranded costs arising from municipal annexation. TDU Systems 
submits that allowing public utilities to seek stranded cost 
recovery arising from municipal annexation exacerbates the unequal 
and unduly discriminatory treatment accorded transmission dependent 
utilities and electric cooperatives.
    \214\ See APPA at 11-12; IL Com at 4-5; NARUC at 2-3.
    \215\ E.g., APPA at 12-13; NARUC at 3; TAPS at 24-25. APPA 
objects that federal regulation of stranded costs associated with 
municipal annexation results in the establishment of overlapping 
federal/state authority that precludes the execution of state laws 
by state authority in a matter normally within the power of the 
state, in violation of the Tenth Amendment. APPA at 13.
---------------------------------------------------------------------------

    Several submit that annexation is a form of franchise competition 
that predated Order No. 888, that transmission access was available 
(though not as readily as after Order No. 888) for many franchise 
competitors utilizing annexation, \216\ and that annexations have 
occurred and will continue to occur based upon motivations removed from 
the open access regime.\217\ CAMU states that

    \216\ APPA at 11; see also NARUC at 3.
    \217\ CAMU at 2.
---------------------------------------------------------------------------

    [a]nnexations have occurred and will continue to occur in a[n] 
unbroken string based upon motivations entirely removed from this 
Commission's open access regime. There is simply no reason to assume 
that the open access rule will accelerate the pace of annexations. 
[\218\]

    \218\ Id. 
---------------------------------------------------------------------------

    NARUC asks the Commission to grant rehearing as a matter of policy. 
It argues that the Commission's assertion of authority to address 
stranded cost issues related to annexation will force the Commission to 
inject itself into state-established processes to second-guess a state 
commission's cost recovery determinations. According to NARUC, this 
will require the Commission to resolve difficult factual issues to 
match specific generation and transmission facilities with specific 
annexed customers.\219\
---------------------------------------------------------------------------

    \219\ NARUC at 3-4.
---------------------------------------------------------------------------

    CAMU similarly contends that the Commission's assertion that it is 
the primary forum for the resolution of annexation-related stranded 
cost issues will introduce needless procedural complications. CAMU 
submits that various state-created mechanisms exist for the 
identification and payment of just compensation in the case of 
municipal annexations. It questions

[[Page 64710]]

how the Commission will offset against stranded cost recovery any 
compensation provided under state law and whether the Commission will 
await the completion of state proceedings before it addresses the 
issue. \220\ CAMU asks the Commission to defer to existing state 
mechanisms and to be the primary forum for the resolution of stranded 
cost recovery issues in annexation situations only where there is no 
state procedure for stranded cost recovery.
---------------------------------------------------------------------------

    \220\ CAMU at 3-5. CAMU notes that some state compensation 
statutes require the annexing municipality to pay ``expectation'' 
damages for a defined future period based upon revenues received 
from the annexed area. CAMU says that this element of damage, which 
is applied in addition to payment for condemned facilities, is meant 
to liquidate claims for lost service territory, idled generation 
assets and other business opportunities, but the awards do not 
separately value each of these elements of damage. CAMU questions 
how the Commission is going to ascertain what element of recovery 
pertains specifically to stranded costs if a state has adopted this 
liquidated damages approach. Id. at 5.
---------------------------------------------------------------------------

    IL Com argues that determining whether the availability of 
wholesale open access is the principal cause of the stranding of public 
utility costs would be administratively difficult. \221\ IL Com also 
submits that the Commission's expectation that parties raise retail-
turned-wholesale stranded cost claims before this Commission in the 
first instance is internally inconsistent with, and contradictory to, 
its statements that it will give great weight in its proceedings to a 
state's view of what might be recoverable and will deduct any recovery 
a state has permitted from departing retail-turned-wholesale customers 
from the costs for which the utility will be allowed to seek recovery 
under the Rule. \222\
---------------------------------------------------------------------------

    \221\ IL Com at 5.
    \222\ Id. at 5-6.
---------------------------------------------------------------------------

    Commission Conclusion. After careful consideration of the arguments 
raised on rehearing, we have decided not to grant rehearing, but we do 
provide further clarification of our decision in Order No. 888-A to be 
the primary forum for stranded cost recovery in certain cases involving 
municipal annexation. As a policy matter, we will consider recovery of 
stranded costs that potentially could arise as a result of municipal 
annexation but only when there is a sufficient nexus in such cases to 
the Commission's Open Access Rule. To clarify, this determination to be 
the primary forum is not a blanket determination for all cases 
involving annexation. A determination of what circumstances make 
Commission review appropriate will be made on the facts pertinent to 
individual cases. The Commission has limited the opportunity to seek 
stranded cost recovery under the Rule to situations in which the 
availability and use of wholesale open access transmission enable a 
generation customer to escape a current power supplier to obtain 
cheaper power supplies. Annexations occur for a myriad of reasons that 
may have nothing to do with seeking less expensive power supplies (for 
example, tax or zoning considerations or consolidation of local public 
services). These reasons existed before adoption of Order No. 888 and, 
absent the nexus to the new availability of these transmission 
services, would not require us to consider the stranded costs from 
annexation in the first instance. On the other hand, an existing 
municipal utility that has newly-annexed territory may use an open 
access tariff of the annexed customers' former power supplier. 
Accordingly, the Commission does not believe it is necessary to reverse 
its previous position that annexations may raise jurisdictional 
stranded cost issues but instead provides this clarification.
    In the course of reviewing the rehearing petitions on annexation, 
the Commission has also had the opportunity to reflect on the rationale 
for our decision to be the primary forum for addressing the recovery of 
stranded costs associated with retail-turned-wholesale customers 
(including a newly-formed municipal utility). We wish to further 
elaborate upon and clarify our prior discussions about recovery of 
costs stranded by retail-turned-wholesale customers. \223\
---------------------------------------------------------------------------

    \223\ In so doing, we also reiterate our concern (expressed in 
Order Nos. 888 and 888-A) that there may be circumstances in which 
customers and/or utilities could attempt, through indirect use of 
open access transmission, to circumvent the ability of any 
regulatory commission--either this Commission or state commissions--
to address recovery of stranded costs. In Order Nos. 888 and 888-A, 
we reserved the right to address such situations on a case-by-case 
basis. Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,819; 
Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 30,409.
---------------------------------------------------------------------------

    First, in setting forth our position on costs stranded in certain 
retail-turned-wholesale and municipal annexation situations, the 
Commission recognized that states may also have jurisdiction over 
retail-turned-wholesale stranded costs and that state adjudications of 
such costs may precede consideration of them here. \224\ Moreover, we 
indicated that ``we are not second-guessing the states as to what a 
utility may recover under state law.'' \225\ As we stated in Order No. 
888-A and reiterate here,

    \224\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,819; 
Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 30,405.
    \225\ Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 
30,405.
---------------------------------------------------------------------------

    Our decision to be the primary forum for recovery of stranded 
costs from retail-turned-wholesale customers is not intended to 
prevent or to interfere with the authority of a state to permit any 
recovery from departing retail customers, such as by imposing an 
exit fee prior to creating the wholesale entity.\226\
---------------------------------------------------------------------------

    \226\ Id. at 30,410.
---------------------------------------------------------------------------

In making this statement, the Commission clearly recognized that it may 
indeed be the states that first address the difficult stranded cost 
issues associated with the formation of new municipal utilities or 
other wholesale entities. The Commission contemplated then, as now, 
that it would nevertheless adjudicate these stranded cost issues where 
states lack authority to do so or where, based on the record before us, 
they fail to provide a forum.\227\
---------------------------------------------------------------------------

    \227\ See City of Las Cruces, New Mexico, 80 FERC para. 61,160 
(1997).
---------------------------------------------------------------------------

    Second, as the Commission stated in Order No. 888-A,

    if the state has permitted any recovery from departing retail-
turned-wholesale customers [for example, if it imposed an exit fee 
prior to, or as a condition of, creating the wholesale entity], such 
amount will not be stranded for purposes of this Rule. We will 
deduct that amount from the costs for which the utility will be 
allowed to seek recovery under this Rule from the Commission.\228\

    \228\ Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 
30,405. See also Order No. 888, FERC Stats. & Regs. para. 31,036 at 
31,819.
---------------------------------------------------------------------------

Further, we will take into account state findings on cost 
determinations associated with retail-turned-wholesale situations and 
``we will give great weight in our proceedings to a state's view of 
what might be recoverable.'' \229\ We believe it is important to 
emphasize that in those instances where states do address stranded 
costs associated with retail-turned-wholesale customers and in cases of 
municipal annexation, we intend to give substantial deference to their 
determinations.
---------------------------------------------------------------------------

    \229\ Order No. 888-A, FERC Stats. & Regs. para. 31,048 at 
30,405.
---------------------------------------------------------------------------

2. Pre-existing Transmission Rights
    TAPS requests clarification that the required nexus between the 
availability and use of Commission-required transmission access and the 
stranding of costs would not be met ``if the municipal utility, 
including as expanded through annexation, possessed rights to 
transmission prior to Order No. 888 and EPAct (for example, NRC license 
conditions and the like).'' \230\ TAPS submits that ``[t]he utility 
exercising these transmission rights should not be subject to stranded 
costs claims before the Commission simply because the municipal utility 
chooses to use the Commission's preferred open access tariff, instead 
of a

[[Page 64711]]

bilateral or other arrangement available under pre-existing rights.'' 
\231\
---------------------------------------------------------------------------

    \230\ TAPS at 27.
    \231\ Id.
---------------------------------------------------------------------------

    Commission Conclusion. We will deny TAPS' requested clarification. 
The existence of rights to transmission prior to Order No. 888 would 
not, in and of itself, indicate that the customer should be relieved of 
potential stranded cost liability under Order Nos. 888 and 888-A.\232\ 
It may be that a customer with some right to transmission service prior 
to Order No. 888 (for example, as a consequence of NRC license 
conditions), was unable to reach an alternative supplier through the 
use of that transmission. Thus, notwithstanding the existence of pre-
existing transmission rights, and depending on the facts of a 
particular case, it may be that the utility incurred costs based on a 
reasonable expectation of continuing to serve the customer.
---------------------------------------------------------------------------

    \232\ As we explained in Order No. 888-A, we declined to include 
``exercise of pre-existing contract rights for transmission and 
designation of wholesale loads'' as an example of a situation for 
which stranded costs may not be sought because we are not prepared 
to make individual factual determinations in the context of the 
Rule. The Commission will address specific requests for stranded 
cost recovery on the facts presented and the merits of the 
particular request. FERC Stats. & Regs. para. 31,048 at 30,358.
---------------------------------------------------------------------------

    On this basis, the Commission will not conclusively presume that a 
customer with a pre-existing right to transmission service could never 
be subject to a stranded cost obligation under Order Nos. 888 and 888-
A. Similarly, the Commission will not conclusively presume that the 
mere existence of a pre-existing right to transmission service 
precludes any reasonable expectation of continued service by the 
utility. However, the existence of pre-existing transmission rights, 
and any circumstances surrounding them, may be used as evidence in the 
determination of whether the utility had a reasonable expectation of 
continuing to serve a customer. \233\
---------------------------------------------------------------------------

    \233\ See Duquesne Light Company, 79 FERC para. 61,116 at 61,520 
(1997).
---------------------------------------------------------------------------

3. Load Growth and Excess Capacity
    Boston Edison seeks rehearing of the Commission's finding in Order 
No. 888-A that a ``cost is not stranded if it is fully recovered in the 
cost-based rates paid by native load.'' \234\ It submits that this 
phrase
---------------------------------------------------------------------------

    \234\ FERC Stats. & Regs. para.31,048 at 30,440.

    Suggests that the cost of capacity released by a departing 
wholesale customer can and should be recovered in the rates of the 
remaining retail and wholesale customers if the remaining customers' 
load or load growth will be sufficient to absorb the released 
capacity. . . . Such cost shifting directly contradicts the cost 
responsibility principles set forth in Order No. 888 [i.e., direct 
assignment].\235\
---------------------------------------------------------------------------

    \235\ Boston Edison at 3.

Boston Edison objects that the rationale for this policy reversal is 
not articulated in Order No. 888-A.
    Commission Conclusion. At the outset, we reiterate that we remain 
committed to the cost responsibility principles established in Order 
No. 888 and continue to believe that a departing wholesale customer 
should be responsible for the costs it strands. Our statement that a 
``cost is not stranded if it is fully recovered in the cost-based rates 
paid by native load'' was not meant to imply that the cost of capacity 
released by a departing wholesale customer should always be recovered 
in the rates of the remaining retail and wholesale customers through 
load growth. Rather, our discussion of load growth correctly recognizes 
that in some instances a utility can meet native load growth with 
existing capacity freed-up by the departure of wholesale load. If a 
utility can recover the costs of existing capacity freed up by a 
departing customer from another customer or group of customers, the 
expected revenues should be reflected in the CMVE component of the 
formula.\236\ Moreover, our requirement that a utility reflect in the 
CMVE component of the formula the revenues it expects to receive from 
the sale of the released capacity does not automatically result in 
remaining customers being forced to subsidize a departing customer's 
stranded cost obligation as Boston Edison posits. Rather, the rate 
treatment of the released capacity needed to meet the load growth of 
native load customers is an open issue that is properly addressed in 
future rate proceedings.
---------------------------------------------------------------------------

    \236\ See City of Alma, Michigan, 80 FERC para.61,265 at 61,961 
(1997).
---------------------------------------------------------------------------

    In short, the revenues lost approach already takes account of the 
marketability of the released capacity and appropriately incorporates 
load growth associated with remaining retail and wholesale customers 
and does not contradict the cost responsibility principle set forth in 
Order Nos. 888 and 888-A.
4. G&T and Distribution Cooperatives
    RUS seeks rehearing and clarification of the Commission's 
determination in Order No. 888-A that, unless stranded costs arise as a 
result of a section 211 order to a G&T cooperative, G&T cooperatives 
may not seek (through the Commission) recovery of stranded costs from 
the customers of their distribution members. RUS argues that the 
customers of a G&T cooperative's distribution members, as well as the 
distribution members themselves, meet the Commission's pro forma tariff 
definition of ``native load customer'' with respect to the G&T. It says 
that, ``as native load customers, both distribution members and their 
customers should be responsible to a G&T for stranded costs arising 
from their use of Commission-required transmission access, or from 
state mandated retail wheeling.'' \237\
---------------------------------------------------------------------------

    \237\ RUS at 16.
---------------------------------------------------------------------------

    RUS also questions the Commission's assertion that ``'to treat a 
G&T cooperative and its member distribution systems as a single 
economic unit for stranded cost purposes would be inconsistent with the 
Commission's decision not to treat cooperatives as a single unit for 
the purposes of Order No. 888's reciprocity provision.'' \238\ RUS 
asserts that different treatment for different purposes is justified 
because the relevant issues with respect to the application of the 
reciprocity requirement on a system-wide basis and the ability to 
recover stranded costs on a system-wide basis are different. RUS 
submits that the Commission confuses corporate affiliation with 
economic integration, and that lack of corporate affiliation does not 
preclude economic integration. RUS says that although G&T cooperatives 
and their distribution members are operationally separate, G&T 
cooperatives and their distribution members function in many ways like 
a single economic unit. According to RUS, G&Ts undertake an obligation 
to construct and operate their systems to meet the reliable electric 
needs of their distribution members and customers of their distribution 
members, and G&T cooperatives and their members are bound together by 
long-term requirements contracts.
---------------------------------------------------------------------------

    \238\ Id. (citing Order No. 888-A, FERC Stats. & Regs. 
para.31,048 at 30,366).
---------------------------------------------------------------------------

    RUS states that, as single economic units, G&T cooperatives or 
distribution members both should be able to seek recovery of stranded 
costs from the customers of distribution members. RUS contends that 
``the Commission's reliance on distribution members to seek to recover 
stranded costs `through contracts with [their] customers or through the 
appropriate regulatory authority' is misplaced'' because 
``[d]istribution members--many of which are not subject to state 
commission jurisdiction--may have neither an appropriate regulatory 
forum through which to seek stranded cost recovery, nor the ability to 
seek to recover stranded costs incurred by their

[[Page 64712]]

G&T cooperatives to serve native load customers.'' \239\
---------------------------------------------------------------------------

    \239\ Id. at 17.
---------------------------------------------------------------------------

    Finally, RUS argues that failing to permit G&T cooperatives to seek 
recovery of stranded costs arising from the loss of native load 
customers due to Commission-required transmission access or the lack of 
state commission authority to permit stranded cost recovery will result 
in unduly discriminatory treatment of cooperatives. Where G&T costs are 
stranded by the ability of customers of distribution members to switch 
suppliers through Commission-required transmission access, RUS submits 
that there is a direct nexus between Commission-required access and the 
stranding of costs. In the case of retail stranded costs, RUS says that 
many state regulatory authorities do not have the authority under state 
law to regulate distribution or G&T cooperatives, thereby creating a 
regulatory gap. RUS states that

    [f]ailure to allow a G&T the opportunity to recover stranded 
costs caused by [the] departure of any of its native load customers, 
including both distribution members and the customers of the 
distribution members, will drastically reduce the G&T's ability to 
cover its costs, including payments on RUS-financed debt, thereby 
endangering the existence of the G&T itself and exposing Federal 
taxpayers to the risk of massive loan defaults.\240\

    \240\ Id. at 19.
---------------------------------------------------------------------------

    Commission Conclusion. We will deny RUS' rehearing request. To 
grant the request would require the Commission to reach beyond its 
regulatory authority (and allow entities not subject to our sections 
205 and 206 jurisdiction an opportunity to recover stranded costs) and 
would broaden the scope of the Order Nos. 888 and 888-A stranded cost 
recovery mechanism.\241\ Indeed, RUS' rehearing request appears to be 
based on a misunderstanding of the limited scope of the stranded cost 
recovery mechanism contained in Order Nos. 888 and 888-A.
---------------------------------------------------------------------------

    \241\ RUS expresses concern in its rehearing request that 
distribution members ``may have neither an appropriate regulatory 
forum through which to seek stranded cost recovery, nor the ability 
to seek to recover stranded costs incurred by their G&T cooperatives 
to serve native load customers.'' RUS at 17. However, presumably 
when a retail customer of a distribution cooperative switches 
suppliers, the retail customer would still have to use the 
distribution lines of the distribution cooperative to receive its 
power. RUS has not explained why the distribution cooperative cannot 
assess a charge to recover stranded costs when the retail customer 
uses those lines.
---------------------------------------------------------------------------

    The stranded cost recovery provisions in Order Nos. 888 and 888-A 
apply, in the case of wholesale stranded costs, to public utilities 
\242\ and transmitting utilities.\243\ In the case of stranded costs 
associated with retail wheeling customers, the provisions of the Rule 
apply only to public utilities.\244\
---------------------------------------------------------------------------

    \242\ A ``public utility'' is defined under section 201(e) of 
the FPA as ``any person who owns or operates facilities subject to 
the jurisdiction of the Commission under this Part (other than 
facilities subject to such jurisdiction solely by reason of sections 
210, 211, or 212).'' 16 U.S.C. 824(e).
    \243\ A ``transmitting utility'' is defined under section 3(23) 
of the FPA as ``any electric utility, qualifying cogeneration 
facility, qualifying small power production facility, or Federal 
power marketing agency which owns or operates electric power 
transmission facilities which are used for the sale of electric 
energy at wholesale.'' 16 U.S.C. 796(23).
    \244\ As we explained in Order No. 888-A, our decision to 
entertain (in certain limited circumstances) requests to recover 
stranded costs associated with retail wheeling customers applies to 
public utilities only because it is based on our jurisdiction under 
sections 205 and 206 of the FPA over the rates, terms, and 
conditions of retail transmission in interstate commerce. FERC 
Stats. & Regs. para. 31,048 at 30,419. Since RUS-financed 
cooperatives are not public utilities subject to our jurisdiction 
under sections 205 and 206 of the FPA, we do not have authority to 
allow them to seek recovery under Order Nos. 888 and 888-A of 
stranded costs associated with retail wheeling customers.
---------------------------------------------------------------------------

The Commission has limited the opportunity for public utilities and 
transmitting utilities to seek stranded cost recovery under Order Nos. 
888 and 888-A primarily to two discrete situations: (1) costs 
associated with customers under wholesale requirements contracts 
executed on or before July 11, 1994 (referred to as ``existing 
wholesale requirements contracts'') that do not contain an exit fee or 
other explicit stranded cost provision; and (2) costs associated with 
retail-turned-wholesale customers (including bundled retail customers 
of a utility that become bundled retail customers of a new municipal 
utility).\245\
---------------------------------------------------------------------------

    \245\ Whether a G&T cooperative's member distribution 
cooperatives and the customers of the distribution cooperatives meet 
the definition of ``native load customer'' under the open access 
tariff (as RUS submits they do) is not relevant for purposes of the 
stranded cost recovery mechanism set forth in Order Nos. 888 and 
888-A.
---------------------------------------------------------------------------

    As the Commission explained in Order No. 888-A, if a cooperative 
obtains its financing through RUS, it is not a public utility subject 
to our jurisdiction under sections 205 and 206 of the FPA. Although we 
have no objection to these G&T cooperatives being able to seek cost 
recovery (including recovery of costs on behalf of their distribution 
cooperatives) through the appropriate regulatory or contractual 
channels, this Commission does not have authority to allow them to seek 
recovery of stranded costs unless they do so in conjunction with 
transmission access that they are required to provide through a section 
211 order. In the latter case, a G&T cooperative that is a transmitting 
utility could seek recovery of stranded costs if it is ordered to 
provide transmission services that permit its distribution cooperative 
to reach another supplier and if it had a requirements contract with 
the distribution cooperative that was executed on or before July 11, 
1994 that did not contain an exit fee or other explicit stranded cost 
provision.\246\
---------------------------------------------------------------------------

    \246\ FERC Stats. & Regs. para.31,048 at 30,366.
---------------------------------------------------------------------------

    As we also explained in Order No. 888-A, a G&T cooperative that is 
a public utility (a non-RUS financed cooperative) would have to have a 
jurisdictional wholesale requirements contract with its distribution 
cooperative in order to be able to seek recovery of stranded costs 
under Order No. 888's stranded cost recovery provisions. We said that, 
in the case of a jurisdictional G&T cooperative, the request that the 
G&T be treated as a single economic unit with the distribution 
cooperative (such that departure of a distribution cooperative's retail 
customer would be treated as resulting in stranded costs for the G&T 
cooperative for which the G&T could seek recovery) is, in effect, a 
request for recovery of stranded costs from an indirect customer. In 
Order No. 888-A, we explained why the Commission does not believe it is 
appropriate or feasible to allow a public utility (or a transmitting 
utility under section 211 of the FPA) to seek recovery of stranded 
costs from an indirect customer (i.e., a customer of a wholesale 
requirements customer of the utility) under the Rule. We indicated that 
``[t]he reasonable expectation analysis would apply only to the direct 
wholesale customer of the utility, not to the indirect customer. It is 
up to the direct wholesale customer of the utility, through its 
contracts with its customers or through the appropriate regulatory 
authority, to seek to recover such costs from its customers.'' \247\ We 
explained that commenters had provided no basis for making an exception 
in the case of cooperatives. Further, we said that ``to treat a G&T 
cooperative and its member distribution cooperatives as a single 
economic unit for stranded cost purposes would be inconsistent with the 
Commission's decision not to treat cooperatives as a single unit for 
purposes of Order No. 888's reciprocity provision.'' \248\
---------------------------------------------------------------------------

    \247\ Id.
    \248\ Id. We continue to believe that it would be inconsistent 
to treat G&T cooperatives and their member distribution cooperatives 
differently for purposes of the reciprocity condition and stranded 
cost recovery, notwithstanding RUS' argument to the contrary.

---------------------------------------------------------------------------

[[Page 64713]]

    Although RUS refers in its rehearing request to a scenario in which 
costs may be stranded by the ability of customers of a distribution 
cooperative to switch suppliers through the use of Commission-required 
transmission access, the scenario RUS posits is not one for which Order 
Nos. 888 and 888-A would permit an opportunity for recovery. Because 
the Commission cannot order retail wheeling, the principal way in which 
the retail customers of a distribution cooperative could use 
Commission-required transmission access (and trigger stranded costs on 
the part of the distribution cooperative) would appear to be through 
municipalization (i.e., through the creation of a new wholesale entity 
to obtain power supplies on their behalf in lieu of obtaining power 
from the distribution cooperative). In such a scenario, however, since 
the distribution cooperative (if RUS-financed) would not be a 
Commission-jurisdictional public utility or transmitting utility, it 
would not be allowed to seek stranded cost recovery under Order Nos. 
888 and 888-A.
5. Treatment of Contracts Extended or Renegotiated Without a Stranded 
Cost Provision
    In Order No. 888-A, the Commission clarified that it will consider 
on a case-by-case basis whether to waive the provisions of 18 CFR 35.26 
(which define a ``new wholesale requirements contract'' as ``any 
wholesale requirements contract executed after July 11, 1994, or 
extended or renegotiated to be effective after July 11, 1994'' 
(emphasis added)) and treat a contract extended or renegotiated 
(without adding a stranded cost provision) to be effective after July 
11, 1994, but before March 29, 1995, as an existing contract for 
stranded cost purposes.\249\
---------------------------------------------------------------------------

    \249\ FERC Stats. & Regs. para. 31,048 at 30,396.
---------------------------------------------------------------------------

    Port of Seattle opposes the Commission's decision in this regard. 
It argues that the Commission in Order No. 888-A sided with Puget on an 
issue that is being litigated between Port of Seattle and Puget in a 
separate proceeding (Docket No. ER96-714), and that the Commission 
improperly prejudiced Port of Seattle by not addressing the concerns 
expressed by Port of Seattle in the underlying case.\250\ It submits 
that Order No. 888-A was not the forum in which it expected the final 
decision in Docket No. ER96-714 to be made, and that its procedural 
rights have been violated. Port of Seattle asks the Commission on 
rehearing to withdraw any determination, reference or statement in 
Order No. 888-A that addresses the issues pending in Docket No. ER96-
714.
---------------------------------------------------------------------------

    \250\ Port of Seattle at 7. Port of Seattle also contends that 
the Commission mischaracterized Port of Seattle's position when it 
referred to Puget's statement that the parties were working within 
the context of the stranded cost NOPR, which provided that the 
utility had three years from the date of the publication of the 
final rules to negotiate or file for stranded cost recovery. Port of 
Seattle says its assumption and position was that Puget made the 
business decision not to include a stranded cost or exit fee 
provision in its letter agreement, thus preventing its recovery of 
any stranded costs. Id. at 8.
---------------------------------------------------------------------------

    Port of Seattle further argues that the Commission improperly 
granted Puget an exclusive waiver of (or private exception to) the 
Rule's definition of ``new'' contracts.
    Commission Conclusion. We will deny Port of Seattle's request for 
rehearing. Port of Seattle misconstrues the scope of the Commission's 
decision and its effect on the pending proceeding in Docket No. ER96-
714-001. The Commission's decision in Order No. 888-A to consider on a 
case-by-case basis whether to waive the provisions of 18 CFR 35.26 and 
treat a contract extended or renegotiated to be effective after July 
11, 1994, but before March 29, 1995, as an existing contract for 
stranded cost purposes does not constitute a ruling on the merits in 
the pending proceeding in Docket No. ER96-714-001. In Order No. 888-A, 
the Commission has gone no further than to state that the matter should 
be considered on a case-by-case basis, and to acknowledge that the 
issue, as between Puget and Port of Seattle, is pending in Docket No. 
ER96-714-001.\251\ Contrary to Port of Seattle's claim, Order No. 888-A 
does not grant Puget a waiver of the Rule's definition of ``new 
wholesale requirements contract.''
---------------------------------------------------------------------------

    \251\ We note that a certification of an uncontested offer of 
settlement in that proceeding is pending before the Commission.
---------------------------------------------------------------------------

6. Customer Expectations of Continued Service at Below-Market Rates
    TDU Systems seeks rehearing of the Commission's decision not to 
adopt a generic mechanism to allow existing requirements customers with 
below-market rates a means to continue to receive power beyond the 
contract term at the pre-existing contract rate if the customer had a 
reasonable expectation of continued service. TDU Systems states that 
the Commission's decision rests on the conclusion that, even if 
customers generally expected to stay on a supplier's system beyond the 
contract term, it is not likely that most customers could have expected 
to continue service at the existing rate. TDU Systems maintains that 
this finding rests on a false distinction between the rate the 
wholesale requirements customer reasonably could have expected to pay 
and the rate the wholesale requirements seller reasonably could have 
expected to collect. It says that neither stranded costs nor ``stranded 
benefits'' \252\ arise from a right to, or expectation of, a 
grandfathered rate. TDU Systems contends that ``stranded benefits'' 
arise because, prior to open access transmission, wholesale 
requirements customers had a reasonable expectation of continuing to 
receive wholesale service at just and reasonable cost-based rates. It 
argues that when open access transmission allows the supplier to charge 
a higher market-based rate instead, the customer's expectation of 
continued cost-based service is destroyed, and the customer may lose 
the benefits it had under the prior regulatory regime.
---------------------------------------------------------------------------

    \252\ TDU Systems uses the term ``stranded benefits'' to refer 
to the benefits to a wholesale requirements customer that may be 
lost if ``open access transmission forces [the customer] to buy 
power at market-based rates'' instead of at cost-based rates. TDU 
Systems at 25.
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    TDU Systems submits that while Order No. 888-A suggests that 
customers could not reasonably expect to continue paying their existing 
rate, the revenues lost approach to quantifying stranded costs assumes 
that sellers reasonably expected to continue collecting a cost-based 
rate equal to the existing rate. TDU Systems says that the Commission's 
best estimate of the seller's lost revenue from a wholesale 
requirements contract is based on the seller's existing, cost-based, 
just and reasonable rate--the same existing cost-based rate that the 
Commission in Order No. 888-A finds the captive requirements customer 
had no reasonable expectation of continuing to pay. TDU Systems says 
these findings directly contradict one another.\253\
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    \253\ Id. at 27-28.
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    TDU further challenges the Commission's statement that ``it is not 
clear'' that the customer could show it reasonably expected continued 
service ``at the existing contract rate (which may be below the market 
price)'' because the utility might have filed changed rates during the 
contract term or sought new rates at the end of the contract term. TDU 
Systems submits that before open access, established Commission policy 
would only have allowed the monopoly utility to charge its captive 
wholesale requirements

[[Page 64714]]

customer a cost-based rate, whether that rate was above or below market 
price.\254\
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    \254\ Id. at 28-29
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    TDU Systems asks the Commission to adopt a generic mechanism to 
allow customers to demonstrate and recover their stranded benefits, 
just as it has done for the recovery of utility stranded costs. If the 
Commission is unwilling to promulgate such a generic rule, TDU Systems 
asks that the Commission clarify the standard that a customer must meet 
in seeking relief under section 206. It says that although Order No. 
888-A states that a customer may file a petition under section 206 ``to 
show that the contract should be extended at the existing contract 
rate,'' the issue is not whether to extend a contract at the existing 
rate, but whether to continue requirements service at a cost-based 
rate. It asks the Commission to correct its description in Order No. 
888-A of the standard the customer must meet in a case-by-case 
proceeding and the relief the Commission would provide.
    Commission Conclusion. As discussed below, we will deny TDU 
Systems' request for rehearing on this issue, but will grant, in part, 
its request for clarification.
    In Order No. 888-A, the Commission rejected TDU Systems' request 
that the Commission provide a generic mechanism to allow existing 
requirements customers a means to continue to receive power beyond the 
contract term at the pre-existing contract rate if the customer had a 
reasonable expectation of continued service. The Commission noted that 
TDU Systems had requested that the customer be given the choice of 
extending its existing contract at existing rates for a period 
corresponding to the customer's expectation of continued service or 
receiving a ``stranded benefits'' payment from the utility consisting 
of the difference between what the customer must pay for new supplies 
and what it paid under the contract.\255\ We concluded that we did not 
have a sufficient basis on which to make generic findings or provide a 
generic formula for addressing this issue:

    \255\ FERC Stats. & Regs. para.31,048 at 30,391.
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    Utilities' expectations may have resulted in millions of dollars 
of investments on behalf of certain customers and the possibility of 
shifting the costs of those investments to other customers that did 
not cause the costs to be incurred. In the case of customers' 
expectations, however, even if customers generally expected to stay 
on a supplier's system beyond the contract term, it is not likely 
that most customers could have expected to continue service at the 
existing rate unless specified in the contract. Moreover, the 
consequences of customers' expectations as a general matter would 
not have the potential to shift significant costs to other 
customers.\256\

    \256\ Id. at 30,393 (emphasis in original),

    At the same time, however, we indicated that a customer under a 
contract may exercise its procedural rights under section 206 of the 
FPA to show that the contract should be extended at the existing 
contract rate. We noted that the customer also may make such a showing 
in the context of a utility's proposed termination of a contract 
pursuant to the Sec. 35.15 notice of termination (approval) 
requirement, which the Commission has retained for power supply 
contracts executed prior to July 9, 1996 (the effective date of Order 
No. 888).
    TDU Systems has not persuaded us that our decision to address this 
issue on a case-by-case, not a generic, basis is in error. 
Notwithstanding TDU Systems' arguments, we continue to believe that the 
extent to which a customer could demonstrate a reasonable expectation 
of continued service at the existing contract rate (or at a cost-based 
rate, if that was the customer's expectation) is best addressed on a 
case-by-case basis. As we explained in Order No. 888-A, we do not 
intend to prejudge whether a requirements customer could ever make such 
a showing, nor do we intend to preclude a customer from attempting to 
make such a showing in appropriate circumstances.
    In response to TDU Systems' request that the Commission clarify the 
standard that a requirements customer must meet in seeking relief under 
section 206, we clarify that a customer may exercise its procedural 
rights under section 206 to show either that the contract should be 
extended at the existing contract rate or, as TDU Systems suggests, 
that the contract should be extended at a cost-based rate. However, the 
relief that the Commission would provide in such a case is a matter 
that is more appropriately determined on a case-by-case basis based on 
the particular facts and circumstances.
7. Miscellaneous
    IL Com seeks rehearing of the following sentence in Order No. 888-
A: ``It was not unreasonable for the utility to plan to continue 
serving the needs of its wholesale requirements customers and retail 
customers, and for those customers to expect the utility to plan to 
meet their needs.'' \257\ IL Com objects that this sentence prejudges 
the reasonable expectation issue.\258\ It asks that the Commission 
withdraw the quoted sentence in full or, at a minimum, withdraw the 
reference to retail customers in the quoted sentence.
---------------------------------------------------------------------------

    \257\ Id. at 30,351 (emphasis added by IL Com).
    \258\ IL Com at 9-10.
---------------------------------------------------------------------------

    IL Com also seeks clarification of the Commission's statement in 
Order No. 888-A that ``[i]f a former wholesale requirements customer or 
a former retail customer uses the new open access to reach a new 
supplier, the utility is entitled to seek recovery of legitimate, 
prudent and verifiable costs that it incurred under the prior 
regulatory regime to serve that customer.'' \259\ IL Com asks the 
Commission to withdraw the words ``or a former retail customer'' from 
this sentence and to clarify that it is not prejudging utilities' 
entitlement to retail stranded cost recovery and is not imposing a 
``legitimate, prudent and verifiable'' standard for the recovery of 
retail stranded costs.\260\
---------------------------------------------------------------------------

    \259\ FERC Stats. & Regs. para.31,048 at 30,351 (emphasis added 
by IL Com).
    \260\ IL Com. at 10-11.
---------------------------------------------------------------------------

    Commission Conclusion. The Commission statements that are the 
subject of IL Com's request for rehearing initially appeared in Order 
No. 888 \261\ and were repeated in Order No. 888-A's summarization of 
Order No. 888. IL Com's request for rehearing with respect to these 
statements should have been raised on rehearing of Order No. 888 and 
therefore was not timely filed. However, we clarify that while we will 
not withdraw our statements, the statements are not intended to 
prejudge the reasonable expectation issue as it might apply to any 
state proceedings on retail stranded costs.
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    \261\ See FERC Stats. & Regs. para.31,036 at 31,789.
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V. Environmental Statement

    In Order No. 888-A, the Commission denied requests for rehearing on 
eight categories of issues relating to the Commission's analysis of 
environmental issues. No rehearing requests were filed concerning Order 
No. 888-A's analysis of environmental issues.

VI. Regulatory Flexibility Act Certification

    The Regulatory Flexibility Act \262\ requires rulemakings to either 
contain a description and analysis of the effect that the proposed or 
final rule will have on small entities or to contain a certification 
that the rule will not have a significant economic impact on a 
substantial number of small entities. In Order No. 888, the Commission 
certified that the Open Access and Stranded Cost Final Rules would not 
impose a significant economic impact on a substantial number of small 
entities. In

[[Page 64715]]

Order No. 888-A, the Commission addressed requests for rehearing that 
questioned this certification and that the final rule would not impose 
a significant economic impact on a substantial number of small 
entities. No rehearing requests of Order No. 888-A were filed on this 
issue and the Commission finds no reason to alter its previous findings 
on this issue.
---------------------------------------------------------------------------

    \262\ 5 U.S.C. 601-612.
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VII. Information Collection Statement

    Order No. 888 contained an information collection statement for 
which the Commission obtained approval from the Office of Management 
and Budget (OMB). \263\ Given that this order on rehearing makes only 
minor revisions to Order Nos. 888 and 888-A, none of which is 
substantive, OMB approval for this order will not be necessary. 
However, the Commission will send a copy of this order to OMB, for 
informational purposes only.
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    \263\ The OMB control number for this collection of information 
is 1902-0096.
---------------------------------------------------------------------------

    The information reporting requirements under this order are 
virtually unchanged from those contained in Order Nos. 888 and 888-A. 
Interested persons may obtain information on the reporting requirements 
by contacting the Federal Energy Regulatory Commission, 888 First 
Street, N.E., Washington, D.C. 20426 [Attention: Michael Miller, 
Information Services Division, (202) 208-1415], and the Office of 
Management and Budget [Attention: Desk Officer for the Federal Energy 
Regulatory Commission, (202) 395-3087].

VIII. Effective Date

    The tariff change to Order Nos. 888 and 888-A made in this order on 
rehearing (see footnote 1) will become effective on February 9, 1998. 
The current requirements of Order Nos. 888 and 888-A will remain in 
effect until this order becomes effective.

    By the Commission.
Lois D. Cashell,
Secretary.

    Note: The following Appendices will not appear in the Code of 
Federal Regulations.

Appendix A--Order No. 888-B: List of Petitioners

1. American Public Power Association, Colorado Association of 
Municipal Utilities, Municipal Electric Systems of Oklahoma, and 
Utah Associated Municipal Power Systems (APPA) \1\
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    \1\ APPA filed its request for rehearing out-of-time on April 4, 
1997. As discussed in Order No. 888-B, the Commission is accepting 
this pleading as a motion for reconsideration.
---------------------------------------------------------------------------

2. Bonneville Power Administration (BPA)
3. Arizona Public Service Company (Arizona)
4. Boston Edison Company, Central Vermont Public Service 
Corporation, Florida Power Corporation, Montaup Electric Company, 
and Wisconsin Public Service Corporation (Boston Edison)
5. Coalition for a Competitive Electric Market (CCEM) \2\
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    \2\ CNG Energy Services Corp., Coastal Electric Services 
Company, Destec Power Services, Inc., Enron Power Marketing, Inc., 
Koch Energy Trading, Inc., NorAm Energy Services, Inc., and Vitol 
Gas & Electric Services, Inc.
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6. Central Maine Power Company (Central Maine)
7. Coalition for Economic Competition (Coalition for Economic 
Competition) \3\
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    \3\ General Public Utilities Corp., Illinois Power Co., Long 
Island Lighting Co., and New York State Electric & Gas Corp.
---------------------------------------------------------------------------

8. Colorado Association of Municipal Utilities (CAMU)
9. Dairyland Power Cooperative (Dairyland)
10. Edison Electric Institute (EEI) \4\
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    \4\ EEI filed its request for rehearing out-of-time on April 4, 
1997. As discussed in Order No.888-B, the Commission is accepting 
this pleading as a motion for reconsideration.
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11. Illinois Commerce Commission (IL Com)
12. Kansas City Power & Light Company (KCPL)
13. Metropolitan Edison Company (Met Ed)
14. National Association of Regulatory Utility Commissioners (NARUC)
15. National Rural Electric Cooperative Association (NRECA)
16. New England Power Pool Executive Committee (NEPOOL)
17. Public Service Commission of the State of New York (NY Com) \5\
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    \5\ Independent Power Producers of New York, Inc. (NY IPPs) 
filed an answer on April 11, 1997.
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18. Niagara Mohawk Power Corporation and PURPA Reform Group (NIMO) 
\6\
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    \6\ Granite State Hydropower Association filed an answer on 
April 21, 1997.
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19. Otter Tail Power Company (Otter Tail)
20. Puget Sound Energy, Inc. (Puget) \7\
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    \7\ Formerly Puget Sound Power & Light Company.
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21. Rural Utilities Service, USDA (RUS)
22. Port of Seattle (Port of Seattle)
23. Soyland Power Cooperative, Inc. (Soyland)
24. Transmission Access Policy Study Group and certain of its 
Members (TAPS) \8\
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    \8\ American Municipal Power-Ohio, Inc., Illinois Municipal 
Electric Agency, Indiana Municipal Power Agency, Littleton Electric 
Light Department, Massachusetts Municipal Wholesale Electric 
Company, Michigan Public Power Agency, Municipal Energy Agency of 
Mississippi, Municipal Energy Agency of Nebraska, New Hampshire 
Electric Cooperative, Inc., Northern California Power Agency, 
Virginia Municipal Electric Association No. 1, on behalf of itself 
and its members (City of Franklin, City of Manassas, Harrisonburg 
Electric Commission, Town of Blackstone, Town of Culpepper, Town of 
Elkton, and Town of Wakefield), and Wisconsin Public Power, Inc. The 
operating companies of the American Electric Power System (AEP) 
filed an answer on April 17, 1997.
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25. Transmission Dependent Utility Systems (TDU Systems) \9\
---------------------------------------------------------------------------

    \9\ Arkansas Electric Cooperative Corporation, Golden Spread 
Electric Cooperative, Inc., Holy Cross Electric Association, Kansas 
Electric Power Cooperative, Inc., Magic Valley Electric Cooperative, 
Inc., Mid-Tex Generation and Transmission Electric Cooperative, 
Inc., North Carolina Electric Membership Corporation, Oklahoma 
Municipal Power Authority, Old Dominion Electric Membership 
Corporation, and Seminole Electric Cooperative, Inc.
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(Name of Transmission Provider) Open Access Transmission Tariff 
Original Sheet No.

Revision to Pro Forma Open Access Transmission Tariff Pursuant to Order 
No. 888-B

Appendix B

    29.1  Condition Precedent for Receiving Service: Subject to the 
terms and conditions of Part III of the Tariff, the Transmission 
Provider will provide Network Integration Transmission Service to 
any Eligible Customer, provided that: (i) The Eligible Customer 
completes an Application for service as provided under Part III of 
the Tariff, (ii) the Eligible Customer and the Transmission Provider 
complete the technical arrangements set forth in Sections 29.3 and 
29.4, (iii) the Eligible Customer executes a Service Agreement 
pursuant to Attachment F for service under Part III of the Tariff or 
requests in writing that the Transmission Provider file a proposed 
unexecuted Service Agreement with the Commission, and (iv) the 
Eligible Customer executes a Network Operating Agreement with the 
Transmission Provider pursuant to Attachment G, or requests in 
writing that the Transmission Provider file a proposed unexecuted 
Network Operating Agreement.

[FR Doc. 97-31841 Filed 12-8-97; 8:45 am]
BILLING CODE 6717-01-P