[Federal Register: June 30, 2005 (Volume 70, Number 125)]
[Rules and Regulations]
[Page 37661-37669]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr30jn05-6]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM02-1-006; Order No. 2003-C]
Standardization of Generator Interconnection Agreements and
Procedures
Issued June 16, 2005.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Order on rehearing.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) affirms,
with certain clarifications, the fundamental determinations in Order
No. 2003-B.
EFFECTIVE DATE: July 18, 2005.
FOR FURTHER INFORMATION CONTACT:
Patrick Rooney (Technical Information), Office of Markets, Tariffs and
Rates, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-6205.
Roland Wentworth (Technical Information), Office of Markets, Tariffs
and Rates, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8262.
Michael G. Henry (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8532.
SUPPLEMENTARY INFORMATION:
Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell,
Joseph T. Kelliher, and Suedeen G. Kelly.
I. Introduction and Summary
1. In this order, we affirm, with certain clarifications, Order No.
2003-B,\1\ which, together with Order Nos. 2003 and 2003-A, governs
interconnection of large generators to the transmission grid. The pro
forma Large Generator Interconnection Procedures (LGIP) and Large
Generator Interconnection Agreement (LGIA) required in those orders
help prevent undue discrimination, preserve the reliability of the
nation's transmission system, and lower prices for customers by
allowing a variety of generation resources to compete in wholesale
electricity markets. At its core, the Commission's orders ensure that
all Generating Facilities that will make sales for resale of electric
energy in interstate commerce are offered Interconnection Service on
comparable terms. These orders benefit customers by establishing the
just and reasonable terms and conditions for interconnecting to the
transmission grid, while ensuring that reliability is protected.
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\1\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats.
& Regs. ] 31,146 (2003) (Order No. 2003), order on reh'g, Order No.
2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ] 31,160
(2004) (Order No. 2003-A), order on reh'g, Order No. 2003-B, 70 FR
265 (Jan. 4, 2005), FERC Stats. & Regs. ] 31,171 (2005) (Order No.
2003-B). See also Notice Clarifying Compliance Procedures, 106 FERC
] 61,009 (2004).
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2. This order on rehearing reaffirms or clarifies the Commission's
policies on the recovery of Network Upgrade costs and non-pricing
policies. For example, it reaffirms the 20-year reimbursement policy
for Network Upgrade costs and clarifies the Commission's policy
regarding credits for Network Upgrades as it applies to Affected System
Operators and jointly owned transmission facilities. The order also
clarifies the Commission's jurisdiction under the Federal Power Act \2\
to apply this Final Rule and further explains the Transmission
Provider's payment obligation for reactive power supplied by an
Interconnection Customer.
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\2\ 16 U.S.C. 791a-825r (2000).
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3. This order takes effect 30 days after issuance by the
Commission. As with the Order No. 2003 compliance process, the
Commission will deem the open access transmission tariff (OATT) of each
non-independent Transmission
[[Page 37662]]
Provider to be amended to adopt the clarifications to the pro forma
LGIP and LGIA contained herein 30 days after issuance of this order by
the Commission. And as with the Order No. 2003-B compliance process,
each non-independent Transmission Provider will be required to amend
its OATT to include the LGIP and LGIA clarifications contained herein
within 60 days after issuance of this order by the Commission. Also,
within 60 days after issuance of this order, each independent
Transmission Provider must submit revised tariff sheets incorporating
its clarifications to its OATT or an explanation under the independent
entity variation standard as to why it is not proposing to adopt each
clarification described in this order.
4. The Commission received 12 timely requests for rehearing or for
clarification of Order No. 2003-B.\3\ Under section 313(a) of the
Federal Power Act (FPA),\4\ requests for rehearing of a Commission
order were due within thirty days after issuance of Order No. 2003-A,
i.e., no later than January 19, 2005. The Commission also received one
answer from the North Carolina Electric Membership Corp. (NCEMC), which
the Commission treats as yet another request for rehearing. Because
this answer was submitted after the statutory 30-day rehearing
deadline, it is rejected. However, the Commission will treat this late-
filed request for rehearing as a request for reconsideration.
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\3\ Requests were filed by Calpine Corporation (Calpine), Edison
Electric Institute (EEI), Entergy Services, Inc. (Entergy), Georgia
Transmission Corp. (Georgia Transmission), MEAG Power, National
Rural Electric Cooperative Association (NRECA), Pacificorp, PSEG
Companies (PSEG), Public Service Company of New Mexico (PNM),
Reliant Resources, Inc. (Reliant), Southern California Edison
Company (SoCal Edison), and Southern Company Services, Inc.
(Southern Company).
\4\ 16 U.S.C. 8251(a) (2000).
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5. For a background discussion, please consult the prior orders in
this proceeding.\5\
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\5\ Order No. 2003 at P 5-17; Order No. 2003-B at P 5-11.
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II. Discussion
A. Pricing and Cost Recovery Provisions
1. Requirement for Full Reimbursement After 20 Years
6. In Order No. 2003, the Commission continued to require the
Transmission Provider and any Affected System Operator to reimburse the
Interconnection Customer for its upfront payments for Network Upgrades
by means of credits against the Interconnection Customer's transmission
bills. We stated that the Interconnection Customer, Transmission
Provider, and Affected System Operator were permitted to adopt any
alternative payment schedule that is mutually agreeable as long as all
such amounts are refunded, with interest, within five years of the
Commercial Operation Date of the Generating Facility. In Order No.
2003-A, we retained this general policy but removed the obligation to
make a balloon payment for any unrefunded amounts after five years. In
Order No. 2003-B, the Commission revised pro forma LGIA article 11.4.1
to state that, other credit and refund provisions of Order No. 2003-A
notwithstanding, full reimbursement by the Transmission Provider shall
not extend beyond 20 years from the Commercial Operation Date; \6\ in
other words, a balloon payment is required at 20 years.
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\6\ Order No. 2003-B at P 34-41.
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a. Rehearing Requests
7. Some petitioners argue that the Transmission Provider should not
be required to reimburse the Interconnection Customer in full after 20
years if the Interconnection Customer has not earned enough credits (by
taking delivery service) to reimburse it for the Network Upgrades.\7\
For example, Entergy states that this requirement is unfair to native
load customers, arbitrary, and inconsistent with the Commission's
previous policies. Entergy argues that the mandatory repayment
provision converts the Interconnection Customer's upfront payment for
Network Upgrade costs that are directly caused by an Interconnection
Request from an investment, where the Interconnection Customer is at
risk, to a loan. Southern Company claims that the Commission's previous
policy of not requiring a balloon payment and allowing transmission
credits only as delivery service was taken from a particular generating
facility, was arguably consistent with the Commission's policy of
allowing Transmission Providers to charge the ``higher of'' incremental
or embedded costs. However, Southern Company claims that, if a full
refund is always required within 20 years, this policy would be
violated.
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\7\ Entergy, Southern Company and PacifiCorp.
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8. Conversely, other petitioners argue that 20 years is too long to
wait for full reimbursement of upfront payments.\8\ Reliant states that
the Commission erred by failing to return to the balanced crediting
approach in Order No. 2003, which required the Transmission Provider to
refund the balance of the Interconnection Customer's upfront payment
within five years. Reliant argues that the 20-year reimbursement
requirement does not provide incentives for proper siting decisions,
and actually raises costs for the very customers the Commission is
seeking to protect. This is because the additional financing costs of a
20-year refund period raise the cost of new generators who wish to
enter the market. In Reliant's view, this creates a barrier to entry
that harms competition, and thereby harms native load and other
Transmission Customers.
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\8\ See Reliant, Calpine and PSEG.
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b. Commission Conclusion
9. In response to those petitioners that object to any requirement
for full reimbursement on a date certain, as well as those that believe
20 years is too long to wait for reimbursement, we note that we have
responded at length to many of these arguments in our previous orders.
We therefore simply reiterate here our conclusion in Order No. 2003-B
that our crediting and refund policy, including the 20-year
reimbursement requirement, provides a reasonable balance between the
objectives of promoting competition and infrastructure development,
protecting the interests of Interconnection Customers, and protecting
native load and other Transmission Customers.\9\
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\9\ We remind petitioners that we continue to view the
Interconnection Customer's upfront payment for Network Upgrades as
essentially a loan from the Interconnection Customer to the
Transmission Provider or Affected System Operator. Although the
appropriate length of the repayment period for such a loan is not a
number that can be determined with great precision, we note that 20
years reflects the approximate minimum life of facilities that
typically constitute Network Upgrades that generally would be needed
to accommodate an Interconnection Customer's generator
interconnection. Also, the courts have recognized that the
Commission sometimes must adopt a value within a range, as long as
the chosen value is related to the problem being addressed. E.g.,
ExxonMobil Gas Marketing Co. v. FERC, 297 F.3d 1071, 1085 (D.C. Cir.
2002) (``We are generally unwilling to review line-drawing performed
by the Commission unless a petitioner can demonstrate that lines
drawn * * * are patently unreasonable, having no relationship to the
underlying regulatory problem.'' (quotes and citation omitted)); see
also Prometheus Radio Project v. FCC, 373 F.3d 372, 410 (D.C. Cir.
2004) (``Deference to the Commission's judgment is highest when
assessing the rationality of the agency's line-drawing
endeavors.''); Sinclair Broad. Group, Inc. v. FCC, 284 F.3d 148, 159
(D.C. Cir. 2002) (granting deference to an agency's line-drawing
efforts within its expertise).
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2. Reimbursement of Upfront Payment for Network Upgrades and Affected
Systems
a. Rehearing Requests
10. Several petitioners ask the Commission to clarify whether an
Affected System Operator has an obligation to reimburse the
Interconnection Customer by means of a
[[Page 37663]]
balloon payment 20 years after the Commercial Operation Date.\10\ For
example, NRECA asks the Commission to clarify that if credits provided
by an Affected System Operator have not fully reimbursed the
Interconnection Customer's upfront payment within 20 years, the
Affected System Operator is not required to make a balloon payment, but
instead may continue to provide the Interconnection Customer with
credits for transmission service on the Affected System until the
Interconnection Customer's entire upfront payment has been reimbursed.
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\10\ See EEI, NRECA, PNM and NCEMC.
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11. On a related matter, NRECA also asks the Commission to clarify
that, the Transmission Provider or Affected System Operator has no
further obligation to reimburse the Interconnection Customer for its
upfront payment if the Generating Facility ceases Commercial Operation
before the Interconnection Customer has been completely reimbursed.
12. Finally, NCEMC asks the Commission to clarify the
Interconnection Customer's right to receive a refund of its upfront
payment for Network Upgrades on an Affected System when the
Interconnection Customer is also a Network Customer of the Affected
System. NCEMC states that it intends to construct a generating facility
and designate it as a network resource on the Transmission Provider's
Transmission System, where NCEMC is a network customer. Although NCEMC
is also a Network Customer of the Affected System, it says that the
transmission service revenues that the Affected System receives from
NCEMC do not vary according to what resources are designated as Network
Resources on the Affected System, but rather with NCEMC's load. NCEMC
argues that a rule that would tie credits from the Affected System to
incremental charges associated with transmission service taken from the
Affected System with respect to the Generating Facility is
inappropriate for an Interconnection Customer that is also a Network
Customer on the Affected System.
b. Commission Conclusion
13. In response to NRECA, we clarify that both the Transmission
Provider and an Affected System Operator need provide credits for
transmission service only when the Interconnection Customer takes
transmission service with the Large Generating Facility identified as
the primary point of receipt of that service. We clarify that both the
Transmission Provider and an Affected System Operator must provide the
20-year lump sum reimbursement to refund any remaining balance, even if
no transmission service was taken. Although Order No. 2003-B could be
read to suggest that the Affected System need only provide
reimbursement for transmission service taken,\11\ this was not our
intent. Indeed, the revised language in article 11.4.1 in Order No.
2003-B clearly subjects an Affected System Operator to the 20-year lump
sum requirement.\12\ This is consistent with the Commission's policy of
treating a non-independent Affected System Operator the same as a non-
independent Transmission Provider because both have the same incentive
to frustrate the development of new, competitive generation.\13\
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\11\ Order No. 2003-B at P 41, 42.
\12\ This obligation does not apply if the Affected System is a
non-jurisdictional entity.
\13\ See Order No. 2003-A at P 636; see also Order No. 2003 at P
738.
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14. In response to NRECA's second point, we clarify that the
Affected System Operator, like the Transmission Provider, must
reimburse the Interconnection Customer for its upfront payment even if
the Generating Facility ceases Commercial Operation before the
Interconnection Customer is completely reimbursed as long as the
Interconnection Agreement between the Interconnection Customer and the
Transmission Provider remains in full force and effect.\14\
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\14\ See Order No. 2003-A at P 619.
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15. In response to NCEMC, we note that, because the circumstances
that NCEMC describes are highly fact-specific, and we do not know all
the relevant facts, they are not appropriately addressed in a
rulemaking. Therefore, we will not attempt to answer NCEMC's request
for clarification in this order on rehearing, and will address the
issue if it arises in a specific proceeding.
3. Reimbursement Obligation of the Operator of a Jointly-Owned System
16. In Order No. 2003-B, the Commission stated that, in the case of
an Affected System that is jointly owned by public and non-public
utilities, it is the responsibility of the Affected System Operator to
provide the credits and to seek reimbursement for any amounts that it
believes it is owed by the other owners.\15\ If a Transmission Provider
provides transmission service on a Transmission System that is jointly
owned, that Transmission Provider must follow a similar procedure.
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\15\ Order No. 2003-B at P 42.
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a. Rehearing Requests
17. Several petitioners ask the Commission to clarify the crediting
and refund responsibilities of an operator of an Affected System that
is jointly owned.\16\ For example, EEI asks the Commission to clarify
that the public utility Transmission Provider's obligation to provide
transmission credits is limited to the amount of upfront payments made
for Network Upgrades owned by the Transmission Provider. EEI argues
that the policy in Order No. 2003-B may work when the cost recovery for
jointly owned facilities is provided for under a single tariff, but it
presents problems when the various joint owners each provide
transmission service independently under their own separate tariffs. In
addition, Georgia Transmission Corporation asks the Commission to
clarify that Order No. 2003-B does not require a non-jurisdictional
owner of a jointly owned transmission system to reimburse the Affected
System Operator or Transmission Provider. Georgia Transmission states
that such clarification would be consistent with the Commission's
statements in Order Nos. 2003 and 2003-A that ``if an Affected System
is a non-public utility, Order No. 2003 does not require that it
provide refunds to the Interconnection Customer to satisfy the
reciprocity condition.''
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\16\ See EEI, Georgia Transmission, MEAG Power, PNM, SoCal
Edison, and Southern Company.
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b. Commission Conclusion
18. The Commission clarifies that it is not requiring every
operator of a jointly owned system, whether it is a Transmission
Provider or an Affected System Operator, to reimburse the
Interconnection Customer for upfront payments for Network Upgrades
received by the non-public utility owners of the system. The discussion
in P 42 of Order No. 2003-B applies only to a situation where the
operator is a public utility and has tariff administration
responsibilities on behalf of the other owners. We clarify that the
operator's responsibility for flowing through credits and reimbursing
the Interconnection Customer for its upfront payment does not extend
beyond its normal duties as the tariff administrator. Each owner of a
jointly-owned system has the financial responsibility under its own
Commission-regulated tariff to provide transmission credits and final
reimbursement to the Interconnection Customer for the upfront payments
that the owner has received. This responsibility does not extend to a
non-public utility transmission owner or operator, of course.\17\
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\17\ See, e.g., Order No. 2003 at P 843.
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[[Page 37664]]
4. Credits for Transmission Service When the Generating Facility Is Not
the Source
19. In Order No. 2003-B, the Commission stated that, if the
Interconnection Customer or other Transmission Customer is taking firm
Point-to-Point Transmission Service under the OATT with the Generating
Facility as the source of the power transmitted, the customer continues
to have all of the rights given by the OATT to change temporarily
Points of Receipt or Delivery, if capacity is available, and is
entitled to continue to receive credits toward the cost of the
transmission service while doing so.\18\
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\18\ Order No. 2003-B at P 38.
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a. Rehearing Requests
20. EEI asks the Commission to clarify that, while a Transmission
Customer may temporarily change its point of receipt, it will not
receive credits for transmission service that does not involve power
generated from the Generating Facility. The Commission should also
clarify what is meant by a ``temporary'' change to ensure that the
Transmission Customer cannot use this provision to game the system and
impose unwarranted costs on native load customers and other users of
the system. In addition, PNM asks the Commission to clarify that sham
designations of transactions through a non-operating Generating
Facility are not a permitted means of obtaining transmission credits.
21. Southern Company argues that, contrary to the claims of some
commenters, denying credits for transmission service when the
Generating Facility is not the source of the power transmitted does not
restrict any rights that the Interconnection Customer has under Order
No. 888. Southern Company states that before Order No. 2003-B,
Interconnection Customers were free to change points of receipt and
delivery subject only to the requirements of Order No. 888. It argues
that nothing in Order No. 2003 or Order No. 2003-A restricts this
right. Providing Interconnection Customers with credits for redirected
service does nothing to increase their ability to change delivery and
receipt points. Instead, Southern Company argues, providing credits for
redirected service will circumvent the native load protections adopted
in Order No. 2003-A.
b. Commission Conclusion
22. The Commission is not persuaded to change the policy under
which the Transmission Provider must provide transmission credits
during periods when the Interconnection Customer is using, in
accordance with the terms of its transmission service, a secondary
receipt point rather than the Generating Facility. As long as the
Interconnection Customer or another entity is taking transmission
service that identifies the Generating Facility as the point of receipt
for that service in the original firm point-to-point transmission
service request, the Interconnection Customer is entitled to a credit
toward the cost of that service. The possibility that this could lead
to abuse is greatly overstated. A transmission customer that elects to
use a secondary point of receipt or delivery under the OATT must take
such service only on a non-firm basis and at the lowest priority level.
The Commission does not believe that access to this non-firm service
option is sufficient to lead to abuse. Furthermore, in response to PNM,
the Commission clarifies that a sham designation of a transaction
through a non-operating Generating Facility is not a permitted means of
obtaining transmission credits.
23. The Commission clarifies that its use of the word
``temporarily'' is intended to distinguish a request to use secondary
receipt point on a non-firm basis as permitted under the tariff from a
request to change the point of receipt on a firm basis.
5. Implementing the ``Higher Of'' Policy
24. In Order No. 2003-B, we stated that our interconnection pricing
policy continues to allow the Transmission Provider to charge the
Interconnection Customer a transmission rate that is the higher of the
incremental cost rate for Network Upgrades required to interconnect the
Generating Facility and an embedded cost rate for the entire
Transmission System (including the cost of the Network Upgrades). We
further stated that, if a Transmission Provider (or any other
interested party) believes that, for an actual interconnection, it
faces circumstances where native load and other customers are not held
harmless, it should make that demonstration in an actual transmission
rate filing.\19\
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\19\ Order No. 2003-B at P 54-57.
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a. Rehearing Requests
25. With reference to the Commission's second statement cited
above, Southern Company claims that the Administrative Procedure Act
requires that agency action be supported by substantial evidence \20\
and that the Commission's attempt to ``pass the buck'' by requiring a
Transmission Provider to demonstrate the negative does not meet that
standard.
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\20\ 5 U.S.C. 706(2)(E) (2000).
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26. In response to our statement that we are willing to look on a
case-by-case basis at proposals to protect native load and other
existing customers, PacifiCorp argues that administrative efficiency
favors a generic rule that addresses the need to fully protect native
load. In PacifiCorp's view, it would be costly, burdensome, and
inefficient to require a Transmission Provider to file a request to
protect its native load every time a merchant generator signs an
interconnection agreement without having executed a service agreement
for transmission delivery service of sufficient duration to cover the
cost of Network Upgrades.
b. Commission Conclusion
27. The Commission reiterates that the appropriate ratemaking
approach to ensure that native load and other customers are held
harmless depends on the particular set of facts that result in native
load and other customers allegedly not being held harmless. For
example, it may depend on the particular circumstances of the
Interconnection Customer, its Generating Facility and location, and
transmission interconnection service that is requested (Energy Resource
Interconnection Service or Network Resource Interconnection Service),
the tariff status of the power buyer (point-to-point or Network
Integration Transmission Service), and the relationship if any of the
Interconnection Customer to the transmission tariff service customer.
This is a ratemaking question that does not lend itself to a generic
solution. Furthermore, supporting an agency action by substantial
evidence requires facts in some cases, so that case-specific, fact-
based determinations are sometimes necessary instead of generic
theoretical solutions.
B. Other Issues
1. Scoping Meeting
28. In Order No. 2003-B, the Commission rejected Southern's
argument that the LGIP section 3.4 requirement to keep the identity of
the Interconnection Customer confidential conflicts with the
Transmission Provider's obligation in LGIP section 3.3.4 to reveal in a
notice any meeting the Transmission Provider conducts with an
affiliated Interconnection Customer. The Commission explained that the
requirement to disclose Affiliate meetings resulted from the
Commission's attempt to balance the need to treat affiliated and
nonaffiliated
[[Page 37665]]
Interconnection Customers alike with the need to make Order No. 2003
conform to the established Code of Conduct and Standards of Conduct
requirements.\21\
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\21\ Order No. 2003-B at P 137.
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a. Request for Rehearing
29. On rehearing, Southern again argues that Order No. 2003-B
discriminates against affiliates of a Transmission Provider because
requiring disclosure of their identities and confidential information
will benefit competitors. Southern argues that while the Commission
attempts to justify this disparate treatment by claiming that
affiliated and non-affiliated generators are not similarly situated,
they are similarly situated in that for both of them, revealing the
identity of the Interconnection Customer would put that customer ``at a
competitive disadvantage and its project at risk.'' \22\ Southern then
cites Federal court precedent saying that the Commission cannot treat
similarly situated customers in a non-comparable manner.\23\
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\22\ See Order No. 2003 at P 114.
\23\ Town of Norwood v. FERC, 202 F.3d 392, 402 (1st Cir. 2000).
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b. Commission Conclusion
30. Contrary to Southern's argument, the Commission concludes that
the disparate treatment here is justified because of concerns about
affiliate abuse. As explained in Order Nos. 2003-A and 2003-B,\24\ this
measure allows Transmission Providers and their affiliates to share
confidential information, but with safeguards that provide the public
with notice of any meetings with affiliated Interconnection Customers
and the opportunity to review a transcript. The affiliate relationship
is a factual difference that justifies the different treatment
here.\25\ Additional safeguards are needed to ensure against affiliate
abuse.\26\ The Commission reaffirms its conclusion that revealing the
affiliate relationship between the Interconnection Customer and
Transmission Provider results in less harm than if there were no
safeguards at all.
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\24\ See Order No. 2003 A at P 107; Order No. 2003-B at P 136.
\25\ See Public Service Co. of Indiana v. FERC, 575 F.2d 1204,
1212 (7th Cir. 1978); Cities of Bethany v. FERC, 727 F.2d 1131, 1140
(D.C. Cir. 1984).
\26\ See, e.g., Entergy Services, Inc., 111 FERC ] 61,145 at P
10 (2005) (initiating hearing to examine the ``credible concerns''
regarding transmission market power, by failing to provide
interconnections or blocking alternative generation sources);
Southern Companies Energy marketing, Inc, 111 FERC ] 61,144 at P 16
(initiating hearing to examine the ``credible concerns'' regarding
unduly preferential treatment afforded affiliates in access
generation sites) (2005); see also Entergy Services, Inc., 103 FERC
] 61,256 at P 44-53 (initiating a hearing to examine concerns
regarding affiliate dealing in a bidding process for power purchase
agreements).
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2. Generator Balancing
31. In Order No. 2003-B, the Commission reaffirmed the decision in
Order No. 2003-A to eliminate from the pro forma LGIA a provision
requiring the Interconnection Customer to make generator balancing
service arrangements (before submitting a schedule for delivery
service) that identify the Interconnection Customer's Generating
Facility as the Point of Receipt for the scheduled delivery. Order No.
2003-B at P 74-75. We removed the requirement because generator
balancing is an ancillary service that is part of delivery service, not
interconnection service. Recognizing that some Transmission Providers
may prefer to include a balancing provision in an interconnection
agreement rather than in a separate agreement, the Commission explained
that the Transmission Provider may do so in individual interconnection
agreements tailored to the Parties' specific circumstances and subject
to Commission approval.
a. Request for Rehearing
32. Southern seeks clarification that nothing in Order No. 2003-B
precludes Southern's approach in its in Docket No. ER04-1161-000, which
is to include a provision in its LGIA that refers to the requirement
that a generator enter into an operating agreement that outlines
options for remedying imbalances, but does not prescribe specific
generator balancing service or rates.
b. Commission Conclusion
33. The Commission has issued an order in Docket No. ER04-1161-000
that addressed Southern's request for clarification and rejected
Southern's proposal to include in the LGIA a reference to a balancing
service agreement.\27\ There the Commission stated that a Transmission
Provider may either adopt a stand-alone generator balancing service
agreement or request the inclusion of a generator balancing service
provision tailored to the Parties' specific standards and circumstances
in an individual interconnection agreement. The Commission does not
include a standardized balancing provision in the LGIA, even one as
limited in scope as Southern proposes, because as explained in Order
No. 2003-A balancing service is more closely related to transmission
delivery service than interconnection service. For the same reasons, we
follow that decision here.
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\27\ Southern Company Services, Inc., 111 FERC ] 61,004 at P 16
(2005), reh'g on other grounds pending.
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3. Reactive Power Payments to Generator
34. Order No. 2003-B reaffirmed Order No. 2003-A's modification to
LGIA article 9.6.3 to require the Transmission Provider to pay the
Interconnection Customer for reactive power the Interconnection
Customer provides or absorbs only when the Transmission Provider asks
the Interconnection Customer to operate its Generating Facility outside
a specified power factor range (or dead band). However, if the
Transmission Provider pays its own or affiliated generators for
reactive power service within the specified range, it must also pay the
Interconnection Customer for providing reactive power within the
specified range.\28\ The Commission stated that although ``the
Transmission Provider is not `paying' its own or affiliated generators
directly for providing reactive power within the specified range, the
owner of the generator is nonetheless being compensated for that
service when the Transmission Provider includes reactive power related
costs in its transmission revenue requirement.'' \29\
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\28\ Order No. 2003-A at P 416; Order No. 2003-B at P 114.
\29\ Order No. 2003-B at P 119.
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a. Requests for Rehearing
35. Southern and PNM take issue with the Commission's statement in
Order No. 2003-B that when a Transmission Provider is required to
provide Reactive Power under Schedule 2 of its OATT, and charges for
that service, it is thereby paying its own generators for reactive
power within the established range, thus triggering a responsibility to
pay the Interconnection Customer in the same manner.
36. Southern argues that this is incorrect because Schedule 2 only
allows the Transmission Provider to be paid for reactive power from
``generation sources.'' The revenue requirements associated with such
generation are not recovered in a transmission revenue requirement
(hence the need for a Schedule 2 charge separate from the OATT
transmission delivery charges). Furthermore, even if this statement is
clarified to be a reference to a Transmission Provider receiving
compensation for its generator-supplied reactive power costs
[[Page 37666]]
in its Schedule 2 charge, Southern continues, that would be incorrect
as well. It would be wrong because, at least in the case of the
Southern Companies, the dollars received for Schedule 2 service do not
go to the generators or to the Transmission Provider, but instead are
treated as revenue credits to reduce the costs that retail customers
would otherwise have to pay. As a result, the beneficiaries of Schedule
2 revenues are retail customers, not the Transmission Provider or its
generators. Paying Interconnection Customers for providing this service
would give them an unfair advantage over Transmission Providers in the
form of additional revenue.
37. PNM agrees that if a Transmission Provider must pay
Interconnection Customers for reactive power within the deadband, it
will need to recover that cost as part of its Schedule 2 revenue
requirement. The result will be an unwarranted windfall to
Interconnection Customers, higher costs for Transmission Customers, and
increased filing burdens for public utility Transmission Providers.
38. PNM and Southern also argue that a service obligation
distinguishes the Transmission Provider from the Interconnection
Customer. They note that a Transmission Provider must plan, construct,
and operate its generation at all times to meet the system's localized
power and voltage requirements. Unlike the Transmission Provider, an
Interconnection Customer constructs its generation in the location best
meeting its own needs. Southern argues that an Interconnection
Customer's generator is simply not ``comparable'' to a Transmission
Provider's generator for purposes of supplying reactive power.
39. Southern notes that Order Nos. 888-A and 888-B explained that a
generator must have to be available and under the Transmission
Provider's control (so that it reduces the Transmission Provider's
reactive power investment requirements) in order to be entitled to
compensation. Since the Interconnection Customer's generators are not
under the Transmission Provider's control, the Transmission Provider
cannot rely on those generators to reduce its investment in reactive
power facilities necessary to satisfy its system's needs (as it can for
its own generators).
40. Alternatively, PNM requests that the Commission clarify
procedures by which Transmission Providers can pass through as part of
their Schedule 2 revenue requirement any amounts that they are required
to pay Interconnection Customers for reactive power within the
specified power range.
41. PNM also requests that the Commission explain what it means
when it states that nothing in LGIA Article 9.6.3 ``disturbs any
present arrangements for reactive power compensation.'' Order No. 2003-
B at P 121. PNM supports applying the policy to new interconnection
agreements and grandfathering existing agreements.
b. Commission Conclusion
42. We disagree with Southern's and PNM's argument that the
Commission should base its decision on what the Transmission Provider
does with the revenues from providing reactive power within the
established range. The Commission is less concerned with the flow of
these revenues than with the unduly discriminatory treatment of non-
affiliated Interconnection Customers that provide this important system
service. We therefore reiterate that if the Transmission Provider's
affiliate receives a payment for providing this service within the
specified range, then payments must be made to non-affiliated
Interconnection Customers for providing the service. Because the non-
affiliates are providing an important service, we disagree with PNM
that such payments would result in a windfall to them.
43. Although the Transmission Provider's or its affiliate's
generators may be required to operate when others are not, this
distinction in availability is not so significant as to eliminate the
need to compensate other generators. With respect to Southern's
assertion that the Interconnection Customer's generators are not under
the Transmission Provider's control, Order No. 2003-B clarified \30\
that while the Transmission Provider cannot demand that the
Interconnection Customer operate its Generating Facility solely to
provide reactive power, it may require the Interconnection Customer to
provide reactive power from time to time when its Generating facility
is in operation. The requirement to pay exists only as long as the
Generating Facility follows the Transmission Provider's reactive power
instructions. This is a sufficient level of control to warrant
compensation for providing reactive power as described in Order Nos.
888-A and 888-B.
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\30\ Order No. 2003-B at P 118.
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44. In response to PNM's requests for clarification, although we do
not agree that selecting the best sources of reactive power from
available generators should necessarily increase reactive power costs--
indeed, it may lower such costs--a Transmission Provider may propose to
incorporate in its rates any such increase in Schedule 2 amounts. At
that time the Commission will consider alternatives for recovery of
these charges.\31\
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\31\ Commission staff has begun a general inquiry into reactive
power pricing reform; see Principles for Efficient and Reliable
Reactive Power Supply and Consumption, Docket No. AD05-1-000
(February 4, 2005) and the discussion at the Commission meeting on
December 15, 2004.
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45. Finally, Order No. 2003 does not abrogate existing
agreements,\32\ and we reiterate that existing agreements for reactive
power compensation need not be amended to incorporate our policy on
reactive power payments for newly interconnecting generators.
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\32\ See Order No. 2003 at P 911.
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4. Interest Rate Applied to Non-jurisdictional Entities
46. LGIA Article 11.4.1 requires that the repayment for Network
Upgrades shall include interest calculated in accordance with the
Commission's regulations. Order No. 2003-B clarified that the interest
rate is in 18 CFR Sec. 35.19a(a)(2)(iii).
a. Request for Rehearing
47. NRECA argues that that interest rate is not appropriate for
non-jurisdictional utilities that are ``subject to'' the
Interconnection Rule due to the Commission's reciprocity condition. The
Commission's interest rate bears no relationship to a non-
jurisdictional utility's cost of borrowing, NRECA explains, and it
provides a windfall to the Interconnection Customer at the expense of a
non-jurisdictional utility's consumers.
b. Commission Conclusion
48. We clarify that a non-jurisdictional entity subject to the
reciprocity condition need not adhere to the crediting policy for
Transmission Providers in Order No. 2003, including the payment of
interest,\33\ unless it applies this same crediting policy to its own
generation. Order No. 2003-A clarified that for rate matters, the
reciprocity condition only requires comparability.\34\ Therefore,
interest (at the Commission's or some other interest rate) would be
payable only if it is payable (at the same interest rate) to the non-
jurisdictional entity's own or affiliated generators, if any.
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\33\ In its request for rehearing, NRECA refers to an interest
rate that the Commission corrected in Order No. 2003-B.
\34\ Order No. 2003-A at 777.
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5. Jurisdiction
49. Order No. 2003-B corrected a misstatement in Order No. 2003-A
and reiterated that if an Interconnection Customer seeks to
interconnect with a
[[Page 37667]]
dual use facility (i.e., a facility that is used for both wholesale and
retail sales) to make a wholesale sale, then Order No. 2003 applies
because that facility is subject to an OATT.\35\
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\35\ Order No. 2003-B at P14.
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Request for Rehearing
50. SoCal Edison argues that the Commission must exercise
jurisdiction over all wholesale generator interconnections, including
those to ``local distribution'' facilities never previously used by
wholesale customers. SoCal Edison says that the Commission incorrectly
asserts that there are three categories of facilities (transmission,
``local distribution,'' and dual use) when only two actually exist
(transmission and ``local distribution''). SoCal Edison says that a
D.C. Circuit opinion finds that only two categories exist, and
wholesale service over ``local distribution'' facilities is Commission-
jurisdictional.\36\ SoCal Edison concludes that because all
interconnections to distribution facilities are to ``local
distribution'' facilities, all such interconnections should be treated
the same for jurisdictional purposes, and jurisdiction should depend
solely on whether the generator makes sales at wholesale. SoCal Edison
therefore requests that the Commission rule that it has jurisdiction
over all interconnections to ``local distribution'' facilities for the
purpose of making wholesale sales.
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\36\ SoCal Edison cites Detroit Edison Co. v. FERC, 334 F.3d 48,
51 (D.C. Cir. 2003) (``[W]hen a local distribution facility is used
in a wholesale transaction, FERC has jurisdiction over that
transaction pursuant to its wholesale jurisdiction under FPA Sec.
201(b)(1).'') and DTE Energy Co. v. FERC, 394 F.3d 954 (D.C. Cir.
2005) (applying a two category analysis).
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Commission Conclusion
51. We disagree with SoCal Edison that we should assert
jurisdiction over all interconnections that could be used for wholesale
sales, including the situation in which the Interconnection Customer
seeks to interconnect to a ``local distribution'' facility being used
exclusively for retail sales and thus is not available for service
under an OATT at the time the Interconnection Request is made. In Order
No. 2003, the Commission explained that the rule applies to
interconnections to the facilities of a public utility's Transmission
System that, at the time the interconnection is requested, may be used
either to transmit electric energy in interstate commerce or to sell
electric energy at wholesale in interstate commerce pursuant to a
Commission filed OATT.\37\ Thus, our assertion of jurisdiction over
interconnections rested on two grounds: first, and primarily, our FPA
jurisdiction over ``transmission'' facilities, which may be used for
wholesale sales or unbundled retail sales and which are subject to an
OATT; and, second, our FPA jurisdiction over wholesale sales which
require the use of ``local distribution'' facilities and thus such
facilities become subject to an OATT for purposes of the wholesale
sales. We concluded that applying our interconnection rules to
facilities already subject to an OATT would properly respect the
jurisdictional bounds recognized by the courts in upholding Order No.
888 and subsequent cases.\38\ To adopt SoCal Edison's position and
interpret our authority more broadly, however, would allow a potential
wholesale seller to cause the involuntary conversion of a facility
previously used exclusively for state-jurisdictional interconnections
and delivery, and subject to the exclusive jurisdiction of the state,
into a facility also subject to the Commission's interconnection
jurisdiction--a result that we believe crosses the jurisdictional line
established by Congress in the FPA.
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\37\ Order No. 2003 at P 804. Pursuant to Order No. 888, as
upheld by the courts, facilities subject to an OATT are
``transmission'' facilities and facilities used for wholesale sales,
whether labeled ``transmission,'' ``distribution,'' or ``local
distribution.'' 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. ] 31,036 at 31,969, 31,980 (1996), order on reh'g, Order No.
888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ] 31,048
(1997), order on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997),
order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in
relevant part sub nom. Transmission Access Policy Study Group v.
FERC, 225 F.3d 667 (D.C. Cir. 2000) (TAPS v. FERC), aff'd sub nom.
New York v. FERC, 535 U.S. 1 (2002); see TAPS v. FERC, 225 F.3d at
696 (noting that the Commission's ``assertion of jurisdiction over
all wholesale transmissions, regardless of the nature of the
facility, is clearly within the scope of its statutory authority'').
\38\ See Detroit Edison Co. v. FERC, 334 F.3d 48 (D.C. Cir.
2003); DTE Energy Co. v. FERC, 394 F.3d 954 (D.C. Cir. 2005).
---------------------------------------------------------------------------
52. FPA section 201(b)(1) gives the Commission the authority to
regulate ``all facilities'' used for transmission and for the wholesale
sale of electric energy in interstate commerce.\39\ The same FPA
section denies the Commission jurisdiction ``over facilities used in
local distribution'' except as specifically provided in Parts II and
III of the FPA.\40\ The Court of Appeals for the D.C. Circuit recently
explained this provision as meaning that, if a wholesale sale of
electric energy in interstate commerce is occurring, the Commission has
jurisdiction over the transaction or service, even if the transaction
occurs over a ``local distribution'' facility.\41\
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\39\ 16 U.S.C. 824a(b)(1) (2000).
\40\ Id.
\41\ Detroit Edison Co. v. FERC, 334 F.3d 48, 51 (D.C. Cir.
2003); accord Transmission Access Policy Study Group v. FERC, 225
F.3d 667, 696 (D.C. Cir. 2000) (TAPS) (noting that ``FERC's
assertion of jurisdiction over all wholesale transmissions,
regardless of the nature of the facility, is clearly within the
scope of its statutory authority,'' and that the statute and case
law support the proposition that the Commission has the authority to
regulate ``all aspects'' of wholesale transactions).
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53. When a ``local distribution'' facility is used to transmit
energy sold at wholesale as well as energy sold at retail, we
previously have called this a ``dual use'' facility because it is used
both for sales subject to Commission jurisdiction and for sales subject
to state jurisdiction.\42\ Under Order No. 2003, if such a facility is
subject to wholesale open access under an OATT at the time the
Interconnection Request is made, and the interconnection will connect a
generator to a facility that would be used to facilitate a wholesale
sale, Order No. 2003 applies and the interconnection must be subject to
Commission-approved terms and conditions. Because the Commission's
authority to regulate in this circumstance is limited to the wholesale
transaction, we conclude that we do not have the authority to directly
regulate the facility that is used to transmit the energy being sold at
wholesale. In other words, while the Commission may regulate the entire
transmission component (rates, terms and conditions) of the wholesale
transaction--whether the facilities used to transmit are labeled
``transmission'' or ``local distribution''--it may not regulate the
``local distribution'' facility itself, which remains state-
jurisdictional. We believe this properly respects the boundaries drawn
in the FPA.
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\42\ We note that the DTE court rejected DTE's attempt to use
the dual use facility or dual function rationale. DTE Energy Co. v.
FERC, 394 F.3d 954, 962-63 (D.C. Cir. 2005). The court, however, did
not address ``dual use'' as it applies to the Commission's authority
to regulate wholesale sales. Also, when a ``dual use'' facility is
involved in a wholesale sale, we do not claim jurisdiction over the
facility itself, just the wholesale sale transaction occurring over
that facility. See Detroit Edison Co. v. FERC, 334 F.3d 48, 51 (D.C.
Cir. 2003) (explaining that the Commission has jurisdiction ``over
all wholesale service,'' including wholesale transactions that occur
over ``local distribution'' facilities).
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6. Wind Power Exemption
54. Order No. 2003-A exempted wind generators from the power factor
design criteria requirement in article 9.6.1, because as nonsynchronous
generators, it would be difficult for these generators
[[Page 37668]]
to maintain the required power factor.\43\ On rehearing, in response to
SoCal Edison's argument that wind generators should not be exempt, the
Commission in Order No. 2003-B explained that it was examining the
issue as part of an ongoing proceeding on technical requirements
applicable to wind. The Commission stated that until the other
proceeding was resolved, it would continue the exemption for wind
generators.
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\43\ Order No. 2003-A at P 407 n.85.
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Request for Rehearing
55. SoCal Edison again asks that the Commission not exempt wind
generators from the power factor requirement citing reliability and
safety consequences. It also asks that the Commission not await the
resolution of the issue in the wind rulemaking and instead adopt an
interim standard that removes the exemption.
Commission Conclusion
56. We note that after SoCal Edison submitted its rehearing
request, the Commission issued the Final Rule on Interconnection for
Wind Energy and Other Alternative Technologies, which requires large
wind plants to provide reactive power, if needed, under the same
technical criteria applicable to conventional large generating
facilities.\44\ Therefore, SoCal Edison's request is moot.
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\44\ Interconnection for Wind Energy, Order No. 661, 111 FERC ]
61,353 (2005).
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7. ``At or Beyond'' Rule
a. Request for Rehearing
57. Southern argues although Order No. 2003-B did not specifically
refer to the ``at or beyond'' rule, it reaffirmed the primary holdings
of Order Nos. 2003 and 2003-A, which did. It argues that in Order No.
2003-B, the Commission failed to note that its ``at or beyond'' rule
had recently been vacated by the D.C. Circuit in Entergy Services, Inc.
v. FERC, 391 F.3d 1240 (D.C. Cir. 2004). Accordingly, Southern
concludes, the ``at or beyond'' rule in this proceeding is a legal
nullity, and the Commission's continued adherence to that policy in
this proceeding is inappropriate.
b. Commission Conclusion
58. We note that the court in Entergy Services did not question the
Commission's authority to apply an ``at or beyond'' rule; it simply
sought an explanation that harmonized the ``at or beyond'' rule with
Commission precedent. Moreover, the Commission has issued an order on
remand explaining that facilities at the point of interconnection are
network facilities.\45\ Therefore, Southern's argument is moot.
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\45\ Nevada Power Co., 111 FERC ] 61,161 at P 16 (2005).
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III. Ministerial Changes to the Pro Forma LGIP and LGIA
59. Since Order No. 2003-B was issued, we have identified certain
sections of the LGIP and articles of the LGIA that require
modification. Because of the ministerial nature of these changes, no
further discussion is needed. The changes are included in Appendix A.
IV. Compliance
60. This order takes effect 30 days after issuance by the
Commission. As with the Order No. 2003 compliance process, the
Commission will deem the OATT of each non-independent Transmission
Provider to be amended to adopt the clarifications to the pro forma
LGIP and LGIA contained in Appendix A herein on the effective date of
this order. A non-independent Transmission Provider should submit
revised tariff sheets incorporating the clarifications in Appendix A
within 60 days after the issuance of this order. Within the same time
frame, each RTO or ISO also must submit either revised tariff sheets
incorporating the clarifications in Appendix A, or an explanation under
the independent entity variation standard as to why it does not propose
to adopt each change.
V. Document Availability
61. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to obtain this document from the Public Reference Room
during normal business hours (8:30 a.m. to 5 p.m. Eastern Time) at 888
First Street, NE., Room 2A, Washington, DC. The full text of this
document is also available electronically from the Commission's
eLibrary system (formerly called FERRIS) in PDF and Microsoft Word
format for viewing, printing, and downloading. eLibrary may be accessed
through the Commission's Home Page (http://www.ferc.gov). To access
this document in eLibrary, type ``RM02-1-'' in the docket number field
and specify a date range that includes this document's issuance date.
62. User assistance is available for eLibrary and the Commission's
website during normal business hours from our Help line at 202-502-8222
or the Public Reference Room at 202-502-8371 Press 0, TTY 202-502-8659.
e-mail the Public Reference Room at public.referenceroom@ferc.gov.
VI. Effective Date
63. Changes to Order Nos. 2003, 2003-A and 2003-B made in this
order on rehearing will become effective 30 days after issuance by the
Commission.
List of Subjects 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By the Commission. Commissioner Brownell dissenting in part with
a separate statement attached.
Linda Mitry,
Deputy Secretary.
The Appendices will not be published in the Code of Federal
Regulations.
[[Page 37669]]
[GRAPHIC] [TIFF OMITTED] TR30JN05.000
Nora Mead BROWNELL, Commissioner dissenting in part:
For the reasons I articulated in my partial dissent to Order No.
2003-B, I would have granted rehearing and reinstated the original
provision in Order No. 2003 that ensured Interconnection Customers full
reimbursement of their up-front funding of Network Upgrades within five
years. Therefore, I dissent from this portion of today's order.
Nora Mead Brownell
[FR Doc. 05-12870 Filed 6-29-05; 8:45 am]
BILLING CODE 6717-01-P