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§ 34.5 Additional information.
The Commission may, in its discretion, require the filing of additional information which appears necessary to
reach a determination on any particular application.
§ 34.6 Form and style.
Each application pursuant to this
part 34 shall conform to the requirements of subpart T of part 385 of this
chapter.
[Order 182, 46 FR 50514, Oct. 14, 1981, as
amended by Order 225, 47 FR 19056, May 3,
1982]
§ 34.7 Filing requirements.
Applications must be filed with the
Secretary of the Commission in accordance with filing procedures posted on
the Commission’s Web site at http://
www.ferc.gov. If an applicant seeks to
protect any portion of an application
from public disclosure, the applicant
must make its filing in accordance
with the Commission’s instructions for
filing privileged materials and critical
energy infrastructure information in
this chapter.
[Order 737, 75 FR 43403, July 26, 2010, as
amended by Order 769, 77 FR 65474, Oct. 29,
2012]
§ 34.8 Verification.
The original application shall be
signed by an authorized representative
of the applicant, who has knowledge of
the matters set forth therein, and it
shall be verified under oath.
EFFECTIVE DATE NOTE: At 70 FR 35375, June
20, 2005, § 34.8 was revised, effective at the
time of the next e-filing release during the
Commission’s next fiscal year. For the convenience of the user, the revised text follows:
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§ 34.8 Verification.
An application verification shall be signed
under oath by an authorized representative
of the applicant, who has knowledge of the
matters set forth therein and as provided in
§ 385.2005 of this chapter, and retained at the
applicant’s business location until the relevant proceeding has been concluded.
§ 34.9 Reports.
The applicant must file reports under
§ 131.43 and § 131.50 of this chapter no
later than 30 days after the sale or
placement of long-term debt or equity
Pt. 35
securities or the entry into guarantees
or assumptions of liabilities pursuant
to authority granted under this part.
[Order 575, 60 FR 4853, Jan. 25, 1995. Redesignated by Order 737, 75 FR 43403, July 26, 2010]
EFFECTIVE DATE NOTE: At 70 FR 35375, June
20, 2005, § 34.9 was revised, effective at the
time of the next e-filing release during the
Commission’s next fiscal year. For the convenience of the user, the revised text follows:
§ 34.9 Filing fee.
Each application shall be accompanied by
the submission of a filing fee if one is prescribed in part 381 of this chapter.
PART 35—FILING OF RATE
SCHEDULES AND TARIFFS
Subpart A—Application
Sec.
35.1 Application; obligation to file rate
schedules, tariffs and certain service
agreements.
35.2 Definitions.
35.3 Notice requirements.
35.4 Permission to become effective is not
approval.
35.5 Rejection of material submitted for filing.
35.6 Submission for staff suggestions.
35.7 Electronic filing of tariffs and related
materials.
35.8 Protests and interventions by interested parties.
35.9 Requirements for filing rate schedules,
tariffs or service agreements.
35.10 Form and style of rate schedules, tariffs and service agreements.
35.10a Forms of service agreements.
35.10b Electric Quarterly Reports.
35.11 Waiver of notice requirement.
Subpart B—Documents To Be Submitted
With a Filing
35.12 Filing of initial rate schedules and
tariffs.
35.13 Filing of changes in rate schedules,
tariffs or service agreements.
Subpart C—Other Filing Requirements
35.14 Fuel cost and purchased economic
power adjustment clauses.
35.15 Notices of cancellation or termination.
35.16 Notice of succession.
35.17 Withdrawals and amendments of rate
schedule, tariff or service agreement filings.
35.18 Asset retirement obligations.
35.19 Submission of information by reference.
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§ 35.1
18 CFR Ch. I (4–1–19 Edition)
35.19a Refund requirements under suspension orders.
35.21 Applicability to licensees and others
subject to section 19 or 20 of the Federal
Power Act.
35.22 Limits for percentage adders in rates
for transmission services; revision of rate
schedules, tariffs or service agreements.
35.23 General provisions.
35.24 Tax normalization for public utilities.
35.25 Construction work in progress.
35.26 Recovery of stranded costs by public
utilities and transmitting utilities.
35.27 Authority of State commissions.
35.28 Non-discriminatory open access transmission tariff.
35.29 Treatment of special assessments levied under the Atomic Energy Act of 1954,
as amended by Title XI of the Energy
Policy Act of 1992.
Subpart D—Procedures and Requirements
for Public Utility Sales of Power to Bonneville Power Administration Under
Northwest Power Act
35.30
35.31
General provisions.
Commission review.
Subpart E—Regulations Governing Nuclear
Plant Decommissioning Trust Funds
35.32
35.33
General provisions.
Specific provisions.
Subpart F—Procedures and Requirements
Regarding Regional Transmission Organizations
35.34
Regional Transmission Organizations.
Subpart G—Transmission Infrastructure
Investment Procedures
35.35 Transmission
ment.
infrasturcture
invest-
Subpart H—Wholesale Sales of Electric Energy, Capacity and Ancillary Services
at Market-Based Rates
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35.36 Generally.
35.37 Market power analysis required.
35.38 Mitigation.
35.39 Affiliate restrictions.
35.40 Ancillary services.
35.41 Market behavior rules.
35.42 Change in status reporting requirement.
APPENDIX A TO SUBPART H OF PART 35—
STANDARD SCREEN FORMAT
APPENDIX B TO SUBPART H OF PART 35—CORPORATE ENTITIES AND ASSETS SAMPLE AP-
Subpart I—Cross-Subsidization Restrictions
on Affiliate Transactions
35.43 Generally.
35.44 Protections against affiliate cross-subsidization.
Subpart J—Credit Practices In Organized
Wholesale Electric Markets
35.45 Applicability.
35.46 Definitions.
35.47 Tariff provisions governing credit
practices in organized wholesale electric
markets.
AUTHORITY: 16 U.S.C. 791a–825r, 2601–2645; 31
U.S.C. 9701; 42 U.S.C. 7101–7352.
SOURCE: Order 271, 28 FR 10573, Oct. 2, 1963,
unless otherwise noted.
Subpart A—Application
§ 35.1 Application; obligation to file
rate schedules, tariffs and certain
service agreements.
(a) Every public utility shall file with
the Commission and post, in conformity with the requirements of this
part, full and complete rate schedules
and tariffs and those service agreements not meeting the requirements of
§ 35.1(g), clearly and specifically setting
forth all rates and charges for any
transmission or sale of electric energy
subject to the jurisdiction of this Commission, the classifications, practices,
rules and regulations affecting such
rates, charges, classifications, services,
rules, regulations or practices, as required by section 205(c) of the Federal
Power Act (49 Stat. 851; 16 U.S.C.
824d(c)). Where two or more public utilities are parties to the same rate
schedule or tariff, each public utility
transmitting or selling electric energy
subject to the jurisdiction of this Commission shall post and file such rate
schedule, or the rate schedule may be
filed by one such public utility and all
other parties having an obligation to
file may post and file a certificate of
concurrence on the form indicated in
§ 131.52 of this chapter: Provided, however, In cases where two or more public
utilities are required to file rate schedules or certificates of concurrence such
PENDIX
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Federal Energy Regulatory Commission
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public utilities may authorize a designated representative to file upon behalf of all parties if upon written request such parties have been granted
Commission authorization therefor.
(b) A rate schedule, tariff, or service
agreement applicable to a transmission
or sale of electric energy, other than
that which proposes to supersede, cancel or otherwise change the provisions
of a rate schedule, tariff, or service
agreement required to be on file with
this Commission, shall be filed as an
initial rate in accordance with § 35.12.
(c) A rate schedule, tariff, or service
agreement applicable to a transmission
or sale of electric energy which proposes to supersede, cancel or otherwise
change any of the provisions of a rate
schedule, tariff, or service agreement
required to be on file with this Commission (such as providing for other or
additional rates, charges, classifications or services, or rules, regulations,
practices or contracts for a particular
customer or customers) shall be filed
as a change in rate in accordance with
§ 35.13, except cancellation or termination which shall be filed as a change
in accordance with § 35.15.
(d)(1) The provisions of this paragraph (d) shall apply to rate schedules,
tariffs or service agreements tendered
for filing on or after August 1, 1976,
which are applicable to the transmission or sale of firm power for resale
to
an
all-requirements
customer,
whether tendered pursuant to § 35.12 as
an initial rate schedule or tendered
pursuant to § 35.13 as a change in an existing rate schedule whose term has expired or whose term is to be extended.
(2) Rate schedules, tariffs or service
agreements covered by the terms of
paragraph (d)(1) of this section shall
contain the following provision when it
is the intent of the contracting parties
to give the party furnishing service the
unrestricted right to file unilateral
rate changes under section 205 of the
Federal Power Act:
Nothing contained herein shall be construed as affecting in any way the right of
the party furnishing service under this rate
schedule to unilaterally make application to
the Federal Energy Regulatory Commission
for a change in rates under section 205 of the
Federal Power Act and pursuant to the Commission’s Rules and Regulations promulgated thereunder.
§ 35.1
(3) Rate schedules, tariffs or service
agreements covered by the terms of
paragraph (d)(1) of this section shall
contain the following provision when it
is the intent of the contracting parties
to withhold from the party furnishing
service the right to file any unilateral
rate changes under section 205 of the
Federal Power Act:
The rates for service specified herein shall
remain in effect for the term of lllll or
until lllll, and shall not be subject to
change through application to the Federal
Energy Regulatory Commission pursuant to
the provisions of Section 205 of the Federal
Power Act absent the agreement of all parties thereto.
(4) Rate schedules covered by the
terms of paragraph (d)(1) of this section, but which are not covered by
paragraphs (d)(2) or (d)(3) of this section, are not required to contain either
of the boilerplate provisions set forth
in paragraph (d)(2) or (d)(3) of this section.
(e) No public utility shall, directly or
indirectly, demand, charge, collect or
receive any rate, charge or compensation for or in connection with electric
service subject to the jurisdiction of
the Commission, or impose any classification, practice, rule, regulation or
contract with respect thereto, which is
different from that provided in a rate
schedule required to be on file with
this Commission unless otherwise specifically provided by order of the Commission for good cause shown.
(f) A rate schedule applicable to the
sale of electric power by a public utility to the Bonneville Power Administration under section 5(c) of the Pacific
Northwest Electric Power Planning
and Conservation Act (Pub. L. No. 96–
501 (1980)) shall be filed in accordance
with subpart D of this part.
(g) For the purposes of paragraph (a)
of this section, any service agreement
that conforms to the form of service
agreement that is part of the public
utility’s approved tariff pursuant to
§ 35.10a of this chapter and any marketbased rate service agreement pursuant
to a tariff shall not be filed with the
Commission. All agreements must,
however, be retained and be made
available for public inspection and
copying at the public utility’s business
office during regular business hours
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§ 35.2
18 CFR Ch. I (4–1–19 Edition)
and provided to the Commission or
members of the public upon request.
Any individually executed service
agreement for transmission, cost-based
power sales, or other generally applicable services that deviates in any material respect from the applicable form of
service agreement contained in the
public
utility’s
tariff
and
all
unexecuted agreements under which
service will commence at the request
of the customer, are subject to the filing requirements of this part.
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 541, 40 FR 56425, Dec. 3, 1975;
Order 541–A, 41 FR 27831, July 7, 1976; 46 FR
50520, Oct. 14, 1981; Order 337, 48 FR 46976,
Oct. 17, 1983; Order 541, 57 FR 21734, May 22,
1992; Order 2001, 67 FR 31069, May 8, 2002;
Order 714, 73 FR 57530, 57533, Oct. 3, 2008; 74
FR 55770, Oct. 29, 2009]
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§ 35.2
Definitions.
(a) Electric service. The term electric
service as used herein shall mean the
transmission of electric energy in
interstate commerce or the sale of
electric energy at wholesale for resale
in interstate commerce, and may be
comprised of various classes of capacity and energy sales and/or transmission services. Electric service shall
include the utilization of facilities
owned or operated by any public utility
to effect any of the foregoing sales or
services whether by leasing or other arrangements. As defined herein, electric
service is without regard to the form of
payment or compensation for the sales
or services rendered whether by purchase and sale, interchange, exchange,
wheeling charge, facilities charge,
rental or otherwise.
(b) Rate schedule. The term rate schedule as used herein shall mean a statement of (1) electric service as defined
in paragraph (a) of this section, (2)
rates and charges for or in connection
with that service, and (3) all classifications, practices, rules, or regulations
which in any manner affect or relate to
the aforementioned service, rates, and
charges. This statement shall be in
writing and may take the physical
form of a contract, purchase or sale or
other agreement, lease of facilities, or
other writing. Any oral agreement or
understanding forming a part of such
statement shall be reduced to writing
and made a part thereof. A rate schedule is designated with a Rate Schedule
number.
(c)(1) Tariff. The term tariff as used
herein shall mean a statement of (1)
electric service as defined in paragraph
(a) of this section offered on a generally applicable basis, (2) rates and
charges for or in connection with that
service, and (3) all classifications, practices, rules, or regulations which in
any manner affect or relate to the
aforementioned service, rates, and
charges. This statement shall be in
writing. Any oral agreement or understanding forming a part of such statement shall be reduced to writing and
made a part thereof. A tariff is designated with a Tariff Volume number.
(2) Service agreement. The term service
agreement as used herein shall mean an
agreement that authorizes a customer
to take electric service under the
terms of a tariff. A service agreement
shall be in writing. Any oral agreement
or understanding forming a part of
such statement shall be reduced to
writing and made a part thereof. A
service agreement is designated with a
Service Agreement number.
(d) Filing date. The term filing date as
used herein shall mean the date on
which a rate schedule, tariff or service
agreement filing is completed by the
receipt in the office of the Secretary of
all supporting cost and other data required to be filed in compliance with
the requirements of this part, unless
such rate schedule is rejected as provided in § 35.5. If the material submitted is found to be incomplete, the
Director of the Office of Energy Market Regulation will so notify the filing
utility within 60 days of the receipt of
the submittal.
(e) Posting (1) The term posting as
used in this part shall mean:
(i) Keeping a copy of every rate
schedule, service agreement, or tariff
of a public utility as currently on file,
or as tendered for filing, with the Commission open and available during regular business hours for public inspection in a convenient form and place at
the public utility’s principal and district or division offices in the territory
served, and/or accessible in electronic
format, and
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Federal Energy Regulatory Commission
(ii) Serving each purchaser under a
rate schedule, service agreement, or
tariff either electronically or by mail
in accordance with the service regulations in Part 385 of this chapter with a
copy of the rate schedule, service
agreement, or tariff. Posting shall include, in the event of the filing of increased rates or charges, serving either
electronically or by mail in accordance
with the service regulations in Part 385
of this chapter each purchaser under a
rate schedule, service agreement or
tariff proposed to be changed and to
each State Commission within whose
jurisdiction such purchaser or purchasers distribute and sell electric energy at retail, a copy of the rate schedule, service agreement or tariff showing such increased rates or charges,
comparative billing data as required
under this part, and, if requested by a
purchaser or State Commission, a copy
of the supporting data required to be
submitted to this Commission under
this part. Upon direction of the Secretary, the public utility shall serve
copies of rate schedules, service agreements, or tariffs, and supplementary
data, upon designated parties other
than those specified herein.
(2) Unless it seeks a waiver of electronic service, each customer, State
Commission, or other party entitled to
service under this paragraph (e) must
notify the public utility of the e-mail
address to which service should be directed. A customer, State Commission,
or other party may seek a waiver of
electronic service by filing a waiver request under Part 390 of this chapter
providing good cause for its inability
to accept electronic service.
(f) Effective date. As used herein the
effective date of a rate schedule, tariff
or service agreement shall mean the
date on which a rate schedule filed and
posted pursuant to the requirements of
this part is permitted by the Commission to become effective as a filed rate
schedule. The effective date shall be 60
days after the filing date, or such other
date as may be specified by the Commission.
(g) Frequency regulation. The term frequency regulation as used in this part
will mean the capability to inject or
withdraw real power by resources capable of responding appropriately to a
§ 35.3
system operator’s automatic generation control signal in order to correct
for actual or expected Area Control
Error needs.
(16 U.S.C. 284(d), 792 et seq.; Pub. L. 95–617;
Pub. L. 95–91; E.O. 12009, 42 FR 46267)
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended at 28 FR 11404, Oct. 24, 1963; 43 FR 36437,
Aug. 17, 1978; 44 FR 16372, Mar. 19, 1979; 44 FR
20077, Apr. 4, 1979; Order 39, 44 FR 46454, Aug.
8, 1979; Order 699, 72 FR 45325, Aug. 14, 2007;
Order 701, 72 FR 61054, Oct. 29, 2007; Order 714,
73 FR 57530, Oct. 3, 2008; Order 755, 76 FR
67285, Oct. 31, 2011]
§ 35.3
Notice requirements.
(a)(1) Rate schedules or tariffs. All rate
schedules or tariffs or any part thereof
shall be tendered for filing with the
Commission and posted not less than
sixty days nor more than one hundredtwenty days prior to the date on which
the electric service is to commence and
become effective under an initial rate
schedule or tariff or the date on which
the filing party proposes to make any
change in electric service and/or rate,
charge, classification, practice, rule,
regulation, or contract effective as a
change in rate schedule or tariff, except as provided in paragraph (b) of
this section, or unless a different period of time is permitted by the Commission. Nothing herein shall be construed as in any way precluding a public utility from entering into agreements which, under this section, may
not be filed at the time of execution
thereof by reason of the aforementioned sixty to one hundred-twenty day
prior filing requirements. The proposed
effective date of any rate schedule or
tariff filing having a filing date in accordance with § 35.2(d) may be deferred
by the public utility making a filing
requesting deferral prior to the rate
schedule or tariff’s acceptance by the
Commission.
(2) Service agreements. Service agreements that are required to be filed and
posted authorizing a customer to take
electric service under the terms of a
tariff, or any part thereof, shall be tendered for filing with the Commission
and posted not more than 30 days after
electric service has commenced or such
other date as may be specified by the
Commission.
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§ 35.4
18 CFR Ch. I (4–1–19 Edition)
(b) Construction of facilities. Rate
schedules, tariffs or service agreements
predicated on the construction of facilities may be tendered for filing and
posted no more than one hundred-twenty days prior to the date set by the parties for the contract to go into effect.
The Commission, upon request, may
permit a rate schedule or service agreement or part thereof to be tendered for
filing and posted more than one hundred-twenty days before it is to become
effective.
(16 U.S.C. 284(d); Pub. L. 95–617; Pub. L. 95–91;
E.O. 12009, 42 FR 46267)
[44 FR 16372, Mar. 19, 1979; 44 FR 20077, Apr.
4, 1979, as amended by Order 714, 73 FR 57531,
Oct. 3, 2008]
§ 35.4 Permission to become effective
is not approval.
The fact that the Commission permits a rate schedule or tariff, tariff or
service agreement or any part thereof
or any notice of cancellation to become
effective shall not constitute approval
by the Commission of such rate schedule or tariff, tariff or service agreement or part thereof or notice of cancellation.
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57531, 57533, Oct. 3,
2008]
§ 35.5 Rejection of material submitted
for filing.
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(a) The Secretary, pursuant to the
Commission’s rules of practice and procedure and delegation of Commission
authority, shall reject any material
submitted for filing with the Commission which patently fails to substantially comply with the applicable requirements set forth in this part, or
the Commission’s rules of practice and
procedure.
(b) A rate filing that fails to comply
with this Part may be rejected by the
Director of the Office of Energy Market Regulation pursuant to the authority delegated to the Director in
§ 375.307(a)(1)(ii) of this chapter.
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 614, 65 FR 18227, Apr. 7, 2000;
Order 699, 72 FR 45325, Aug. 14, 2007; Order
701, 72 FR 61054, Oct. 29, 2007]
§ 35.6
Submission for staff suggestions.
Any public utility may submit a rate
schedule, tariff or service agreement or
any part thereof or any material relating thereto for the purpose of receiving
staff suggestions and comments thereon prior to filing with the Commission.
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57531, Oct. 3, 2008]
§ 35.7 Electronic filing of tariffs and
related materials.
(a) General rule. All filings made in
proceedings initiated under this part
must be made electronically, including
tariffs, rate schedules and service
agreements, or parts thereof, and material that relates to or bears upon
such documents, such as cancellations,
amendments,
withdrawals,
termination, or adoption of tariffs.
(b) Requirement for signature. All filings must be signed in compliance with
the following:
(1) The signature on a filing constitutes a certification that: the contents are true and correct to the best
knowledge and belief of the signer; and
that the signer possesses full power and
authority to sign the filing.
(2) A filing must be signed by one of
the following:
(i) The person on behalf of whom the
filing is made;
(ii) An officer, agent, or employee of
the company, governmental authority,
agency, or instrumentality on behalf of
which the filing is made; or,
(iii) A representative qualified to
practice before the Commission under
§ 385.2101 of this chapter who possesses
authority to sign.
(3) All signatures on the filing or any
document included in the filing must
comply, where applicable, with the requirements in Part 385 of this chapter
with respect to sworn declarations or
statements and electronic signatures.
(c) Format requirements for electronic
filing. The requirements and formats
for electronic filing are listed in instructions for electronic filing and for
each form. These formats are available
on the Internet at http://www.ferc.gov
and can be obtained at the Federal Energy Regulatory Commission, Public
Reference Room, 888 First Street, NE.,
Washington, DC 20426.
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Federal Energy Regulatory Commission
(d) Only filings filed and designated
as filings with statutory action dates
in accordance with these electronic filing requirements and formats will be
considered to have statutory action
dates. Filings not properly filed and
designated as having statutory action
dates will not become effective, pursuant to the Federal Power Act, should
the Commission not act by the requested action date.
(c) OATT and other open access documents filed by Independent System Operators or Regional Transmission Organizations must be filed either as individual sheets or sections. If filed as sections, the sections must be no larger
than the 1.1 level, including schedules
or attachments. Individual service
agreements that are part entered into
pursuant to the OATT may be filed as
entire documents.
[Order 714, 73 FR 57531, Oct. 3, 2008, as amended by Order 714–A, 79 FR 29076, May 21, 2014]
[Order 714, 73 FR 57531, Oct. 3, 2008]
§ 35.8 Protests and interventions by interested parties.
Unless the notice issued by the Commission provides otherwise, any protest or intervention to a rate filing
made pursuant to this part must be
filed in accordance with §§ 385.211 and
385.214 of this chapter, on or before 21
days after the subject rate filing. A
protest must state the basis for the objection. A protest will be considered by
the Commission in determining the appropriate action to be taken, but will
not serve to make the protestant a
party to the proceeding. A person wishing to become a party to the proceeding must file a motion to intervene.
[Order 612, 64 FR 72537, Dec. 28, 1999; 65 FR
18229, Apr. 7, 2000, as amended by Order 647,
69 FR 32438, June 10, 2004; Order 714, 73 FR
57531, Oct. 3, 2008]
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§ 35.10
§ 35.9 Requirements for filing rate
schedules, tariffs or service agreements.
(a) Rate schedules, tariffs, and service agreements may be filed either by
dividing the rate schedule, tariff, or
service agreements into individual
sheets or sections, or as an entire document except as provided in paragraphs
(b) and (c) of this section.
(b) Open Access Transmission Tariffs
(OATT) filed by utilities that are not
Independent System Operators or Regional
Transmission
Organizations
must be filed either as individual
sheets or sections. If filed as sections,
the sections must be no larger than the
1.0 level, although each schedule or attachment may be a single section. Individual service agreements that are entered into pursuant to the OATT may
be filed as entire documents.
§ 35.10 Form and style of rate schedules, tariffs and service agreements.
(a) Every rate schedule, tariff or
service agreement offered for filing
with the Commission under this part,
shall show on a title page, which shall
be otherwise blank, (1) the name of the
filing public utility, (2) the names of
other utilities rendering or receiving
service under the rate schedule, tariff
or service agreement ; and (3) a brief
description of the service to be provided under the rate schedule, tariff or
service agreement .
(b) At the time a public utility files
with the Commission and posts under
this part to supersede or change the
provisions of a rate schedule, tariff, or
service agreement previously filed with
the Commission under this part, in addition to the other requirements of this
part, it must list in the transmittal
letter the sheets or sections revised,
and file a marked version of the rate
schedule, tariff or service agreement
sheets or sections showing additions
and deletions. New language must be
marked by either highlighting, background shading, bold text, or underlined text. Deleted language must be
marked by strike-through.
(c) In any filing to supersede or
change the provisions of a rate schedule, tariff, or service agreement previously filed with the Commission
under this part, only those revisions
appropriately designated and marked
under paragraph (b) of this section constitute the filing. Revisions to unmarked portions of the rate schedule,
tariff or service agreement are not considered part of the filing nor will any
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§ 35.10a
18 CFR Ch. I (4–1–19 Edition)
acceptance of the filing by the Commission constitute acceptance of such
unmarked changes.
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 568, 59 FR 40240, Aug. 8, 1994;
Order 714, 73 FR 57532, Oct. 3, 2008]
§ 35.10a Forms of service agreements.
(a) To the extent a public utility
adopts a standard form of service
agreement for a service other than
market-based power sales, the public
utility shall include as part of its applicable tariff(s) an unexecuted standard service agreement approved by the
Commission for each category of generally applicable service offered by the
public utility under its tariff(s). The
standard format for each generally applicable service must reference the
service to be rendered and where it is
located in its tariff(s). The standard
format must provide spaces for insertion of the name of the customer, effective date, expiration date, and term.
Spaces may be provided for the insertion of receipt and delivery points, contract quantity, and other specifics of
each transaction, as appropriate.
(b) Forms of service agreement submitted under this section shall be filed
electronically as prescribed in § 35.7 for
the filing of rate schedules.
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[Order 2001, 67 FR 31069, May 8, 2002, as
amended by Order 714, 73 FR 57532, Oct. 3,
2008]
§ 35.10b Electric Quarterly Reports.
Each public utility as well as each
non-public utility with more than a de
minimis market presence shall file an
updated Electric Quarterly Report with
the Commission covering all services it
provides pursuant to this part, for each
of the four calendar quarters of each
year, in accordance with the following
schedule: for the period from January 1
through March 31, file by April 30; for
the period from April 1 through June
30, file by July 31; for the period July 1
through September 30, file by October
31; and for the period October 1 through
December 31, file by January 31. Electric Quarterly Reports must be prepared in conformance with the Commission’s guidance posted on the FERC
Web site (http://www.ferc.gov).
(a) For purposes of this section, the
term ‘‘non-public utility’’ means any
market participant that is exempted
from the Commission’s jurisdiction
under 16 U.S.C. 824(f).
The term does not include an entity
that engages in purchases or sales of
wholesale electric energy or transmission services within the Electric
Reliability Council of Texas or any entity that engages solely in sales of
wholesale electric energy or transmission services in the states of Alaska
or Hawaii.
(b) For purposes of this section, the
term ‘‘de minimis market presence’’
means any non-public utility that
makes 4,000,000 megawatt hours or less
of annual wholesale sales, based on the
average annual sales for resale over the
preceding three years as published by
the Energy Information Administration’s Form 861.
(c) For purposes of this section, the
following wholesale sales made by a
non-public utility with more than a de
minimis market presence are excluded
from the EQR filing requirement:
(1) Sales by a non-public utility, such
as a cooperative or joint action agency,
to its members; and
(2) Sales by a non-public utility
under a long-term, cost-based agreement required to be made to certain
customers under Federal or state statute.
[Order 768, 77 FR 61924, Oct. 11, 2012, as
amended by Order 770, 77 FR 71299, Nov. 30,
2012]
§ 35.11
Waiver of notice requirement.
Upon application and for good cause
shown, the Commission may, by order,
provide that a rate schedule or tariff,
tariff or service agreement, or part
thereof, shall be effective as of a date
prior to the date of filing or prior to
the date the rate schedule or tariff,
tariff or service agreement would become effective in accordance with
these rules. Application for waiver of
the prior notice requirement shall
show (a) how and the extent to which
the filing public utility and purchaser(s) under such rate schedule or
tariff, tariff or service agreement, or
part thereof, would be affected if the
notice requirement is not waived, and
(b) the effects of the waiver, if granted,
upon purchasers under other rate
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Federal Energy Regulatory Commission
schedules. The filing public utility requesting such waiver of notice shall
serve copies of its request therefor
upon all purchasers.
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57532, 57533, Oct. 3,
2008]
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Subpart B—Documents To Be
Submitted With a Filing
§ 35.12 Filing of initial rate schedules
and tariffs.
(a) The letter of a public utility
transmitting to the Commission for filing an initial rate schedule or tariff
shall list the documents submitted
with the filing; give the date on which
the service under that rate schedule or
tariff is expected to commence; state
the names and addresses of those to
whom the rate schedule or tariff has
been mailed; contain a brief description of the kinds of services to be furnished at the rates specified therein;
and summarize the circumstances
which show that all requisite agreement to the rate schedule or tariff or
the filing thereof, including any contract embodied therein, has in fact
been obtained. In the case of coordination and interchange arrangements in
the nature of power pooling transactions, all supporting data required to
be submitted in support of a rate
schedule or tariff filing shall also be
submitted by parties filing certificates
of concurrence, or a representative to
file supporting data on behalf of all
parties may be designated as provided
in § 35.1.
(b) In addition, the following material shall be submitted:
(1) Estimates of the transactions and
revenues under an initial rate schedule.
This shall include estimates, by
months and for the year, of the quantities of services to be rendered and of
the revenues to be derived therefrom
during the 12 months immediately following the month in which those services will commence. Such estimates
should be subdivided by classes of service, customers, and delivery points and
shall show all billing determinants,
e.g., kw, kwh, fuel adjustment, power
factor adjustment. These estimates
will not be required where they cannot
be made with relative accuracy as, for
§ 35.12
example, in cases of interconnection
arrangements containing schedules of
rates for emergency energy, spinning
reserve or economy energy or in cases
of coordination and integration of hydroelectric generating resources whose
output cannot be predicted quantitatively due to water conditions.
(2)(i) Basis of the rate or charge proposed in an initial rate schedule or tariff and an explanation of how the proposed rate or charge was derived. For
example, is it a standard rate of the filing public utility; is it a special rate
arrived at through negotiations and, if
so, were unusual customer requirements or competitive factors involved;
and is it designed to produce a return
substantially equal to the filing public
utility’s overall rate of return or is it
essentially an increment cost plus a
share of the savings rate? Were special
cost of service studies prepared in connection with the derivation of the rate?
(ii) A summary statement of all cost
(whether fully distributed, incremental
or other) computations involved in arriving at the derivation of the level of
the rate, in sufficient detail to justify
the rate, shall be submitted with the
filing, except that if the filing includes
nothing more than service to one or
more added customers under an established rate of the utility for a particular class of service, such summary
statement of cost computations is not
required. In all cases, the Secretary is
authorized to require the submission of
the complete cost studies as part of the
filing and each filing public utility
shall submit the same upon request by
the Secretary in such form as he or she
shall direct.
(3) A comparison of the proposed initial rate with other rates of the filing
public utility for similar wholesale for
resale and transmission services.
(4) If any facilities are installed or
modified in order to supply the service
to be furnished under the proposed rate
schedule or tariff, the filing public utility shall show on an appropriate available map (or sketch) and single line
diagram the additions or changes to be
made.
(5) In support of the design of the
proposed rate, the filing public utility
shall submit the same material required to be furnished pursuant to
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
§ 35.13(h)(37) Statement BL. In addition
to the summary cost analysis required
by Statement BL, the public utility
shall also submit a complete explanation as to the method used in arriving at the cost of service allocated to
the sales and service for which the rate
or charge is proposed, and showing the
principal determinants used for allocation purposes. In connection therewith,
the following data should be submitted:
(i) In the event the filing public utility considers certain special facilities
as being devoted entirely to the service
involved, it shall show the cost of service related to such special facilities.
(ii) Computations showing the energy
responsibility of the service, based
upon considerations of energy sales
under the proposed rate schedule or
tariff and the kWh delivered from the
filing public utility’s supply system.
(iii) Computations showing the demand responsibility of the service, and
explaining the considerations upon
which such responsibility was determined (e.g., coincident or non-coincident peak demands, etc.).
(Federal Power Act, 16 U.S.C. 792–828c; Department of Energy Organization Act, 42
U.S.C. 7101–7352; E.O. 12009, 42 FR 46267; Pub.
L. 96–511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.))
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended at 28 FR 11404, Oct. 24, 1963; Order 537, 40
FR 48674, Oct. 17, 1975; Order 91, 45 FR 46363,
July 10, 1980; Order 714, 73 FR 57532, Oct. 3,
2008]
§ 35.13 Filing of changes in rate schedules, tariffs or service agreements.
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CONTENTS
(a) General rule.
(1) Filing for any rate schedule change not
otherwise excepted.
(2) Abbreviated filing requirements.
(3) Cost of service data required by letter.
(b) General information.
(c) Information relating to the effect of the
rate schedule change.
(d) Cost of service information.
(1) Filing of Period I data.
(2) Filing of Period II data.
(3) Definitions.
(4) Test period.
(5) Work papers.
(6) Additional information.
(7) Attestation.
(e) Testimony and exhibits.
(1) Filing requirements.
(2) Case in chief.
(3) Burden of proof.
(f) Filing by parties concurring in coordination and interchange arrangements.
(g) Commission precedents and policy.
(h) Cost of service statements.
(1) AA—Balance sheets.
(2) AB—Income statements.
(3) AC—Retained earnings statements.
(4) AD—Cost of plant.
(5) AE—Accumulated depreciation and amortization.
(6) AF—Specified deferred credits.
(7) AG—Specified plant accounts (other
than plant in service) and deferred debits.
(8) AH—Operation and maintenance expenses.
(9) AI—Wages and salaries.
(10) AJ—Depreciation and amortization expenses.
(11) AK—Taxes other than income taxes.
(12) AL—Working capital.
(13) AM—Construction work in progress.
(14) AN—Notes payable.
(15) AO—Rate for allowance for funds used
during construction.
(16) AP—Federal income tax deductions—
interest.
(17) AQ—Federal income tax deductions—
other than interest.
(18) AR—Federal tax adjustments.
(19) AS—Additional state income tax deductions.
(20) AT—State tax adjustments.
(21) AU—Revenue credits.
(22) AV—Rate of return.
(23) AW—Cost of short-term debt.
(24) AX—Other recent and pending rate
changes.
(25) AY—Income and revenue tax rate data.
(26) BA—Wholesale customer rate groups.
(27) BB—Allocation demand and capability
data.
(28) BC—Reliability data.
(29) BD—Allocation energy and supporting
data.
(30) BE—Specific assignment data.
(31) BF—Exclusive-use commitments of
major power supply facilities.
(32) BG—Revenue data to reflect changed
rates.
(33) BH—Revenue data to reflect present
rates.
(34) BI—Fuel cost adjustment factors.
(35) BJ—Summary data tables.
(36) BK—Electric utility department cost
of service, total and as allocated.
(37) BL—Rate design information.
(38) Statement BM—Construction program
statement.
(a) General rule. Every public utility
shall file the information required by
this section, as applicable, at the time
it files with the Commission under
§ 35.1 all or part of a rate schedule, tariff or service agreement to supersede or
otherwise change the provisions of a
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Federal Energy Regulatory Commission
rate schedule, tariff or service agreement filed with the Commission under
§ 35.1. Any petition filed under § 385.207
of this chapter for waiver of any provision of this section shall specifically
identify the requirement that the applicant wishes the Commission to
waive.
(1) Filing for any rate schedule change
or tariff not otherwise excepted. Except
as provided in paragraph (a)(2) of this
section, any utility that files a rate
schedule, tariff, or service agreement
change shall submit with its filing the
information specified in paragraphs (b),
(c), (d), (e), and (h) of this section, in
accordance with paragraph (g) of this
section.
(2) Abbreviated filing requirements—(i)
For certain small rate increases. Any
utility that files a rate increase for
power or transmission services not covered by paragraph (a)(2)(ii) of this section may elect to file under this paragraph instead of paragraph (a)(1) of this
section, if the proposed increase for the
Test Period, as defined in paragraph
(a)(2)(i)(A) of this section, is equal to
or less than $200,000, regardless of customer consent, or equal to or less than
$1 million if all wholesale customers
that belong to the affected rate class
consent.
(A) Definition: The Test Period, for
purposes of paragraph (a)(2)(i) of this
section, means the most recent calendar year for which actual data are
available, the last day of which is no
more than fifteen months before the
date of tender for filing under § 35.1 of
the notice of rate schedule.
(B) Any utility that elects to file
under this subparagraph must file the
following information, conforming its
submission to any rule of general applicability and to any Commission order
specifically applicable to such utility:
(1) A complete cost of service analysis for the Test Period, consistent
with the requirements of paragraph
(h)(36), Statement BK, of this section.
(2) A complete derivation and explanation of all allocation factors and special assignments, consistent with the
information required in § 35.12(b)(5).
(3) A complete calculation of revenues for the Test Period and for the
first 12 months after the proposed effective date, consistent with the re-
§ 35.13
quirements of paragraph (c)(1) of this
section.
(4) If the proposed rates contain a
fuel cost or purchased economic power
adjustment clause, as defined in § 35.14,
the company must provide the derivation of its base cost of fuel (Fb) and its
monthly fuel factors (Fm) for the Test
Period and the resulting fuel adjustment clause revenues. If any pro forma
adjustments affect the fuel clause in
any way, the company must show the
impact on Fm, kWh sales in the base
period (Sm), Fb and kWh sales in the
current period (Sb), as well as on fuel
adjustment clause revenues.
(5) Rate design calculations and narrative consistent with the information
required in paragraph (h)(37) of this
section and in § 35.12(b)(5).
(6) The information required in paragraphs (b), (c)(2) and (c)(3) of this section and in § 35.12(b)(2).
(C) Data shall be reconciled with the
utility’s most recent FERC Form 1. If
the utility has not yet submitted Form
1 for the Test Period, the utility shall
submit the relevant Form 1 pages in
draft form.
(D) The utility may make pro forma
adjustments
for
post-Test
Period
changes that occur before the proposed
effective date and that are known and
measurable at the time of filing. The
utility shall provide a narrative statement explaining all pro forma adjustments.
(E) If the utility models its filing in
whole or in part on retail rate decisions or settlements, the utility must
provide detailed calculations and a
narrative statement showing how all
retail rate treatments are factored into
the cost of service.
(F) If the Commission sets the filing
for hearing, the Commission will allow
the company a specific time period in
which to file testimony, exhibits, and
supplemental workpapers to complete
its case-in-chief. While not required
under this subpart, a utility may elect
to submit Statements AA through BM
for the Test Period in accord with the
requirements of paragraphs (d), (g) and
(h) of this section.
(ii) Rate increases for service of short
duration or for interchange or coordination service. Any utility that files a rate
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
increase for any service of short duration and of a type for which the need
and usage cannot be reasonably forecasted (such as emergency or shortterm power), or for service that is an
integral part of a coordination and
interchange arrangement, may submit
with its filing only the information required in paragraphs (b), (c) and (h)(37)
of this section and in § 35.12(b)(2) and
(b)(5), conforming its submission to
any rule of general applicability and to
any Commission order specifically applicable to such utility.
(iii) For rate schedule, tariff, or service
agreement changes other than rate increases. Any utility that files a rate
change that does not provide for a rate
increase or that provides for a rate increase that is based solely on a change
in delivery points, a change in delivery
voltage, or a similar change in service,
must submit with its filing only the information required in paragraphs (b)
and (c) of this section.
(iv) Computing rate increases. For purposes of this subparagraph and paragraph (d)(2)(ii) of this section, the
amount of any rate increase shall be
the difference between the total revenues to be recovered under the rate
change and the total revenues recovered or recoverable under the rate to be
superseded or supplemented and shall
be determined by:
(A) applying the components of the
rate to be superseded or supplemented
to the billing determinants for the
twelve months of Period I;
(B) Applying the components of the
rate change to the billing determinants
for the twelve months of Period I; and
(C) Subtracting the total revenues
under subclause (A) from the total revenues under subclause (B).
(3) Cost of service data required by letter. The Director of the Office of Energy Market Regulation may, by letter, require a utility that is not required under paragraph (a)(1) of this
section to submit cost of service data
to submit such specified cost of service
data as are needed for Commission
analysis of the rate schedule change.
(b) General information. Any utility
subject to paragraph (a) of this section
shall file the following general information:
(1) A list of documents submitted
with the rate change;
(2) The date on which the utility proposes to make the rate change effective;
(3) The names and addresses of persons to whom a copy of the rate change
has been posted;
(4) A brief description of the rate
change;
(5) A statement of the reasons for the
rate change;
(6) A showing that all requisite
agreement to the rate change, or to the
filing of the rate change, including any
agreement required by contract, has in
fact been obtained;
(7) A statement showing any expenses or costs included in the cost of
service statements for Period I or Period II, as defined in paragraph (d)(3) of
this section, that have been alleged or
judged in any administrative or judicial proceeding to be illegal, duplicative, or unnecessary costs that are demonstrably the product of discriminatory employment practices; and
(c) Information relating to the effect of
the rate change. Any utility subject to
paragraph (a) of this section shall also
file the following information or materials:
(1) A table or statement comparing
sales and services and revenues from
sales and services under the rate schedule, tariff, or service agreement to be
superseded and under the rate change,
by applying the components of each
such rate schedule or tariff to the billing determinants for each class of service, for each customer, and for each delivery point or set of delivery points
that constitutes a billing unit:
(i) Except as provided in clause (ii),
for each of the twelve months immediately before and each of the twelve
months immediately after the proposed
effective date of the rate change, and
the total for each of the two twelve
month periods; or
(ii) At the election of the utility:
(A) If the utility files Statements BG
and BH under paragraph (h) for Period
I, for each of the twelve months of Period I instead of for the twelve months
immediately before the proposed effective date of the rate change; and
(B) If Period II is the test period, for
each of the twelve months of Period II
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Federal Energy Regulatory Commission
instead of for the twelve months immediately after the proposed effective
date of the rate change;
(2) A comparison of the rate change
and the utility’s other rates for similar
wholesale for resale and transmission
services; and
(3) If any specifically assignable facilities have been or will be installed or
modified in order to supply service
under the rate change, an appropriate
map or sketch and single line diagram
showing the additions or changes to be
made.
(d) Cost of service information—(1) Filing of Period I data. Any utility that is
required under paragraph (a)(1) of this
section to submit cost of service information, or that is subject to the exceptions in paragraphs (a)(2)(i) and
(a)(2)(ii) of this section but elects to
file such information, shall submit
Statements AA through BM under
paragraph (h) of this section using:
(i) Unadjusted Period I data; or
(ii) Period I data adjusted to reflect
changes that affect revenues and costs
prior to the proposed effective date of
the rate change and that are known
and measurable with reasonable accuracy at the time the rate schedule
change is filed, if such utility:
(A) Is not required to and does not
file Period II data;
(B) Adjusts all Period I data to reflect such changes; and
(C) Fully supports the adjustments in
the appropriate cost of service statements.
(2) Filing of Period II data. (i) Except
as provided in clause (ii) of this subparagraph, any utility that is required
under paragraph (a)(1) of this section
to submit cost of service information
shall submit Statements AA through
BM described in paragraph (h) using estimated costs and revenues for Period
II;
(ii) A utility may elect not to file Period II data if:
(A) The utility files a rate increase
that is less than one million dollars for
Period I; or
(B) All wholesale customers that belong to the affected rate class have
consented to the rate increase.
(3) Definitions. For purposes of this
section:
§ 35.13
(i) Period I means the most recent
twelve consecutive months, or the
most recent calendar year, for which
actual data are available, the last day
of which is no more than fifteen
months before the date of tender for
filing under § 35.1 of the notice of rate
change;
(ii) Period II means any period of
twelve consecutive months after the
end of Period I that begins:
(A) No earlier than nine months before the date on which the rate change
is proposed to become effective; and
(B) No later than three months after
the date on which the rate change is
proposed to become effective.
(4) Test period. If Period II data are
not submitted for Statements AA
through BM, Period I shall be the test
period. If Period II data are submitted
for Statements AA through BM, Period
II shall be the test period.
(5) Work papers. A utility that files
adjusted Period I data or that files Period II data shall submit all work papers relating to such data. The utility
shall provide a comprehensive explanation of the bases for the adjustments
or estimates and, if such adjustments
or estimates are based on a regularly
prepared corporate budget, shall include relevant excerpts from such
budget. Work papers and documents
containing additional explanatory material shall be provided in electronic
format, shall be legible, shall be assigned page numbers, and shall be
marked, organized and indexed according to:
(A) Subject matter;
(B) The cost of service statements to
which they apply; and
(C) Witness.
(6) Attestation. A utility shall include
in its filing an attestation by its chief
accounting officer or another of its officers that, to the best of that officer’s
knowledge, information, and belief, the
cost of service statements and supporting data submitted under this
paragraph are true, accurate, and current representations of the utility’s
books, budgets, or other corporate documents.
(e) Testimony and exhibits—(1) Filing
requirements. (i) A utility subject to
paragraph (a)(1) of this section shall
file Statements AA through BM under
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
paragraph (h) as exhibits with its rate
change and may file any other exhibits
in support of its rate schedule change.
(ii) A utility subject to paragraph
(a)(1) of this section shall file prepared
testimony. Such testimony shall include an explanation of all exhibits, including Statements AA through BM,
and shall include support for all adjustments to book or budgeted data relied
on in preparing the exhibits.
(iii) To the extent that testimony
and exhibits other than Statements AA
through BM duplicate information required to be submitted in such statements, the testimony and exhibits may
incorporate such information by referencing the specific statement containing such material.
(2) Case in chief. In order to avoid
delay in processing rate filings, such
cost of service statements, testimony,
and other exhibits described in paragraph (e)(1) of this section shall be the
utility’s case in chief in the event the
matter is set for hearing.
(3) Burden of proof. Any utility that
files a rate increase shall be prepared
to go forward at a hearing on reasonable notice on the data submitted
under this section, to sustain the burden of proof under the Federal Power
Act of establishing that the rate increase is just and reasonable and not
unduly discriminatory or preferential
or otherwise unlawful within the meaning of the Act.
(f) Filing by parties concurring in coordination and interchange arrangements.
For coordination and interchange arrangements in the nature of power
pooling transactions, all information
required to be submitted in support of
a rate change under paragraphs (a)(1),
(2), and (3) of this section shall be submitted by each party filing a certificate of concurrence under § 35.1. If a
representative is designated and authorized in accordance with § 35.1 to file
supporting information on behalf of all
parties to a rate change, such filing
shall fulfill the requirement in this
paragraph for individual submittals by
each party.
(g) Commission precedents and policy.
If a utility submits cost of service data
under paragraph (d) of this section, it
shall conform all such submissions to
any rule of general applicability and to
any Commission order specifically applicable to such utility.
(h) Cost of service statements. Any utility subject to paragraph (a)(1) of this
section shall submit the following
Statements AA through BM in accordance with the requirements of paragraphs (d) and (g) of this section.
(1) Statement AA—Balance sheets.
Statement AA consists of balance
sheets as of the beginning and the end
of both Period I and Period II, and the
most recently available balance sheet,
including any applicable notes, and an
explanation of any significant accounting changes since the most recent filing by the utility under this section
that involves the same wholesale customer rate class. Balance sheets shall
be constructed in accordance with the
annual report form for electric utilities
specified in part 141.
(2) Statement AB—Income statements.
Statement AB consists of income
statements for both Period I and Period II, and the most recently available
income statement, including any applicable notes, and an explanation of any
significant accounting changes since
the most recent filing by the utility
under this section that involves the
same wholesale customer rate class. Income statements shall be prepared in
accordance with the annual report
form for electric utilities specified in
part 141.
(3) Statement AC—Retained earnings
statements. Statement AC consists of
retained earnings statements for both
Period I and Period II, and the most recently available retained earnings
statement, including any notes applicable thereto. Retained earnings statements shall be prepared in accordance
with the annual report form for electric utilities specified in part 141.
(4) Statement AD—Cost of plant. Statement AD is a statement of the original
cost of total electric plant in service
according to functional classification
for Period I and Period II. If the plant
functions and subfunctions for Period I
and Period II are different, the utility
shall explain and justify the differences.
(i) For each separately identified
function and subfunction of production
plant or transmission plant, the utility
shall state the original cost as of the
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Federal Energy Regulatory Commission
beginning of the first month and the
end of each month of both Period I and
Period II, with an average of the thirteen balances for each period. If any of
the Period I or Period II thirteen
monthly balances is not available or is
unrepresentative of the current plan of
the utility for plant in service, the
utility shall provide an explanation of
the relevant circumstances.
(ii) For each separately identified
function and subfunction of plant other
than production or transmission, the
utility shall state the original cost as
of the beginning and the end of both
Period I and Period II, with an average
of the beginning and end balances for
each period. If any of the Period I or
Period II balances is not available or is
unrepresentative of the current plan of
the utility for plant in service, the
utility shall provide an explanation of
the relevant circumstances.
(iii) The utility shall show the electric plant in service in accordance with
each of the following five major functional classifications:
(A) Production;
(B) Transmission;
(C) Distribution;
(D) General and Intangible; and
(E) Common and Other.
(iv) To the extent feasible, the utility
shall show completed construction not
classified in accordance with clause
(iii) in accordance with tentative classification to major functional accounts. If this is not feasible, the utility shall describe such facilities as
other plant under clause (iii)(E).
(v) If a utility designs its rate change
so that subdivision of the major functional classifications is necessary to
support the changed rate, the utility
shall supply the original cost information for any of the five major functional plant classifications in clause
(iii) that are divided into subfunctional
categories. If subfunctional original
cost information is provided, the utility shall explain the importance of providing such information to support the
changed rate. The utility shall describe
each subfunctional category in substantive terms, such as steam electric
production or high voltage transmission.
(vi) The utility shall select any subfunctional categories, as appropriate,
under the following criteria:
§ 35.13
(A) Production plant categories shall
be established as necessary to segregate costs for production services
with special characteristics, such as
base, intermediate or peaking load.
The utility shall provide a description
of each such service and shall list a
brief descriptive title for each corresponding subfunctional category.
(B) Transmission plant categories
shall be chosen to reflect the extent to
which the facilities are proposed to be
allocated on a common basis among all
or specific segments of utility services.
For descriptive purposes, plant may
also be categorized according to accounting or engineering terminology,
such as high voltage overhead lines. The
utility shall provide brief descriptive
transmission category titles and explain the basis for the titles. If a utility allocates all transmission plant
among utility services on the basis of a
single set of allocation data, the utility
may show original cost in total without subfunctionalization.
(C) Distribution plant categories
shall be selected according to engineering or use characteristics meaningful
for allocations or assignments to
wholesale services such as substations,
overhead lines, meters, or non-wholesale. The utility shall provide brief descriptive distribution category titles
and shall explain the basis for the titles.
(D) If the utility divides any general,
intangible, common, and other plant
functional classifications into subfunctional categories, the subfunctional
categories shall be chosen to group together facilities that share a common
basis for allocation between wholesale
and other electric services. The utility
shall provide a brief descriptive title
for each general and intangible subfunctional category, and for each common and other subfunctional category,
with an explanation of the basis of
each category selection. A utility need
not divide the functional classifications of plant into subfunctional categories if these functions of plant are
allocated in Statement BK on the basis
of utility labor expenses.
(E) A separate category shall be provided for each specific assignment of
plant reported in Statement BE. Such
assignments are applicable principally
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
but not necessarily exclusively to distribution facilities. The utility shall
provide brief descriptive titles consistent with Statement BE.
(F) A separate category shall be provided for each exclusive-use commitment of major power supply facilities
as required to be reported at Statement BF. The utility shall provide
brief descriptive titles consistent with
Statement BF.
(5) Statement AE—Accumulated depreciation and amortization. Statement AE
is a statement of the accumulated provision for depreciation and amortization of electric plant for Period I and
Period II, provided according to major
functional classifications selected by
the utility in Statement AD under
paragraph (h)(4) and divided into the
subfunctional categories selected by
the utility in Statement AD, to the extent that subfunctionalized data are
available.
(i) For each function and subfunction
of electric production and transmission
plant in service identified in Statement AD, the utility shall set forth the
accumulated depreciation and amortization as of the beginning of the first
month and the end of each month of
both Period I and Period II. The utility
shall state an average for each period
computed as the average of the thirteen balances.
(ii) For each function and subfunction of electric plant in service other
than production or transmission, identified in Statement AD, the utility
shall state the accumulated depreciation and amortization as of the beginning and the end of Period I and Period
II, with an average of the beginning
and end balances for each period.
(iii) If any of the Period I or Period II
balances is not available or is unrepresentative of the current plan of the
utility for depreciation reserves, the
utility shall provide an explanation of
the relevant circumstances.
(iv) If accumulated depreciation and
amortization data are not available for
any subfunction selected in Statement
AD, the utility shall:
(A) Provide a comparison of the current depreciation rate of the major
functional classification and the depreciation rate estimated to be appro-
priate to the subfunctional category;
and
(B) State and explain the estimation
techniques which the utility proposes
to utilize in the absence of subfunctional data, such as the proration of
accumulated depreciation and amortization data among the subfunctional
categories according to the data for
electric plant in service in Statement
AD. If any of the proposed estimation
techniques require data that are not
provided elsewhere in the cost of service statements in paragraph (h) of this
section, the utility shall supply the
necessary data in Statement AE.
(6) Statement AF—Specified deferred
credits. Statement AF consists of balances of specified accounts and items
which are to be considered in the determination of the net original cost rate
base. All required balances are to be
stated as of the beginning and end of
both Period I and Period II, with an average of the beginning and end balances for each period. If any of the Period I and Period II balances is not
available or is unrepresentative of the
current operating plan of the utility,
the utility shall include an explanation
of the relevant circumstances. If subaccounts are maintained to reflect differences in ratemaking treatment
among regulatory authorities that
have jurisdiction, balances shall be
provided in accordance with such subaccounts, with detailed explanations of
the bases upon which the subaccounts
were established and are maintained.
The balances of deferred credits required to be filed in this statement are
described in paragraph (h)(6) (i)
through (v) of this section. All references to numbered accounts refer to
the Commission’s Uniform System of
Accounts, 18 CFR part 101.
(i) The utility shall state total electric balances for accumulated deferred
investment tax credits Account 255,
and shall separate the credits into balances applicable to pre-1971 and post1970 qualifying property additions. If
the utility maintains records to show
Account 255 component balances according to the major functional classifications identified in Statement AD
under paragraph (h)(4), the utility shall
provide the component balances by
function. If the data are not available
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Federal Energy Regulatory Commission
by function, the utility shall describe
the procedure by which the utility believes it can reasonably estimate the
portion of the total electric balances
for each major functional classification. The utility may show by function
the component balances obtained by
applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service
statements in this paragraph, the utility shall supply in Statement AF the
necessary data, such as historical functional patterns of plant additions eligible for the tax credits. The utility shall
state whether the Internal Revenue
Code General Rule, § 46(f)(1), is applicable with respect to restrictions on credit treatment for ratemaking purposes.
If the General Rule is not applicable,
the utility shall state which election it
has made with respect to special rules
for ratable or immediate flow-through
for ratemaking purposes.
(ii) The utility shall state the total
electric component balances for accumulated deferred income tax Account
281 pertaining to accelerated amortization property. The utility shall show
separate components for defense, pollution control, and other facilities. The
utility shall show balances for each
component and totaled for the electric
utility department. If the utility maintains records to show Account 281 component balances according to the major
functional classifications identified in
Statement AD under paragraph (h)(4),
the utility shall provide such component balances. If data are not available
by function, the utility shall describe
the procedure by which the utility believes it can reasonably estimate the
portion of the total electric balances
for each major functional classification. The utility may show by function
the component balances obtained by
applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service
statements in this paragraph, the utility shall supply in Statement AF the
necessary data.
(iii) The utility shall state the total
electric component balances for accumulated deferred income tax Account
282 pertaining to electric utility property other than accelerated amortization property. The utility shall itemize
§ 35.13
the balances in Account 282, to the extent data are available, in detail sufficient to identify the specific major
properties involved and shall list the
balances according to the accounting
entries, such as liberalized depreciation, for which interperiod tax allocation was used and included in this account. Component balances shall be
shown individually and in total for the
electric utility department. If the utility maintains records to show account
282 component balances according to
the major functional classifications
identified in Statement AD under paragraph (h)(4), the utility shall provide
such component balances by function.
If the data are not available by function, the utility shall describe the procedure by which the utility believes it
can reasonably estimate the portion of
the total electric balances for each
major functional classification. The
utility may show by function the component balances obtained by applying
the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements
in this paragraph, the utility shall supply in Statement AF the necessary
data, such as historical functional patterns of plant additions.
(iv) The utility shall state the total
electric component balances for accumulated deferred income tax Account
283 pertaining to interperiod income
tax allocations not related to property.
The utility shall itemize in detail balances in Account 283, to the extent
data are available, and shall list the
balances according to the accounting
entries for which interperiod tax allocation was used and included in this
account. Component balances shall be
shown individually and in total for the
electric utility department. If the utility maintains records to show Account
283 component balances according to
the major functional classifications
identified in Statement AD under paragraph (h)(4), the utility shall provide
such component balances by function.
If the data are not available by function, the utility shall describe the procedure by which the utility believes it
can reasonably estimate the portion of
the total electric balances for each
major functional classification. The
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
utility may show by function the component balances obtained by applying
the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements
in this paragraph, the filing shall supply in Statement AF the necessary
data.
(v) The utility shall show electric
utility balances for every other item
that the utility believes should be included in Statement AF. The utility
shall explain the reasons for inclusion
of each item.
(7) Statement AG—Specified plant accounts (other than plant in service) and
deferred debits. Statement AG is a
statement of balances of specified accounts and items that are to be considered in the determination of the net
original cost rate base. Except as prescribed in clause (ii), the utility shall
state all required balances as of the beginning and the end of Period I and Period II, with an average of the beginning and end balances for each period.
If any of the Period I or Period II balances is not available or is unrepresentative of the current operating plan
of the utility, the utility shall provide
a full explanation of the relevant circumstances. If subaccounts are maintained to reflect differences in ratemaking treatment among regulatory
authorities having jurisdiction, the
utility shall provide balances in accordance with such subaccounts, with
detailed explanations of the bases upon
which the subaccounts were established and are maintained. The balances required to be submitted under
Statement AG are described in clauses
(7)(i) through (vi).
(i) For each separately identified
major functional classification selected
by the utility in Statement AD, the
utility shall state the electric utility
land and land rights balances for electric plant held for future use in account 105. If itemized in detail, balances shall be totaled for each major
functional classification.
(ii) The utility shall state the electric utility component balances in Accounts 107 and 120.1, individually and in
total, for each item of construction
work in progress for pollution control
facilities, fuel conversion facilities, or
any other facilities that qualify for in-
clusion in rate base under § 35.26. The
utility shall state such balances for
each major functional and subfunctional classification under Statement
AD as of the beginning of the first
month and the end of each month of
Period I and Period II with an average
of the 13 balances for each period.
(iii) For each major functional classification under Statement AD and with
respect to property otherwise includable in plant in service, the utility
shall state the balances for extraordinary property losses Account 182. If
itemized in detail, balances shall be totaled for each major functional classification. The utility shall provide information about Commission authorization for any loss included in Account 182 and shall state when the loss
was claimed for tax purposes.
(iv) The utility shall state the total
electric component balances for accumulated deferred income taxes Account 190. The component balances in
Account 190 shall be itemized in detail
and listed according to the accounting
entries for which interperiod tax allocation was used. Component balances
shall be shown individually and in
total for the electric utility department. If the utility maintains records
to show Account 190 component balances according to the major functional classifications identified in
Statement AD under paragraph (h)(4),
the utility shall provide such component balances by function. If the data
are not available by function, the filing
utility shall describe the procedure by
which the utility believes it can reasonably estimate the portion of the
total electric balances for each major
functional classification. The utility
may show by function the component
balances obtained by applying the procedure. If such estimation requires
data that are not provided elsewhere in
the cost of service statements in this
paragraph, the utility shall supply in
Statement AG the necessary data.
(v) Balances shall be shown for every
other item that the utility believes
should be included in Statement AG.
The utility shall provide support for inclusion of each item, and a brief descriptive title for each such item.
(8) Statement AH—Operation and maintenance expenses. Statement AH is a
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Federal Energy Regulatory Commission
statement of electric utility operation
and maintenance expenses for Period I
and Period II provided according to the
accounts prescribed by the Commission’s Uniform System of Accounts, 18
CFR part 101.
(i) For Period I and Period II, the
utility shall itemize and subtotal all
operation and maintenance expenses
according to the major functional classifications of Statement AD in paragraph (h)(4) and the subfunctional categories of those classifications. The
utility shall further divide the operation
and
maintenance
expenses
itemized under the production classification and each of its subfunctional
categories to reflect expenses relating
to the energy component (list each
item by account number and compute
fuel costs on an as-burned basis), the
demand component, and any other production expenses.
(ii) For Period I and Period II, the
utility shall report production operation and maintenance expenses according to appropriate account numbers. The utility shall apply the following principles in developing Period
I and Period II production operation
and maintenance data for this statement:
(A) Total production operation and
maintenance expenses shall be segregated into energy, demand, and other
components. The utility shall specifically state and support its criteria for
classifications between energy and demand, and for use of the production
other classification, such as specific assignments related to sales from particular generating units.
(B) Fuel expense for cost of service
purposes shall be the total as-burned
expense incurred. If the utility defers a
portion of such expense for accounting
purposes, the deferral amount shall be
separately stated and accompanied by
material that shows computational detail in support of such amount. If
claimed nuclear fuel expense reflects a
change in the estimated net salvage
value of nuclear fuel, the utility shall
show the amounts involved and explain
the relevant circumstances.
(C) If the amount of production fuel
expense is significantly affected by abnormal Period I water availability for
hydroelectric generation, the utility
§ 35.13
shall explain how water availability
was taken into account in developing
projected Period II production fuel expenses.
(iii) For Period I and Period II, the
utility shall report operation and
maintenance expenses attributable to
the transmission and distribution functions according to appropriate account
numbers. If Period II transmission and
distribution plant data are not provided by subfunctional category in
Statement AD, the utility need only
provide for Period II total operation
and maintenance expenses for each
function.
(iv) For Period I and Period II, the
utility shall report in total for each period, operation and maintenance expenses incurred under each of the categories of customer accounting, customer service and information, and
sales.
(v) For Period I and Period II, the
utility shall itemize administrative
and general expenses by groups that
are directly assignable, such as regulatory Commission expenses, or that
are related to selected plant or expense
items for which an allocation to wholesale services is independently determinable, such as items related to labor
expense or to a category of production
plant in service. Administrative and
general expenses shall include a detailed itemization of the general advertising Account 930.1 and the miscellaneous general expenses Account 930.2.
If Account 930 data are not projected
on a detailed basis for Period II, the
utility shall provide its best estimate
of the Account 930.1 expense items and
a descriptive list of expense items anticipated as miscellaneous general expenses in Account 930.2. Where applicable, separate items shall be shown for
general plant maintenance, and for
common and other plant maintenance.
(vi) In addition to annual production
data for Period I and Period II, the
utility shall provide monthly expense
data by accounts for fuel in Accounts
501, 518, and 547 and purchased power in
Account 555. For each type of transaction, such as firm power or economy
interchange power, monthly purchased
power expense data shall be subtotaled
separately for interchange receipts and
deliveries. For monthly fuel Accounts
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
501, 518, and 547, and for each type of
purchased power transaction, the
monthly data shall identify components to be claimed under the fuel adjustment clause of the utility.
(9) Statement AI—Wages and salaries.
Statement AI consists of statements of
the electric utility wages and salaries,
for Period I and Period II, that are included in operation and maintenance
expenses reported in Statement AH.
(i) For Period I and Period II, the
utility shall show the distribution of
wages and salaries by function according to the form prescribed for operation and maintenance expenses by the
Commission’s Uniform System of Accounts, 18 CFR part 101. The statement
shall also include by function additional wages and salaries attributable
to common and other plant classifications identified in Statement AD in
paragraph (h)(4).
(ii) For Period I and Period II, the
utility shall show total production
wages and salaries, itemized and subtotaled into energy and demand related
components in accordance with classifications of Statement AH operation
and maintenance production expenses
of which production wages and salaries
are a part.
(10) Statement AJ—Depreciation and
amortization expenses. Statement AJ
consists of statements of depreciation
and amortization expenses for Period I
and Period II.
(i) For Period I and Period II, the
utility shall show the depreciation and
amortization expenses and the depreciable plant balances of the filing utility, in accordance with major functional classifications selected by the
utility in Statement AD under paragraph (h)(4).
(ii) The utility shall divide the major
functional classifications of depreciation and amortization expenses shown
in clause (i) into the subfunctional categories selected by the utility for electric plant in service in Statement AD,
to the extent such data are available.
(iii) If depreciation and amortization
expense data are not available for any
subfunctional category selected in
Statement AD, the utility shall:
(A) Provide a comparison of the current depreciation rate of the major
functional classification and the depre-
ciation rate estimated to be appropriate to the subfunctional category;
and
(B) State and explain the estimation
techniques that the utility utilized in
developing each estimated subfunctional depreciation rate. If utilization
of such estimation techniques requires
data that are not provided elsewhere in
the cost of service statements in this
paragraph, the utility shall supply
such data in Statement AJ.
(iv) For Period I and Period II, the
utility shall show the annual depreciation rate applicable to each function
and subfunction for which depreciation
expense is reported. The utility shall
indicate the bases upon which the depreciation rates were established. If
the depreciation rates used for Period I
or Period II data differ from those employed to support the utility’s prior approved jurisdictional electric rate, the
utility shall include in or append to
Statement AJ detailed studies in support of such changes. These detailed
studies shall include:
(A) Copies of any reports or analyses
prepared by any independent consultant or utility personnel to support the
proposed depreciation rates; and
(B) A detailed capital recovery study
showing by primary account the depreciation base, accumulated provision for
depreciation, cost of removal, net salvage, estimated service life, attained
age of survivors, accrual rate, and annual depreciation expense.
(11) Statement AK—Taxes other than
income taxes. Statement AK consists of
statements of taxes other than income
taxes for Period I and Period II.
(i) For Period I and Period II, the
utility shall itemize and total any
taxes other than income taxes according to clauses (i) (A) through (D).
(A) Revenue taxes. The utility shall
show total revenue taxes levied by each
taxing authority and identify the revenue taxes, under both the present and
changed rate, applicable to wholesale
services for which a rate change is
filed. The utility shall identify revenue
taxes associated with each revenue
credit item reported in Statement AU
under paragraph (h)(21).
(B) Real estate and property taxes. The
utility shall itemize and total all real
estate and property taxes. If the utility
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Federal Energy Regulatory Commission
maintains records to show tax component balances according to the major
functional classifications identified in
Statement AD under paragraph (h)(4),
the utility shall supply the component
balances by function. If the data are
not available by function, the utility
shall describe the procedure by which
the utility believes it can reasonably
estimate the portion of the total electric balances for each major functional
classification. The utility may show by
function the component balances obtained by applying the procedure. If
such estimation requires data that are
not provided elsewhere in the cost of
service statements in this paragraph,
the utility shall supply the necessary
data in Statement AK.
(C) Payroll taxes. The utility shall
itemize and total all payroll taxes. If
the utility maintains records to show
tax component balances according to
the major functional classifications
identified in Statement AD in paragraph (h)(4), the utility shall provide
the component balances by function. If
the data are not available by function,
the utility shall describe the procedure
by which the utility believes it can reasonably estimate the portion of the
total electric balances for each major
functional classification. The utility
may show by function the component
balances obtained by applying the procedure. If such estimation requires
data that are not provided elsewhere in
the cost of service statements in this
paragraph, the utility shall provide the
necessary data in Statement AK.
(D) Miscellaneous taxes. The utility
shall itemize and total all miscellaneous taxes which are directly assignable or which are related to any selected plant or expense item for which
an allocation to wholesale services is
independently determinable, such as
items related to transmission plant in
service or to net distribution plant.
(ii) If any of the taxes itemized under
clause (11)(i) are levied by a taxing authority that is a customer, or is related
to a customer, whose services would be
affected by the changed rate schedule,
the utility shall show amounts of such
taxes according to the taxing authority, identify the related customer, and
provide an explanation of the relevant
circumstances.
§ 35.13
(12) Statement AL—Working capital.
Statement AL consists of statements
for Period I and Period II designed to
establish the need for working capital
to maintain adequate levels of operating supplies, to meet required prepayments, and to meet ongoing cash
disbursements that must be made at a
time different than related revenue receipts for utility services rendered.
(i) Supplies and prepayments. The utility shall supply statements to show
monthly balances of operating supplies
and
prepayments
itemized
under
clauses (i) (A) through (C). The utility
shall state all required balances as of
the beginning of the first month and
the end of each month of both Period I
and Period II, with an average of the
thirteen balances for each period. If
any of the Period I or Period II balances is not available or is unrepresentative of the current operating plan
of the utility for supplies or prepayments, the utility shall include an explanation
of
the
relevant
circumstances. Operating supply and prepayment balances shall be itemized
under the following categories:
(A) Fuel supplies. The utility shall
state the fuel supply balances for each
type of electric utility production
plant, except hydraulic. The utility
shall describe its overall fossil fuel supply objectives for Period I and Period
II, in terms of projected average days
of burn for major fossil fuel generating
stations, if feasible. The utility shall
explain substantial differences, if any,
between actual Period I inventories
and the target objectives, or between
Period II objectives and Period I objectives. Nuclear fuel balances shall include fuel in stock, fuel in the reactor
and spent fuel in the process of cooling
in Accounts 120.2, 120.3, 120.4, less accumulated provisions for amortization of
nuclear fuel assemblies in Account
120.5.
(B) Plant materials and operating supplies. The utility shall state materials
and operating supply balances for each
of the major electric utility operating
functions of production, transmission,
and distribution, and for each significant type of miscellaneous operating
supplies. Miscellaneous supplies shall
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
be grouped to facilitate suitable allocations or assignments among utility
services.
(C) Prepayments. The utility shall indicate prepayment balances for each
major prepayment item, with a brief
description of the item. Balances shall
be grouped and subtotaled to facilitate
suitable allocations or assignments
among utility services.
(ii) Cash working capital. The utility
shall indicate average monthly working cash requirements that reflect the
extent to which day-to-day operational
utility service revenues are received
later or earlier than cash disbursements necessary to provide the services, with an explanation of how such
requirements are derived.
(13) Statement AM—Construction work
in progress. Statement AM is a statement of the amount of construction
work in progress described according to
functional classification for Period I
and Period II. For production plant and
transmission plant, the utility shall
state the balances as of the beginning
of the first month and the end of each
month of both Period I and Period II,
with an average of the 13 balances for
each period. For each function of plant
identified in Statement AD other than
production or transmission, the utility
shall state the balances as of the beginning and the end of both Period I and
Period II, with an average of the beginning and end balances for each period.
If any Period I or Period II balance is
not available, the utility shall include
monthly estimates and an explanation
of the relevant circumstances. Pollution control facilities, fuel conversion
facilities,
or
other
construction
amounts reported in Statement AG
shall be excluded from amounts reported in this Statement.
(14) Statement AN—Notes payable.
Statement AN is a statement of the
electric utility portion of average
notes payable for Period I and Period
II. The utility shall indicate balances
as of the beginning of the first month
and the end of each month of both Period I and Period II, with an average of
the thirteen balances for each period. If
any of the Period I or Period II balances is not available or is unrepresentative of the current financing plan
of the utility, the utility shall provide
an explanation of the relevant circumstances. If a utility has operations
other than electric, the utility shall
also show allocations between electric
and other utility departments on an
appropriate basis, such as the average
amount of construction work in
progress and net plant.
(15) Statement AO—Rate for allowance
for funds used during construction.
Statement AO is a statement of the
basis of the rate for computing the allowance for funds used during construction (AFUDC) for Period I and Period II.
(i) The utility shall show the computations of the maximum rates for
the construction allowances computed
in accordance with plant instructions
of the Commission’s Uniform System
of Accounts, 18 CFR part 101. The utility shall show the rates computed annually, and shall provide the rates for
each annual period that includes any
part of Period I or Period II. If the utility proposes to use a net-of-tax rate,
the utility shall show the derivation
for both the gross-of-tax and net-of-tax
rates.
(ii) If the book allowance amounts of
AFUDC do not reflect the maximum
rates for allowances for funds computed in accordance with clause (i), the
utility shall show the derivation for
the actual rates utilized in computing
AFUDC, including derivation of any
net-of-tax rate utilized by the utility.
(16) Statement AP—Federal income tax
deductions—interest. Statement AP is a
statement of electric utility interest
charges for Period I and Period II. For
each period, the utility shall state the
total electric utility interest in terms
of three or more component items described in clauses (i) through (iv).
(i) The utility shall state the allowance for borrowed funds used for electric utility construction Account 432 as
a separate component. The utility shall
show supporting detail, including computation of the amounts on the basis of
AFUDC rates claimed in Statement
AO.
(ii) The utility shall state interest
for borrowed funds used for electric
utility construction Account 431 as a
separate component. If applicable, the
utility shall also show all elements of
Account 431 related to purposes other
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Federal Energy Regulatory Commission
than electric utility construction, with
detailed supporting material, such as a
computation of allocations between
electric and other utility departments
with explanatory material to support
the bases of such allocations.
(iii) The utility shall state the interest on long-term debt required for electric rate base investment as a separate
component. The interest amount shall
be consistent with that shown and utilized in Statement BK under paragraph
(h)(36) of this section.
(iv) The utility shall show other interest items appropriate in the determination of net taxable income allocable to the wholesale services at issue.
The utility shall describe and support
each item and shall accompany each
item with a statement of the basis on
which the item is allocable to the
wholesale services. The utility shall
also list a short descriptive title for
each item.
(17) Statement AQ—Federal income tax
deductions—other than interest. Statement AQ is a statement of other deductions from net operating income before
Federal income taxes, for Period I and
Period II, which deductions are appropriate in determining the net taxable
income allocable to the wholesale services subject to the changed rate. The
utility shall show unallowable deductions as negative entries in this statement. The utility shall itemize deductions in accordance with clause (i)
through (iii) and individually identify
each by a brief descriptive title.
(i) The utility shall report, as a separate component of this statement, the
difference between tax and book depreciation, in total, or in individual
amounts based on the Internal Revenue
Code provisions that permit the utility
to use various methods of computing
depreciation for tax purposes, such as
liberalized depreciation or the asset depreciation range. If the utility reports
the differences in total only, it shall
list the specific Internal Revenue Code
provisions that result in the difference.
(ii) The utility shall state taxes and
pensions capitalized as a separate component.
(iii) The utility shall describe and
support other deduction items appropriate in the determination of net taxable income allocable to the wholesale
§ 35.13
services. Each item shall be accompanied by a brief explanation of the
basis on which the item is allocable to
the wholesale services.
(18) Statement AR—Federal tax adjustments. Statement AR is a statement of
adjustments to Federal income taxes
for Period I and Period II. If subaccounts are maintained to reflect differences in ratemaking treatment
among regulatory authorities having
jurisdiction, the utility shall provide
adjustment amounts in accordance
with such subaccounts. The utility
shall report detailed explanations of
the bases upon which the subaccounts
were established and are maintained.
(i) For each major function of plant
identified in Statement AD under paragraph (h)(4), the utility shall state the
electric utility component adjustment
for the Federal portions of the provision for deferred income tax Account
410.1. If the data are not available by
function, the utility shall state the
amounts for the total electric utility
and shall describe the procedure by
which the utility believes it can reasonably estimate the portion of the
total electric balances for each major
functional classification. The utility
may show by function the component
balances obtained by applying the procedure. If such estimation requires
data that are not provided elsewhere in
the cost of service statements in this
paragraph, the utility shall supply in
Statement AR the necessary data. The
utility shall provide the adjustment
amounts for total electric and, to the
extent available for each such major
functional component, accompanied by
summary totals segregated in accordance with related balance sheet Accounts 281, 282, 283, and 190 [see Statements AF and AG]. Account 190 items
require a negative sign for entries in
Statement AR. The utility shall identify the summarized items by account
number.
(ii) The utility shall provide for the
Federal portions of the provision for
deferred income tax-credit Account
411.1 the data required by clause (i) for
Account 410.1.
(iii) For each major functional classification of plant identified in Statement AD under paragraph (h)(4), the
utility shall provide the electric utility
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
component for investment tax credits
generated for Period I and Period II,
credits utilized for each period, and the
allocations to current income for each
period. If the data are not available by
function, the utility shall state the
amounts for total electric utility and
shall describe the procedure by which
the utility believes it can reasonably
estimate the portion of the total electric balances for each major functional
classification. The utility may show by
function the component balance obtained by applying the procedure. If
such estimation requires data that are
not provided elsewhere in the cost of
service statements in this paragraph,
the utility shall supply in Statement
AR the necessary data. If itemized in
detail, balances shall be subtotaled for
each major function, and totaled for
the electric utility department. Detailed data shall be consistent with
that provided in Statement AF under
paragraph (h)(6) of this section.
(iv) The utility shall list and designate as other adjustment items any
additional Federal income tax adjustments and shall provide a brief descriptive title for each item. The utility
shall explain the reasons for inclusion
of each item, and shall indicate the
basis on which each will be assigned or
allocated to the wholesale services subject to the changed rate and to the
other electric utility services.
(19) Statement AS—Additional state income tax deductions. Statement AS is a
listing of state income tax deductions
for Period I and Period II, in addition
to those listed at Statements AP and
AQ for Federal tax purposes. The utility shall explain the reasons for inclusion of each item. The utility shall indicate the basis on which each item is
to be assigned or allocated to the
wholesale services at issue and to the
other electric utility services. If applicable, the utility shall show unallowable deductions as negative entries in
this statement. The utility shall provide the percentage of Federal income
tax payable which is deductible for
state income tax purposes, if applicable. [See also Statement AY, dealing
with tax rate data.]
(20) Statement AT—State tax adjustments. Statement AT is a statement of
adjustments to state income taxes for
Period I and Period II. The utility shall
prepare and present the data in statement AT as prescribed for Federal tax
adjustments in Statement AR. The
utility shall annotate Statement At
data as necessary to identify state tax
adjustments that are not properly deductible for Federal tax purposes.
(21) Statement AU—Revenue credits.
Statement AU is, for Period I and Period II, a statement of the operating
revenue balances in Accounts 450
through 456, and other revenue items,
such as short-term sales in Account
447, that are appropriately credited to
the cost of service for determinations
of costs allocable to the wholesale
services subject to the changed rate.
The utility shall include revenue credits proposed for exclusive-use commitment of major power supply facilities
according to instructions for preparation of Statement BF under paragraph
(h)(31) of this section. When applicable,
the utility shall state revenue taxes for
each revenue credit item. The utility
shall explain the reasons for inclusion
of each item, and shall indicate the
basis for assigning or allocating each
item to the wholesale services subject
to the changed rate and to the other
electric utility services.
(22) Statement AV—Rate of return.
Statement AV is a statement and explanation of the percentage rate of return requested by the utility. The utility shall provide the complete capital
structure, including ratios, component
costs and weighted component costs
claimed by the utility. The utility
shall submit additional data where any
component of the capital of the utility
is not primarily obtained through its
own financing, but is primarily obtained from a company by which the
utility is controlled, as defined in the
Commission’s Uniform System of Accounts, 18 CFR part 101. The utility
shall submit the additional data, if required with respect to the debt capital,
preferred stock capital and common
stock capital of such controlling company or any intermediate company
through which such funds have been secured.
(i) General. The utility shall show,
based on the capitalization of the utility, the cost of debt capital and preferred stock capital, the claimed rate
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Federal Energy Regulatory Commission
of return on the common equity of the
utility and the resulting overall rate of
return requested.
(A) For Period I and, if applicable,
Period II, the utility shall show in tabular form the following:
(1) Cost of each capital element, including claimed rate of return on equity capital;
(2) Capitalization amounts and ratios;
(3) Weighted cost of each capital element; and
(4) Overall claimed rate of return.
(B) When a Period II filing is submitted the utility shall provide:
(1) A full explanation of, and supporting work papers for, the pro forma
adjustments to the actual capitalization data to arrive at the Period II capitalization; and
(2) The pro forma adjustment to Period I data to arrive at the Period II
amount for unappropriated undistributed subsidiary earnings in Account
216.1.
(C) If not included elsewhere in the
filing, the utility shall submit the
amount for Account 216.1 for Period I
as part of this statement.
(ii) Debt capital. (A) The utility shall
show the weighted cost for all issues of
long-term debt capital as of the end of
Period I, as expected on the date the
changed rate is filed, and, if applicable,
as estimated for the end of Period II.
The weighted cost is calculated by: (1)
Multiplying the cost of money for each
issue under clause (B)(6) below by the
principal amount outstanding for each
issue, which yields the annualized cost
for each issue; and (2) adding the annual cost of each issue to obtain the
total for all issues, which is divided by
the total principal amount outstanding
for all issues to obtain the weighted
cost for all issues.
(B) The utility shall show the following for each class and series of longterm debt outstanding as of the end of
Period I, as expected on the date the
changed rate is filed, and, if applicable,
as estimated to be outstanding as of
the end of Period II.
(1) Title;
(2) Date of offering and date of maturity;
(3) Interest rate;
(4) Principal amount of issue;
§ 35.13
(5) Net proceeds to the utility;
(6) Cost of money, which is the yield
to maturity at issuance based on the
interest rate and net proceeds to the
utility determined by reference to any
generally accepted table of bond yields;
(7) Principal amount outstanding;
(8) Name and relationship of issuer
and if the debt issue was issued by an
affiliate; and
(9) If the utility has acquired at a discount or premium some part of the
outstanding debt which could be used
in meeting sinking fund requirements,
or for some other reason, the annual
amortization of the discount or premium for each issue of debt from the
date of the reacquisition over the remaining life of the debt being retired.
The utility shall show separately the
total discount and premium to be amortized, and the amortized amount applicable to Period I and, if applicable,
Period II.
(C) The utility shall show the beforetax interest coverage, for the twelve
months of Period I based on the indenture requirements. The utility shall
provide a copy of the work papers used
to make the calculations, with explanations appropriate to understand the
calculations.
(iii) Preferred stock and preference
stock capital. (A) This statement shall
show the weighted cost for all issues of
preferred and preference stock capital
as of the end of Period I, as expected on
the date the changed rate is filed, and,
if applicable, as estimated for the end
of Period II. The weighted cost is calculated by: (1) Multiplying the cost of
money for each issue under clause
(B)(9) by the par amount outstanding
for each issue, which yields the
annualized cost for each issue; and (2)
adding the annual cost of each issue to
obtain the total for all issues, which is
divided by the total par amount outstanding for all issues to obtain the
weighted cost for all issues.
(B) The statement shall show for
each class and issue of preferred and
preference stock outstanding as of the
end of Period I, as expected on the date
the changed rate is filed, and, if applicable, as estimated to be outstanding
as of the end of Period II:
(1) Title;
(2) Date of offering;
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
(3) If callable, call price;
(4) If convertible, terms of conversion;
(5) Dividend rate;
(6) Par or stated amount of issue;
(7) Net proceeds to the filing utility;
(8) Ratio of net proceeds to gross proceeds received by the filing utility;
(9) Cost of money (dividend rate divided by the ratio of net proceeds to
gross proceeds for each issue);
(10) Par or stated amount outstanding; and
(11) If issue is owned by an affiliate,
name and relationship of owner.
(iv) Common stock capital. This statement shall show the following information for each sale of common stock
during the five-year period preceding
the date of the balance sheet for the
end of Period I and for each sale of
common stock between the end of Period I and the date that the changed
rate is filed:
(A) Number of shares offered;
(B) Date of offering;
(C) Gross proceeds at offering price;
(D) Underwriters’ commissions;
(E) Dividends per share;
(F) Net proceeds to company;
(G) Issuance expenses; and
(H) Whether issue was offered to
stockholders
through
subscription
rights or to the public and whether
common stock was issued for property
or for capital stock of others.
(v) Supplementary financial data. The
utility shall submit a statement indicating the sources and uses of funds for
Period I and as estimated for Period II
and a copy of the utility’s most recent
annual report to the stockholders. The
utility shall also supply a prospectus
for its most recent issue of securities
and a copy of the latest prospectus
issued by any subsidiary of the filing
utility or by any holding company of
which the filing utility is a subsidiary.
(23) Statement AW—Cost of short-term
debt. In Statement AW, the utility
shall provide a statement of the cost of
capital rate for short-term debt of the
utility as of the end of Period I, as expected on the date the proposed rate is
filed, and, if applicable, as estimated
for the end of Period II, with details
supporting each stated cost. The shortterm debt rate shown in Statement AW
shall include only the short-term debt
that appears on the income statement
as interest expense and shall not include nominal forms of financing, such
as trust agreements.
(24) Statement AX—Other recent and
pending rate changes. Statement AX is
a statement describing the extent to
which operating revenues are subject
to refund for Period I and, if applicable,
Period II, for each rate change filed
with any Federal, state, or other regulatory body that has jurisdiction. The
utility shall list and submit any orders
in which applications for a rate increase have been acted on by any regulatory body during Period I, Period II,
or the interval between Period I and
Period II, and a copy of each transmittal letter or equivalent written document by which a utility summarized
and submitted any pending applications that have not been acted on.
Statement AX shall reflect information available at the time of submittal
under this paragraph. Notwithstanding
any other provision of this section,
Statement AX is required to be filed
only if the proposed rate design tracks
retail rates.
(25) Statement AY—Income and revenue
tax rate data. (i) Statement AY is a
statement of tax rate data for Period I
and Period II arranged as follows:
(A) Nominal Federal income tax rate;
(B) Nominal state income tax rate;
(C) Proportion of Federal income
taxes payable which is deductible for
state income tax purposes. If an allowable deduction is stated in other terms,
the utility shall provide an estimate of
the effective deduction as a percentage
of Federal tax payable; and
(D) Revenue tax rate. If the revenue
tax rate is scaled, the utility shall
show approximate weighted average
rates for relevant revenue levels and
full supporting data.
(ii) If the utility serves in more than
one jurisdiction for revenue or state income tax purposes, the utility shall
state the appropriate tax rates for each
wholesale customer group at issue and
for all other customers as a composite
group. [See, Statement BA under paragraph (h)(26) for wholesale customer
grouping criteria.] If there are any
changes in tax rates that occur in Period I or that may occur in Period II,
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the utility shall describe such changes
and the effective date of the changes.
(26) Statement BA—Wholesale customer
rate groups. (i) Statement BA is a list of
wholesale customers by group for the
purpose of:
(A) Allocating the allowable costs of
the utility to such customer groups on
the basis of electric utility services
rendered; and
(B) Comparing proposed revenues
from each customer group with the
cost of service as allocated to that
group.
(ii) The utility shall limit the number of wholesale customer groups listed
to the minimum required under the following criteria:
(A) At least one customer group shall
be specified for each separate wholesale
rate subject to the changed rate filing.
(B) In general, all customers proposed to be served on the same rate
shall be included in a common group. If
the utility believes that there are significant differences in services provided under the same rate, the utility
shall subdivide the common group
served by the same rate into separate
customer groups characterized by the
type of service provided each group and
shall demonstrate whether the common rate is cost-based by means of
cost-justification for each service
group. Certain customer groupings,
such as cooperatives or municipals,
may also be utilized to facilitate purchaser evaluations of the changed rate.
(C) In all cases, the utility shall select customer groupings on a basis consistent with rate design information
provided in Statement BL under paragraph (h)(37) of this section.
(iii) The utility shall enumerate all
wholesale customer rate groups, together with a brief descriptive title for
each group. For example:
Group 1. Full Requirements Tariff
FR–1.
Group 2. Partial Requirements Tariff
PR–1.
(27) Statement BB—Allocation demand
and capability data. Statement BB is a
statement of electric utility demand
and capability data for Period I and Period II to be considered as a basis for
allocating related costs to the wholesale services subject to the changed
rate.
§ 35.13
(i) For each month of Period I and
Period II, with an average for each period, the utility shall show the maximum peak firm kilowatt demand on
the power supply system of the utility,
and the kilowatt demands of the wholesale services that coincide with the
system monthly maximum power supply demand, including for Period I the
date and hour for such coincidental
peak demands. The utility shall state
these kilowatt demands in terms of 60minute intervals or other intervals adjusted to the equivalent of 60 minutes.
The utility shall not include in the
data the demands associated with interruptible power supply services, firm
or nonfirm transmission wheeling services, or demands associated with other
services the revenues from which are
shown as revenue credits in Statement
AU under paragraph (h)(21). The utility
shall provide wholesale service demand
data as follows:
(A) The wholesale service data for
each individual customer delivery
point or set of delivery points that constitutes an individual wholesale customer billing unit shall include demands at delivery. The individual customer wholesale service data shall be
summarized and subtotaled in accordance with Statement BA customer
groupings.
(B) The data supplied for each wholesale customer group under clause (A)
shall be adjusted for losses to reflect
demand at the power supply level. The
data shall be totaled to show total customer group demand at power supply
level for each month of Period I and
Period II.
(ii) To the extent such data are available, the utility shall state Period I
and Period II monthly maximum demand data for interruptible power supply services, firm wheeling services,
and nonfirm wheeling services. The
utility shall also provide, to the extent
data are available, firm wheeling demand data for any of the 60-minute periods that coincide with the times of
power supply peak demands shown
under clause (i). The utility shall indicate the basis of all demands, such as
metered demands or contract demands,
reported under this clause. For interruptible services, the utility shall provide a description of the conditions
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
under which service may be interrupted or curtailed. The utility shall
include available information on actual interruptions or curtailments during a three-year period that includes
Period I. If any of the wholesale rates
at issue are for interruptible or
curtailable service, the utility shall
provide any demand data specifically
relevant to such service.
(iii) If a utility establishes plant categories in Statement AD under paragraph (h)(4) of this section for the purpose of supporting wholesale rates for
firm power supply services with special
characteristics, such as base load, intermediate, or peaking, the utility
shall provide in Statement BB the demand data required by clause (i) in
total and in separate corresponding demand values consistent with the service characteristics. Corresponding values shall be stated for the system demand of the utility, and for each applicable wholesale service group.
(iv) If a utility establishes plant categories in Statement AD under paragraph (h)(4) of this section for the purpose of supporting wholesale rates for
nonfirm power supply services, such as
capacity sales, the utility shall include
in Statement BB for each month of Period I and Period II the monthly capability data relied on by the utility in
developing costs allocable to such
rates, with an explanation of the underlying cost allocation rationale.
(v) If a utility establishes production
plant categories in Statement AD
under paragraph (h)(4) of this section
for the purpose of supporting wholesale
rates based on specialized ratemaking
theories such as marginal cost pricing,
time-of-day pricing, or base, intermediate, and peaking characteristics,
the utility shall include in Statement
BB all demand and capability data relied on by the utility in developing support on a cost of service basis, with appropriate explanatory material.
(vi) For each month of Period I and
Period II, the utility shall provide any
additional demand data that the utility believes to be relevant to the allocation of electric utility costs to the
wholesale services at issue. The utility
shall fully support all such data and
shall explain the rationale and the specific application proposed.
(vii) Based upon information reported
in Statements BB and BC, the utility
shall list selected months that are normally the months of greatest significance in determining the need of the
utility for power supply capability
throughout the year. All twelve
months may be selected, if appropriate.
In its selection, the utility shall take
into account any effects of local weather seasons and, particularly, the extent
to which peak demands may tend to be
similar in magnitude in two or more
months of a weather season. The utility shall explain the reasons for the selections and describe the significance
for the selections of seasonal variations in the weather.
(28) Statement BC—Reliability data.
Statement BC is a statement relating
to reference standards of the filing
utility for electric power supply reliability, and to information designed to
reflect monthly availability of generating capacity reserves.
(i) For Period II, Period I, and each of
the three calendar years preceding Period I, the utility shall state and briefly explain its objective reference standard of production power supply reliability and the rationale underlying its
choice of a reliability standard, including whether it participates with other
electric utilities in the selection of a
common standard on an area or pool
basis. The utility shall identify any
such participating utilities, and provide a general explanation of the basis
upon which the reliability standard
was jointly developed.
(ii) The utility shall describe how its
objective standard for production
power supply reliability affects its
electric generating facility construction planning and purchased power
planning.
(iii) For the peak day of each month
of Period II, Period I, and, to the extent data are available, for the peak
day of each month of the three calendar years preceding Period I, the
utility shall include tabular schedules
designed to show the following:
(A) Net peak load in megawatts,
itemized to show:
(1) Gross peak firm load, including all
firm sales assured available by the reserve capacity of the utility;
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(2) All firm purchases assured available by the reserve capacity of the supplier; and
(3) Net peak load, computed as gross
peak load under clause (1) minus all
firm purchases under clause (2).
(B) Net available dependable capacity, that is, the load-carrying ability of
the electric production facilities determined for the purpose of scheduling capacity in day-to-day operations, provided in megawatts and itemized to
show:
(1) The owned dependable capacity of
the utility for each production plant
category selected in Statement AD
under paragraph (h)(4);
(2) Scheduled maintenance of owned
dependable capacity of the utility;
(3) Purchased dependable capacity of
the utility;
(4) Scheduled maintenance of purchased dependable capacity of the utility; and
(5) Net available dependable capacity, computed as the owned dependable
capacity under clause (1), minus scheduled maintenance of owned capacity
under clause (2), plus purchased dependable capacity under clause (3),
minus scheduled maintenance of purchased capacity under clause (4).
(C) Available reserves in megawatts,
which is the net available dependable
capacity under clause (iii)(B) minus
net peak load under clause (iii)(A).
(D) Available reserves as a percent of
peak load, which is the available reserves under clause (iii)(C) divided by
net peak load under clause (iii)(A).
(29) Statement BD—Allocation energy
and supporting data. Statement BD is a
statement of electric utility energy
data for Period I and Period II to be
considered as bases for allocating related costs to the wholesale services
subject to the changed rate.
(i) For each month of Period I and
Period II, and as totaled for the twelve
months of each period, the utility shall
show the megawatt-hours of firm
power supply energy required by the
system of the utility and the megawatt-hour energy requirements of the
wholesale customer groups whose services will be subject to the changed rate.
The wholesale service data for each individual customer delivery point or set
of delivery points that constitutes an
§ 35.13
individual wholesale customer billing
unit shall include megawatt-hours at
delivery. The utility shall summarize
and subtotal these individual customer
data in accordance with Statement BA
customer groupings under paragraph
(h)(26). The utility shall show a loss adjustment for each wholesale customer
group to reflect energy at the power
supply level. The utility shall total the
data to show total customer group energy requirements at power supply
level for each month of Period I and
Period II.
(ii) Data provided under clause (i)
shall not include energy associated
with interruptible or curtailable services, or energy associated with other
services, the revenues from which are
shown as revenue credits in Statement
AU under paragraph (h)(21) of this section. The utility shall separately state
Period I and Period II monthly and
total energy data for any such services
provided by the utility. If any of the
proposed wholesale rates at issue are
for interruptible or curtailable service,
the utility shall provide descriptive
material and energy data specifically
relevant to such services.
(iii) If a utility selects subfunctional
categories in Statement AD under
paragraph (h)(4) of this section for the
purpose of supporting any changed
wholesale rate for firm power supply
services with special characteristics,
such as base load, intermediate, and
peaking services, the utility shall separate the energy data required by clause
(i) into corresponding energy values
consistent with the service characteristics and consistent with energy-related
expense categories utilized in Statement AH under paragraph (h)(8) of this
section. The utility shall state the corresponding values for the utility’s system energy and for each applicable
wholesale service group.
(iv) If a utility establishes plant categories in Statement AD under paragraph (h)(4) of this section for the purpose of supporting any changed wholesale rate for nonfirm production services, or the changed wholesale rate
based on specialized ratemaking theories [see paragraph (h)(27)(v) of this
section], the utility shall include in
Statement BD all energy data relied on
by the utility in developing the support
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
on a cost of service basis and relevant
explanatory material. Energy data provided under this clause shall be consistent with related expense categories
utilized in Statement AH under paragraph (h)(8) of this section.
(v) For each month of Period I and
Period II, and as totaled for the twelve
months of each period, the utility shall
show the megawatt-hours generated,
itemized in accordance with Statement
AD production subfunctional categories, and the megawatt-hours purchased or interchanged, itemized to
show each type of transaction, such as
firm energy or economy interchanged
energy.
The
utility
shall
quantitatively reconcile such data with the
system allocation energy reported in
this statement, and with energy data
underlying the fuel and purchased
power expense reported in Statement
AH.
(30) Statement BE—Specific assignment
data. (i) Statement BE is a statement
of specific components of the electric
costs of service of the utility for Period
I and Period II. Statement BE costs of
service are those apportioned among
wholesale services subject to the rate
change and other utility services, on a
basis other than:
(A) Demand, capability, or energy
data provided in Statements BB and
BD;
(B) A proportional relationship based
on a selected plant category or expense
item for which an allocation to wholesale services is to be independently determined; or
(C) Exclusive-use commitment in
Statement BF under paragraph (h)(31)
of this section.
(ii) The utility shall include specific
assignments considered appropriate by
the utility. Typical cost of service
components that could be specifically
assigned are distribution plant [see examples listed in Statement AD under
paragraph (h)(4) of this section], certain total electric wages and salaries
provided in Statement AI under paragraph (h)(9) of this section, such as
wages and salaries for customer accounting and for customer service and
information, and certain administrative and general expense items. [See examples listed in Statement AH under
paragraph (h)(8) of this section.]
(iii) The utility shall limit specific
assignments to the minimum required
to adequately provide for costs not otherwise appropriately allocable.
(iv) For each specific assignment, the
utility shall include at least the following information:
(A) Brief descriptive component title,
such as distribution substations or rate
case expenses;
(B) Total electric amount in dollars;
(C) Wholesale customer group dollar
amounts stated individually for each
wholesale customer rate group identified in Statement BA under paragraph
(h)(26), and stated in total for all such
groups; and
(D) Explanation of the basis on which
assignments were made, accompanied
by supporting detailed computations.
(31) Statement BF—Exclusive-use commitments of major power supply facilities.
Statement BF is a statement describing and justifying the commitment to
exclusive-use for particular services of
all or a stated portion of electric utility generation units or plants, or major
transmission facilities.
(i) For Period I and Period II, the
utility shall list each transaction in
which all or a stated portion of the
output of a specified filing utilityowned generating unit or group of
units was committed exclusively to a
particular customer or group of customers, or to a power pool or similar
power supply entity. For each such
transaction, the utility shall provide
the following information:
(A) Brief descriptive title for each
commitment;
(B) Name of plant and unit designation;
(C) Name of the purchaser or power
pool or other similar power supply entity;
(D) Duration of the transaction;
(E) Basis of rates or charges, stated
in terms of whether a transaction reflects marginal, incremental, or fully
distributed costs, the specific overall
and common equity rates of return included in costs, provided on both a
claimed and earned basis to the extent
such information is available, the approximate date of the cost analysis on
which the rates and charges were
based, and any other considerations
significant to the transaction;
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Federal Energy Regulatory Commission
(F) Revenue received for each month
of Period I and Period II or, if applicable, monthly quantities of power and
energy received or available from
power pools as consideration for commitment to a pool; and
(G) Proposed treatment in the cost of
service determinations for the wholesale services at issue. For example, a
credit of revenue to the total electric
cost of service, in Statement AU under
paragraph (h)(21), could be proposed to
account for unit capacity sales based
upon incremental capital costs. The
utility shall include explanatory material and support for the proposed procedures.
(ii) For Period I and Period II, the
utility shall list each transaction in
which all, or a portion, of a major
transmission facility owned by the filing utility was committed exclusively
to a particular customer or group of
customers. For each such transaction,
the utility shall provide information
similar to that required by clause (i).
(32) Statement BG—Revenue data to reflect changed rates. Statement BG is a
statement of revenues for Period I and
Period II, including those under the
changed rate for the wholesale services
at issue.
(i) For each month of Period I and
Period II, and in total for each of the
two periods, the utility shall show all
billing determinants and metered
quantities for each delivery point or
set of delivery points that constitutes
an individual wholesale customer billing unit, and the result of applying
each specific rate component to the
billing determinants for each billing
unit stated with the total of the computed monthly bill for the customer. If
the rates include a fuel clause, the utility shall compute and total the revenues under the fuel clause to reflect
fuel costs incurred during each month
of Period I and Period II. That is, the
fuel clause revenues for the first month
of Period I shall reflect fuel costs incurred for that month, and so on for
each month of Period I and Period II.
In computing fuel clause revenues, the
utility shall determine fuel cost according to § 35.14 of this chapter.
(ii) If the form of the proposed fuel
clause would produce revenues different from those computed in accord-
§ 35.13
ance with clause (i), the utility shall
separately compute and state such fuel
clause revenues for each customer for
each month of Period I and Period II.
(iii) The utility shall summarize separately revenue data computed in accordance with clauses (i) and (ii) above
for each month and in total for Period
I and Period II, in accordance with
wholesale rate groups specified in
Statement BA under paragraph (h)(26)
of this section. The utility shall show
total electric department revenues for
each period to include revenues under
the changed rate for all such wholesale
customer rate groups.
(iv) For Period I and as estimated for
Period II, the utility shall summarize
all billing determinants and revenues
received
from
interruptible
or
curtailable services. Billing determinants and revenue data shall be consistent with interruptible demand and
energy data in Statements BB and BD.
The utility shall include an explanation of the extent to which interruptible or curtailable service revenues
are or are not included in revenue credits in Statement AU under paragraph
(h)(21) of this section.
(33) Statement BH—Revenue data to reflect present rates. Statement BH is a
statement of revenues for Period I and
Period II, including those under
present rates for wholesale services at
issue, and for total electric service to
reflect such revenues for wholesale
services. The utility shall prepare this
statement to include data consistent
with criteria specified for presentation
of revenue under the changed rate in
Statement BG under paragraph (h)(32)
of this section.
(34) Statement BI—Fuel cost adjustment
factors. Statement BI is a statement of
monthly fuel cost adjustment factors
under the changed rate and under the
present rates, for Period I and Period
II.
(i) If the changed rate schedule embodies a fuel cost adjustment clause,
the utility shall show detailed derivations of fuel cost adjustment factors
computed to reflect fuel cost incurred
during each month of Period I and Period II. Fuel cost adjustment factors
are those required for revenue determinations in accordance with paragraph (h)(32)(i) of Statement BG.
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§ 35.13
18 CFR Ch. I (4–1–19 Edition)
(ii) If additional proposed fuel clause
revenue data are reported in accordance with paragraph (h)(32)(ii) of Statement BG, the utility shall show detailed derivation of applicable monthly
fuel adjustment factors.
(iii) If the present rate includes a fuel
cost adjustment change, the utility
shall show detailed derivations of fuel
cost adjustment factors for each month
of Period I and Period II. The utility
shall include in Statement BI derivations for all monthly factors required
in the computation of present fuel
clause revenues reported in Statement
BH. The utility shall provide an explanation of the differences between the
present and proposed fuel clauses.
(iv) All fuel cost adjustment factors
shall be cost-based. The utility shall
make a computational showing that
shall develop adjustment factors in a
manner consistent with the requirements of § 35.14 of this chapter. The
utility shall provide supporting detail
on cost by type of fuel, and shall show
separately the allowable fuel clause
cost component of purchased or interchanged energy. All fuel cost data shall
be consistent with that included in operation and maintenance expenses in
Statement AH under paragraph (h)(8)
of this section.
(35) Statement BJ—Summary data tables. Statement BJ is a tabular summary of portions of Period I and Period
II data from specific cost of service
statements in this paragraph. The utility shall summarize under descriptive
titles the Period I and Period II data
from the cost of service provisions listed in this subparagraph. The utility
shall supply the data in the manner described for each cost of service statement and in this subparagraph.
(i) If a utility provides in Statement
BK information that is substantially
equivalent to the information required
in this statement, the utility may fulfill the requirements of this statement
by specifically referring to the location
in Statement BK of the information required in this subparagraph.
(ii) The utility shall provide the information in the following statements
as average total electric department
monthly balances for each function and
subfunction of plant:
(A) Statement AD—(h)(4)(i) and (ii);
(B) Statement AE—(h)(5)(i) and (ii);
(C) Statement AF—(h)(6)(i) through
(v);
(D) Statement AG—(h)(7)(i) through
(vi);
(E) Statement AL—(h)(12)(i) and (ii);
(F) Statement AM—(h)(13); and
(G) Statement AN—(h)(14).
(iii) The utility shall provide the information in the following statements
as total electric department annual
revenue and expense amounts:
(A) Statement AH—(h)(8)(i), (iv) and
(v);
(B) Statement AI—(h)(9)(i) and (ii);
(C) Statement AJ—(h)(10)(i);
(D) Statement AK—(h)(11)(i);
(E) Statement AP—(h)(16)(i) through
(iv);
(F) Statement AQ—(h)(17)(i) through
(iii);
(G) Statement AR—(h)(18)(i) through
(iv);
(H) Statement AS—(h)(19);
(I) Statement AT—(h)(20); and
(J) Statement AU—(h)(21).
(iv) The utility shall provide all cost
of capital amounts in the following
statements.
(A) Statement AV—(h)(22)(i)(A); and
(B) Statement AW—(h)(23);
(v) The utility shall provide all tax
rate data in Statement AY, paragraph
(h)(25)(i) of this section.
(vi) The utility shall provide the information in the following statements
as appropriate, for total electric department values and individual customer group values:
(A) Statement BB—(h)(27)(i) through
(vi);
(B) Statement BD—(h)(29)(i) through
(iv);
(C) Statement BE—(h)(30)(iv) (A), (B),
and (C);
(D) Statement BG—(h)(32)(iii); and
(E) Statement BH—(h)(33).
(36) Statement BK—Electric utility department cost of service, total and as allocated. Statement BK is a statement of
the claimed fully allocated cost of
service of the utility developed and
shown for Period I and Period II. The
utility shall include analytical support
for each rate proposed to be differentiated on a time-of-use basis. The utility shall also provide any marginal or
incremental cost information that is
required to support the changed rate
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Federal Energy Regulatory Commission
developed on a marginal or incremental cost basis. The utility shall
show allocations of fully distributed
costs to the wholesale services subject
to the changed rate accompanied by a
comparison of allocated costs with revenues under the changed rate. Nothing
in this subparagraph shall preclude use
by any utility of any cost of service
technique it believes reasonable and
that is consistent with the requirements of paragraph (g) of this section.
(i) The utility shall base the fully
distributed cost of service and the allocations thereof upon data provided in
the accompanying detailed statements
required under this section and additional data which the utility may submit and support in connection with
this statement. The cost of service
data of the utility shall conform to the
following requirements:
(A) The total electric rate base and
cost of service shall be itemized and
summarized by major functions and in
a format designed to facilitate review
and analysis.
(B) Based on the total electric rate
base and cost of service, and on allocated or assigned component elements,
the cost of service for each Statement
BA wholesale customer rate group
under paragraph (h)(26) shall be
itemized and summarized by major
functions in a format consistent with
that shown for total electric.
(C) The costs of service data for total
electric and for each of the wholesale
customer groups shall include data
that show the return and the income
taxes by components and in total,
based upon the rate of return claimed
by the utility in Statement AV under
paragraph (h)(22). Individual components of income taxes shall include income taxes payable, provision for deferred income tax—debits and deferred
income tax—credits, investment tax
credits, or other adjustments.
(D) The fully distributed cost of service study of the utility shall disclose
the principal determinants for allocation of total electric costs among the
wholesale customer groups, including
but not limited to the following:
(1) Computations showing the energy
responsibilities of the wholesale services, with supporting detail;
§ 35.13
(2) Computations showing the demand responsibilities of the wholesale
services, with supporting detail; and
(3) Computations showing the specific assignment responsibilities of the
wholesale services, with supporting detail.
(ii) For the total electric service and
for each wholesale customer rate
group, the utility shall compare the
fully distributed cost of service with
the revenues under the changed rate.
Based on the comparison, the utility
shall show the revenue excess or deficiency and the earned rate of return
computed for the total electric service
and for each wholesale customer rate
group.
(iii) For any filing that contains Period II data, the utility shall supply
any work papers and additional explanatory material necessary to support
Statement BK, indexed, referenced and
paginated as provided in paragraph
(d)(5) of this section.
(iv) The utility shall provide a tabular comparison of Period II total electric fully distributed cost items with
those of Period I. The comparisons
shall show item amounts for each of
the two periods, and also shall show
Period II item amounts as percentages
of equivalent items for Period I. Comparisons shall include at least the following items, accompanied by explanatory notes with respect to significant
variations among the comparative percentages:
(A) Rate base;
(B) Production expenses;
(C) Transmission expenses;
(D) Customer accounting, customer
service and information, and sales expenses;
(E) Depreciation expenses;
(F) Taxes except income and revenue;
(G) Income taxes;
(H) Revenue taxes; and
(I) Return claimed.
(37) Statement BL—Rate design information. In support of the design of the
changed rate, the utility shall submit
the following material:
(i) A narrative statement describing
and justifying the objectives of the design of the changed rate. If the purpose
of the rate design is to reflect costs,
the utility shall state how that objective is achieved, and shall accompany
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§ 35.14
18 CFR Ch. I (4–1–19 Edition)
it with a summary cost analysis that
would justify the rate design, including
any discounts or surcharges based on
delivery voltage level or other specific
considerations. Such summary cost
analysis shall be consistent with, derived from, and cross-referenced to the
data in cost of service Statement BK.
If the rate design is not intended to reflect costs, whether fully distributed,
marginal, incremental, or other, the
utility shall provide a statement to
justify the departure from cost-based
rates.
(ii) If the billing determinants, such
as quantities of demand, energy, or delivery points, are on different bases
than the cost allocation determinants
supporting such charges, the utility
shall submit an explanation setting
forth the economic or other considerations that warrant such departure.
The information shall include at least
the following:
(A) If the individual rate for the demand, energy and customer charges do
not correspond to the comparable cost
classifications
supporting
such
charges, a detailed explanation stating
the reasons for the differences.
(B) If the changed rate contains more
than one demand or energy block, a detailed explanation indicating the rationale for the blocking and the considerations upon which such blocking is
based, including adequate cost support
for the specified blocking.
(38) Statement BM—Construction program statement. Statement BM is a
summary of data and supporting assumptions relating to the economics of
any construction program to replace or
expand the utility’s power supply that
shall be filed if the utility is filing for
construction work in progress in rate
base under § 35.26(c)(3) of this chapter.
The filing utility shall describe generally its program for providing reliable and economic power for the period
beginning with the date of the filing
and ending with the tenth year after
the test period. The statement shall include an assessment of the relative
costs of adopting alternative strategies
including an analysis of alternative
production plant, e.g., cogeneration,
small power production, heightened
load management and conservation efforts, additions to transmission plant
or increased purchases of power, and an
explanation of why the program adopted is prudent and consistent with a
least-cost energy supply program.
(Federal Power Act, 16 U.S.C. 791–828c; Dept.
of Energy Organization Act, 42 U.S.C. 7101–
7352; E.O. 12009, 42 FR 46267, 3 CFR 142 (1978);
Pub. L. 96–511, 94 Stat. 2812 (44 U.S.C. 3501 et
seq.))
[Order 91, 45 FR 46363, July 10, 1980]
EDITORIAL NOTE: For FEDERAL REGISTER citations affecting § 35.13, see the List of CFR
Sections Affected, which appears in the
Finding Aids section of the printed volume
and at www.govinfo.gov.
Subpart C—Other Filing
Requirements
§ 35.14 Fuel cost and purchased economic power adjustment clauses.
(a) Fuel adjustment clauses (fuel
clause) which are not in conformity
with the principles set out below are
not in the public interest. These regulations contemplate that the filing of
proposed rate schedules, tariffs or service agreements which embody fuel
clauses failing to conform to the following principles may result in suspension of those parts of such rate schedules, tariffs, or service agreements:
(1) The fuel clause shall be of the
form that provides for periodic adjustments per kWh of sales equal to the
difference between the fuel and purchased economic power costs per kWh
of sales in the base period and in the
current period:
Adjustment Factor = Fm/Sm-Fb/Sb
Where: F is the expense of fossil and nuclear
fuel and purchased economic power in
the base (b) and current (m) periods; and
S is the kWh sales in the base and current periods, all as defined below.
(2) Fuel and purchased economic
power costs (F) shall be the cost of:
(i) Fossil and nuclear fuel consumed
in the utility’s own plants, and the
utility’s share of fossil and nuclear fuel
consumed in jointly owned or leased
plants.
(ii) The actual identifiable fossil and
nuclear fuel costs associated with energy purchased for reasons other than
identified in paragraph (a)(2)(iii) of this
section.
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(iii) The total cost of the purchase of
economic power, as defined in paragraph (a)(11) of this section, if the reserve capacity of the buyer is adequate
independent of all other purchases
where non-fuel charges are included in
either Fb or Fm;
(iv) Energy charges for any purchase
if the total amount of energy charges
incurred for the purchase is less than
the buyer’s total avoided variable cost;
(v) And less the cost of fossil and nuclear fuel recovered through all intersystem sales.
(3) Sales (S) must be all kWh’s sold,
excluding inter-system sales. Where for
any reason, billed system sales cannot
be coordinated with fuel costs for the
billing period, sales may be equated to
the sum of: (i) Generation, (ii) purchases, (iii) exchange received, less (iv)
energy associated with pumped storage
operations, less (v) inter-system sales
referred to in paragraph (a)(2)(iv) of
this section, less (vi) total system
losses.
(4) The adjustment factor developed
according to this procedure shall be
modified to properly allow for losses
(estimated if necessary) associated
only with wholesale sales for resale.
(5) The adjustment factor developed
according to this procedure may be further modified to allow the recovery of
gross receipts and other similar revenue based tax charges occasioned by
the fuel adjustment revenues.
(6) The cost of fossil fuel shall include no items other than those listed
in Account 151 of the Commission’s
Uniform System of Accounts for Public
Utilities and Licensees. The cost of nuclear fuel shall be that as shown in Account 518, except that if Account 518
also contains any expense for fossil fuel
which has already been included in the
cost of fossil fuel, it shall be deducted
from this account. (Paragraph C of Account 518 includes the cost of other
fuels used for ancillary steam facilities.)
(7) Where the cost of fuel includes
fuel from company-owned or controlled 1 sources, that fact shall be
noted and described as part of any fil1 As defined in the Commission’s Uniform
System of Accounts 18 CFR part 101, Definitions 5B.
§ 35.14
ing. Where the utility purchases fuel
from a company-owned or controlled
source, the price of which is subject to
the jurisdiction of a regulatory body,
and where the price of such fuel has
been approved by that regulatory body,
such costs shall be presumed, subject
to rebuttal, to be reasonable and includable in the adjustment clause. If
the current price, however, is in litigation and is being collected subject to
refund, the utility shall so advise the
Commission and shall keep a separate
account of such amounts paid which
are subject to refund, and shall advise
the Commission of the final disposition
of such matter by the regulatory body
having jurisdiction. With respect to the
price of fuel purchases from companyowned or controlled sources pursuant
to contracts which are not subject to
regulatory authority, the utility company shall file such contracts and
amendments thereto with the Commission for its acceptance at the time it
files its fuel clause or modification
thereof. Any subsequent amendment to
such contracts shall likewise be filed
with the Commission as a rate schedule
change and may be subject to suspension under section 205 of the Federal
Power Act. Fuel charges by affiliated
companies which do not appear to be
reasonable may result in the suspension of the fuel adjustment clause or
cause an investigation thereof to be
made by the Commission on its own
motion under section 206 of the Federal
Power Act.
(8) All rate filings which contain a
proposed new fuel clause or a change in
an existing fuel clause shall conform
such clauses with the regulations.
Within one year of the effectiveness of
this rulemaking, all public utilities
with rate schedules that contain a fuel
clause should conform such clauses
with the regulations. Recognizing that
individual public utilities may have
special operating characteristics that
may warrant granting temporary
delays in the implementation of the
regulations, the Commission may,
upon showing of good cause, waive the
requirements of this section of the regulations for an additional one-year period so as to permit the public utilities
sufficient time to adjust to the requirements.
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§ 35.14
18 CFR Ch. I (4–1–19 Edition)
(9) All rate filings containing a proposed new fuel clause or change in an
existing fuel clause shall include:
(i) A description of the fuel clause
with detailed cost support for the base
cost of fuel and purchased economic
power or energy.
(ii) Full cost of service data unless
the utility has had the rate approved
by the Commission within a year, provided that such cost of service may not
be required when an existing fuel cost
adjustment clause is being modified to
conform to the Commission’s regulations.
(10)
Whenever
particular
circumstances prevent the use of the
standards provided for herein, or the
use thereof would result in an undue
burden, the Commission may, upon application under § 385.207 of this chapter
and for good cause shown, permit deviation from these regulations.
(11) For the purpose of paragraph
(a)(2)(iii) of this section, the following
definitions apply:
(i) Economic power is power or energy
purchased over a period of twelve
months or less where the total cost of
the purchase is less than the buyer’s
total avoided variable cost.
(ii) Total cost of the purchase is all
charges incurred in buying economic
power and having such power delivered
to the buyer’s system. The total cost
includes, but is not limited to, capacity
or reservation charges, energy charges,
adders, and any transmission or wheeling charges associated with the purchase.
(iii) Total avoided variable cost is all
identified and documented variable
costs that would have been incurred by
the buyer had a particular purchase
not been made. Such costs include, but
are not limited to, those associated
with fuel, start-up, shut-down or any
purchases that would have been made
in lieu of the purchase made.
(12) For the purpose of paragraph
(a)(2)(iii) of this section, the following
procedures and instructions apply:
(i) A utility proposing to include purchase charges other than those for fuel
or energy in fuel and purchased economic power costs (F) under paragraph
(a)(2)(iii) of this section shall amend its
fuel cost adjustment clause so that it
is consistent with paragraphs (a)(1) and
(a)(2)(iii) of this section. Such amendment shall state the system reserve capacity criteria by which the system operator decides whether a reliability
purchase is required. Where the utility
filing the statement is required by a
State or local regulatory body (including a plant site licensing board) to file
a capacity criteria statement with that
body, the system reserve capacity criteria in the statement filed with the
Commission shall be identical to those
contained in the statement filed with
the State or local regulatory body. Any
utility that changes its reserve capacity criteria shall, within 45 days of
such change, file an amended fuel cost
and purchased economic power adjustment clause to incorporate the new criteria.
(ii) Reserve capacity shall be deemed
adequate if, at the time a purchase was
initiated, the buyer’s system reserve
capacity criteria were projected to be
satisfied for the duration of the purchase without the purchase at issue.
(iii) The total cost of the purchase
must be projected to be less than total
avoided variable cost, at the time a
purchase was initiated, before any nonfuel purchase charge may be included
in Fm.
(iv) The purchasing utility shall
make a credit to Fm after a purchase
terminates if the total cost of the purchase exceeds the total avoided variable cost. The amount of the credit
shall be the difference between the
total cost of the purchase and the total
avoided variable cost. This credit shall
be made in the first adjustment period
after the end of the purchase. If a utility fails to make the credit in the first
adjustment period after the end of the
purchase, it shall, when making the
credit, also include in Fm interest on
the amount of the credit. Interest shall
be calculated at the rate required by
§ 35.19a(a)(2)(iii) of this chapter, and
shall accrue from the date the credit
should have been made under this paragraph until the date the credit is made.
(v) If a purchase is made of more capacity than is needed to satisfy the
buyer’s system reserve capacity criteria because the total costs of the
extra capacity and associated energy
are less than the buyer’s total avoided
variable costs for the duration of the
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Federal Energy Regulatory Commission
purchase, the charges associated with
the non-reliability portion of the purchase may be included in F.
(Approved by the Office of Management and
Budget under control number 1902–0096)
(Federal Power Act, 16 U.S.C. 824d, 824e and
825h (1976 & Supp. IV 1980); Department of
Energy Organization Act, 42 U.S.C. 7171, 7172
and 7173(c) (Supp. IV 1980); E.O. 12009, 3 CFR
part 142 (1978); 5 U.S.C. 553 (1976))
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 421, 36 FR 3047, Feb. 17, 1971; 39
FR 40583, Nov. 19, 1974; Order 225, 47 FR 19056,
May 3, 1982; Order 352, 48 FR 55436, Dec. 13,
1983; 49 FR 5073, Feb. 10, 1984; Order 529, 55 FR
47321, Nov. 13, 1990; Order 600, 63 FR 53809,
Oct. 7, 1998; Order 714, 73 FR 57532, Oct. 3,
2008; 73 FR 63886, Oct. 28, 2008]
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§ 35.15 Notices of cancellation or termination.
(a) General rule. When a rate schedule, tariff or service agreement or part
thereof required to be on file with the
Commission is proposed to be cancelled
or is to terminate by its own terms and
no new rate schedule, tariff or service
agreement or part thereof is to be filed
in its place, a filing must be made to
cancel such rate schedule, tariff or
service agreement or part thereof at
least sixty days but not more than one
hundred-twenty days prior to the date
such cancellation or termination is
proposed to take effect. A copy of such
notice to the Commission shall be duly
posted. With such notice, each filing
party shall submit a statement giving
the reasons for the proposed cancellation or termination, and a list of the
affected purchasers to whom the notice
has been provided. For good cause
shown, the Commission may by order
provide that the notice of cancellation
or termination shall be effective as of a
date prior to the date of filing or prior
to the date the filing would become effective in accordance with these rules.
(b) Applicability. (1) The provisions of
paragraph (a) of this section shall
apply to all contracts for unbundled
transmission service and all power sale
contracts:
(i) Executed prior to July 9, 1996; or
(ii) If unexecuted, filed with the Commission prior to July 9, 1996.
(2) Any power sales contract executed
on or after July 9, 1996 that is to terminate by its own terms shall not be sub-
§ 35.17
ject to the provisions of paragraph (a)
of this section.
(c) Notice. Any public utility providing jurisdictional services under a
power sales contract that is not subject
to the provisions of paragraph (a) of
this section shall notify the Commission of the date of the termination of
such contract within 30 days after such
termination takes place.
[Order 888, 61 FR 21692, May 10, 1996, as
amended by Order 714, 73 FR 57532, Oct. 3,
2008]
§ 35.16
Notice of succession.
Whenever the name of a public utility is changed, or its operating control
is transferred to another public utility
in whole or in part, or a receiver or
trustee is appointed to operate any
public utility, the exact name of the
public utility, receiver, or trustee
which will operate the property thereafter shall be filed within 30 days
thereafter with the Commission with a
tariff consistent with the electronic filing requirements in § 35.7 of this part.
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57533, Oct. 3, 2008]
§ 35.17 Withdrawals and amendments
of rate schedule, tariff or service
agreement filings.
(a) Withdrawals of rate schedule, tariff
or service agreement filings prior to Commission action. (1) A public utility may
withdraw in its entirety a rate schedule, tariff or service agreement filing
that has not become effective and upon
which no Commission or delegated
order has been issued by filing a withdrawal motion with the Commission.
Upon the filing of such motion, the
proposed rate schedule, tariff or service
agreement sections will not become effective under section 205(d) of the Federal Power Act in the absence of Commission action making the rate schedule, tariff or service agreement filing
effective.
(2) The withdrawal motion will become effective, and the rate schedule,
tariff or service agreement filing will
be deemed withdrawn, at the end of 15
days from the date of filing of the withdrawal motion, if no answer in opposition to the withdrawal motion is filed
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§ 35.18
18 CFR Ch. I (4–1–19 Edition)
within that period and if no order disallowing the withdrawal is issued within that period. If an answer in opposition is filed within the 15 day period,
the withdrawal is not effective until an
order accepting the withdrawal is
issued.
(b) Amendments or modifications to rate
schedule, tariff or service agreement sections prior to Commission action on the
filing. A public utility may file to
amend or modify, and may file a settlement that would amend or modify, a
rate schedule, tariff or service agreement section contained in a rate schedule, tariff or service agreement filing
that has not become effective and upon
which no Commission or delegated
order has yet been issued. Such filing
will toll the notice period in section
205(d) of the Federal Power Act for the
original filing, and establish a new date
on which the entire filing will become
effective, in the absence of Commission
action, no earlier than 61 days from the
date of the filing of the amendment or
modification.
(c) Withdrawal of suspended rate schedules, tariffs, or service agreements, or
parts thereof. Where a rate schedule,
tariff, or service agreement, or part
thereof has been suspended by the
Commission, it may be withdrawn during the period of suspension only by
special permission of the Commission
granted upon application therefor and
for good cause shown. If permitted to
be withdrawn, any such rate schedule,
tariff, or service agreement may be
refiled with the Commission within a
one-year period thereafter only with
special permission of the Commission
for good cause shown.
(d) Changes in suspended rate schedules, tariffs, or service agreements, or
parts thereof. A public utility may not,
within the period of suspension, file
any change in a rate schedule, tariff, or
service agreement, or part thereof,
which has been suspended by order of
the Commission except by special permission of the Commission granted
upon application therefor and for good
cause shown.
(e) Changes in rate schedules or tariffs
or parts thereof continued in effect and
which were proposed to be changed by the
suspended filing. A public utility may
not, within the period of suspension,
file any change in a rate schedule or
tariff or part thereof continued in effect by operation of an order of suspension and which was proposed to be
changed by the suspended filing, except
by special permission of the Commission granted upon application therefor
and for good cause shown.
[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57533, Oct. 3, 2008; 74
FR 55770, Oct. 29, 2009]
§ 35.18 Asset retirement obligations.
(a) A public utility that files a rate
schedule, tariff or service agreement
under § 35.12 or § 35.13 and has recorded
an asset retirement obligation on its
books must provide a schedule, as part
of the supporting work papers, identifying all cost components related to
the asset retirement obligations that
are included in the book balances of all
accounts reflected in the cost of service computation supporting the proposed rates. However, all cost components related to asset retirement obligations that would impact the calculation of rate base, such as electric plant
and related accumulated depreciation
and accumulated deferred income
taxes, may not be reflected in rates and
must be removed from the rate base
calculation through a single adjustment.
(b) A public utility seeking to recover nonrate base costs related to
asset retirement costs in rates must
provide, with its filing under § 35.12 or
§ 35.13, a detailed study supporting the
amounts proposed to be collected in
rates.
(c) A public utility that has recorded
asset retirement obligations on its
books, but is not seeking recovery of
the asset retirement costs in rates,
must remove all asset-retirement-obligations-related cost components from
the cost of service supporting its proposed rates.
[Order 631, 68 FR 19619, Apr. 21, 2003, as
amended by Order 714, 73 FR 57533, Oct. 3,
2008]
§ 35.19 Submission of information by
reference.
If all or any portion of the information called for in this part has already
been submitted to the Commission,
substantially in the form prescribed
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Federal Energy Regulatory Commission
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above, specific reference thereto may
be made in lieu of re-submission in response to the requirements of this part.
§ 35.19a Refund requirements under
suspension orders.
(a) Refunds. (1) The public utility
whose proposed increased rates or
charges were suspended shall refund at
such time in such amounts and in such
manner as required by final order of
the Commission the portion of any increased rates or charges found by the
Commission in that suspension proceeding not to be justified, together
with interest as required in paragraph
(a)(2) of this section.
(2) Interest shall be computed from
the date of collection until the date refunds are made as follows:
(i) At a rate of seven percent simple
interest per annum on all excessive
rates or charges held prior to October
10, 1974;
(ii) At a rate of nine percent simple
interest per annum on all excessive
rates or charges held between October
10, 1974, and September 30, 1979; and
(iii)(A) At an average prime rate for
each calendar quarter on all excessive
rates or charges held (including all interest applicable to such rates or
charges) on or after October 1, 1979.
The applicable average prime rate for
each calendar quarter shall be the
arithmetic mean, to the nearest onehundredth of one percent, of the prime
rate values published in the Federal Reserve Bulletin, or in the Federal Reserve’s ‘‘Selected Interest Rates’’ (Statistical Release H. 15), for the fourth,
third, and second months preceding the
first month of the calendar quarter.
(B) The interest required to be paid
under clause (iii)(A) shall be compounded quarterly.
(3) Any public utility required to
make refunds pursuant to this section
shall bear all costs of such refunding.
(b) Reports. Any public utility whose
proposed increased rates or charges
were suspended and have gone into effect pending final order of the Commission pursuant to section 205(e) of the
Federal Power Act shall keep accurate
account of all amounts received under
the increased rates or charges which
became effective after the suspension
period, for each billing period, speci-
§ 35.21
fying by whom and in whose behalf
such amounts are paid.
[44 FR 53503, Sept. 14, 1979, as amended at 45
FR 3889, Jan. 21, 1980; Order 545, 57 FR 53990,
Nov. 16, 1992; 74 FR 54463, Oct. 22, 2009]
§ 35.21 Applicability to licensees and
others subject to section 19 or 20 of
the Federal Power Act.
Upon further order of this Commission issued upon its own motion or
upon complaint or request by any person or State within the meaning of sections 19 or 20 of the Federal Power Act,
the provisions of §§ 35.1 through 35.19
shall be operative as to any licensee or
others who are subject to this Commission’s jurisdiction in respect to services and the rates and charges of payment therefor by reason of the requirements of sections 19 or 20 of the Federal Power Act. The requirement of
this section for compliance with the
provisions of §§ 35.1 through 35.19 shall
be in addition to and independent of
any obligation for compliance with
those regulations by reason of the provisions of sections 205 and 206 of the
Federal Power Act. For purposes of applying this section Electric Service as
otherwise defined in § 35.2(a) shall
mean: Services to customers or consumers of power within the meaning of
sections 19 or 20 of the Federal Power
Act which may be comprised of various
classes of capacity and energy and/or
transmission services subject to the jurisdiction of this Commission. Electric
Service shall include the utilization of
facilities owned or operated by any licensee or others to effect any of the
foregoing sales or services whether by
leasing or other arrangements. As defined herein Electric Service is without
regard to the form of payment or compensation for the sales or services rendered, whether by purchase and sale,
interchange,
exchange,
wheeling
charge, facilities charge, rental or otherwise. For purposes of applying this
section, Rate Schedule as otherwise defined in § 35.2(b) shall mean: A statement of
(1) Electric service as defined in this
§ 35.21,
(2) Rates and charges for or in connection with that service, and
(3) All classifications, practices,
rules, regulations, or contracts which
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§ 35.22
18 CFR Ch. I (4–1–19 Edition)
in any manner affect or relate to the
aforementioned service, rates and
charges. This statement shall be in
writing and may take the physical
form of a contractual document, purchase or sale agreement, lease of facilities, tariff 5 or other writing. Any oral
agreement or understanding forming a
part of such statement shall be reduced
to writing and made a part thereof.
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[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57533, Oct. 3, 2008]
§ 35.22 Limits for percentage adders in
rates for transmission services; revision of rate schedules, tariffs or
service agreements.
(a) Applicability. This section applies
to all electric rate schedules, tariffs or
service agreements required to be filed
under this part that are used for transactions in which the utility or system
performs a transmission or purchase
and resale function.
(b) Definition. For purposes of this
section, purchased power price means
the amount paid by a utility or system
that performs a transmission or purchase and resale function for electric
power generated by another utility or
system.
(c) General rule. (1) If a utility or system uses a rate component that recovers revenues computed wholly or in
part as a percentage of the purchased
power price, the utility or system shall
establish a limit on the revenues recovered by such rate component in any
transaction, in accordance with paragraph (d) of this section.
(2) The limit established under this
paragraph shall be stated in mills per
kilowatt-hour.
(d) Cost support information. (1) A utility or system shall submit cost support
information to justify any revenue
limit established under paragraph (c)
of this section, except as provided in
paragraph (e) of this section.
(2) The information submitted under
this section shall consist of those
costs, other than the purchased power
price, incurred by a utility or system
as a result of a transmission or purchase and resale transaction, which
costs are not recovered under any
other rate component.
5 See
§ 35.2.
(e) Exception. A utility or system
need not submit the cost support information required under paragraph (d) of
this section if the limit established
under paragraph (c) of this section is
not more than one mill per kilowatthour.
(f) Revision of rate schedules, tariffs or
service agreements. Every utility or system shall:
(1) Amend any rate schedule, tariffs
or service agreements to indicate any
limit established pursuant to this section, not later than 60 days after the effective date of this rule; and
(2) Hereafter conform any rate or
rate change filed under this part to the
requirements of this section.
(Federal Power Act, as amended, 16 U.S.C.
792–828c; Department of Energy Organization
Act, 42 U.S.C. 7101–7352; E.O. 12009, 3 CFR 142
(1978))
[Order 84, 45 FR 31300, May 13, 1980. Redesignated by Order 545, 57 FR 53990, Nov. 16, 1992,
as amended by Order 714, 73 FR 57533, Oct. 3,
2008]
§ 35.23
General provisions.
(a) Applicability. This subpart applies
to any wholesale sale of electric energy
in a coordination transaction by a public utility if that sale requires the use
of an emissions allowance.
(b) Implementation Procedures. (1) If a
public utility has a coordination rate
schedule on file that expressly provides
for the recovery of all incremental or
out-of-pocket costs, such utility may
make an abbreviated rate filing detailing how it will recover emissions allowance costs. Such filing must include
the following: the index or combination
of indices to be used; the method by
which the emission allowance amounts
will be calculated; timing procedures;
how inconsistencies, if any, with dispatch criteria will be reconciled; and
how any other rate impacts will be addressed. In addition, a utility making
an abbreviated filing must:
(i) Clearly identify the filing as being
limited to an amendment to a coordination rate to reflect the cost of emissions allowances, in the first paragraph
of the letter of transmittal accompanying the filing;
(ii) Submit the revisions in accordance with § 35.7; and
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Federal Energy Regulatory Commission
(iii) Identify each rate schedule to
which the amendment applies.
(2) The abbreviated filing must apply
consistent treatment to all coordination rate schedules. If the filing does
not apply consistent rate treatment,
the public utility must explain why it
does not do so.
(3) If a public utility wants to charge
incremental costs for emissions allowances, but its rate schedule on file with
the Commission does not provide for
the recovery of all incremental costs,
the selling public utility may submit
an abbreviated filing if all customers
agree to the rate change. If customers
do not agree, the selling public utility
must tender its emissions allowance
proposal in a separate section 205 rate
filing, fully justifying its proposal.
[59 FR 65938, Dec. 22, 1994, as amended by
Order 714, 73 FR 57533, Oct. 3, 2008]
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§ 35.24 Tax normalization for public
utilities.
(a) Applicability. (1) Except as provided in subparagraph (2) of this paragraph, this section applies, with respect to rate schedules filed under
§§ 35.12 and 35.13 of this part, to the
ratemaking treatment of the tax effects of all transactions for which there
are timing differences.
(2) This section does not apply to the
following timing differences:
(i) Differences that result from the
use of accelerated depreciation;
(ii) Differences that result from the
use of Class Life Asset Depreciation
Range (ADR) provisions of the Internal
Revenue Code;
(iii) Differences that result from the
use of accelerated amortization provisions on certified defense and pollution
control facilities;
(iv) Differences that arise from recognition of extraordinary property
losses as a current expense for tax purposes but as a deferred and amortized
expense for book purposes;
(v) Differences that arise from recognition of research, development, and
demonstration expenditures as a current expense for tax purposes but as a
deferred and amortized expense for
book purposes;
(vi) Differences that result from different tax and book reporting of de-
§ 35.24
ferred gains or losses from disposition
of utility plant;
(vii) Differences that result from the
use of the Asset Guideline Class ‘‘Repair Allowance’’ provision of the Internal Revenue Code;
(viii) Differences that result from
recognition of purchased gas costs as a
current expense for tax purposes but as
a deferred expense for book purposes.
(See Order 13, issued October 18, 1978; Order
203, issued May 29, 1958; Order 204, issued May
29, 1958; Order 404, issued May 15, 1970; Order
408, issued August 26, 1970; Order 432, issued
April 23, 1971; Order 504, issued February 11,
1974; Order 505, issued February 11, 1974;
Order 566, issued June 3, 1977; Opinion 578,
issued June 3, 1970; and Opinion 801, issued
May 31, 1977.)
(b) General rules—1) Tax normalization
required. (i) A public utility must compute the income tax component of its
cost of service by using tax normalization for all transactions to which this
section applies.
(ii) Except as provided in paragraph
(c) of this section, application of tax
normalization by a public utility under
this section to compute the income tax
component will not be subject to caseby-case adjudication.
(2) Reduction of, and addition to, rate
base. (i) The rate base of a public utility using tax normalization under this
section must be reduced by the balances that are properly recordable in
Account 281, ‘‘Accumulated deferred income taxes-accelerated amortization
property;’’ Account 282, ‘‘Accumulated
deferred income taxes—other property;’’ and Account 283, ‘‘Accumulated
deferred income taxes—other.’’ Balances that are properly recordable in
Account 190, ‘‘Accumulated deferred income taxes,’’ must be treated as an addition to rate base.
(ii) Such rate base reductions or additions must be limited to deferred taxes
related to rate base, construction or
other jurisdictional activities.
(iii) If a public utility uses an approved purchased gas adjustment
clause or a research, development and
demonstration tracking clause, the
rate base reductions or additions required under this subparagraph must
apply only to the extent that the balances in Account 190 and Accounts 281
through 283 are not used, for purposes
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§ 35.25
18 CFR Ch. I (4–1–19 Edition)
of calculating carrying charges, as an
offset to balances properly recordable
in Account 188, ‘‘Research development
and demonstration expenditures,’’ or
Account 191, ‘‘Unrecovered purchased
gas costs.’’
(c) Special rules. (1) This paragraph
applies:
(i) If the public utility has not provided deferred taxes in the same
amount that would have accrued had
tax normalization been applied for the
tax effects of timing difference transactions originating at any time prior
to the test period; or
(ii) If, as a result of changes in tax
rates, the accumulated provision for
deferred taxes becomes deficient in or
in excess of amounts necessary to meet
future tax liabilities as determined by
application of the current tax rate to
all timing difference transactions originating in the test period and prior to
the test period.
(2) The public utility must compute
the income tax component in its cost
of service by making provision for any
excess or deficiency in deferred taxes
described in subparagraphs (1)(i) or
(1)(ii) of this paragraph.
(3) The public utility must apply a
Commission-approved
ratemaking
method made specifically applicable to
the public utility for determining the
cost of service provision described in
subparagraph (2) of this paragraph. If
no Commission-approved ratemaking
method has been made specifically applicable to the public utility, then the
public utility must use some ratemaking method for making such provision, and the appropriateness of this
method will be subject to case-by-case
determination.
(d) Definitions. For purposes of this
section, the term:
(1) Tax normalization means computing the income tax component as if
the amounts of timing difference transactions recognized in each period for
ratemaking purposes were also recognized in the same amount in each such
period for income tax purposes.
(2) Timing differences means differences between amounts of expenses
or revenues recognized for income tax
purposes and amounts of expenses or
revenues recognized for ratemaking
purposes, which differences arise in one
time period and reverse in one or more
other time periods so that the total
amounts of expenses or revenues recognized for income tax purposes and for
ratemaking purposes are equal.
(3) Commission-approved ratemaking
method means a ratemaking method approved by the Commission in a final
decision including approval of a settlement agreement containing a ratemaking method only if such settlement
agreement applies that method beyond
the effective term of the settlement
agreement.
(4) Income tax purposes means for the
purpose of computing income tax under
the provisions of the Internal Revenue
Code or the income tax provisions of
the laws of a State or political subdivision of a State (including franchise
taxes).
(5) Income tax component means that
part of the cost of service that covers
income tax expenses allowable by the
Commission.
(6) Ratemaking purposes means for the
purpose of fixing, modifying, approving, disapproving or rejecting rates
under the Federal Power Act or the
Natural Gas Act.
(7) Tax effect means the tax reduction
or addition associated with a specific
expense or revenue transaction.
(8) Transaction means an activity or
event that gives rise to an accounting
entry that is used in determining revenues or expenses.
[46 FR 26636, May 14, 1981. Redesignated and
amended by Order 144–A, 47 FR 8342, Feb. 26,
1982; Redesignated by Order 545, 57 FR 53990,
Nov. 16, 1992]
§ 35.25
Construction work in progress.
(a) Applicability. This section applies
to any rate schedule filed under this
part by any public utility as defined in
subsection 201(e) of the Federal Power
Act.
(b) Definitions. For purposes of this
section:
(1) Constuction work in progress or
CWIP means any expenditure for public
utility plant in process of construction
that is properly included in Accounts
107 (construction work in progress) and
120.1 (nuclear fuel in process of refinement, conversion, enrichment, and fabrication) of part 101 of this chapter, the
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Federal Energy Regulatory Commission
Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the
Federal
Power
Act
(Major
and
Nonmajor), that would otherwise be eligible for allowance for funds used during construction (AFUDC) treatment.
(2) Double whammy means a situation
which may arise when a wholesale electric rate customer embarks upon its
own or participates in a construction
program to supply itself with all or a
portion of its future power needs,
thereby reducing its future dependence
on the CWIP of the rate applicant, but
is simultaneously forced to pay to the
CWIP public utility rate applicant the
CWIP portion of the wholesale rates
that reflects existing levels of service
or a different anticipated service level.
(3) Fuel conversion facility means any
addition to public utility plant that enables a natural gas-burning plant to
convert to the use of other fuels, or
that enables an oil-burning plant to
convert to the use of other fuels, other
than natural gas. Such facilities include those that alter internal plant
workings, such as oil or coal burners,
soot blowers, bottom ash removal systems and concomitant air pollution
control facilities, and any facility
needed for receiving and storing the
fuel to which the plant is being converted, which facility would not be necessary if the plant continued to burn
gas or oil.
(4) Pollution control facility means an
identifiable structure or portions of a
structure that is designed to reduce the
amount of pollution produced by the
power plant, but does not include any
facility that reduces pollution by substituting a different method of generation or that generates the additional
power necessitated by the operation of
a pollution control facility.
(c) General rule. For purposes of any
initial rate schedule or any rate schedule change filed under § 35.12 or § 35.13
of this part, a public utility may include in its rate base any costs of construction work in progress (CWIP), including allowance for funds used during
construction (AFUDC), as provided in
this section.
(1) Pollution control facilities—(i) General rule. Any CWIP for pollution control facilities allocable to electric
§ 35.25
power sales for resale may be included
in the rate base of the public utility.
(ii) Qualification as a pollution control
facility. In determining whether a facility is a pollution control facility for
purposes of this section, the Commission will consider:
(A) Whether such facility is the type
facility described in the Internal Revenue Service laws, 26 U.S.C. 169(d)(1), as
follows:
‘‘A new identifiable treatment facility
which is used * * * to abate or control water
or atmospheric pollution or contamination
by removing, altering, disposing, storing, or
preventing the creation or emission of pollutants, contaminants, wastes or heat’’;
(B) Whether such facility has been
certified by a local, state, or federal
agency as being in conformity with, or
required by, a program of pollution
control;
(C) Other evidence showing that such
facilities are for pollution control.
(2) Fuel conversion facilities. Any
CWIP for fuel conversion facilities allocable to electric power sales for resale
may be included in the rate base of the
public utility.
(3) Non-pollution control of fuel conversion (non-PC/FC) CWIP. No more than
50 percent of any CWIP allocable to
electric power sales for resale not otherwise included in rate base under
paragraphs (c) (1) and (2) of this section, may be included in the rate base
of the public utility.
(4) Forward looking allocation ratios.
Every test period CWIP project requested for wholesale rate base treatment pursuant to § 35.26(c)(1), (2), and
(3) of this part will be allocated to the
customer classes on the basis of forward looking allocation ratios reflecting the anticipated average annual use
the wholesale customers will make of
the system over the estimated service
life of the project. Supporting documentation, as required by §§ 35.12 and
35.13 of this part, must be in sufficient
detail to permit examination and
verification of the forward looking allocation ratio’s recognition of each
wholesale customer’s plans, if any, for
future alternative or supplementary
power supplies. For the purpose of preventing anticompetitive effects, including CWIP-induced price squeeze
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§ 35.25
18 CFR Ch. I (4–1–19 Edition)
and double whammy, sufficient recognition of such plans may require the
public utility applicant to provide for
separate customer groups or provide
for a rate design incorporating selected
CWIP project credits.
(d) Effective date. If a public utility
proposes in its filed rates to include
CWIP in rate base under this section,
that portion of the rate related to
CWIP is collectible at the time the
general rates become effective pursuant to Commission order, whether or
not subject to refund, except as provided in paragraph (g) of this section.
(e) Discontinuance of AFUDC. On the
date that any proposed rate that includes CWIP in rate base becomes effective, a public utility that has included CWIP in rate base must discontinue the capitalization of any
AFUDC related to those amounts of
CWIP is rate base.
(f) Accounting procedures. When a public utility files to include CWIP in its
rate base pursuant to this section, it
must propose accounting procedures in
that rate schedule filing that:
(1) Ensure that wholesale customers
will not be charged for both capitalized
AFUDC and corresponding amounts of
CWIP proposed to be included in rate
base; and
(2) Ensure that wholesale customers
will not be charged for any corresponding AFUDC capitalized as a result of different accounting or ratemaking treatments accorded CWIP by
state or local regulatory authorities.
(g) Anticompetitive procedures—(1) Filing requirements. In order to facilitate
Commission review of the anticompetitive effects of applications for CWIP
pursuant to § 35.26(c)(3), a public utility
applying for rates based upon inclusion
of such CWIP in rate base must include
the following information in its filing:
(i) The percentage of the proposed increase in the jurisdictional rate level
attributable to non-pollution control/
fuel conversion CWIP and the percentage of non-pollution control/fuel conversion CWIP supporting the proposed
rate level;
(ii) The percentage of non-pollution
control/fuel conversion CWIP permitted by the state or local commission supporting the current retail rates
of the public utility against which the
relevant wholesale customers compete;
and
(iii) Individual earned rate of return
analyses of each of the competing retail rates developed on a basis fully
consistent with the wholesale cost of
service for the same test period if the
requested percentage of wholesale nonpollution control/fuel conversion CWIP
exceeds that permitted by the relevant
state or local authority to support the
currently competing retail rates.
(2) Preliminary relief. (i) If an intervenor in its initial pleading alleges
that a price squeeze will occur as a direct result of the public utility’s request for CWIP pursuant to § 35.26(c)(3),
makes a showing that it is likely to
incur harm if such CWIP is allowed
subject to refund, and makes a showing
of how the harm to the intervenor
would be mitigated or eliminated by
the types of preliminary relief requested, the Commission will consider
preliminary relief at the suspension
stage of the case pursuant to paragraph
(g)(4) of this section. In determining
whether to grant preliminary relief,
the Commission will balance the following public interest considerations:
(A) The harm to the intervenor if it
is not granted preliminary relief from
the requested CWIP;
(B) The harm to the public utility if,
during the interim period of preliminary relief, the public utility is required to recover its financing charges
later through AFUDC rather than immediately through CWIP; and
(C) Mitigating bias against investment in new plants, ensuring accurate
price signals, and fostering rate stability.
(ii) Whether or not preliminary relief
is granted at the suspension stage will
not preclude consideration of further
interim or final remedies later in the
proceedings, if warranted.
(3) If the Commission makes a final
determination that a price squeeze due
solely to allowance of a lower percentage of non-pollution control/fuel conversion CWIP in the public utility’s retail rate base than allowed by this
Commission, the Commission will consider an adjustment to non-pollution
control/fuel conversion CWIP in order
to eliminate or mitigate the price
squeeze.
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Federal Energy Regulatory Commission
(4) If an intervenor meets the requirements of paragraph (g)(2) of this
section, the Commission, depending on
the type of showing made including the
likelihood, immediacy, and severity of
any anticompetitive harm, may:
(i) Suspend the entire rate increase
or all or a portion of the non-pollution
control/fuel conversion CWIP component for up to five months;
(ii) Allow all or a portion of the nonpollution control/fuel conversion CWIP
only prospectively from the issuance of
the Commission’s final order on rehearing on the matter; or
(iii) Take such other action as is
proper under the circumstances.
[Order 474, 52 FR 23965, June 26, 1987, as
amended by Order 474–A, 52 FR 35702, Sept.
23, 1987; Order 474–B, 54 FR 32804, Aug. 10,
1989. Redesignated by Order 545, 57 FR 53990,
Nov. 16, 1992, as amended by Order 626, 67 FR
36096, May 23, 2002]
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§ 35.26 Recovery of stranded costs by
public utilities and transmitting
utilities.
(a) Purpose. This section establishes
the standards that a public utility or
transmitting utility must satisfy in
order to recover stranded costs.
(b) Definitions—1) Wholesale stranded
cost means any legitimate, prudent and
verifiable cost incurred by a public
utility or a transmitting utility to provide service to:
(i) A wholesale requirements customer that subsequently becomes, in
whole or in part, an unbundled wholesale transmission services customer of
such public utility or transmitting
utility; or
(ii) A retail customer that subsequently becomes, either directly or
through another wholesale transmission
purchaser,
an
unbundled
wholesale transmission services customer of such public utility or transmitting utility.
(2) Wholesale requirements customer
means a customer for whom a public
utility or transmitting utility provides
by contract any portion of its bundled
wholesale power requirements.
(3) Wholesale transmission services
means the transmission of electric energy sold, or to be sold, at wholesale in
interstate commerce or ordered pursu-
§ 35.26
ant to section 211 of the Federal Power
Act (FPA).
(4) Wholesale requirements contract
means a contract under which a public
utility or transmitting utility provides
any portion of a customer’s bundled
wholesale power requirements.
(5) Retail stranded cost means any legitimate, prudent and verifiable cost
incurred by a public utility to provide
service to a retail customer that subsequently becomes, in whole or in part,
an unbundled retail transmission services customer of that public utility.
(6) Retail transmission services means
the transmission of electric energy
sold, or to be sold, in interstate commerce directly to a retail customer.
(7) New wholesale requirements contract
means any wholesale requirements contract executed after July 11, 1994, or extended or renegotiated to be effective
after July 11, 1994.
(8) Existing wholesale requirements contract means any wholesale requirements
contract executed on or before July 11,
1994.
(c) Recovery of wholesale stranded
costs—1) General requirement. A public
utility or transmitting utility will be
allowed to seek recovery of wholesale
stranded costs only as follows:
(i) No public utility or transmitting
utility may seek recovery of wholesale
stranded costs if such recovery is explicitly prohibited by a contract or settlement agreement, or by any power
sales or transmission rate schedule or
tariff.
(ii) No public utility or transmitting
utility may seek recovery of stranded
costs associated with a new wholesale
requirements contract if such contract
does not contain an exit fee or other
explicit stranded cost provision.
(iii) If wholesale stranded costs are
associated with a new wholesale requirements contract containing an exit
fee or other explicit stranded cost provision, and the seller under the contract is a public utility, the public utility may seek recovery of such costs, in
accordance with the contract, through
rates for electric energy under sections
205–206 of the FPA. The public utility
may not seek recovery of such costs
through any transmission rate for FPA
section 205 or 211 transmission services.
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§ 35.26
18 CFR Ch. I (4–1–19 Edition)
(iv) If wholesale stranded costs are
associated with a new wholesale requirements contract, and the seller
under the contract is a transmitting
utility but not also a public utility, the
transmitting utility may not seek an
order from the Commission allowing
recovery of such costs.
(v) If wholesale stranded costs are associated with an existing wholesale requirements contract, if the seller under
such contract is a public utility, and if
the contract does not contain an exit
fee or other explicit stranded cost provision, the public utility may seek recovery of stranded costs only as follows:
(A) If either party to the contract
seeks a stranded cost amendment pursuant to a section 205 or section 206 filing under the FPA made prior to the
expiration of the contract, and the
Commission accepts or approves an
amendment permitting recovery of
stranded costs, the public utility may
seek recovery of such costs through
FPA section 205–206 rates for electric
energy.
(B) If the contract is not amended to
permit recovery of stranded costs as
described in paragraph (c)(1)(v)(A) of
this section, the public utility may file
a proposal, prior to the expiration of
the contract, to recover stranded costs
through FPA section 205–206 or section
211–212 rates for wholesale transmission services to the customer.
(vi) If wholesale stranded costs are
associated with an existing wholesale
requirements contract, if the seller
under such contract is a transmitting
utility but not also a public utility,
and if the contract does not contain an
exit fee or other explicit stranded cost
provision, the transmitting utility may
seek recovery of stranded costs
through FPA section 211–212 transmission rates.
(vii) If a retail customer becomes a
legitimate wholesale transmission customer of a public utility or transmitting
utility,
e.g.,
through
municipalization, and costs are stranded as a result of the retail-turnedwholesale customer’s access to wholesale transmission, the utility may seek
recovery of such costs through FPA
section 205–206 or section 211–212 rates
for wholesale transmission services to
that customer.
(2) Evidentiary demonstration for
wholesale stranded cost recovery. A public utility or transmitting utility seeking to recover wholesale stranded costs
in accordance with paragraphs (c)(1) (v)
through (vii) of this section must demonstrate that:
(i) It incurred costs to provide service
to a wholesale requirements customer
or retail customer based on a reasonable expectation that the utility would
continue to serve the customer;
(ii) The stranded costs are not more
than the customer would have contributed to the utility had the customer
remained a wholesale requirements
customer of the utility, or, in the case
of a retail-turned-wholesale customer,
had the customer remained a retail
customer of the utility; and
(iii) The stranded costs are derived
using the following formula: Stranded
Cost Obligation = (Revenue Stream Estimate—Competitive Market Value Estimate) × Length of Obligation (reasonable expectation period).
(3) Rebuttable presumption. If a public
utility or transmitting utility seeks recovery of wholesale stranded costs associated with an existing wholesale requirements contract, as permitted in
paragraph (c)(1) of this section, and the
existing wholesale requirements contract contains a notice provision, there
will be a rebuttable presumption that
the utility had no reasonable expectation of continuing to serve the customer beyond the term of the notice
provision.
(4) Procedure for customer to obtain
stranded cost estimate. A customer under
an existing wholesale requirements
contract with a public utility seller
may obtain from the seller an estimate
of the customer’s stranded cost obligation if it were to leave the public utility’s generation supply system by filing with the public utility a request for
an estimate at any time prior to the
termination date specified in its contract.
(i) The public utility must provide a
response within 30 days of receiving the
request. The response must include:
(A) An estimate of the customer’s
stranded cost obligation based on the
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Federal Energy Regulatory Commission
formula in paragraph (c)(2)(iii) of this
section;
(B) Supporting detail indicating how
each element in the formula was derived;
(C) A detailed rationale justifying
the basis for the utility’s reasonable
expectation of continuing to serve the
customer beyond the termination date
in the contract;
(D) An estimate of the amount of released capacity and associated energy
that would result from the customer’s
departure; and
(E) The utility’s proposal for any
contract amendment needed to implement the customer’s payment of
stranded costs.
(ii) If the customer disagrees with
the utility’s response, it must respond
to the utility within 30 days explaining
why it disagrees. If the parties cannot
work out a mutually agreeable resolution, they may exercise their rights to
Commission resolution under the FPA.
(5) A customer must be given the option to market or broker a portion or
all of the capacity and energy associated with any stranded costs claimed
by the public utility.
(i) To exercise the option, the customer must so notify the utility in
writing no later than 30 days after the
public utility files its estimate of
stranded costs for the customer with
the Commission.
(A) Before marketing or brokering
can begin, the utility and customer
must execute an agreement identifying, at a minimum, the amount and
the price of capacity and associated energy the customer is entitled to schedule, and the duration of the customer’s
marketing or brokering of such capacity and energy.
(ii) If agreement over marketing or
brokering cannot be reached, and the
parties seek Commission resolution of
disputed issues, upon issuance of a
Commission order resolving the disputed issues, the customer may reevaluate its decision in paragraph
(c)(5)(i) of this section to exercise the
marketing or brokering option. The
customer must notify the utility in
writing within 30 days of issuance of
the Commission’s order resolving the
disputed issues whether the customer
will market or broker a portion or all
§ 35.27
of the capacity and energy associated
with stranded costs allowed by the
Commission.
(iii) If a customer undertakes the
brokering option, and the customer’s
brokering efforts fail to produce a
buyer within 60 days of the date of the
brokering agreement entered into between the customer and the utility, the
customer shall relinquish all rights to
broker the released capacity and associated energy and will pay stranded
costs as determined by the formula in
paragraph (c)(2)(iii) of this section.
(d) Recovery of retail stranded costs—1)
General requirement. A public utility
may seek to recover retail stranded
costs through rates for retail transmission services only if the state regulatory authority does not have authority under state law to address stranded
costs at the time the retail wheeling is
required.
(2) Evidentiary demonstration necessary
for retail stranded cost recovery. A public
utility seeking to recover retail stranded costs in accordance with paragraph
(d)(1) of this section must demonstrate
that:
(i) It incurred costs to provide service
to a retail customer that obtains retail
wheeling based on a reasonable expectation that the utility would continue
to serve the customer; and
(ii) The stranded costs are not more
than the customer would have contributed to the utility had the customer
remained a retail customer of the utility.
[Order 888–A, 62 FR 12460, Mar. 14, 1997]
§ 35.27
Authority of State commissions.
Nothing in this part—
(a) Shall be construed as preempting
or affecting any jurisdiction a State
commission or other State authority
may have under applicable State and
Federal law, or
(b) Limits the authority of a State
commission in accordance with State
and Federal law to establish
(1) Competitive procedures for the acquisition of electric energy, including
demand-side management, purchased
at wholesale, or
(2) Non-discriminatory fees for the
distribution of such electric energy to
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§ 35.28
18 CFR Ch. I (4–1–19 Edition)
retail consumers for purposes established in accordance with State law.
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[Order 697, 72 FR 40038, July 20, 2007]
§ 35.28 Non-discriminatory open access
transmission tariff.
(a) Applicability. This section applies
to any public utility that owns, controls or operates facilities used for the
transmission of electric energy in
interstate commerce and to any nonpublic utility that seeks voluntary
compliance with jurisdictional transmission tariff reciprocity conditions.
(b) Definitions—(1) Requirements service agreement means a contract or rate
schedule under which a public utility
provides any portion of a customer’s
bundled wholesale power requirements.
(2) Economy energy coordination agreement means a contract, or service
schedule thereunder, that provides for
trading of electric energy on an ‘‘if, as
and when available’’ basis, but does not
require either the seller or the buyer to
engage in a particular transaction.
(3) Non-economy energy coordination
agreement means any non-requirements
service agreement, except an economy
energy coordination agreement as defined in paragraph (b)(2) of this section.
(4) Demand response means a reduction in the consumption of electric energy by customers from their expected
consumption in response to an increase
in the price of electric energy or to incentive payments designed to induce
lower consumption of electric energy.
(5) Demand response resource means a
resource capable of providing demand
response.
(6) An operating reserve shortage
means a period when the amount of
available supply falls short of demand
plus the operating reserve requirement.
(7) Market Monitoring Unit means the
person or entity responsible for carrying out the market monitoring functions that the Commission has ordered
Commission-approved independent system operators and regional transmission organizations to perform.
(8) Market Violation means a tariff
violation, violation of a Commissionapproved order, rule or regulation,
market manipulation, or inappropriate
dispatch that creates substantial concerns regarding unnecessary market
inefficiencies.
(9) Electric storage resource as used in
this section means a resource capable
of receiving electric energy from the
grid and storing it for later injection of
electric energy back to the grid.
(c) Non-discriminatory open access
transmission tariffs. (1) Every public
utility that owns, controls, or operates
facilities used for the transmission of
electric energy in interstate commerce
must have on file with the Commission
an open access transmission tariff of
general applicability for transmission
services, including ancillary services,
over such facilities. Such tariff must be
the pro forma tariff promulgated by the
Commission, as amended from time to
time, or such other tariff as may be approved by the Commission consistent
with the principles set forth in Commission rulemaking proceedings promulgating and amending the pro forma
tariff.
(i) Subject to the exceptions in paragraphs (c)(1)(ii), (c)(1)(iii), (c)(1)(iv),
and (c)(1)(v) of this section, the open
access transmission tariff, which tariff
must be the pro forma tariff required by
Commission rulemaking proceedings
promulgating and amending the pro
forma tariff, and accompanying rates
must be filed no later than 60 days
prior to the date on which a public
utility would engage in a sale of electric energy at wholesale in interstate
commerce or in the transmission of
electric energy in interstate commerce.
(ii) If a public utility owns, controls,
or operates facilities used for the
transmission of electric energy in
interstate commerce, it must file the
revisions to its open access transmission tariff required by Commission
rulemaking proceedings promulgating
and amending the pro forma tariff, pursuant to section 206 of the FPA and accompanying rates pursuant to section
205 of the FPA in accordance with the
procedures set forth in Commission
rulemaking proceedings promulgating
and amending the pro forma tariff.
(iii) If a public utility owns, controls,
or operates transmission facilities used
for the transmission of electric energy
in interstate commerce, such facilities
are jointly owned with a non-public
utility, and the joint ownership contract prohibits transmission service
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Federal Energy Regulatory Commission
over the facilities to third parties, the
public utility with respect to access
over the public utility’s share of the
jointly owned facilities must file the
revisions to its open access transmission tariff required by Commission
rulemaking proceedings promulgating
and amending the pro forma tariff pursuant to section 206 of the FPA and accompanying rates pursuant to section
205 of the FPA in accordance with the
procedures set forth in Commission
rulemaking proceedings promulgating
and amending the pro forma tariff.
(iv) Any public utility whose transmission facilities are under the independent control of a Commission-approved ISO or RTO may satisfy its obligation under paragraph (c)(1) of this
section, with respect to such facilities,
through the open access transmission
tariff filed by the ISO or RTO.
(v) If a public utility obtains a waiver
of the tariff requirement pursuant to
paragraph (d) of this section, it does
not need to file the open access transmission tariff required by this section.
(vi) Any public utility that seeks a
deviation from the pro forma tariff promulgated by the Commission, as
amended from time to time, must demonstrate that the deviation is consistent with the principles set forth in
Commission rulemaking proceedings
promulgating and amending the pro
forma tariff.
(vii) Each public utility’s open access
transmission tariff must include the
standards incorporated by reference in
part 38 of this chapter.
(2) Subject to the exceptions in paragraphs (c)(2)(i) and (c)(3)(iii) of this section, every public utility that owns,
controls, or operates facilities used for
the transmission of electric energy in
interstate commerce, and that uses
those facilities to engage in wholesale
sales and/or purchases of electric energy, or unbundled retail sales of electric energy, must take transmission
service for such sales and/or purchases
under the open access transmission
tariff filed pursuant to this section.
(i) For sales of electric energy pursuant to a requirements service agreement executed on or before July 9, 1996,
this requirement will not apply unless
separately ordered by the Commission.
For sales of electric energy pursuant to
§ 35.28
a bilateral economy energy coordination agreement executed on or before
July 9, 1996, this requirement is effective on December 31, 1996. For sales of
electric energy pursuant to a bilateral
non-economy
energy
coordination
agreement executed on or before July
9, 1996, this requirement will not apply
unless separately ordered by the Commission.
(ii) [Reserved]
(3) Every public utility that owns,
controls, or operates facilities used for
the transmission of electric energy in
interstate commerce, and that is a
member of a power pool, public utility
holding company, or other multi-lateral trading arrangement or agreement
that contains transmission rates,
terms or conditions, must have on file
a joint pool-wide or system-wide open
access transmission tariff, which tariff
must be the pro forma tariff promulgated by the Commission, as amended
from time to time, or such other open
access transmission tariff as may be
approved by the Commission consistent
with the principles set forth in Commission rulemaking proceedings promulgating and amending the pro forma
tariff.
(i) For any power pool, public utility
holding company or other multi-lateral
arrangement or agreement that contains transmission rates, terms or conditions and that is executed after October 11, 2011, this requirement is effective on the date that transactions
begin under the arrangement or agreement.
(ii) For any power pool, public utility
holding company or other multi-lateral
arrangement or agreement that contains transmission rates, terms or conditions and that is executed on or before May 14, 2007, a public utility member of such power pool, public utility
holding company or other multi-lateral
arrangement or agreement that owns,
controls, or operates facilities used for
the transmission of electric energy in
interstate commerce must file the revisions to its joint pool-wide or systemwide open access transmission tariff required by Commission rulemaking proceedings promulgating and amending
the pro forma tariff pursuant to section
206 of the FPA and accompanying rates
pursuant to section 205 of the FPA in
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§ 35.28
18 CFR Ch. I (4–1–19 Edition)
accordance with the procedures set
forth in Commission rulemaking proceedings promulgating and amending
the pro forma tariff.
(iii) A public utility member of a
power pool, public utility holding company or other multi-lateral arrangement or agreement that contains
transmission rates, terms or conditions
and that is executed on or before July
9, 1996 must take transmission service
under a joint pool-wide or system-wide
open access transmission tariff filed
pursuant to this section for wholesale
trades among the pool or system members.
(4) Consistent with paragraph (c)(1) of
this section, every Commission-approved ISO or RTO must have on file
with the Commission an open access
transmission tariff of general applicability for transmission services, including ancillary services, over such facilities. Such tariff must be the pro forma
tariff promulgated by the Commission,
as amended from time to time, or such
other tariff as may be approved by the
Commission consistent with the principles set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
(i) Subject to paragraph (c)(4)(ii) of
this section, a Commission-approved
ISO or RTO must file the revisions to
its open access transmission tariff required by Commission rulemaking proceedings promulgating and amending
the pro forma tariff pursuant to section
206 of the FPA and accompanying rates
pursuant to section 205 of the FPA in
accordance with the procedures set
forth in Commission rulemaking proceedings promulgating and amending
the pro forma tariff.
(ii) If a Commission-approved ISO or
RTO can demonstrate that its existing
open access transmission tariff is consistent with or superior to the pro
forma tariff promulgated by the Commission, as amended from time to
time, the Commission-approved ISO or
RTO may instead set forth such demonstration in its filing pursuant to section 206 in accordance with the procedures set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
(d) Waivers. (1) A public utility subject to the requirements of this section
and 18 CFR parts 37 (Open Access
Same-Time Information System) and
358 (Standards of Conduct for Transmission Providers) may file a request
for waiver of all or part of such requirements for good cause shown. Except as provided in paragraph (f) of this
section, an application for waiver must
be filed no later than 60 days prior to
the time the public utility would have
to comply with the requirement.
(2) The requirements of this section,
18 CFR parts 37 (Open Access SameTime Information System) and 358
(Standards of Conduct for Transmission Providers) are waived for any
public utility that is or becomes subject to such requirements solely because it owns, controls, or operates
Interconnection
Customer’s
Interconnection Facilities, in whole or in
part, as that term is defined in the
standard generator interconnection
procedures and agreements referenced
in paragraph (f) of this section, or comparable jurisdictional interconnection
facilities that are the subject of interconnection agreements other than the
standard generator interconnection
procedures and agreements referenced
in paragraph (f) of this section, if the
entity that owns, operates, or controls
such facilities either sells electric energy, or files a statement with the
Commission that it commits to comply
with and be bound by the obligations
and procedures applicable to electric
utilities under section 210 of the Federal Power Act.
(i) The waivers referenced in this
paragraph (d)(2) shall be deemed to be
revoked as of the date the public utility ceases to satisfy the qualifications
of this paragraph (d)(2), and may be revoked by the Commission if the Commission determines that it is in the
public interest to do so. After revocation of its waivers, the public utility
must comply with the requirements
that had been waived within 60 days of
revocation.
(ii) Any eligible entity that seeks
interconnection or transmission services with respect to the interconnection facilities for which a waiver is in
effect pursuant to this paragraph (d)(2)
may follow the procedures in sections
210, 211, and 212 of the Federal Power
Act, 18 CFR 2.20, and 18 CFR part 36. In
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Federal Energy Regulatory Commission
any proceeding pursuant to this paragraph (d)(2)(ii):
(A) The Commission will consider it
to be in the public interest to grant
priority rights to the owner and/or operator of interconnection facilities
specified in this paragraph (d)(2) to use
capacity thereon when such owner and/
or operator can demonstrate that it
has specific plans with milestones to
use such capacity to interconnect its
or its affiliate’s future generation
projects.
(B) For the first five years after the
commercial operation date of the
interconnection facilities specified in
this paragraph (d)(2), the Commission
will apply the rebuttable presumption
that the owner and/or operator of such
facilities has definitive plans to use the
capacity thereon, and it is thus in the
public interest to grant priority rights
to the owner and/or operator of such facilities to use capacity thereon.
(e) Non-public utility procedures for
tariff reciprocity compliance. (1) A nonpublic utility may submit an open access transmission tariff and a request
for declaratory order that its voluntary transmission tariff meets the
requirements of Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
(i) Any submittal and request for declaratory order submitted by a nonpublic utility will be provided an NJ
(non-jurisdictional) docket designation.
(ii) If the submittal is found to be an
acceptable open access transmission
tariff, an applicant in a Federal Power
Act (FPA) section 211 or 211A proceeding against the non-public utility
shall have the burden of proof to show
why service under the open access
transmission tariff is not sufficient and
why a section 211 or 211A order should
be granted.
(2) A non-public utility may file a request for waiver of all or part of the
reciprocity conditions contained in a
public utility open access transmission
tariff, for good cause shown. An application for waiver may be filed at any
time.
(f) Standard generator interconnection
procedures and agreements. (1) Every
public utility that is required to have
on file a non-discriminatory open ac-
§ 35.28
cess transmission tariff under this section must amend such tariff by adding
the standard interconnection procedures and agreement and the standard
small generator interconnection procedures and agreement required by Commission rulemaking proceedings promulgating and amending such interconnection procedures and agreements,
or such other interconnection procedures and agreements as may be required by Commission rulemaking proceedings promulgating and amending
the standard interconnection procedures and agreement and the standard
small generator interconnection procedures and agreement.
(i) Any public utility that seeks a deviation from the standard interconnection procedures and agreement or the
standard small generator interconnection procedures and agreement required by Commission rulemaking proceedings promulgating and amending
such interconnection procedures and
agreements, must demonstrate that
the deviation is consistent with the
principles set forth in Commission
rulemaking proceedings promulgating
and amending such interconnection
procedures and agreements.
(ii)–(iv) [Reserved]
(2) The non-public utility procedures
for tariff reciprocity compliance described in paragraph (e) of this section
are applicable to the standard interconnection procedures and agreements.
(3) A public utility subject to the requirements of this paragraph (f) may
file a request for waiver of all or part
of the requirements of this paragraph
(f), for good cause shown.
(g) Tariffs and operations of Commission-approved independent system operators and regional transmission organizations—(1) Demand response and pricing—
(i) Ancillary services provided by demand
response resources. (A) Every Commission-approved independent system operator or regional transmission organization that operates organized markets
based on competitive bidding for energy
imbalance,
spinning
reserves,supplemental reserves, reactive
power and voltage control, or regulation and frequency response ancillary
services (or its functional equivalent in
the Commission-approved independent
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§ 35.28
18 CFR Ch. I (4–1–19 Edition)
system operator’s or regional transmission organization’s tariff) must accept bids from demand response resources in these markets for that product on a basis comparable to any other
resources, if the demand response resource meets the necessary technical
requirements under the tariff, and submits a bid under the Commission-approved independent system operator’s
or regional transmission organization’s
bidding rules at or below the marketclearing price, unless not permitted by
the laws or regulations of the relevant
electric retail regulatory authority.
(B) Each Commission-approved independent system operator or regional
transmission organization must allow
providers of a demand response resource to specify the following in their
bids:
(1) A maximum duration in hours
that the demand response resource
may be dispatched;
(2) A maximum number of times that
the demand response resource may be
dispatched during a day; and
(3) A maximum amount of electric
energy reduction that the demand response resource may be required to
provide either daily or weekly.
(ii) Removal of deviation charges. A
Commission-approved independent system operator or regional transmission
organization with a tariff that contains
a day-ahead and a real-time market
may not assess charge to a purchaser
of electric energy in its day-ahead market for purchasing less power in the
real-time market during a real-time
market period for which the Commission-approved independent system operator or regional transmission organization declares an operating reserve
shortage or makes a generic request to
reduce load to avoid an operating reserve shortage.
(iii) Aggregation of retail customers.
Each
Commission-approved
independent system operator and regional
transmission organization must accept
bids from an aggregator of retail customers that aggregates the demand response of the customers of utilities
that distributed more than 4 million
megawatt-hours in the previous fiscal
year, and the customers of utilities
that distributed 4 million megawatthours or less in the previous fiscal
year, where the relevant electric retail
regulatory authority permits such customers’ demand response to be bid into
organized markets by an aggregator of
retail customers. An independent system operator or regional transmission
organization must not accept bids from
an aggregator of retail customers that
aggregates the demand response of the
customers of utilities that distributed
more than 4 million megawatt-hours in
the previous fiscal year, where the relevant electric retail regulatory authority prohibits such customers’ demand
response to be bid into organized markets by an aggregator of retail customers, or the customers of utilities
that distributed 4 million megawatthours or less in the previous fiscal
year, unless the relevant electric retail
regulatory authority permits such customers’ demand response to be bid into
organized markets by an aggregator of
retail customers.
(iv) Price formation during periods of
operating reserve shortage. (A) Each
Commission-approved independent system operator and regional transmission organization must modify its
market rules to allow the marketclearing price during periods of operating reserve shortage to reach a level
that rebalances supply and demand so
as to maintain reliability while providing sufficient provisions for mitigating market power. Each Commission-approved independent system operator and regional transmission organization must trigger shortage pricing
for any interval in which a shortage of
energy or operating reserves is indicated during the pricing of resources
for that interval.
(B) A Commission-approved independent system operator or regional
transmission organization may phase
in this modification of its market
rules.
(v) Demand response compensation in
energy markets. Each Commission-approved independent system operator or
regional
transmission
organization
that has a tariff provision permitting
demand response resources to participate as a resource in the energy market by reducing consumption of electric energy from their expected levels
in response to price signals must:
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Federal Energy Regulatory Commission
(A) Pay to those demand response resources the market price for energy for
these reductions when these demand
response resources have the capability
to balance supply and demand and
when payment of the market price for
energy to these resources is cost-effective as determined by a net benefits
test accepted by the Commission;
(B) Allocate the costs associated with
demand response compensation proportionally to all entities that purchase
from the relevant energy market in the
area(s) where the demand response reduces the market price for energy at
the time when the demand response resource is committed or dispatched.
(vi) Settlement intervals. Each Commission-approved independent system
operator and regional transmission organization must settle energy transactions in its real-time markets at the
same time interval it dispatches energy, must settle operating reserves
transactions in its real-time markets
at the same time interval it prices operating reserves, and must settle
intertie transactions at the same time
interval it schedules intertie transactions.
(2) Long-term power contracting in organized markets. Each Commission-approved independent system operator or
regional
transmission
organization
must provide a portion of its Web site
for market participants to post offers
to buy or sell power on a long-term
basis.
(3) Market monitoring policies. (i) Each
Commission-approved independent system operator or regional transmission
organization must modify its tariff
provisions governing its Market Monitoring Unit to reflect the directives
provided in OrderNo. 719, including the
following:
(A) Each Commission-approved independent system operator or regional
transmission organization must include in its tariff a provision to provide
its Market Monitoring Unit access to
Commission-approved independent system operator and regional transmission organization market data, resources and personnel to enable the
MarketMonitoring Unit to carry out
its functions.
(B) The tariff provision must provide
the Market Monitoring Unit complete
§ 35.28
access to the Commission-approved
independent system operator’s and regional
transmission
organization’s
databases of market information.
(C) The tariff provision must provide
that any data created by the Market
Monitoring Unit, including, but not
limited to, reconfiguring of the Commission-approved independent system
operator’s and regional transmission
organization’s data, will be kept within
the exclusive control of the Market
Monitoring Unit.
(D) The Market Monitoring Unit
must report to the Commission-approved independent system operator’s
or regional transmission organization’s
board of directors, with its management members removed, or to an independent committee of the Commissionapproved independent system operator’s or regional transmission organization’s board of directors. A Commission-approved independent system operator or regional transmission organization that has both an internal Market Monitoring Unit and an external
Market Monitoring Unit may permit
the internal Market Monitoring Unit
to report to management and the external Market Monitoring Unit to report to the Commission-approved independent system operator’s or regional
transmission organization’s board of
directors with its management members removed, or to an independent
committee of the Commission-approved independent system operator or
regional
transmission
organization
board of directors. If the internal market monitor is responsible for carrying
out any or all of the core Market Monitoring Unit functions identified in
paragraph (g)(3)(ii) of this section, the
internal market monitor must report
to the independent system operator’s
or regional transmission organization’s
board of directors.
(E) A Commission-approved independent system operator or regional
transmission organization may not
alter the reports generated by the Market Monitoring Unit, or dictate the
conclusions reached by the Market
Monitoring Unit.
(F) Each Commission-approved independent system operator or regional
transmission organization must consolidate the core Market Monitoring
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§ 35.28
18 CFR Ch. I (4–1–19 Edition)
Unit provisions into one section of its
tariff. Each independent system operator or regional transmission organization must include a mission statement
in the introduction to the Market Monitoring Unit provisions that identifies
the Market Monitoring Unit’s goals,
including the protection of consumers
and market participants by the identification and reporting of market design
flaws and market power abuses.
(ii) Core Functions of Market Monitoring Unit. The Market Monitoring
Unit must perform the following core
functions:
(A) Evaluate existing and proposed
market rules, tariff provisions and
market design elements and recommend proposed rule and tariff
changes to the Commission-approved
independent system operator or regional transmission organization, to
the Commission’s Office of Energy
Market Regulation staff and to other
interested entities such as state commissions and market participants, provided that:
(1) The Market Monitoring Unit is
not to effectuate its proposed market
design itself, and
(2) The Market Monitoring Unit must
limit distribution of its identifications
and recommendations to the independent system operator or regional
transmission organization and to Commission staff in the event it believes
broader dissemination could lead to exploitation, with an explanation of why
further dissemination should be avoided at that time.
(B) Review and report on the performance of the wholesale markets to
the Commission-approved independent
system operator or regional transmission organization, the Commission,
and other interested entities such as
state commissions and market participants, on at least a quarterly basis and
submit a more comprehensive annual
state of the market report. The Market
Monitoring Unit may issue additional
reports as necessary.
(C) Identify and notify the Commission’s Office of Enforcement staff of instances in which a market participant’s or the Commission-approved
independent system operator’s or regional transmission organization’s behavior may require investigation, in-
cluding, but not limited to, suspected
Market Violations.
(iii) Tariff administration and mitigation (A) A Commission-approved independent system operator or regional
transmission organization may not
permit its Market Monitoring Unit,
whether internal or external, to participate in the administration of the
Commission-approved independent system operator’s or regional transmission organization’s tariff or, except
as provided in paragraph (g)(3)(iii)(D)
of this section, to conduct prospective
mitigation.
(B) A Commission-approved independent system operator or regional
transmission organization may permit
its Market Monitoring Unit to provide
the inputs required for the Commission-approved independent system operator or regional transmission organization to conduct prospective mitigation, including, but not limited to, reference levels, identification of system
constraints, and cost calculations.
(C) A Commission-approved independent system operator or regional
transmission organization may allow
its Market Monitoring Unit to conduct
retrospective mitigation.
(D) A Commission-approved independent system operator or regional
transmission organization with a hybrid Market Monitoring Unit structure
may permit its internal market monitor to conduct prospective and/or retrospective mitigation, in which case it
must assign to its external market
monitor the responsibility and the
tools to monitor the quality and appropriateness of the mitigation.
(E) Each Commission-approved independent system operator or regional
transmission organization must identify in its tariff the functions the Market Monitoring Unit will perform and
the functions the Commission-approved independent system operator or
regional transmission organization will
perform.
(iv) Protocols on Market Monitoring
Unit referrals to the Commission of suspected violations. (A) A Market Monitoring Unit is to make a non-public referral to the Commission in all instances where the Market Monitoring
Unit has reason to believe that a Market Violation has occurred. While the
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Federal Energy Regulatory Commission
Market Monitoring Unit need not be
able to prove that a Market Violation
has occurred, the Market Monitoring
Unit is to provide sufficient credible
information to warrant further investigation by the Commission. Once the
Market Monitoring Unit has obtained
sufficient credible information to warrant referral to the Commission, the
Market Monitoring Unit is to immediately refer the matter to the Commission and desist from independent
action related to the alleged Market
Violation. This does not preclude the
Market Monitoring Unit from continuing to monitor for any repeated instances of the activity by the same or
other entities, which would constitute
new Market Violations. The Market
Monitoring Unit is to respond to requests from the Commission for any
additional information in connection
with the alleged Market Violation it
has referred.
(B) All referrals to the Commission
of alleged Market Violations are to be
in writing, whether transmitted electronically, by fax, mail, or courier. The
Market Monitoring Unit may alert the
Commission orally in advance of the
written referral.
(C) The referral is to be addressed to
the Commission’s Director of the Office
of Enforcement, with a copy also directed to both the Director of the Office of Energy Market Regulation and
the General Counsel.
(D) The referral is to include, but
need not be limited to, the following
information.
(1) The name[s] of and, if possible,
the contact information for, the
entity[ies] that allegedly took the
action[s] that constituted the alleged
Market Violation[s];
(2) The date[s] or time period during
which the alleged Market Violation[s]
occurred and whether the alleged
wrongful conduct is ongoing;
(3) The specific rule or regulation,
and/or tariff provision, that was allegedly violated, or the nature of any inappropriate dispatch that may have occurred;
(4) The specific act[s] or conduct that
allegedly constituted the Market Violation;
(5) The consequences to the market
resulting from the acts or conduct, in-
§ 35.28
cluding, if known, an estimate of economic impact on the market;
(6) If the Market Monitoring Unit believes that the act[s] or conduct constituted a violation of the anti-manipulation rule of Part 1c, a description of
the alleged manipulative effect on market prices, market conditions, or market rules;
(7) Any other information the Market
Monitoring Unit believes is relevant
and may be helpful to the Commission.
(E) Following a referral to the Commission, the Market Monitoring Unit is
to continue to notify and inform the
Commission of any information that
the Market Monitoring Unit learns of
that may be related to the referral, but
the Market Monitoring Unit is not to
undertake any investigative steps regarding the referral except at the express direction of the Commission or
Commission Staff.
(v) Protocols on Market Monitoring
Unit Referrals to the Commission of Perceived Market Design Flaws and Recommended Tariff Changes. (A) A Market
Monitoring Unit is to make a referral
to the Commission in all instances
where the Market Monitoring Unit has
reason to believe market design flaws
exist that it believes could effectively
be remedied by rule or tariff changes.
The Market Monitoring Unit must
limit distribution of its identifications
and recommendations to the independent system operator or regional
transmission organization and to the
Commission in the event it believes
broader dissemination could lead to exploitation, with an explanation of why
further dissemination should be avoided at that time.
(B) All referrals to the Commission
relating to perceived market design
flaws and recommended tariff changes
are to be in writing, whether transmitted electronically, by fax, mail, or
courier. The Market Monitoring Unit
may alert the Commission orally in advance of the written referral.
(C) The referral should be addressed
to the Commission’s Director of the Office of Energy Market Regulation, with
copies directed to both the Director of
the Office of Enforcement and the General Counsel.
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§ 35.28
18 CFR Ch. I (4–1–19 Edition)
(D) The referral is to include, but
need not be limited to, the following
information.
(1) A detailed narrative describing
the perceived market design flaw[s];
(2) The consequences of the perceived
market design flaw[s], including, if
known, an estimate of economic impact on the market;
(3) The rule or tariff change(s) that
the Market Monitoring Unit believes
could remedy the perceived market design flaw;
(4) Any other information the Market
Monitoring Unit believes is relevant
and may be helpful to the Commission.
(E) Following a referral to the Commission, the Market Monitoring Unit is
to continue to notify and inform the
Commission of any additional information regarding the perceived market
design flaw, its effects on the market,
any additional or modified observations concerning the rule or tariff
changes that could remedy the perceived design flaw, any recommendations made by the Market Monitoring
Unit to the regional transmission organization or independent system operator, stakeholders, market participants or state commissions regarding
the perceived design flaw, and any actions taken by the regional transmission organization or independent
system operator regarding the perceived design flaw.
(vi) Market Monitoring Unit ethics
standards. Each Commission-approved
independent system operator or regional transmission organization must
include in its tariff ethical standards
for its Market Monitoring Unit and the
employees of its Market Monitoring
Unit. At a minimum, the ethics standards must include the following requirements:
(A) The Market Monitoring Unit and
its employees must have no material
affiliation with any market participant
or affiliate.
(B) The Market Monitoring Unit and
its employees must not serve as an officer, employee, or partner of a market
participant.
(C) The Market Monitoring Unit and
its employees must have no material
financial interest in any market participant or affiliate with potential ex-
ceptions for mutual funds and non-directed investments.
(D) The Market Monitoring Unit and
its employees must not engage in any
market transactions other than the
performance of their duties under the
tariff.
(E) The Market Monitoring Unit and
its employees must not be compensated, other than by the Commission-approved independent system operator or regional transmission organization that retains or employs it, for
any expert witness testimony or other
commercial services, either to the
Commission-approved independent system operator or regional transmission
organization or to any other party, in
connection with any legal or regulatory proceeding or commercial transaction relating to the Commission-approved independent system operator or
regional transmission organization or
to the Commission-approved independent system operator’s or regional
transmission organization’s markets.
(F) The Market Monitoring Unit and
its employees may not accept anything
of value from a market participant in
excess of a de minimis amount.
(G) The Market Monitoring Unit and
its employees must advise a supervisor
in the event they seek employment
with a market participant, and must
disqualify themselves from participating in any matter that would have
an effect on the financial interest of
the market participant.
(4) Electronic delivery of data. Each
Commission-approved regional transmission organization and independent
system operator must electronically
deliver to the Commission, on an ongoing basis and in a form and manner
consistent with its own collection of
data and in a form and manner acceptable to the Commission, data related to
the markets that the regional transmission organization or independent
system operator administers.
(5) Offer and bid data. (i) Unless a
Commission-approved independent system operator or regional transmission
organization obtains Commission approval for a different period, each Commission-approved independent system
operator and regional transmission organization must release its offer and
bid data within three months.
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Federal Energy Regulatory Commission
(ii) A Commission-approved independent system operator or regional
transmission organization must mask
the identity of market participants
when releasing offer and bid data. The
Commission-approved independent system operators and regional transmission organization may propose a
time period for eventual unmasking.
(6) Responsiveness of Commission-approved independent system operators and
regional transmission organizations. Each
Commission-approved independent system operator or regional transmission
organization must adopt business practices and procedures that achieve Commission-approved independent system
operator and regional transmission organization board of directors’ responsiveness to customers and other stakeholders and satisfy the following criteria:
(i) Inclusiveness. The business practices and procedures must ensure that
any customer or other stakeholder affected by the operation of the Commission-approved independent system operator or regional transmission organization, or its representative, is permitted to communicate the customer’s
or other stakeholder’s views to the
independent system operator’s or regional
transmission
organization’s
board of directors;
(ii) Fairness in balancing diverse interests. The business practices and procedures must ensure that the interests of
customers or other stakeholders are
equitably considered, and that deliberation and consideration of Commission-approved independent system operator’s and regional transmission organization’s issues are not dominated
by any single stakeholder category;
(iii) Representation of minority positions. The business practices and procedures must ensure that, in instances
where stakeholders are not in total
agreement on a particular issue, minority positions are communicated to
the Commission-approved independent
system operator’s and regional transmission organization’s board of directors at the same time as majority positions; and
(iv) Ongoing responsiveness. The business practices and procedures must
provide for stakeholder input into the
Commission-approved independent sys-
§ 35.28
tem operator’s or regional transmission organization’s decisions as
well as mechanisms to provide feedback to stakeholders to ensure that information exchange and communication continue over time.
(7) Compliance filings. All Commission-approved independent system operators and regional transmission organizations must make a compliance filing with the Commission as described
in Order No. 719 under the following
schedule:
(i) The compliance filing addressing
the accepting of bids from demand response resources in markets for ancillary services on a basis comparable to
other resources, removal of deviation
charges, aggregation of retail customers, shortage pricing during periods
of operating reserve shortage, longterm power contracting in organized
markets, Market Monitoring Units,
Commission-approved independent system operators’ and regional transmission organizations’ board of directors’ responsiveness, and reporting on
the study of the need for further reforms to remove barriers to comparable treatment of demand response
resources must be submitted on or before April 28, 2009.
(ii) A public utility that is approved
as a regional transmission organization
under § 35.34, or that is not approved
but begins to operate regional markets
for electric energy or ancillary services
after December 29, 2008, must comply
with Order No. 719 and the provisions of
paragraphs (g)(1) through (g)(5) of this
section before beginning operations.
(8) Frequency regulation compensation
in ancillary services markets. Each Commission-approved independent system
operator or regional transmission organization that has a tariff that provides
for the compensation for frequency regulation service must provide such compensation based on the actual service
provided, including a capacity payment
that includes the marginal unit’s opportunity costs and a payment for performance that reflects the quantity of
frequency regulation service provided
by a resource when the resource is accurately following the dispatch signal.
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§ 35.28
18 CFR Ch. I (4–1–19 Edition)
(9) Electric storage resources. (i) Each
Commission-approved independent system operator and regional transmission organization must have tariff
provisions providing a participation
model for electric storage resources
that:
(A) Ensures that a resource using the
participation model for electric storage
resources in an independent system operator or regional transmission organization market is eligible to provide all
capacity, energy, and ancillary services that it is technically capable of
providing;
(B) Ensures that a resource using the
participation model for electric storage
resources can be dispatched and can set
the wholesale market clearing price as
both a wholesale seller and wholesale
buyer consistent with rules that govern the conditions under which a resource can set the wholesale price;
(C) Accounts for the physical and
operational characteristics of electric
storage resources through bidding parameters or other means; and
(D) Establishes a minimum size requirement for resources using the participation model for electric storage
resources that does not exceed 100 kW.
(ii) The sale of electric energy from
an independent system operator or regional transmission organization market to an electric storage resource that
the resource then resells back to that
market must be at the wholesale locational marginal price.
(10) Transparency—(i) Uplift reporting.
Each
Commission-approved
independent system operator or regional
transmission organization must post
two reports, at minimum, regarding
uplift on a publicly accessible portion
of its website. First, each Commissionapproved independent system operator
or regional transmission organization
must post uplift, paid in dollars, and
categorized by transmission zone, day,
and uplift category. Transmission zone
shall be defined as the geographic area
that is used for the local allocation of
charges. Transmission zones with fewer
than four resources may be aggregated
with one or more neighboring transmission zones, until each aggregated
zone contains at least four resources,
and reported collectively. This report
shall be posted within 20 calendar days
of the end of each month. Second, each
Commission-approved independent system operator or regional transmission
organization must post the resource
name and the total amount of uplift
paid in dollars aggregated across the
month to each resource that received
uplift payments within the calendar
month. This report shall be posted
within 90 calendar days of the end of
each month.
(ii) Reporting Operator-Initiated Commitments. Each Commission-approved
independent system operator or regional transmission organization must
post a report of each operator-initiated
commitment listing the size of the
commitment, transmission zone, commitment reason, and commitment
start time on a publicly accessible portion of its website within 30 calendar
days of the end of each month. Transmission zone shall be defined as a geographic area that is used for the local
allocation of charges. Commitment
reasons shall include, but are not limited to, system-wide capacity, constraint management, and voltage support.
(iii) Transmission constraint penalty
factors.
Each
Commission-approved
independent system operator or regional transmission organization must
include, in its tariff, its transmission
constraint penalty factor values; the
circumstances, if any, under which the
transmission constraint penalty factors can set locational marginal prices;
and the procedure, if any, for temporarily changing the transmission constraint penalty factor values. Any procedure for temporarily changing transmission constraint penalty factor values must provide for notice of the
change to market participants.
(11) A resource’s incremental energy
offer must be capped at the higher of
$1,000/MWh or that resource’s costbased incremental energy offer. For the
purpose of calculating Locational Marginal Prices, Regional Transmission
Organizations and Independent System
Operators must cap cost-based incremental energy offers at $2,000/MWh.
The actual or expected costs underlying a resource’s cost-based incremental energy offer above $1,000/MWh
must be verified before that offer can
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Federal Energy Regulatory Commission
be used for purposes of calculating Locational Marginal Prices. If a resource
submits an incremental energy offer
above $1,000/MWh and the actual or expected costs underlying that offer cannot be verified before the market clearing process begins, that offer may not
be used to calculate Locational Marginal Prices and the resource would be
eligible for a make-whole payment if
that resource is dispatched and the resource’s actual costs are verified afterthe-fact. A resource would also be eligible for a make-whole payment if it is
dispatched and its verified cost-based
incremental energy offer exceeds $2,000/
MWh. All resources, regardless of type,
are eligible to submit cost-based incremental energy offers in excess of $1,000/
MWh.
[Order 888, 61 FR 21693, May 10, 1996]
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EDITORIAL NOTE: For FEDERAL REGISTER citations affecting § 35.28, see the List of CFR
Sections Affected, which appears in the
Finding Aids section of the printed volume
and at www.govinfo.gov.
§ 35.29 Treatment of special assessments levied under the Atomic Energy Act of 1954, as amended by
Title XI of the Energy Policy Act of
1992.
The costs that public utilities incur
relating to special assessments under
the Atomic Energy Act of 1954, as
amended by the Energy Policy Act of
1992, are costs that may be reflected in
jurisdictional rates. Public utilities
seeking to recover the costs incurred
relating to special assessments shall
comply with the following procedures.
(a) Fuel adjustment clauses. In computing the Account 518 cost of nuclear
fuel pursuant to § 35.14(a)(6), utilities
seeking to recover the costs of special
assessments through their fuel adjustment clauses shall:
(1) Deduct any expenses associated
with special assessments included in
Account 518;
(2) Add to Account 518 one-twelfth of
any payments made for special assessments within the 12-month period ending with the current month; and
(3) Deduct from Account 518 onetwelfth of any refunds of payments
made for special assessments received
within the 12-month period ending with
the current month that is received
§ 35.30
from the Federal government because
the public utility has contested a special assessment or overpaid a special
assessment.
(b) Cost of service data requirements.
Public utilities filing rate applications
under §§ 35.12 or 35.13 (regardless of
whether the utility elects the abbreviated, unadjusted Period I, adjusted
Period I, or Period II cost support requirements) must submit cost data
that is computed in accordance with
the requirements specified in paragraphs (a) (1), (2) and (3) of this section.
(c) Formula rates. Public utilities
with formula rates on file that provide
for the automatic recovery of nuclear
fuel costs must reflect the costs of special assessments in accordance with
the requirements specified in paragraphs (a) (1), (2) and (3) of this section.
[Order 557, 58 FR 51221, Oct. 1, 1993. Redesignated by Order 888, 61 FR 21692, May 10, 1996]
Subpart D—Procedures and Requirements for Public Utility
Sales of Power to Bonneville
Power Administration Under
Northwest Power Act
AUTHORITY: Federal Power Act, 16 U.S.C.
792–828c (1976 and Supp. IV 1980) and Pacific
Northwest Electric Power Planning and Conservation Act, 16 U.S.C. 830–839h (Supp. IV
(1980)).
§ 35.30
General provisions.
(a) Applicability. This subpart applies
to any sales of electric power subject
to the Commission’s jurisdiction under
Part II of the Federal Power Act from
public utilities to the Administrator of
the Bonneville Power Administration
(BPA) at the average system cost
(ASC) of that utility’s resources (electric power generation by the utility)
pursuant to section 5(c) of the Pacific
Northwest Electric Power Planning
and Conservation Act, 16 U.S.C. 830–
839h. The ASC is determined by BPA in
accordance with 18 CFR part 301.
(b) Effectiveness of rates. (1) During
the period between the date of BPA’s
determination of ASC and the date of
the final order issued by the Commission, the utility may charge the rate
based on the ASC determined by BPA,
subject to § 35.31(c) of this part.
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§ 35.31
18 CFR Ch. I (4–1–19 Edition)
(2) Except as otherwise provided
under this section, the ASC ordered by
the Commission will be deemed in effect from the beginning of the relevant
exchange
period,
as
defined
in
§ 301.1(b)(95) of this chapter. For any
initial exchange period after the Commission approves a new ASC methodology, the ASC will be effective retroactively under this paragraph only if
the utility files its new ASC within the
time allowed under BPA procedures.
Any utility that files a revised ASC
with BPA in accordance with this paragraph must promptly file with the
Commission a notice of timely filing of
the new ASC.
(c) Filing requirements. Within 15 business days of the date of issuance of the
BPA report on a utility’s ASC, the utility must file with the Commission the
ASC determined by BPA, the BPA
written report, the utility’s ASC schedules, material necessary to comply
with 18 CFR 35.13(c), and any other material requested by the Commission or
its staff.
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[Order 337, 48 FR 46976, Oct. 17, 1983, as
amended by Order 400, 49 FR 39300, Oct. 5,
1984]
§ 35.31 Commission review.
(a) Procedures. Filings under this subpart are subject to the procedures applicable to other filings under section
205 of the Federal Power Act, as the
Commission deems appropriate.
(b) Commission standard. With respect
to any filing under this subpart, the
Commission will determine whether
the ASC set by BPA for the applicable
exchange period was determined in accordance with the ASC methodology
set forth at 18 CFR 301.1. If the ASC is
not in accord with the methodology,
the Commission will order that BPA
amend the ASC to conform with the
methodology. If the ASC is in accord
with the methodology, the rate is
deemed just and reasonable.
(c) Refunds and adjustments. (1) Any
ASC-based rate charged by a public
utility under this subpart pending
Commission order is subject to refund
or to adjustment that increases the
ASC-based rate.
(2) Any interest on refunds ordered
by the Commission under this subpart
is computed in accordance with 18 CFR
35.19a. Interest on any increase ordered
by the Commission will be at the rate
charged to BPA by the U.S. Treasury
during that period, unless the Commission orders another interest rate.
(Approved by the Office of Management and
Budget under control number 1902–0096)
[Order 337, 48 FR 46976, Oct. 17, 1983, as
amended at 49 FR 1177, Jan. 10, 1984]
Subpart E—Regulations Governing
Nuclear
Plant
Decommissioning Trust Funds
§ 35.32
General provisions.
(a) If a public utility has elected to
provide for the decommissioning of a
nuclear power plant through a nuclear
plant decommissioning trust fund
(Fund), the Fund must meet the following criteria:
(1) The Fund must be an external
trust fund in the United States, established pursuant to a written trust
agreement, that is independent of the
utility, its subsidiaries, affiliates or associates. If the trust fund includes
monies collected both in Commissionjurisdictional rates and in non-Commission-jurisdictional rates, then a
separate account of the Commissionjurisdictional monies shall be maintained.
(2) The utility may provide overall
investment policy to the Trustee or Investment Manager, but it may do so
only in writing, and neither the utility
nor its subsidiaries, affiliates or associates may serve as Investment Manager
or otherwise engage in day-to-day management of the Fund or mandate individual investment decisions.
(3) The Fund’s Investment Manager
must exercise the standard of care,
whether in investing or otherwise, that
a prudent investor would use in the
same circumstances. The term ‘‘prudent investor’’ means a prudent investor as described in Restatement of the
Law (Third), Trusts § 227, including
general comments and reporter’s notes,
pages 8–101. St. Paul, MN: American
Law Institute Publishers, (1992). ISBN
0–314–84246–2. This incorporation by reference was approved by the Director of
the Federal Register in accordance
with 5 U.S.C. 552(a) and 1 CFR part 51.
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Federal Energy Regulatory Commission
Copies may be obtained from the American Law Institute, 4025 Chestnut
Street, Philadelphia, PA 19104, and are
also available in local law libraries.
Copies may be inspected at the Federal
Energy Regulatory Commission’s Library, Room 95–01, 888 First Street, NE.
Washington, DC or at the National Archives and Records Administration
(NARA). For information on the availability of this material at NARA, call
202–741–6030,
or
go
to:
http://
www.archives.gov/federallregister/
codeloflfederallregulations/
ibrllocations.html.
(4) The Trustee shall have a net
worth of at least $100 million. In calculating the $100 million net worth requirement, the net worth of the Trustee’s parent corporation and/or affiliates
may be taken into account only if such
entities guarantee the Trustee’s responsibilities to the Fund.
(5) The Trustee or Investment Manager shall keep accurate and detailed
accounts of all investments, receipts,
disbursements and transactions of the
Fund. All accounts, books and records
relating to the Fund shall be open to
inspection and audit at reasonable
times by the utility or its designee or
by the Commission or its designee. The
utility or its designee must notify the
Commission prior to performing any
such inspection or audit. The Commission may direct the utility to conduct
an audit or inspection.
(6) Absent the express authorization
of the Commission, no part of the assets of the Fund may be used for, or diverted to, any purpose other than to
fund the costs of decommissioning the
nuclear power plant to which the Fund
relates, and to pay administrative
costs and other incidental expenses, including taxes, of the Fund.
(7) If the Fund balances exceed the
amount actually expended for decommissioning after decommissioning has
been completed, the utility shall return the excess jurisdictional amount
to ratepayers, in a manner the Commission determines.
(8) Except for investments tied to
market indexes or other mutual funds,
the Investment Manager shall not invest in any securities of the utility for
which it manages the funds or in that
§ 35.32
utility’s subsidiaries, affiliates, or associates or their successors or assigns.
(9) The utility and the Fiduciary
shall seek to obtain the best possible
tax treatment of amounts collected for
nuclear plant decommissioning. In this
regard, the utility and the Fiduciary
shall take maximum advantage of tax
deductions and credits, when it is consistent with sound business practices
to do so.
(10) Each utility shall deposit in the
Fund at least quarterly all amounts included in Commission-jurisdictional
rates to fund nuclear power plant decommissioning.
(b) The establishment, organization,
and maintenance of the Fund shall not
relieve the utility or its subsidiaries,
affiliates or associates of any obligations it may have as to the decommissioning of the nuclear power plant. It is
not the responsibility of the Fiduciary
to ensure that the amount of monies
that a Fund contains are adequate to
pay for a nuclear unit’s decommissioning.
(c) A utility may establish both
qualified and non-qualified Funds with
respect to a utility’s interest in a specific nuclear plant. This section applies
to both ‘‘qualified’’ (under the Internal
Revenue Code, 26 U.S.C. 468A, or any
successor section) and non-qualified
Funds.
(d) A utility must regularly supply to
the Fund’s Investment Manager, and
regularly update, essential information
about the nuclear unit covered by the
Trust Fund Agreement, including its
description, location, expected remaining useful life, the decommissioning
plan the utility proposes to follow, the
utility’s liquidity needs once decommissioning begins, and any other information that the Fund’s Investment
Manager would need to construct and
maintain, over time, a sound investment plan.
(e) A utility should monitor the performance of all Fiduciaries of the Fund
and, if necessary, replace them if they
are not properly performing assigned
responsibilities.
[Order 580–A, 62 FR 33348, June 19, 1997, as
amended at 69 FR 18803, Apr. 9, 2004]
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§ 35.33
18 CFR Ch. I (4–1–19 Edition)
§ 35.33 Specific provisions.
(a) In addition to the general provisions of § 35.32, the Trustee must observe the provisions of this section.
(b) The Trustee may use Fund assets
only to:
(1) Satisfy the liability of a utility
for decommissioning costs of the nuclear power plant to which the Fund
relates as provided by § 35.32; and
(2) Pay administrative costs and
other incidental expenses, including
taxes, of the Fund as provided by
§ 35.32.
(c) To the extent that the Trustee
does not currently require the assets of
the Fund for the purposes described in
paragraphs (b)(1) and (b)(2) of this section, the Investment Manager, when
investing Fund assets, must exercise
the same standard of care that a reasonable person would exercise in the
same circumstances. In this context, a
‘‘reasonable person’’ means a prudent
investor as described in Restatement of
the Law (Third), Trusts § 227, including
general comments and reporter’s notes,
pages 8–101. St. Paul, MN: American
Law Institute Publishers, 1992. ISBN 0–
314–84246–2. This incorporation by reference was approved by the Director of
the Federal Register in accordance
with 5 U.S.C. 552(a) and 1 CFR part 51.
Copies may be obtained from the American Law Institute, 4025 Chestnut
Street, Philadelphia, PA 19104, and are
also available in local law libraries.
Copies may be inspected at the Federal
Energy Regulatory Commission, 888
First Street, NE. Washington, DC or at
the National Archives and Records Administration (NARA). For information
on the availability of this material at
NARA, call 202–741–6030, or go to: http://
www.archives.gov/federal-register/cfr/ibrlocations.html.
(d) The utility must submit to the
Commission by March 31 of each year,
one original and three conformed copies of the financial report furnished to
the utility by the Fund’s Trustee that
shows for the previous calendar year:
(1) Fund assets and liabilities at the
beginning of the period;
(2) Activity of the Fund during the
period, including amounts received
from the utility, a summary amount
for purchases of fund investments and
a summary amount for sales of fund in-
vestments, gains and losses from investment activity, disbursements from
the Fund for decommissioning activity
and payment of Fund expenses, including taxes; and
(3) Fund assets and liabilities at the
end of the period. The report should
not include the liability for decommissioning.
(4) Public utilities owning nuclear
plants must maintain records of individual purchase and sales transactions
until after decommissioning has been
completed and any excess jurisdictional amounts have been returned to
ratepayers in a manner that the Commission determines. The public utility
need not include these records in the financial report that it furnishes to the
Commission by March 31 of each year.
(e) The utility must also mail a copy
of the financial report provided to the
Commission pursuant to paragraph (d)
of this section to anyone who requests
it.
(f) If an independent public accountant has expressed an opinion on the report or on any portion of the report,
then that opinion must accompany the
report.
[Order 580–A, 62 FR 33348, June 19, 1997, as
amended at 69 FR 18803, Apr. 9, 2004; Order
658, 70 FR 34343, June 14, 2005; Order 737, 75
FR 43404, July 26, 2010]
Subpart F—Procedures and Requirements Regarding Regional Transmission Organizations
§ 35.34 Regional Transmission Organizations.
(a) Purpose. This section establishes
required characteristics and functions
for Regional Transmission Organizations for the purpose of promoting efficiency and reliability in the operation
and planning of the electric transmission grid and ensuring non-discrimination in the provision of electric
transmission services. This section further directs each public utility that
owns, operates, or controls facilities
used for the transmission of electric
energy in interstate commerce to
make certain filings with respect to
forming and participating in a Regional Transmission Organization.
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Federal Energy Regulatory Commission
(b) Definitions. (1) Regional Transmission Organization means an entity
that satisfies the minimum characteristics set forth in paragraph (j) of this
section, performs the functions set
forth in paragraph (k) of this section,
and accommodates the open architecture condition set forth in paragraph
(l) of this section.
(2) Market participant means:
(i) Any entity that, either directly or
through an affiliate, sells or brokers
electric energy, or provides ancillary
services to the Regional Transmission
Organization, unless the Commission
finds that the entity does not have economic or commercial interests that
would be significantly affected by the
Regional Transmission Organization’s
actions or decisions; and
(ii) Any other entity that the Commission finds has economic or commercial interests that would be significantly affected by the Regional Transmission Organization’s actions or decisions.
(3) Affiliate means the definition
given in section 2(a)(11) of the Public
Utility Holding Company Act (15 U.S.C.
79b(a)(11)).
(4) Class of market participants means
two or more market participants with
common economic or commercial interests.
(c) General rule. Except for those public utilities subject to the requirements of paragraph (h) of this section,
every public utility that owns, operates or controls facilities used for the
transmission of electric energy in
interstate commerce as of March 6, 2000
must file with the Commission, no
later than October 15, 2000, one of the
following:
(1) A proposal to participate in a Regional Transmission Organization consisting of one of the types of submittals set forth in paragraph (d) of this
section; or
(2) An alternative filing consistent
with paragraph (g) of this section.
(d) Proposal to participate in a Regional
Transmission Organization. For purposes
of this section, a proposal to participate in a Regional Transmission Organization means:
(1) Such filings, made individually or
jointly with other entities, pursuant to
sections 203, 205 and 206 of the Federal
§ 35.34
Power Act (16 U.S.C. 824b, 824d, and
824e), as are necessary to create a new
Regional Transmission Organization;
(2) Such filings, made individually or
jointly with other entities, pursuant to
sections 203, 205 and 206 of the Federal
Power Act (16 U.S.C. 824b, 824d, and
824e), as are necessary to join a Regional Transmission Organization approved by the Commission on or before
the date of the filing; or
(3) A petition for declaratory order,
filed individually or jointly with other
entities, asking whether a proposed
transmission entity would qualify as a
Regional Transmission Organization
and containing at least the following:
(i) A detailed description of the proposed transmission entity, including a
description of the organizational and
operational structure and the intended
participants;
(ii) A discussion of how the transmission entity would satisfy each of
the characteristics and functions of a
Regional Transmission Organization
specified in paragraphs (j), (k) and (l) of
this section;
(iii) A detailed description of the
Federal Power Act section 205 rates
that will be filed for the Regional
Transmission Organization; and
(iv) A commitment to make filings
pursuant to sections 203, 205 and 206 of
the Federal Power Act (16 U.S.C. 824b,
824d, and 824e), as necessary, promptly
after the Commission issues an order in
response to the petition.
(4) Any proposal filed under this
paragraph (d) must include an explanation of efforts made to include public
power entities and electric power cooperatives in the proposed Regional
Transmission Organization.
(e) [Reserved]
(f) Transfer of operational control. Any
public utility’s proposal to participate
in a Regional Transmission Organization filed pursuant to paragraph (c)(1)
of this section must propose that operational control of that public utility’s
transmission facilities will be transferred to the Regional Transmission
Organization on a schedule that will
allow the Regional Transmission Organization to commence operating the facilities no later than December 15, 2001.
NOTE TO PARAGRAPH (f): The requirement in
paragraph (f) of this section may be satisfied
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§ 35.34
18 CFR Ch. I (4–1–19 Edition)
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by proposing to transfer to the Regional
Transmission Organization ownership of the
facilities in addition to operational control.
(g) Alternative filing. Any filing made
pursuant to paragraph (c)(2) of this section must contain:
(1) A description of any efforts made
by that public utility to participate in
a Regional Transmission Organization;
(2) A detailed explanation of the economic, operational, commercial, regulatory, or other reasons the public utility has not made a filing to participate
in a Regional Transmission Organization, including identification of any existing obstacles to participation in a
Regional Transmission Organization;
and
(3) The specific plans, if any, the public utility has for further work toward
participation in a Regional Transmission Organization, a proposed timetable for such activity, an explanation
of efforts made to include public power
entities in the proposed Regional
Transmission Organization, and any
factors (including any law, rule or regulation) that may affect the public
utility’s ability or decision to participate in a Regional Transmission Organization.
(h) Public utilities participating in approved transmission entities. Every public utility that owns, operates or controls facilities used for the transmission of electric energy in interstate
commerce as of March 6, 2000, and that
has filed with the Commission on or before March 6, 2000 to transfer operational control of its facilities to a
transmission entity that has been approved or conditionally approved by
the Commission on or before March 6,
2000 as being in conformance with the
eleven ISO principles set forth in Order
No. 888, FERC Statutes and Regulations, Regulations Preamble January
1991–June 1996 ¶ 31,036 (Final Rule on
Open Access and Stranded Costs; see 61
FR 21540, May 10, 1996), must, individually or jointly with other entities, file
with the Commission, no later than
January 15, 2001:
(1) A statement that it is participating in a transmission entity that
has been so approved;
(2) A detailed explanation of the extent to which the transmission entity
in which it participates has the charac-
teristics and performs the functions of
a Regional Transmission Organization
specified in paragraphs (j) and (k) of
this section and accommodates the
open architecture conditions in paragraph (l) of this section; and
(3) To the extent the transmission
entity in which the public utility participates does not meet all the requirements of a Regional Transmission Organization specified in paragraphs (j),
(k), and (l) of this section,
(i) A proposal to participate in a Regional Transmission Organization that
meets such requirements in accordance
with paragraph (d) of this section,
(ii) A proposal to modify the existing
transmission entity so that it conforms
to the requirements of a Regional
Transmission Organization, or
(iii) A filing containing the information specified in paragraph (g) of this
section addressing any efforts, obstacles, and plans with respect to conformance with those requirements.
(i) Entities that become public utilities
with transmission facilities. An entity
that is not a public utility that owns,
operates or controls facilities used for
the transmission of electric energy in
interstate commerce as of March 6,
2000, but later becomes such a public
utility, must file a proposal to participate in a Regional Transmission Organization in accordance with paragraph
(d) of this section, or an alternative filing in accordance with paragraph (g) of
this section, by October 15, 2000 or 60
days prior to the date on which the
public utility engages in any transmission of electric energy in interstate
commerce, whichever comes later. If a
proposal to participate in accordance
with paragraph (d) of this section is
filed, it must propose that operational
control of the applicant’s transmission
system will be transferred to the Regional
Transmission
Organization
within six months of filing the proposal.
(j) Required characteristics for a Regional Transmission Organization. A Regional Transmission Organization must
satisfy the following characteristics
when it commences operation:
(1) Independence. The Regional Transmission Organization must be independent of any market participant.
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Federal Energy Regulatory Commission
The Regional Transmission Organization must include, as part of its demonstration of independence, a demonstration that it meets the following:
(i) The Regional Transmission Organization, its employees, and any nonstakeholder directors must not have financial interests in any market participant.
(ii) The Regional Transmission Organization must have a decision making
process that is independent of control
by any market participant or class of
participants.
(iii) The Regional Transmission Organization must have exclusive and
independent authority under section
205 of the Federal Power Act (16 U.S.C.
824d), to propose rates, terms and conditions of transmission service provided over the facilities it operates.
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NOTE TO PARAGRAPH (j)(1)(iii): Transmission owners retain authority under section 205 of the Federal Power Act (16 U.S.C.
824d) to seek recovery from the Regional
Transmission Organization of the revenue requirements associated with the transmission
facilities that they own.
(iv)(A) The Regional Transmission
Organization must provide:
(1) With respect to any Regional
Transmission Organization in which
market participants have an ownership
interest, a compliance audit of the
independence of the Regional Transmission Organization’s decision making process under paragraph (j)(1)(ii) of
this section, to be performed two years
after approval of the Regional Transmission Organization, and every three
years thereafter, unless otherwise provided by the Commission.
(2) With respect to any Regional
Transmission Organization in which
market participants have a role in the
Regional Transmission Organization’s
decision making process but do not
have an ownership interest, a compliance audit of the independence of the
Regional Transmission Organization’s
decision making process under paragraph (j)(1)(ii) of this section, to be performed two years after its approval as
a Regional Transmission Organization.
(B) The compliance audits under
paragraph (j)(1)(iv)(A) of this section
must be performed by auditors who are
not affiliated with the Regional Transmission Organization or transmission
§ 35.34
facility owners that are members of
the Regional Transmission Organization.
(2) Scope and regional configuration.
The Regional Transmission Organization must serve an appropriate region.
The region must be of sufficient scope
and configuration to permit the Regional Transmission Organization to
maintain reliability, effectively perform its required functions, and support efficient and non-discriminatory
power markets.
(3) Operational authority. The Regional Transmission Organization must
have operational authority for all
transmission facilities under its control. The Regional Transmission Organization must include, as part of its
demonstration of operational authority, a demonstration that it meets the
following:
(i) If any operational functions are
delegated to, or shared with, entities
other than the Regional Transmission
Organization, the Regional Transmission Organization must ensure that
this sharing of operational authority
will not adversely affect reliability or
provide any market participant with
an unfair competitive advantage. Within two years after initial operation as a
Regional Transmission Organization,
the Regional Transmission Organization must prepare a public report that
assesses whether any division of operational authority hinders the Regional
Transmission Organization in providing reliable, non-discriminatory and
efficiently priced transmission service.
(ii) The Regional Transmission Organization must be the security coordinator for the facilities that it controls.
(4) Short-term reliability. The Regional
Transmission Organization must have
exclusive authority for maintaining
the short-term reliability of the grid
that it operates. The Regional Transmission Organization must include, as
part of its demonstration with respect
to reliability, a demonstration that it
meets the following:
(i) The Regional Transmission Organization must have exclusive authority
for receiving, confirming and implementing all interchange schedules.
(ii) The Regional Transmission Organization must have the right to order
redispatch of any generator connected
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§ 35.34
18 CFR Ch. I (4–1–19 Edition)
to transmission facilities it operates if
necessary for the reliable operation of
these facilities.
(iii) When the Regional Transmission
Organization operates transmission facilities owned by other entities, the
Regional Transmission Organization
must have authority to approve or disapprove all requests for scheduled outages of transmission facilities to ensure that the outages can be accommodated within established reliability
standards.
(iv) If the Regional Transmission Organization operates under reliability
standards established by another entity (e.g., a regional reliability council),
the Regional Transmission Organization must report to the Commission if
these standards hinder it from providing reliable, non-discriminatory and
efficiently priced transmission service.
(k) Required functions of a Regional
Transmission Organization. The Regional Transmission Organization must
perform the following functions. Unless
otherwise noted, the Regional Transmission Organization must satisfy
these obligations when it commences
operations.
(1) Tariff administration and design.
The Regional Transmission Organization must administer its own transmission tariff and employ a transmission pricing system that will promote efficient use and expansion of
transmission and generation facilities.
As part of its demonstration with respect to tariff administration and design, the Regional Transmission Organization must satisfy the standards
listed in paragraphs (k)(1)(i) and (ii) of
this section, or demonstrate that an alternative proposal is consistent with or
superior to satisfying such standards.
(i) The Regional Transmission Organization must be the only provider of
transmission service over the facilities
under its control, and must be the sole
administrator of its own Commissionapproved open access transmission tariff. The Regional Transmission Organization must have the sole authority to
receive, evaluate, and approve or deny
all requests for transmission service.
The Regional Transmission Organization must have the authority to review
and approve requests for new interconnections.
(ii) Customers under the Regional
Transmission Organization tariff must
not be charged multiple access fees for
the recovery of capital costs for transmission service over facilities that the
Regional Transmission Organization
controls.
(2) Congestion management. The Regional Transmission Organization must
ensure the development and operation
of market mechanisms to manage
transmission congestion. As part of its
demonstration with respect to congestion management, the Regional Transmission Organization must satisfy the
standards listed in paragraph (k)(2)(i)
of this section, or demonstrate that an
alternative proposal is consistent with
or superior to satisfying such standards.
(i) The market mechanisms must accommodate broad participation by all
market participants, and must provide
all transmission customers with efficient price signals that show the consequences of their transmission usage
decisions. The Regional Transmission
Organization must either operate such
markets itself or ensure that the task
is performed by another entity that is
not affiliated with any market participant.
(ii) The Regional Transmission Organization must satisfy the market
mechanism requirement no later than
one year after it commences initial operation. However, it must have in place
at the time of initial operation an effective protocol for managing congestion.
(3) Parallel path flow. The Regional
Transmission Organization must develop and implement procedures to address parallel path flow issues within
its region and with other regions. The
Regional Transmission Organization
must satisfy this requirement with respect to coordination with other regions no later than three years after it
commences initial operation.
(4) Ancillary services. The Regional
Transmission Organization must serve
as a provider of last resort of all ancillary services required by Order No. 888,
FERC Statutes and Regulations, Regulations Preamble January 1991–June
1996 ¶ 31,036 (Final Rule on Open Access
and Stranded Costs; see 61 FR 21540,
May 10, 1996), and subsequent orders.
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Federal Energy Regulatory Commission
As part of its demonstration with respect to ancillary services, the Regional Transmission Organization must
satisfy the standards listed in paragraphs (k)(4)(i) through (iii) of this section, or demonstrate that an alternative proposal is consistent with or
superior to satisfying such standards.
(i) All market participants must have
the option of self-supplying or acquiring ancillary services from third parties subject to any restrictions imposed
by the Commission in Order No. 888,
FERC Statutes and Regulations, Regulations Preamble January 1991–June
1996 ¶ 31,036 (Final Rule on Open Access
and Stranded Costs), and subsequent
orders.
(ii) The Regional Transmission Organization must have the authority to
decide the minimum required amounts
of each ancillary service and, if necessary, the locations at which these
services must be provided. All ancillary service providers must be subject
to direct or indirect operational control by the Regional Transmission Organization. The Regional Transmission
Organization must promote the development of competitive markets for ancillary services whenever feasible.
(iii) The Regional Transmission Organization must ensure that its transmission customers have access to a
real-time balancing market. The Regional Transmission Organization must
either develop and operate this market
itself or ensure that this task is performed by another entity that is not
affiliated with any market participant.
(5) OASIS and Total Transmission Capability (TTC) and Available Transmission Capability (ATC). The Regional
Transmission Organization must be the
single OASIS site administrator for all
transmission facilities under its control and independently calculate TTC
and ATC.
(6) Market monitoring. To ensure that
the Regional Transmission Organization provides reliable, efficient and not
unduly discriminatory transmission
service, the Regional Transmission Organization must provide for objective
monitoring of markets it operates or
administers to identify market design
flaws, market power abuses and opportunities for efficiency improvements,
and propose appropriate actions. As
§ 35.34
part of its demonstration with respect
to market monitoring, the Regional
Transmission Organization must satisfy the standards listed in paragraphs
(k)(6)(i) through (k)(6)(iii) of this section, or demonstrate that an alternative proposal is consistent with or
superior to satisfying such standards.
(i) Market monitoring must include
monitoring the behavior of market participants in the region, including
transmission owners other than the
Regional Transmission Organization, if
any, to determine if their actions
hinder the Regional Transmission Organization in providing reliable, efficient and not unduly discriminatory
transmission service.
(ii) With respect to markets the Regional Transmission Organization operates or administers, there must be a
periodic assessment of how behavior in
markets operated by others (e.g., bilateral power sales markets and power
markets operated by unaffiliated power
exchanges) affects Regional Transmission Organization operations and
how Regional Transmission Organization operations affect the efficiency of
power markets operated by others.
(iii) Reports on opportunities for efficiency improvement, market power
abuses and market design flaws must
be filed with the Commission and affected regulatory authorities.
(7) Planning and expansion. The Regional Transmission Organization must
be responsible for planning, and for directing or arranging, necessary transmission expansions, additions, and upgrades that will enable it to provide efficient, reliable and non-discriminatory transmission service and coordinate such efforts with the appropriate
state authorities. As part of its demonstration with respect to planning
and expansion, the Regional Transmission Organization must satisfy the
standards listed in paragraphs (k)(7)(i)
and (ii) of this section, or demonstrate
that an alternative proposal is consistent with or superior to satisfying
such standards.
(i) The Regional Transmission Organization planning and expansion process must encourage market-driven operating and investment actions for preventing and relieving congestion.
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§ 35.35
18 CFR Ch. I (4–1–19 Edition)
(ii) The Regional Transmission Organization’s planning and expansion process must accommodate efforts by state
regulatory commissions to create
multi-state agreements to review and
approve new transmission facilities.
The Regional Transmission Organization’s planning and expansion process
must be coordinated with programs of
existing Regional Transmission Groups
(See § 2.21 of this chapter) where appropriate.
(iii) If the Regional Transmission Organization is unable to satisfy this requirement when it commences operation, it must file with the Commission
a plan with specified milestones that
will ensure that it meets this requirement no later than three years after
initial operation.
(8) Interregional coordination. The Regional Transmission Organization must
ensure the integration of reliability
practices within an interconnection
and market interface practices among
regions.
(l) Open architecture. (1) Any proposal
to participate in a Regional Transmission Organization must not contain
any provision that would limit the capability of the Regional Transmission
Organization to evolve in ways that
would improve its efficiency, consistent with the requirements in paragraphs (j) and (k) of this section.
(2) Nothing in this regulation precludes an approved Regional Transmission Organization from seeking to
evolve with respect to its organizational design, market design, geographic scope, ownership arrangements, or methods of operational control, or in other appropriate ways if the
change is consistent with the requirements of this section. Any future filing
seeking approval of such changes must
demonstrate that the proposed changes
will meet the requirements of paragraphs (j), (k) and (l) of this section.
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[Order 2000–A, 65 FR 12110, Mar. 8, 2000, as
amended by Order 679, 71 FR 43338, July 31,
2006]
Subpart G—Transmission
structure Investment
sions
§ 35.35 Transmission infrastructure investment.
(a) Purpose. This section establishes
rules for incentive-based (including
performance-based) rate treatments for
transmission of electric energy in
interstate commerce by public utilities
for the purpose of benefiting consumers
by ensuring reliability and reducing
the cost of delivered power by reducing
transmission congestion.
(b) Definitions. (1) Transco means a
stand-alone
transmission
company
that has been approved by the Commission and that sells transmission services at wholesale and/or on an
unbundled retail basis, regardless of
whether it is affiliated with another
public utility.
(2) Transmission Organization means a
Regional Transmission Organization,
Independent System Operator, independent transmission provider, or
other transmission organization finally
approved by the Commission for the
operation of transmission facilities.
(c) General rule. All rates approved
under the rules of this section, including any revisions to the rules, are subject to the filing requirements of sections 205 and 206 of the Federal Power
Act and to the substantive requirements of sections 205 and 206 of the
Federal Power Act that all rates,
charges, terms and conditions be just
and reasonable and not unduly discriminatory or preferential.
(d) Incentive-based rate treatments for
transmission infrastructure investment.
The Commission will authorize any incentive-based rate treatment, as discussed in this paragraph (d), for transmission
infrastructure
investment,
provided that the proposed incentivebased rate treatment is just and reasonable and not unduly discriminatory
or preferential. A public utility’s request for one or more incentive-based
rate treatments, to be made in a filing
pursuant to section 205 of the Federal
Power Act, or in a petition for a declaratory order that precedes a filing pursuant to section 205, must include a detailed explanation of how the proposed
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Federal Energy Regulatory Commission
rate treatment complies with the requirements of section 219 of the Federal Power Act and a demonstration
that the proposed rate treatment is
just, reasonable, and not unduly discriminatory or preferential. The applicant must demonstrate that the facilities for which it seeks incentives either
ensure reliability or reduce the cost of
delivered power by reducing transmission congestion consistent with the
requirements of section 219, that the
total package of incentives is tailored
to address the demonstrable risks or
challenges faced by the applicant in
undertaking the project, and that resulting rates are just and reasonable.
For purposes of this paragraph (d), incentive-based rate treatment means
any of the following:
(1) For purposes of this paragraph (d),
incentive-based rate treatment means
any of the following:
(i) A rate of return on equity sufficient to attract new investment in
transmission facilities;
(ii) 100 percent of prudently incurred
Construction Work in Progress (CWIP)
in rate base;
(iii) Recovery of prudently incurred
pre-commercial operations costs;
(iv) Hypothetical capital structure;
(v) Accelerated depreciation used for
rate recovery;
(vi) Recovery of 100 percent of prudently incurred costs of transmission
facilities that are cancelled or abandoned due to factors beyond the control of the public utility;
(vii) Deferred cost recovery; and
(viii) Any other incentives approved
by the Commission, pursuant to the requirements of this paragraph, that are
determined to be just and reasonable
and not unduly discriminatory or preferential.
(2) In addition to the incentives in
§ 35.35(d)(1), the Commission will authorize the following incentive-based
rate treatments for Transcos, provided
that the proposed incentive-based rate
treatment is just and reasonable and
not unduly discriminatory or preferential:
(i) A return on equity that both encourages Transco formation and is sufficient to attract investment; and
(ii) An adjustment to the book value
of transmission assets being sold to a
§ 35.35
Transco to remove the disincentive associated with the impact of accelerated
depreciation on federal capital gains
tax liabilities.
(e) Incentives for joining a Transmission Organization. The Commission
will authorize an incentive-based rate
treatment, as discussed in this paragraph (e), for public utilities that join
a Transmission Organization, if the applicant demonstrates that the proposed
incentive-based rate treatment is just
and reasonable and not unduly discriminatory or preferential. Applicants
for the incentive-based rate treatment
must make a filing with the Commission under section 205 of the Federal
Power Act. For purposes of this paragraph (e), an incentive-based rate
treatment means a return on equity
that is higher than the return on equity the Commission might otherwise
allow if the public utility did not join
a Transmission Organization. The
Commission will also permit transmitting utilities or electric utilities that
join a Transmission Organization the
ability to recover prudently incurred
costs associated with joining the
Transmission
Organization,
either
through transmission rates charged by
transmitting utilities or electric utilities or through transmission rates
charged by the Transmission Organization that provides services to such utilities.
(f) Approval of prudently-incurred
costs. The Commission will approve recovery of prudently-incurred costs necessary to comply with the mandatory
reliability standards pursuant to section 215 of the Federal Power Act, provided that the proposed rates are just
and reasonable and not unduly discriminatory or preferential.
(g) Approval of prudently incurred costs
related to transmission infrastructure development. The Commission will approve recovery of prudently-incurred
costs related to transmission infrastructure development pursuant to section 216 of the Federal Power Act, provided that the proposed rates are just
and reasonable and not unduly discriminatory or preferential.
(h) FERC–730, Report of transmission
investment activity. Public utilities that
have been granted incentive rate treatment for specific transmission projects
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§ 35.36
18 CFR Ch. I (4–1–19 Edition)
must file FERC–730 on an annual basis
beginning with the calendar year incentive rate treatment is granted by
the Commission. Such filings are due
by April 18 of the following calendar
year and are due April 18 each year
thereafter. The following information
must be filed:
(1) In dollar terms, actual transmission investment for the most recent
calendar year, and projected, incremental investments for the next five
calendar years;
(2) For all current and projected investments over the next five calendar
years, a project by project listing that
specifies for each project the most upto-date, expected completion date, percentage completion as of the date of
filing, and reasons for delays. Exclude
from this listing projects with projected costs less than $20 million; and
(3) For good cause shown, the Commission may extend the time within
which any FERC–730 filing is to be filed
or waive the requirements applicable
to any such filing.
(i) Rebuttable presumption. (1) The
Commission will apply a rebuttable
presumption that an applicant has
demonstrated that its project is needed
to ensure reliability or reduces the cost
of delivered power by reducing congestion for:
(i) A transmission project that results from a fair and open regional
planning process that considers and
evaluates projects for reliability and/or
congestion and is found to be acceptable to the Commission; or
(ii) A project that has received construction approval from an appropriate
state commission or state siting authority.
(2) To the extent these approval processes do not require that a project ensures reliability or reduce the cost of
delivered power by reducing congestion, the applicant bears the burden of
demonstrating that its project satisfies
these criteria.
(j) Commission authorization to site
electric transmission facilities in interstate
commerce. If the Commission pursuant
to its authority under section 216 of the
Federal Power Act and its regulations
thereunder has issued one or more permits for the construction or modification of transmission facilities in a na-
tional interest electric transmission
corridor designated by the Secretary,
such facilities shall be deemed to either ensure reliability or reduce the
cost of delivered power by reducing
congestion for purposes of section
219(a).
[Order 679, 71 FR 43338, July 31, 2006, as
amended by Order 679–A, 72 FR 1172, Jan. 10,
2007, Order 691, 72 FR 5174, Feb. 5, 2007]
Subpart H—Wholesale Sales of
Electric Energy, Capacity and
Ancillary Services at MarketBased Rates
SOURCE: Order 697, 72 FR 40038, July 20,
2007, unless otherwise noted.
§ 35.36 Generally.
(a) For purposes of this subpart:
(1) Seller means any person that has
authorization to or seeks authorization
to engage in sales for resale of electric
energy, capacity or ancillary services
at market-based rates under section 205
of the Federal Power Act.
(2) Category 1 Seller means a Seller
that:
(i) Is either a wholesale power marketer that controls or is affiliated with
500 MW or less of generation in aggregate per region or a wholesale power
producer that owns, controls or is affiliated with 500 MW or less of generation in aggregate in the same region as
its generation assets;
(ii) Does not own, operate or control
transmission facilities other than limited equipment necessary to connect
individual generating facilities to the
transmission grid (or has been granted
waiver of the requirements of Order
No. 888, FERC Stats. & Regs. ¶ 31,036);
(iii) Is not affiliated with anyone
that owns, operates or controls transmission facilities in the same region as
the Seller’s generation assets;
(iv) Is not affiliated with a franchised
public utility in the same region as the
Seller’s generation assets; and
(v) Does not raise other vertical market power issues.
(3) Category 2 Sellers means any Sellers not in Category 1.
(4) Inputs to electric power production
means intrastate natural gas transportation, intrastate natural gas storage
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Federal Energy Regulatory Commission
or distribution facilities; physical coal
supply sources and ownership of or control over who may access transportation of coal supplies;
(5) Franchised public utility means a
public utility with a franchised service
obligation under State law.
(6) Captive customers means any
wholesale or retail electric energy customers served by a franchised public
utility under cost-based regulation.
(7) Market-regulated power sales affiliate means any power seller affiliate
other than a franchised public utility,
including a power marketer, exempt
wholesale generator, qualifying facility
or other power seller affiliate, whose
power sales are regulated in whole or
in part on a market-rate basis.
(8) Market information means non-public information related to the electric
energy and power business including,
but not limited to, information regarding sales, cost of production, generator
outages,
generator
heat
rates,
unconsummated transactions, or historical generator volumes. Market information includes information from
either affiliates or non-affiliates.
(9) Affiliate of a specified company
means:
(i) Any person that directly or indirectly owns, controls, or holds with
power to vote, 10 percent or more of
the outstanding voting securities of
the specified company;
(ii) Any company 10 percent or more
of whose outstanding voting securities
are owned, controlled, or held with
power to vote, directly or indirectly,
by the specified company;
(iii) Any person or class of persons
that the Commission determines, after
appropriate notice and opportunity for
hearing, to stand in such relation to
the specified company that there is liable to be an absence of arm’s-length
bargaining in transactions between
them as to make it necessary or appropriate in the public interest or for the
protection of investors or consumers
that the person be treated as an affiliate; and
(iv) Any person that is under common control with the specified company.
(v) For purposes of paragraph (a)(9),
owning, controlling or holding with
power to vote, less than 10 percent of
§ 35.37
the outstanding voting securities of a
specified company creates a rebuttable
presumption of lack of control.
(b) The provisions of this subpart
apply to all Sellers authorized, or seeking authorization, to make sales for resale of electric energy, capacity or ancillary services at market-based rates
unless otherwise ordered by the Commission.
[Order 697, 72 FR 40038, July 20, 2007, as
amended by Order 697–A, 73 FR 25912, May 7,
2008; Order 697–B, 73 FR 79627, Dec. 30, 2008;
Order 816, 80 FR 67108, Oct. 30, 2015; Order 816–
A, 81 FR 33383, May 26, 2016]
§ 35.37 Market power analysis required.
(a) (1) In addition to other requirements in subparts A and B, a Seller
must submit a market power analysis
in the following circumstances: when
seeking market-based rate authority;
for Category 2 Sellers, every three
years, according to the schedule posted
on the Commission’s Web site; or any
other time the Commission directs a
Seller to submit one. Failure to timely
file an updated market power analysis
will constitute a violation of Seller’s
market-based rate tariff.
(2) When submitting a market power
analysis, whether as part of an initial
application or an update, a Seller must
include an appendix of assets, in the
form provided in appendix B of this
subpart, and an organizational chart.
The organizational chart must depict
the Seller’s current corporate structure indicating all affiliates.
(b) A market power analysis must address whether a Seller has horizontal
and vertical market power.
(c)(1) There will be a rebuttable presumption that a Seller lacks horizontal
market power with respect to sales of
energy, capacity, energy imbalance
service, generation imbalance service,
and primary frequency response service
if it passes two indicative market
power screens: a pivotal supplier analysis based on annual peak demand of
the relevant market, and a market
share analysis applied on a seasonal
basis. There will be a rebuttable presumption that a Seller lacks horizontal
market power with respect to sales of
operating reserve-spinning and operating reserve-supplemental services if
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§ 35.38
18 CFR Ch. I (4–1–19 Edition)
the Seller passes these two indicative
market power screens and demonstrates in its market-based rate application how the scheduling practices
in its region support the delivery of operating reserve resources from one balancing authority area to another.
There will be a rebuttable presumption
that a Seller possesses horizontal market power with respect to sales of energy, capacity, energy imbalance service, generation imbalance service, operating reserve-spinning service, operating reserve-supplemental service,
and primary frequency response service
if it fails either screen.
(2) Sellers and intervenors may also
file alternative evidence to support or
rebut the results of the indicative
screens. Sellers may file such evidence
at the time they file their indicative
screens. Intervenors may file such evidence in response to a Seller’s submissions.
(3) If a Seller does not pass one or
both screens, the Seller may rebut a
presumption of horizontal market
power by submitting a Delivered Price
Test analysis. A Seller that does not
rebut a presumption of horizontal market power or that concedes market
power, is subject to mitigation, as described in § 35.38.
(4) When submitting the indicative
screens, a Seller must use the format
provided in appendix A of this subpart
and file the indicative screens in an
electronic spreadsheet format. A Seller
must include all supporting materials
referenced in the indicative screens.
(5) Sellers submitting simultaneous
transmission import limit studies must
file Submittal 1, and, if applicable,
Submittal 2, in the electronic spreadsheet format provided on the Commission’s Web site.
(d) To demonstrate a lack of vertical
market power, a Seller that owns, operates or controls transmission facilities, or whose affiliates own, operate or
control transmission facilities, must
have on file with the Commission an
Open Access Transmission Tariff, as
described in § 35.28; provided, however,
that a Seller whose foreign affiliate(s)
own, operate or control transmission
facilities outside of the United States
that can be used by competitors of the
Seller to reach United States markets
must demonstrate that such affiliate
either has adopted and is implementing
an Open Access Transmission Tariff as
described in § 35.28, or otherwise offers
comparable, non-discriminatory access
to such transmission facilities.
(e) To demonstrate a lack of vertical
market power in wholesale energy markets through the affiliation, ownership
or control of inputs to electric power
production, such as the transportation
or distribution of the inputs to electric
power production, a Seller must provide the following information:
(1) A description of its ownership or
control of, or affiliation with an entity
that owns or controls, intrastate natural gas transportation, intrastate natural gas storage or distribution facilities;
(2) Physical coal supply sources and
ownership or control over who may access transportation of coal supplies;
and
(3) A Seller must ensure that this information is included in the record of
each new application for market-based
rates and each updated market power
analysis. In addition, a Seller is required to make an affirmative statement that it and its affiliates have not
erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market.
(f) If the Seller seeks to protect any
portion of a filing from public disclosure, the Seller must make its filing in
accordance with the Commission’s instructions for filing privileged materials and critical energy infrastructure
information in § 388.112 of this chapter.
[Order 697, 72 FR 40038, July 20, 2007, as
amended by Order 697–B, 73 FR 79627, Dec. 30,
2008; Order 769, 77 FR 65475, Oct. 29, 2012;
Order 784, 78 FR 46209, July 30, 2013; Order
816, 80 FR 67108, Oct. 30, 2015; Order 819, 80 FR
73977, Nov. 27, 2015]
§ 35.38 Mitigation.
(a) A Seller that has been found to
have market power in generation or
ancillary services, or that is presumed
to have horizontal market power in
generation or ancillary services by virtue of failing or foregoing the relevant
market power screens, as described in
35.37(c), may adopt the default mitigation detailed in paragraph (b) of this
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Federal Energy Regulatory Commission
section for sales of energy or capacity
or paragraph (c) of this section for
sales of ancillary services or may propose mitigation tailored to its own particular circumstances to eliminate its
ability to exercise market power. Mitigation will apply only to the market(s)
in which the Seller is found, or presumed, to have market power.
(b) Default mitigation for sales of energy or capacity consists of three distinct products:
(1) Sales of power of one week or less
priced at the Seller’s incremental cost
plus a 10 percent adder;
(2) Sales of power of more than one
week but less than one year priced at
no higher than a cost-based ceiling reflecting the costs of the unit(s) expected to provide the service; and
(3) New contracts filed for review
under section 205 of the Federal Power
Act for sales of power for one year or
more priced at a rate not to exceed embedded cost of service.
(c) Default mitigation for sales of ancillary services consist of: (1) A cap
based on the relevant OATT ancillary
service rate of the purchasing transmission operator; or (2) the results of a
competitive solicitation that meets the
Commission’s requirements for transparency, definition, evaluation, and
competitiveness.
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[Order 697, 72 FR 40038, July 20, 2007, as
amended by Order 784, 78 FR 46210, July 30,
2013]
§ 35.39 Affiliate restrictions.
(a) General affiliate provisions. As a
condition of obtaining and retaining
market-based rate authority, the conditions provided in this section, including the restriction on affiliate sales of
electric energy and all other affiliate
provisions, must be satisfied on an ongoing basis, unless otherwise authorized by Commission rule or order. Failure to satisfy these conditions will constitute a violation of the Seller’s market-based rate tariff.
(b) Restriction on affiliate sales of electric energy or capacity. As a condition of
obtaining and retaining market-based
rate authority, no wholesale sale of
electric energy or capacity may be
made between a franchised public utility with captive customers and a market-regulated power sales affiliate
§ 35.39
without first receiving Commission authorization for the transaction under
section 205 of the Federal Power Act.
All authorizations to engage in affiliate wholesale sales of electric energy
or capacity must be listed in a Seller’s
market-based rate tariff.
(c) Separation of functions. (1) For the
purpose of this paragraph, entities acting on behalf of and for the benefit of
a franchised public utility with captive
customers (such as entities controlling
or marketing power from the electrical
generation assets of the franchised
public utility) are considered part of
the franchised public utility. Entities
acting on behalf of and for the benefit
of the market-regulated power sales affiliates of a franchised public utility
with captive customers are considered
part of the market-regulated power
sales affiliates.
(2) (i) To the maximum extent practical, the employees of a market-regulated power sales affiliate must operate
separately from the employees of any
affiliated franchised public utility with
captive customers.
(ii) Franchised public utilities with
captive customers are permitted to
share support employees, and field and
maintenance employees with their
market-regulated power sales affiliates. Franchised public utilities with
captive customers are also permitted
to share senior officers and boards of
directors with their market-regulated
power sales affiliates; provided, however, that the shared officers and
boards of directors must not participate in directing, organizing or executing generation or market functions.
(iii) Notwithstanding any other restrictions in this section, in emergency
circumstances affecting system reliability, a market-regulated power sales
affiliate and a franchised public utility
with captive customers may take steps
necessary to keep the bulk power system in operation. A franchised public
utility with captive customers or the
market-regulated power sales affiliate
must report to the Commission and
disclose to the public on its Web site,
each emergency that resulted in any
deviation from the restrictions of section 35.39, within 24 hours of such deviation.
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§ 35.40
18 CFR Ch. I (4–1–19 Edition)
(d) Information sharing. (1) A franchised public utility with captive customers may not share market information with a market-regulated power
sales affiliate if the sharing could be
used to the detriment of captive customers, unless simultaneously disclosed to the public.
(2) Permissibly shared support employees, field and maintenance employees and senior officers and board of directors under §§ 35.39(c)(2)(ii) may have
access to information covered by the
prohibition of § 35.39(d)(1), subject to
the no-conduit provision in § 35.39(g).
(e) Non-power goods or services. (1) Unless otherwise permitted by Commission rule or order, sales of any nonpower goods or services by a franchised
public utility with captive customers,
to a market-regulated power sales affiliate must be at the higher of cost or
market price.
(2) Unless otherwise permitted by
Commission rule or order, sales of any
non-power goods or services by a market-regulated power sales affiliate to
an affiliated franchised public utility
with captive customers may not be at
a price above market.
(f) Brokering of power. (1) Unless otherwise permitted by Commission rule
or order, to the extent a market-regulated power sales affiliate seeks to
broker power for an affiliated franchised public utility with captive customers:
(i) The market-regulated power sales
affiliate must offer the franchised public utility’s power first;
(ii) The arrangement between the
market-regulated power sales affiliate
and the franchised public utility must
be non-exclusive; and
(iii) The market-regulated power
sales affiliate may not accept any fees
in conjunction with any brokering
services it performs for an affiliated
franchised public utility.
(2) Unless otherwise permitted by
Commission rule or order, to the extent a franchised public utility with
captive customers seeks to broker
power for a market-regulated power
sales affiliate:
(i) The franchised public utility must
charge the higher of its costs for the
service or the market price for such
services;
(ii) The franchised public utility
must market its own power first, and
simultaneously make public (on the
Internet) any market information
shared with its affiliate during the
brokering; and
(iii) The franchised public utility
must post on the Internet the actual
brokering charges imposed.
(g) No conduit provision. A franchised
public utility with captive customers
and a market-regulated power sales affiliate are prohibited from using anyone, including asset managers, as a
conduit to circumvent the affiliate restrictions in §§ 35.39(a) through (g).
(h) Franchised utilities without captive
customers. If necessary, any affiliate restrictions regarding separation of functions, power sales or non-power goods
and services transactions, or brokering
involving two or more franchised public utilities, one or more of whom has
captive customers and one or more of
whom does not have captive customers,
will be imposed on a case-by-case basis.
[Order 697, 72 FR 40038, July 20, 2007, as
amended by Order 697–A, 73 FR 25912, May 7,
2008]
§ 35.40 Ancillary services.
A Seller may make sales of ancillary
services at market-based rates only if
it has been authorized by the Commission and only in specific geographic
markets as the Commission has authorized.
§ 35.41 Market behavior rules.
(a) Unit operation. Where a Seller participates in a Commission-approved organized market, Seller must operate
and schedule generating facilities, undertake maintenance, declare outages,
and commit or otherwise bid supply in
a manner that complies with the Commission-approved rules and regulations
of the applicable market. A Seller is
not required to bid or supply electric
energy or other electricity products
unless such requirement is a part of a
separate Commission-approved tariff or
is a requirement applicable to Seller
through Seller’s participation in a
Commission-approved organized market.
(b) Communications. A Seller must
provide accurate and factual information and not submit false or misleading
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Federal Energy Regulatory Commission
information, or omit material information, in any communication with the
Commission,
Commission-approved
market
monitors,
Commission-approved regional transmission organizations,
Commission-approved
independent system operators, or jurisdictional transmission providers, unless
Seller exercises due diligence to prevent such occurrences.
(c) Price reporting. To the extent a
Seller engages in reporting of transactions to publishers of electric or natural gas price indices, Seller must provide accurate and factual information,
and not knowingly submit false or misleading information or omit material
information to any such publisher, by
reporting its transactions in a manner
consistent with the procedures set
forth in the Policy Statement on Natural
Gas and Electric Price Indices, issued by
the Commission in Docket No. PL03–3–
000, and any clarifications thereto.
Seller must identify as part of its Electric Quarterly Report filing requirement in § 35.10b of this chapter the publishers of electricity and natural gas
indices to which it reports its transactions. In addition, Seller must adhere to any other standards and requirements for price reporting as the
Commission may order.
(d) Records retention. A Seller must
retain, for a period of five years, all
data and information upon which it
billed the prices it charged for the electric energy or electric energy products
it sold pursuant to Seller’s marketbased rate tariff, and the prices it reported for use in price indices.
kpayne on VMOFRWIN702 with $$_JOB
[Order 697, 72 FR 40038, July 20, 2007, as
amended by Order 768, 77 FR 61924, Oct. 11,
2012]
§ 35.42 Change in status reporting requirement.
(a) As a condition of obtaining and
retaining market-based rate authority,
a Seller must timely report to the
Commission any change in status that
would reflect a departure from the
characteristics the Commission relied
upon in granting market-based rate authority. A change in status includes,
but is not limited to, the following:
(1) Ownership or control of generation capacity or long-term firm purchases of capacity and/or energy that
§ 35.42
results in cumulative net increases
(i.e., the difference between increases
and decreases in affiliated generation
capacity) of 100 MW or more of capacity based on nameplate or seasonal capacity ratings, or, for solar photovoltaic facilities, nameplate capacity,
or, for other energy-limited resources,
nameplate or five-year average capacity factors, in any individual relevant
geographic market, or of inputs to
electric power production, or ownership, operation or control of transmission facilities; or
(2) Affiliation with any entity not
disclosed in the application for market-based rate authority that:
(i) Owns or controls generation facilities or has long-term firm purchases of
capacity and/or energy that results in
cumulative net increases (i.e., the difference between increases and decreases in affiliated generation capacity) of 100 MW or more of capacity
based on nameplate or seasonal capacity ratings, or, for solar photovoltaic
facilities, nameplate capacity, or, for
other energy-limited resources, nameplate or five-year average capacity factors, in any individual relevant geographic market;
(ii) Owns or controls inputs to electric power production;
(iii) Owns, operates or controls transmission facilities; or
(iv) Has a franchised service area.
(b) Any change in status subject to
paragraph (a) of this section must be
filed no later than 30 days after the
change in status occurs. Power sales
contracts with future delivery are reportable 30 days after the physical delivery has begun. Failure to timely file
a change in status report constitutes a
tariff violation.
(c) When submitting a change in status notification regarding a change
that impacts the pertinent assets held
by a Seller or its affiliates with market-based rate authorization, a Seller
must include an appendix of all assets,
including the new assets and/or affiliates reported in the change in status,
in the form provided in appendix B of
this subpart, and an organizational
chart. The organizational chart must
depict the Seller’s prior and new corporate structures indicating all affiliates unless the Seller demonstrates
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§ 35.42
18 CFR Ch. I (4–1–19 Edition)
that the change in status does not af-
fect the corporate structure of the Seller’s affiliations.
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[Order 697–D, 75 FR 14351, Mar. 25, 2010, as
amended by Order 816, 80 FR 67108, Oct. 30,
2015; Order 816–A, 81 FR 33383, May 26, 2016]
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PC31
Federal Energy Regulatory Commission
Pt. 35, Subpt. H, App. A
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ER30OC15.000
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APPENDIX A TO SUBPART H OF PART 35—STANDARD SCREEN FORMAT
Pt. 35, Subpt. H, App. A
18 CFR Ch. I (4–1–19 Edition)
Appendix A: Standard Screen Format (Data provided for illustrative purposes only)
Part II- Market Share Analysis
Staff Notes:
The file differs from the file published in the NOPR:
1. All entered values must be positive (no parenthesis/negative numbers)
2. The formulas (and the text in the row description) have been changed to reflect number 1.
3. Instruction: Enter all numeric values as ositive numbers (blue values)
Don1 enter values into an outlined cell (black values)
Applicant-> Company X, LLC (TO)
Study Area-> Company X BAA
Data Year-> Dec 2011-Nov 2012
As filed by the ApplicanVSeller
Row
Winter
Spring
Summer
(MW)
(MW)
(MW)
Seller and Affiliate Capacity (owned, controlled or under L T contract)
A Installed Capacily (inside the study area)
1,000
900
1,500
A1 Remote Capacity (from outside the study anea)
400
200
300
B Long-Tenm Firm Purchases (inside the studyanea)
60
40
70
B1 Long-Tenm Firm Purchases (fnom outside the study anea)
200
200
200
Long-Tenm Firm Sales (in and outside the study anea)
500
500
500
D Seasonal Average Planned Outages
150
50
80
E Uncommitted Capacity Imports
0
0
0
Fall
(MW)
c
Capacity Deductions
F Average Peak Native Load in the Season
G Amount of Line F Attributable to Seller, if any
H Amount of Line F Attributable to Non-Affiliates, if any
I Study Anea Reserve Requinement
J Amount of Line I Attributable to Seller, if any
K Amount of Line I Attributable to Non-Affiliates, if any
L
L1
M
M1
N
0
p
Non-Affiliate Capacity (owned, controlled or under L T contract)
Installed Capacity (inside the study area)
Remote Capacity (from outside the study anea)
Long-Tenm Finm Purchases (inside the studyanea)
Long-Tenm Firm Purchases (fnom outside the study anea)
Long-Tenm Firm Sales (in and outside the study anea)
Seasonal Average Planned Outages
Uncommitted Capacity Imports
Supply Calculation
Q Total Competing Supply (L +L 1+M+M1 +P-H-K-N-0)
R Selle~s Uncommitted Capacity (A+A 1+B+B 1+E-C-D-G-J)
Total Seasonal Uncommitted Capacity (Q+R)
s
T
u
v
Selle~s
Market Share (R+S)
Results (Pass if< 20% and Fail
if~
1,000
200
30
200
500
100
0
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
1,000
700
300
200
100
100
900
700
200
200
100
100
1,200
900
300
300
200
100
800
600
2oo
100
80
20
250
50
30
40
50
10
2,000
200
50
30
30
30
20
1,500
300
50
30
40
60
10
2,500
150
50
30
1,300
1,910
210
2,120
1,460
90
1,550
2,450
290
2,740
1,260
150
1,410
10.6%
Pass
10.6%
Pass
9.9%
Pass
20%)
Total Imports, as filed by Seller (E+P)
SIL value•
2,ooo
2,000
Do Total Imports exceed SIL value? (is U<=V)
No
5.8%
Pass
I
1 5oo
1,500
No
I
2.5oo
2.500
No
20
50
20
I
Reference
I
I
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
worksheet X
1,300
1,300
No
*Transmission owners filing triennials should use the SIL values from their Submittal1, Row 10 (see Puget Sound Energy, Inc., 135 FERC ~ 61,254 (2011)).
other sellers should use Commission-accepted SIL values, if they exist for the study area and study period. If these values do not exist, sellers should
use SIL values that have been filed but not accepted.
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[Order 816, 80 FR 67108, Oct. 30, 2015]
Federal Energy Regulatory Commission
Pt. 35, Subpt. H, App. B
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ER26MY16.039
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APPENDIX B TO SUBPART H OF PART 35—CORPORATE ENTITIES AND ASSETS SAMPLE
APPENDIX
Pt. 35, Subpt. H, App. B
18 CFR Ch. I (4–1–19 Edition)
-,
_j
ln~t~~io__!ls_!o_! c~"!P~t~gJ:~ ~~e~Ae_p!n~ixJ~!.t: !o~g_:!~~ F!!'~ P~\!e~P-~r~a~e-~e~~e~tsj~~ _
LCo!u~n _ _ _ _ _ _ T_!!_Ie_ _ _ _ _ _ __J _ _ _ _ --~or_!!1CI_!_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ~e~r~ti~n _ _ _ _ _ _ _ _ _ _ J
I
i
Name of the Filing Entity or affiliate of the Filing Entity that is
I [A[
!Free Form Text
purchasing the energy or capacity.
;
r-····- -···
-~--;;-,.;;~-;;~;;;~-,iii~;-,,;tiwth~;i,;iiin;;h;;c;;~;;,iw;;;d/~;;,n;;;;;..-1
L _ _
---- --------
-- ---- ---- --
eller Name
[B[
jFree Form Text
1
Please use the exact name as in the Company Registration database ifj
possible.
1
I
Contcacted amo,nt of the
in
lithe oontcact is foe the entice I
PPA MW.
output of a specific generation unit, you may de-rate the unit using
the same de-rating methodology that is used for generators of the
!Numeric. Either an integer or fixed width
same technology elsewhere in the appendix. If this amount is de!numeric with one decimal
rated please explain in the End Notes Sheet. Energy-only contracts
!
must be converted from MWh to MW. Only report contracts one year
erlanger.
!
[C[
[D[
":
~:::~~alancing Authority Area (Sink)
-···[F[
graphic Region (Sink)
[H[
L _ _
I
is sourced to the extent the source location(s) is specified in the PPA.
One ofthe six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or
their designated submarkets (PJM-East, 5004/5005, AP South,
!submarkets please use one of the
!
I
!
I
ispecificText
!
I!
Same instruction as the Generation Assets Sheet.
. .nd_E.~~
=. . lm~!_~l~!.=
=. -= =. -= J.~~-~~
. .==. -= =. . ==. -= =. . ==. -= The~-~}t~~Ea~~
.. -~t~~!P~....==
. -= =. . ==. -= =. -= =. -= =. -= =. -= Jj
Date
(mo/da/yr)
jMM/DD/YY
End Date of the PPA
lGJ
[I[
~~~~;~e::~:~~k~:~~~n: :a~!~~;~~ :;t~:~i~;:;e:~~;::s:~~hp;h:s~PA!
!abbreviations or names in the next
Connecticut, Southwest Connecticut, New York City, Long Island) or a
jcolumn. For balancing authority areas
NERC-defined Balancing Authority Area name. For all PPAs, identify j
_ .... __ ... __ ... __ ... __ ... _ J.P.~~~-~s~~-~,!! r:!,~-~C-:!,~_f!.n~.. !!.ar:!:!.~..- _ ... _ "!~-~e_!~~ c~-~ity_,_~!!._d[?.E;:n~E~ i~~-~iV_!;E~d._ ... __ ... __ ... __ ... _ J
I
f- -···1
i
i
!column. For balancing authority areas
!please use the NERC-defined name
IFree Form Text. For Markets or
[E[
i
!
!
One ofthe six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or I
their designated submarkets (PJM-East, 5004/5005, AP South,
.
h
k
·
1 d)
Connecticut, Sout west Connecticut, New Yor City, Long Is an or a
1
jFree Form Text. For Markets or
jsubmarkets please use one of the
jabbreviations or names in the next
Location:
Market/Balancing Authority Area
Source)
!
Enter the text "Unit" if the PPA is from a specific unit such as a wind !
i
generator selling its output to a utility, or from multiple units at a
I
single plant. Please provide the name of the unit or facility supplying!
ype of PPA (Unit or System)
j"Unit" or "System"
the PPA in the End Notes Sheet. Enter "System" if the PPA is sourced
!
from a utility's or IPP's fleet with different units providing power at j
different times.
1
1
EndNot;Nu~b;(En;rtext"i;;-E~-~---- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - --~
I
~ ~l__N~e~Sb_e~) _ _ _ _ _ _ _ _ _ J~t~e~
_________
---~m~~s~u~i~~~e~e~e~t~n~s~e~S~e~--
______ j
~ __ tln~t~~io__!ls_!o_! c~"!P~t~gJ:~ ~;e~Ae_p!n~ixJ~!.t:_!r~n~m!ss_!ol!ff!a~.r~l ~a!_ ~s!ts_
_ i
f---Co!u'!!n{. _ _ _ _ _ _ T_!!_le_ _ _ _ _ _ ~ _ _ _ _ _ _ ~Of!!la_!_ _ _ _ _ _ -· _ _ _ _ _ _ _ _ _ _ ~e~r~ti~n _ _ _ _ _ _ _ _ _ _ ~
~ l~.L f..~.!!n~~-~ity_~!!_d!!;_~.!_n~_~A_!!_i_!!_a~~..- ~ ..-- _, ___ .... __ , ___ .... __ , ___ .... _ - .. ·-~-~~~~-~u~L~~ ..~e_§_~!!_e~-~~n~~e~-~~e~_: ___ , ___ , ___ , __ -!
1
jCite to order accepting OATT or the
i
Commission cite to the order accepting the Filing Entity's or its Energy i
1 [B] jorder approving the transfer of
!
Affiliate's current OATT, or the order transferring control of the
transmission facilities to an RT0/150.
!transmission facilities to an RTO or ISO i
I
i
Legal name of the facility and brief description of the type of facility
jFree Form Text
(i.e. transmission line or gas pipeline).
1 [C] jAsset Name and Use
~ l!?..L tC?..~n~~-~Y _ .... __, ___, ___, ___, __ ~..-I
(E]
_, ___ .... __ , ___ .... __ , ___ .... __ , __: f!.~.~e ~f.._!be_~_~_!ity_~~nJ!!.~J:h~-~~n~~~siE.~Ln~~~l £~.~as~t7..~- _, __
!Controlled By
~
Name of the Entity that controls the transmission/natural gas assets.
c-L------L------------------L .... lFL...lD~~-.So!!.~.~EI '!!'.~.~sf~!.T~d _ .... __ , ____
1 [G] jMarket/Balancing Authority Area
1 [H] !Geographic Region
...J _,___. . __,___. . __,___. . __,__ -..~m~..~s!!:_~-~i~...~ t!!_~_..§e!!~.~t~-~_!.5~~-~ S!!_~-~- _ ....__,___...._
i
i
I--T-------------:--------------I
1
[I]
jSize (e.g., length and kV for electric,
!length and diameter for pipelines, and !Free Form Text
capacity for gas storage)
i
I
!
f-.... _ - ..·+
specific type of facility. For example, for electric "Size" refers to the
length and kV rating of the transmission line; for gas pipeline "Size"
refers to the length and diameter of the pipeline; for gas storage
!
"Size"
refers
to the
capacity
ofthe
_,, __,,__,,__,,__,,__,,__....-1 _,, __,,__,,__,,__,,__,,__,,_ _,,__,,_
_ ,, __
,, __
,, __ ,,
__ ,,facility.
__ ,, __ ,, __ ,, __ ,, __ ,,_
I
1 [J] lEnd Not~ Nu)mber (Enter text in End
L .... _ .. __ ... l~. ~-~~-~-17..~ ...- ....- ...- ...- ...- ....- ...- ...- ...- ....J . .-
Same instruction as the Generation Assets Sheet.
!
. .- . .- . . - . . - . .- . .- . . - . . - . .- . .- . . - . . - . .- . .- . .- . . - . .- . .- . .- . . - . . - . .- . .- . . - . . - . .- . .- . . - . . - . .- . .- . .- . . - . .- . .- . .- . . - . .- . . J
348
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ER26MY16.040
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Same instruction as the Generation Assets Sheet.
Same instruction as the Generation Assets Sheet.
Des~ri;ti~n~f;e~i;crlthefacilit;in-th~;e;;u~es--;e-;;v-;n;to~h;
Federal Energy Regulatory Commission
,---
-11-;,;t~ucti~n~fo; ~o~pleti;.gth;
A;s;t-App;ndbtSh;et:-E;.d
1 _C~I~~nj _________ l}tle_________ l
1
[A]
I, End
N~t;s----- ~-----------------------------------
_________Fp-:_m_!l~ ________ l ______________ _!)~s_£r!P!!~"- _____________ _
[Integer
Note Number
fshould match an End Note number in the Generation Assets, Long!Term Firm PPAs or Transmission/Natural Gas Assets Sheets.
'
Isheet (Generation Assets, Long-Term
[B]
Pt. 35, Subpt. H, App. B
i
f
!Firm PPAs or Transmission/Natural Gas !The words "Generation", "PPA", or
!Indicates in which asset sheet the End Note is located.
!Assets)
:
:"Transmission/Natural Gas"
]~~l~n~t~ry ~~~ ===========IF~e~ ~o!~ie~t= =============Ir~x~ er~v}d}n~!h~ ~~ifi~a~~n~~e~~a~~t~rY ~o~e= ========-
Filing
Docket# Generation
Market/
Geographic
Date
Entity and whereMBR
Balancing
In-Service
Name
Owned Controlled
Region
Control
its Energy authority was (Plant or
Authority
By
By
Dote
Transferred
Affiliates
granted
Unit Name)
Are•
Filing Entity
and Its Energy
Affiliates
Market/
Balancing
Authority Area
Source
Seller Name
,-----------------
Location
Market/
Balancing
Authority
Area Sink
Capacity
Rating: Used
in Filing
(MWJ
Methodology Number
Usedin[K]:
(Enter
(N)ameplate,
text in
(S)easonai,S-yr
End
(U)nit,5-yr(E)IA, Notes
Alternative
Sheet
Geographic
Region
text in End
Notes Sheet
(Sink)
~------ Tk;etAPP~~dix~Tr;n~;;:.i;sio-;.7Natu-;~
---------L--~---L-_L
Capacity
Rating:
Nameplate
(MW)
G;sA;s;ts-------
r-------
~----------
__ L __ L ____ L ___ L ___ _
~----------------~------~------~-----~-----~-----~---------~-------~---------1
I
;
I
;
I
I
!
- ~--~ ~---~ ~--~ ~--~ ~--~ ~--= ~--~ ~--~ }. ~~~-~rf.~.J~~-~s~Js~-~~~-~~~~~-~~n~[o~--~~-~~r~l. ~~~~~~!.a~~~~~.J'fP..~lf.~~~~~~~~~~~a~. ~t~.~i.~)~.~}l~.~~~~. ~--------
[A]
[B]
[C]
-------------~---
Flll~!~::::;nd
Affiliates
Cite to order
acceptingOATI
or order
approvingthe
transfer of
transmission
facilities to an
RTOo•ISO
I
[D]
---~-----
Asset Name
and Use
[E]
i
I
[F]
i
--:-----~-----
Owned By
[G]
I
Location
[H]
i
[I]
I
Size
[J]
- - - - - - - - ..
Size (e.g.,
length and kV
Market/
for electric,
End Note Number
Date
length and
Controlled
Control
Balanci~g Geographic Region
(Entertextln End
diameter for
By
Transferred Authority
Notes Sheet)
pipelines, and
Area
capacity for gas
........
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I
§ 35.43
18 CFR Ch. I (4–1–19 Edition)
[Order 816–A, 81 FR 33383, May 26, 2016]
Subpart I—Cross-Subsidization Restrictions on Affiliate Transactions
§ 35.43 Generally.
(a) For purposes of this subpart:
(1) Affiliate of a specified company
means:
(i) For any person other than an exempt wholesale generator:
(A) Any person that directly or indirectly owns, controls, or holds with
power to vote, 10 percent or more of
the outstanding voting securities of
the specified company;
(B) Any company 10 percent or more
of whose outstanding voting securities
are owned, controlled, or held with
power to vote, directly or indirectly,
by the specified company;
(C) Any person or class of persons
that the Commission determines, after
appropriate notice and opportunity for
hearing, to stand in such relation to
the specified company that there is liable to be an absence of arm’s-length
bargaining in transactions between
them as to make it necessary or appropriate in the public interest or for the
protection of investors or consumers
that the person be treated as an affiliate; and
(D) Any person that is under common
control with the specified company.
(E) For purposes of paragraph (a)(1)(i)
of this section, owning, controlling or
holding with power to vote, less than 10
percent of the outstanding voting securities of a specified company creates a
rebuttable presumption of lack of control.
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SOURCE: 73 FR 11025, Feb. 29, 2008, unless
otherwise noted.
(ii) For any exempt wholesale generator (as defined under § 366.1 of this
chapter), consistent with section 214 of
the Federal Power Act (16 U.S.C. 824m),
which provides that ‘‘affiliate’’ will
have the same meaning as provided in
section 2(a) of the Public Utility Holding Company Act of 1935 (15 U.S.C.
79b(a)(11)):
(A) Any person that directly or indirectly owns, controls, or holds with
power to vote, 5 percent or more of the
outstanding voting securities of the
specified company;
(B) Any company 5 percent or more
of whose outstanding voting securities
are owned, controlled, or held with
power to vote, directly or indirectly,
by the specified company;
(C) Any individual who is an officer
or director of the specified company, or
of any company which is an affiliate
thereof under paragraph (a)(1)(ii)(A) of
this section; and
(D) Any person or class of persons
that the Commission determines, after
appropriate notice and opportunity for
hearing, to stand in such relation to
the specified company that there is liable to be an absence of arm’s-length
bargaining in transactions between
them as to make it necessary or appropriate in the public interest or for the
protection of investors or consumers
that the person be treated as an affiliate.
(2) Captive customers means any
wholesale or retail electric energy customers served by a franchised public
utility under cost-based regulation.
(3) Franchised public utility means a
public utility with a franchised service
obligation under state law.
Federal Energy Regulatory Commission
kpayne on VMOFRWIN702 with $$_JOB
(4) Market-regulated power sales affiliate means any power seller affiliate
other than a franchised public utility,
including a power marketer, exempt
wholesale generator, qualifying facility
or other power seller affiliate, whose
power sales are regulated in whole or
in part on a market-rate basis.
(5) Non-utility affiliate means any affiliate that is not in the power sales or
transmission business, other than a
local gas distribution company or an
interstate natural gas pipeline.
(b) The provisions of this subpart
apply to all franchised public utilities
that have captive customers or that
own or provide transmission service
over jurisdictional transmission facilities.
§ 35.44 Protections against affiliate
cross-subsidization.
(a) Restriction on affiliate sales of electric energy. No wholesale sale of electric
energy may be made between a franchised public utility with captive customers and a market-regulated power
sales affiliate without first receiving
Commission authorization for the
transaction under section 205 of the
Federal Power Act. This requirement
does not apply to energy sales from a
qualifying facility, as defined by 18
CFR 292.101, made under market-based
rate authority granted by the Commission.
(b) Non-power goods or services. (1) Unless otherwise permitted by Commission rule or order, and except as permitted by paragraph (b)(4) of this section, sales of any non-power goods or
services by a franchised public utility
that has captive customers or that
owns or provides transmission service
over jurisdictional transmission facilities, including sales made to or
through its affiliated exempt wholesale
generators or qualifying facilities, to a
market-regulated power sales affiliate
or non-utility affiliate must be at the
higher of cost or market price.
(2) Unless otherwise permitted by
Commission rule or order, and except
as permitted by paragraphs (b)(3) and
(b)(4) of this section, a franchised public utility that has captive customers
or that owns or provides transmission
service
over
jurisdictional
transmission facilities, may not purchase or
§ 35.46
receive non-power goods and services
from a market-regulated power sales
affiliate or a non-utility affiliate at a
price above market.
(3) A franchised public utility that
has captive customers or that owns or
provides transmission service over jurisdictional transmission facilities,
may only purchase or receive nonpower goods and services from a centralized service company at cost.
(4) A company in a single-state holding company system, as defined in
§ 366.3(c)(1) of this chapter, may provide
general administrative and management non-power goods and services to,
or receive such goods and services
from, other companies in the same
holding company system, at cost, provided that the only parties to transactions involving these non-power
goods and services are affiliates or associate companies, as defined in § 366.1
of this chapter, of a holding company
in the holding company system.
(c) Exemption for price under fuel adjustment clause regulations. Where the
price of fuel from a company-owned or
controlled source is found or presumed
under § 35.14 to be reasonable and includable in the adjustment clause,
transactions involving that fuel shall
be exempt from the affiliate price restrictions in § 35.44(b).
[73 FR 11025, Feb. 29, 2008, as amended by
Order 707–A, 73 FR 43083, July 24, 2008]
Subpart J—Credit Practices In Organized Wholesale Electric
Markets
SOURCE: Order 741, 75 FR 65962, Oct. 27, 2010,
unless otherwise noted.
§ 35.45
Applicability.
This subpart establishes credit practices for organized wholesale electric
markets for the purpose of minimizing
risk to market participants.
§ 35.46
Definitions.
As used in this subpart:
(a) Market Participant means an entity that qualifies as a Market Participant under § 35.34.
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§ 35.47
18 CFR Ch. I (4–1–19 Edition)
(b) Organized Wholesale Electric Market includes an independent system operator and a regional transmission organization.
(c) Regional Transmission Organization
means an entity that qualifies as a Regional
Transmission
Organization
under 18 CFR 35.34.
(d)
Independent
System
Operator
means an entity operating a transmission system and found by the Commission to be an Independent System
Operator.
kpayne on VMOFRWIN702 with $$_JOB
§ 35.47 Tariff
provisions
regarding
credit practices in organized wholesale electric markets.
Each organized wholesale electric
market must have tariff provisions
that:
(a) Limit the amount of unsecured
credit extended by an organized wholesale electric market to no more than
$50 million for each market participant; where a corporate family includes more than one market participant participating in the same organized wholesale electric market, the
limit on the amount of unsecured credit extended by that organized wholesale electric market shall be no more
than $50 million for the corporate family.
(b) Adopt a billing period of no more
than seven days and allow a settlement
period of no more than seven days.
(c) Eliminate unsecured credit in financial transmission rights markets
and equivalent markets.
(d) Establish a single counterparty to
all market participant transactions, or
require each market participant in an
organized wholesale electric market to
grant a security interest to the organized wholesale electric market in the
receivables of its transactions, or provide another method of supporting netting that provides a similar level of
protection to the market and is approved by the Commission. In the alternative, the organized wholesale
electric market shall not net market
participants’ transactions and must establish credit based on market participants’ gross obligations.
(e) Limit to no more than two days
the time period provided to post additional collateral when additional col-
lateral is requested by the organized
wholesale electric market.
(f) Require minimum participation
criteria for market participants to be
eligible to participate in the organized
wholesale electric market.
(g) Provide a list of examples of circumstances when a market administrator may invoke a ‘‘material adverse
change’’ as a justification for requiring
additional collateral; this list does not
limit a market administrator’s right to
invoke such a clause in other circumstances.
[Order 741, 75 FR 65962, Oct. 27, 2010, as
amended by Order 741–A, 76 FR 10498, Feb. 25,
2011]
PART 36—RULES CONCERNING APPLICATIONS FOR TRANSMISSION
SERVICES UNDER SECTION 211
OF THE FEDERAL POWER ACT
AUTHORITY: 5 U.S.C. 551–557; 16 U.S.C. 791a–
825r; 31 U.S.C. 9701; 42 U.S.C. 7107–7352.
§ 36.1 Notice provisions applicable to
applications for transmission services under section 211 of the Federal Power Act.
(a) Definitions. (1) Affected party
means each affected electric utility,
each affected State regulatory authority, and each affected Federal power
marketing agency.
(2) Affected electric utility means each
electric utility that has made arrangements for the sale or purchase of electric energy to be transmitted pursuant
to the particular application for transmission services, and each transmitting utility, as defined in section 3(23)
of the Federal Power Act, 16 U.S.C.
796(23), being requested to transmit
such electric energy.
(3) Affected State regulatory authority
means a State regulatory authority, as
defined in section 3(21) of the Federal
Power Act, 16 U.S.C. 796(21), regulating
the rates and charges of each affected
electric utility.
(4) Affected Federal power marketing
agency means a Federal power marketing agency that operates in the
service area of each affected electric
utility.
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| File Type | application/pdf |
| File Modified | 2019-07-30 |
| File Created | 2019-07-31 |