[Federal Register Volume 60, Number 16 (Wednesday, January 25, 1995)]
[Rules and Regulations]
[Pages 4831-4860]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-1449]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Parts 2, 34, 35, 41, 131, 292, 294, 382, and 385
[Docket No. RM92-12-000]
Streamlining of Regulations Pertaining to Parts II and III of the
Federal Power Act and the Public Utility Regulatory Policies Act of
1978; Order No. 575
Issued January 13, 1995.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
amending its regulations governing public utilities and qualifying
facilities. The final rule revises and clarifies Commission policies
regarding: Rate filings by public utilities under the Federal Power
Act; issuances of securities and assumptions of liabilities by public
utilities, licensees and others; and procedural and technical rules
governing qualifying facilities. The final rule is intended to
streamline the Commission's processing of its workload and reduce
regulatory burdens on the electric utility and qualifying facility
industries.
EFFECTIVE DATE: This rule is effective February 24, 1995.
FOR FURTHER INFORMATION CONTACT:
Andre Goodson (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 825 North Capitol St., N.E.,
Washington, D.C. 20426, Telephone: (202) 208-2167;
Joseph C. Lynch (Legal Information), Federal Energy Regulatory
Commission, Office of the General Counsel, 825 North Capitol Street,
N.E., Washington, D.C. 20426, Telephone: (202) 208-2128;
Wayne McDanal (Technical information concerning Part 34 matters),
Office of Chief Accountant, 825 North Capitol Street, N.E., Washington,
D.C. 20426, Telephone: (202) 219-2622;
Howard B. Forman (Technical information concerning Part 35 matters),
Office of Electric Power Regulation, 825 North Capitol Street, N.E.,
Washington, D.C. 20426, Telephone: (202) 208-0545;
Qualifying Facilities Desk Officer (Technical information concerning
Part 292 matters), Office of Electric Power Regulation, 825 North
Capitol Street, N.E., Washington, D.C. 20426, Telephone: (202) 208-
0571;
James K. Newton (Technical information concerning Part 294 matters),
Office of Electric Power Regulation, 825 North Capitol Street, N.E.,
Washington, D.C. 20426, Telephone: (202) 208-0578; or
William C. Booth (Technical information concerning Part 382 matters),
Office of Electric Power Regulation, 825 North Capitol Street, N.E.,
Washington, D.C. 20426, Telephone: (202) 208-0849.
SUPPLEMENTARY INFORMATION: In addition to publishing the full text of
this document in the Federal Register, the Commission also provides all
interested persons an opportunity to inspect or copy the contents of
this document during normal business hours in Room 3401, at 941 North
Capitol Street, N.E., Washington, D.C. 20426.
The Commission Issuance Posting System (CIPS), an electronic
bulletin board service, provides access to the texts of formal
documents issued by the Commission. CIPS is available at no charge to
the user and may be accessed using a personal computer with a modem by
dialing (202) 208-1397. To access CIPS, set your communications
software to 19200, 14400, 12000, 9600, 7200, 4800, 2400, 1200 or
300bps, full duplex, no parity, 8 data bits and 1 stop bit. The full
text of this document will be available on CIPS for 60 days from the
date of issuance in ASCII and WordPerfect 5.1 format. After 60 days the
document will be archived, but still accessible. The complete text on
diskette in WordPerfect format may also be purchased from the
Commission's copy contractor, La Dorn Systems Corporation, also located
in Room 3104, 941 North Capitol Street, N.E., Washington, D.C. 20426.
Table of Contents
I. Introduction
II. Public Reporting Burden
III. Discussion
A. Part 2--General Policy and Interpretations: Section 2.4(d)--
Initial Rate Schedules
B. Part 34--Application for Authorization of the Issuance of
Securities or the Assumption of Liabilities
1. Section 34.1(c)(1)--Exemption if State Regulates Security
Prior to Issuance
2. Section 34.1(c)(2)--Exemption for Short Term Notes or Drafts
3. Section 34.2--Placement of Securities
4. Section 34.3--Contents of Application for Issuance of
Securities
5. Section 34.4--Required Exhibits
6. Section 34.10--Reports
7. Section 34.11--Unopposed Applications to Issue Securities
and/or Assume Liabilities
8. Part 131--Forms: Section 131.50
C. Part 35--Filing of Rate Schedules
1. Sections 35.13(a)(2)(i)(A) and (B)--Rate Increases of Less
Than $200,000, Regardless of Customer Consent, and Rate Increases
Below $1,000,000, With Customer Consent
2. Other Changes to Section 35.13
D. Part 41--Accounts, Records and Memoranda: Sections 41.3 and
41.7
E. Proposed Procedural Modifications and Revised Definitions
Under Part 292--Regulations Under Sections 201 and 210 of the Public
Utility Regulatory Policies Act of 1978 (PURPA) With Regard to Small
Power Production and Cogeneration
1. Administration of the 90-Day Certification Period
2. Improvements in the Self-Certification Process
3. Revocation of Qualifying Status
4. Pre-Authorized Recertification [[Page 4832]]
5. Qualifying Transmission and Interconnection Equipment
6. Maximum Net Power Production Capacity
7. Increased Specificity of the Qualifying Facility
Certification Application Filing Requirements: Form 556
F. Proposed Technical Modifications for Qualifying Small Power
Production and Cogeneration Facilities Under Part 292
1. Calendar Year Operating and Efficiency Value Calculations
2. Clarification of the Sequential Use of Energy Requirement
3. Section 292.204(a)--Criteria for Small Power Production
Facilities
4. Waste
G. Part 294--Procedures for Shortages of Electric Energy and
Capacity Under Section 206 of the Public Utility Regulatory Policies
Act of 1978
H. Part 382--Annual Charges: Sections 382.102 and 382.201
I. Part 385--Rules of Practice and Procedure
IV. Environmental Statement
V. Regulatory Flexibility Certification
VI. Information Collection Statement
List of Subjects
Before Commissioners: Elizabeth Anne Moler, Chair; Vicky A.
Bailey, James J. Hoecker, William L. Massey, and Donald F. Santa,
Jr.
I. Introduction
On November 16, 1992, the Federal Energy Regulatory Commission
(Commission) issued a Notice of Proposed Rulemaking (NOPR) in which the
Commission proposed to revise its regulations regarding: (a) Rate
filings by public utilities under the Federal Power Act (FPA); (b)
assumptions of liabilities and issuances of securities by public
utilities, licensees, and certain other entities; and (c) procedural
and technical rules governing qualifying facilities.1 The
Commission requested that interested persons submit written comments no
later than January 15, 1993. Forty entities submitted comments.2
\1\Streamlining of Regulations Pertaining to Parts II and III of
the Federal Power Act and the Public Utility Regulatory Policies Act
of 1978, Notice of Proposed Rulemaking, 57 FR 55176 (Nov. 24, 1992),
IV FERC Stats. & Regs. 32,489 (1992), errata adding Appendix, 57 FR
58168 (Dec. 9, 1992), IV FERC Stats. & Regs. 32,491 (1992).
\2\The commenters are: American Cogeneration Association
(American Cogen); American Forest and Paper Association (American
Forest and Paper); American Gas Association (AGA); American Iron and
Steel Institute (American Iron and Steel); Anthracite Region
Independent Power Producers Association (Anthracite IPPs); Applied
Energy Services Corporation (Applied Energy); Arizona Public Service
Company (Arizona Public Service); Atlantic City Electric Company
(Atlantic Electric); Baltimore Gas & Electric Company (Baltimore Gas
& Electric); Public Utilities Commission of the State of California
(CPUC); Consumers Power Company (Consumers Power); Curran, Corbett &
Stiles; Delmarva Power & Light Company (Delmarva); Detroit Edison
Company (Detroit Edison); Steven A. Duff; Duke Power Company (Duke
Power); Edison Electric Institute (EEI); Electric Generation
Association; Florida Power & Light Company (Florida P&L); General
Electric Company (General Electric); Gulf States Utilities Company
(Gulf States); Long Island Lighting Company (LILCO); National
Independent Energy Producers (Independent Energy Producers); New
England Power Company (NEP); New York State Electric & Gas Company
(NYSEG); Niagara Mohawk Power Corporation (Niagara Mohawk); Oxbow
Power Corporation (Oxbow); Pennsylvania Power & Light Company
(Pennsylvania P&L); Ridgewood Power Corporation (Ridgewood); RW
Power Partners, L.P. (RW Partners); San Diego Gas & Electric Company
(SDG&E); Southern California Edison Company (Southern California
Edison); Southern Company Services, Inc. (Southern Companies);
Tenaska, Inc. (Tenaska); Texaco Cogeneration and Power Company
(Texaco); Texas-New Mexico Power Company (Texas-New Mexico); United
States Small Business Administration (Small Business
Administration); UtiliCorp United, Inc. (UtiliCorp); Utility Systems
Florida; and Donald L. Warner.
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The Commission is now adopting a final rule revising its
regulations to streamline the processing of the Commission's workload
and to reduce regulatory burdens on the electric utility and qualifying
facility industries.
II. Public Reporting Burden
The final rule establishes new reporting requirements, modifies
existing reporting requirements and eliminates those requirements that
are now obsolete. On balance, the Commission believes that the overall
burden on industry and individuals will be lessened over time by these
proposed changes. The Commission seeks to simplify and streamline its
requirements to reduce the burden on respondents including
utilities,3 and/or persons seeking the following: Obtaining
Commission certification or filing a notice of the qualifying status of
their cogeneration facilities and small power producers; obtaining
Commission approval to issue securities or assume obligations or
liabilities; responding to the Commission's audits of their financial
records; filing in response to the assessment of Commission's annual
charges; submitting contingency plans in preparation of energy
shortages.
\3\As used in reference to the part 34 regulations, the term
``utility'' means public utility, licensee and other entities
subject to the provisions of the FPA.
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The current public reporting burden for these information
collections is estimated to average the following number of hours per
response: FERC-516 976 hours for the 234 respondents that complete a
filing; FERC-523 120 hours for the 60 respondents that complete a
filing; FERC-525 193.25 hours per response for the 83 respondents that
respond to audit review; FERC Form 556 6.2 hours for 332 respondents
that complete an application for certification; FERC-582 4 hours for
179 respondents who prepare and submit remuneration for annual charges
assessed on them by the Commission; and FERC-585 76 hours per response
for average of 6 respondents who annually have submitted changes to
contingency plans (out of the 110 utilities with plans on file). These
estimates include the time for reviewing instructions, searching
existing data sources, gathering and maintaining the data needed, and
completing and reviewing the collection of information.
The changes in Part 34 (FERC-523) will reduce the reporting burden
by 10 hours per filing. The changes in Part 35 (FERC-516) will increase
the reporting burden by 0.1 hours per filing. The changes in Part 292
(FERC-556) will increase the reporting burden by 0.77 hours per filing
for notices of self-certification. However, these changes will reduce
the reporting burden for applications for Commission certification by
2.5 hours per filing. This reflects a reduction in the amount of
analysis to determine whether the facility is a qualifying facility.
The results from the changes in Parts 294 (FERC-585) and 382 (FERC-582)
on the reporting burden are difficult to quantify, but should, over
time, result in a reduction of the reporting burden. The changes in
Part 41 (FERC-525) will not affect the reporting burden.
With respect to the utilities and persons filing information under
FERC-523, the Commission believes that there will be an average burden
decrease due to the elimination of several requirements and increases
in the thresholds for the reporting of information to meet other
requirements. For the additional information that will be required
there should be a minimal burden increase as a result, because much of
the information is already collected by industry in other contexts. The
final rule simplifies the provisions for the issuance of short-term
notes and drafts with maturities of a year or less and deletes an
after-the fact filing requirement. Further, the final rule simplifies
the procedures for the placement of securities thereby streamlining the
regulatory process.
Likewise, the final rule deletes the requirement to include a copy
of the corporate charter or articles of incorporation, because a
statement of corporate purposes will provide the necessary information.
However, the final rule will require the submission of a Statement of
Cash Flows and Interest Coverage containing data on an actual basis for
the same twelve-month period. This information is to be submitted in a
format already prescribed in FERC Form No. 1. The Commission has
[[Page 4833]] instituted this requirement to facilitate the preparation
of financial statements to be submitted as part of the application
because the utilities already prepare quarterly financial statements
and may use such statements as the basis for the information required
to be submitted. The use of the FERC Form No. 1 format will relieve
utilities of the necessity of compiling data in a format that has
limited applicability.
For the information to be filed in Part 35 and collected under the
heading FERC-516, the Commission will require more information than is
currently required on small rate increases for requirements services.
However, the Commission believes that the additional information will
allow for more efficient processing of applications and, by reducing or
eliminating the need for extensive discovery, eliminate protracted
proceedings. The final rule creates a new abbreviated filing option for
small increases in rates for non-coordination, firm power and
transmission services.
Concerning FERC-525, the final rule modifies shortened procedures
for hearings on a utility's accounts, records and memoranda. The
Commission seeks to reduce the amount of litigation, particularly the
number of hearings when the material facts are not in dispute.
The Commission estimates that the public reporting burden for the
other filing requirements under this proposed final rule will reduce
the existing reporting burden. The requirements for the certification
of small power production and cogeneration facilities as qualifying
facilities under Part 292 of the regulations has been revised and
clarified to reflect changing industry conditions and the Commission's
experience with the qualifying facilities program. In particular, the
Commission intends to act within 90 days on the filing of an
application for certification, or within 90 days of the filing of the
supplement or amendment to the application. This will allow the
application process to be conducted in a timely fashion and with some
certainty to the applicant as to when the Commission deems an
application complete.
In the NOPR, the Commission proposed a standardized application
form, FERC Form 556, to facilitate successful applications for
Commission certification of qualifying status. Form 556 allows
cogenerators and small power producers to report the specific
characteristics of their facilities and provides a step-by-step
application of pertinent regulations to their facilities. To provide
greater assurance to lenders, electric utilities and state regulatory
institutions, the final rule also adopts the use of the FERC Form 556
information requirement format for notices of self-certification.
Through the use of Form 556, the self-certification process will be
similar to the Commission certification process, for it will
incorporate sufficient substantive information. But the notice of self-
certification will remain a simple procedure that is both quick and
economical. There will be no Commission review or filing fee, and the
process should promote discussions between the applicants, electric
utilities and affected regulatory commissions to resolve any problems.
To make Form 556 easier to use, the Commission is eliminating
redundancies and, wherever possible, cross-referencing items to related
sections of the Commission's regulations or stating the underlying
Federal Power Act (FPA) or Commission requirement.
In the proposed rule, the Commission also sought to make it easier
to determine the energy sources that certain qualifying small power
production facilities may use. To make it easier to certify a
qualifying facility, the Commission also proposed to list specific
energy sources that it had previously approved for treatment as waste.
In the final rule, the Commission publishes a list of waste energy
inputs already approved by the Commission. In addition, the Commission
is also streamlining its waste determination process for those energy
inputs that do not appear on the list by changing its approach to
require that the proposed waste fuel source only have little or no
commercial value.
In its changes to Part 382 of the regulations concerning the
submission of annual charges and the information collected under FERC-
582, the final rule clarifies the Commission's requirements by making
the calculation of annual charges consistent with the classification of
transaction volumes as reported on the FERC Form 1.
For the information collected under FERC-585 under Part 294 of the
Commission's regulations, the final rule provides a public utility with
the option of not separately reporting its contingency plans if it
already includes certain provisions in its wholesale rate schedules.
Otherwise, the public utility must file a brief statement, summarizing
its contingency plans. In the event the public utilities avail
themselves of this option, it would reduce the number of annual
respondents and total burden.
Comments regarding these burden estimates or any other aspects of
these collections of information, including suggestions for reducing
the burden, can be sent to the Federal Energy Regulatory Commission,
941 North Capitol Street, N.E. Washington, D.C. 20426 [Attention:
Michael Miller, Information Services Division, (202) 208-1415]; and to
the Office of Information and Regulatory Affairs, Office of Management
and Budget [Attention: Desk Officer for Federal Energy Regulatory
Commission], FAX: (202) 395-5167.
III. Discussion
For the reasons discussed below, the Commission hereby deletes or
revises the following regulations:
A. Part 2--General Policy and Interpretations: Section 2.4(d)--Initial
Rate Schedules
The Commission noted in the NOPR that Sec. 2.4(d) provides that an
initial rate schedule can be suspended and an interim rate established,
and that both can be made subject to refund. However, the United States
Court of Appeals for the District of Columbia Circuit has held that the
Commission does not have authority to suspend initial rate
filings.4 Accordingly, in the NOPR the Commission proposed to
delete this provision from the regulations. Only Southern Companies
commented on this proposed change, and they agree that the deletion of
the provision is appropriate.5 For the reasons given in the NOPR,
and described above, the final rule will delete this provision from the
Commission's regulations.
\4\Middle South Energy, Inc. v. FERC, 747 F.2d 763 (D.C. Cir.
1984).
\5\Southern Companies also disagrees with the Commission's
interpretation of what constitutes an initial rate; however, that
issue is beyond the scope of this proceeding.
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B. Part 34--Application for Authorization of the Issuance of Securities
or the Assumption of Liabilities
1. Section 34.1(c)(1)--Exemptions if State Regulates Security Prior to
Issuance
Under sections 19, 20 and 204 of the FPA,6 utilities,
licensees, and certain other entities are required to obtain Commission
authorization to issue securities or to assume any obligation or
liability with respect to the securities of another person.7 The
NOPR proposed [[Page 4834]] revising Sec. 34.1(c)(1) by clarifying that
section. No one commented on this proposed change; we will incorporate
the proposed change in the final rule to make it clear that if an
agency of a state in which a utility is organized and operating
approves or authorizes, in writing, the issuance of securities prior to
their issuance, the utility is exempt from the provisions of sections
19, 20 and 204 of the FPA and the regulations under 18 CFR part 34 with
respect to the issuance of such securities.
\6\16 U.S.C. 812, 813, 824c.
\7\There are certain exceptions to this requirement. Under
section 204(e) of the FPA, a public utility does not require
Commission authorization to issue, renew, or assume debt with a
maturity date of not more than one year, if the debt, together with
all of the other debt having a maturity of one year or less that the
utility has then outstanding, does not exceed five percent of the
par value of the utility's securities then outstanding.
Under section 204(f) of the FPA, a public utility does not
require Commission authorization to issue securities or assume debt
if the State commission in which it is organized and operating
regulates the issuance of its securities.
Under section 318 of the FPA, a utility that is subject to the
requirements of the Public Utility Holding Company Act is not
subject to the requirements of the FPA with respect to the issue,
sale, or guarantee of a security, or assumption of obligation or
liability.
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2. Section 34.1(c)(2)--Exemptions for Short-Term Notes or Drafts
The NOPR proposed amending Sec. 34.1(c)(2), which relates to
exempting from the Commission's requirements the issuance or renewal of
short-term notes or drafts, to simplify the provisions and to delete an
unnecessary, after-the-fact filing requirement. The Commission proposed
to revise the language of this regulation to read as follows:
Under section 204(e) of the FPA, the issuance, renewal or
assumption of liability on a note or draft maturing not more than
one year after such issuance, renewal or assumption of liability is
not subject to the provisions of this Part if the note or draft
aggregates, along with all other then-outstanding notes and drafts,
not more than five percent of the:
(A) Par value of the then-outstanding securities of the utility
and,
(B) In the case of no par value securities, the fair market
value of such securities.
Baltimore Gas & Electric, EEI, Gulf States, and Pennsylvania P&L
commented on the proposed change. Baltimore Gas & Electric, EEI and
Gulf States suggest revising the proposed language to make it clear
that the exemption does not apply to notes and drafts with maturities
of more than one year.
We agree with these comments and will amend the text of
Sec. 34.1(c)(2) to avoid any confusion as to the securities to which
the regulations apply.
EEI and Gulf States suggest that the regulations not use the ``par
value'' of the then-outstanding securities in determining the value of
a company's then-outstanding securities because the par value may be
significantly lower than the issue price or current market value of
securities. Pennsylvania P&L also recommends that the Commission
provide a valuation date.
The arguments with regard to the use of par value are not
persuasive. Section 204(e) of the FPA refers to ``par value of the
other securities then outstanding.''8 It is clear from this
language that the statute requires the use of ``par value'' if the
security has a par value. We have no authority to recognize current
market value or issue price as the measure of the amount of securities
``then outstanding'' if there is a par value stated. However, in the
case of securities having no par value, we believe that fair market
value is appropriate.
\8\16 U.S.C. 824c(e).
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As to a specific date for the 5 percent measurement, although the
precise timing of the issuance of securities is wholly within the
purview of utility management, we will clarify the language to indicate
that the 5 percent test would be applied as of the date of the issuance
or renewal of the securities or assumption of the liabilities.
3. Section 34.2--Placement of Securities
The NOPR proposed amending Sec. 34.2, to rename the section and to
allow for the placement of securities by either competitive bid or
negotiated placement. The proposed amendment recognized exemptions from
these requirements, simplified the placement procedures and streamlined
the regulatory process. The Commission proposed to revise the title and
language of this regulation as follows:
Section 34.2--Placement of Securities
(a) Method of issuance. Upon obtaining authorization from the
Commission, utilities may issue securities by either a competitive bid
or negotiated placement, provided that:
(i) Competitive bids are obtained from at least two prospective
dealers, purchasers or underwriters; or
(ii) Negotiated offers are obtained from at least three prospective
dealers, purchasers or underwriters; and
(iii) The utility:
(A) Accepts the bid or offer that provides the utility with the
lowest cost of money for fixed or variable interest or dividend rate
securities, or
(B) Accepts the bid or offer that provides the utility with the
greatest net proceeds for securities with no specified interest or
dividend rates or,
(C) Has filed for and obtained authorization from the Commission to
accept bids or offers other than those specified in (iii)(A) or
(iii)(B) above.
(b) Exemptions. (i) Multiple bids or offers are not required for
the issuance of securities:
(A) To existing holders of securities on a pro rata basis;
(B) When the utility receives an unsolicited proposal to purchase
its securities; or
(C) With maturities of one year or less.
(ii) The utility may request exemption from the multiple bid or
offer rule when the utility believes such an exemption is appropriate,
based on the facts and circumstances of the particular issuance.
(c) Prohibitions. No securities shall be placed with any person
who:
(i) Has performed any service or accepted any fee or compensation
with respect to the proposed issuance of securities; or
(ii) Would be in violation of section 305(a) of the FPA.
Baltimore Gas & Electric suggests that we change Sec. 34.2(b) so
that this section will clearly provide exemptions from the multiple bid
or offer requirements of Sec. 34.2(a). EEI, Gulf States and UtiliCorp
suggest that we include within the exemptions from negotiated bid and
placement requirements particular types of securities (treasury stock
and securities ``backing up'' pollution control debt issued by a third
party, for instance).
These comments have merit, and we will modify the final rule
accordingly. We will not, however, include treasury stock among the
list of exempted securities; we are not persuaded that a blanket
exemption is justified for treasury stock. For all practical purposes,
the issuance of treasury stock is not substantially different from the
issuance of new shares of common stock.
EEI and Gulf States suggest that we delete the prohibition in
Sec. 34.2(c)(1) against accepting bids from or entering into
negotiations with persons that have accepted a fee for services
performed in connection with the proposed issuance of securities. We
reject this recommendation. However, we note that proposed
Sec. 34.2(c)(1) did not include language (which is currently in this
paragraph of our regulations) indicating that it involves services
performed prior to the submission of bids or the beginning of
negotiations. The proposed rule, like the existing rule, should contain
this language. Upon further consideration, the final rule will include
this language in the regulations.
EEI and Gulf States suggest that we codify the Commission's policy
of allowing utilities to issue securities or assume obligations or
liabilities over a two-year period. EEI and Gulf States are correct
that it is the Commission's policy to allow companies to issue
securities at any time within a two-year [[Page 4835]] period, without
any additional authorization from the Commission.9 Our policy
regarding the two-year authorization period is clear and working well.
We do not think that the requested codification is necessary. The
matter is best dealt with through the Commission's authorization
process, leaving the Commission the flexibility to address the facts
and circumstances in the filings on a case-by-case basis and, where
appropriate, to grant authorizations for periods different than the
basic two-year period. Accordingly, we will not adopt the suggestion.
\9\See Montana-Dakota Utilities Company, 21 FERC 62,358 (1982).
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4. Sec. 34.3--Contents of Application for Issuance of Securities
The NOPR proposed amending Sec. 34.3, which governs the contents of
an application to issue securities. No one commented on this aspect of
the proposed rule, and we will adopt the proposed change.
UtiliCorp suggests that an application also include a draft order,
prepared by the applicant. We will reject this suggestion. The
inclusion of a requirement that applications include a draft order will
increase the burden on the applicants without substantially aiding the
Commission in its processing of filings.
5. Sec. 34.4--Required Exhibits
a. Section 34.4(a), Exhibit A. The Commission proposed to delete
the current language in paragraph (a) and to substitute the following:
The applicant must file the statement of corporate purposes from
its articles of incorporation.
The Commission stated that it has found that the information
currently required in paragraph (a) is not necessary for the processing
of a securities application. A statement of corporate purposes will
provide the information necessary without the need for applications to
include the entire corporate charter or articles of incorporation. No
one commented on the proposed change to Exhibit A; we will adopt the
change as proposed.
b. Sections 34.4 (c) and (d), Exhibits C, D and E. The Commission
proposed to delete paragraph (c), and to redesignate paragraphs (d) and
(e) as paragraphs (c) and (d), respectively. The Commission also
proposed to revise newly-designated paragraphs (c) and (d) and to add a
new paragraph (e).
The Commission noted that current paragraph (c) requires a
statement of control over the utility by firms issuing securities or
supplying electrical equipment and that the Commission can obtain this
information from other existing sources.
The NOPR proposed that the newly-designated and revised paragraphs
(c) and (d) would require that a balance sheet and income statement be
submitted for the twelve-month period ending with the most recent
calendar quarter. New paragraph (e) would require the submission of a
four-column Statement of Cash Flows and Interest Coverage, containing
data on an actual basis for the same twelve-month period, and on a pro-
forma basis for each of the next two succeeding 12-month periods.
The Commission proposed these changes to facilitate the preparation
of financial statements to be submitted as part of the application
because the utilities already prepare quarterly financial statements
and may use such statements as the basis for the information required
to be submitted. The Commission expected that the addition of the
statement of cash flows and interest coverage would facilitate the
processing of applications under Part 34.
Baltimore Gas & Electric and Consumers Power suggest that we change
the proposed regulations to allow for the submission, for Exhibits C,
D, and E, of financial statements for periods other than those ending
with the latest calendar quarter, if such statements are the latest
available statements. We agree with this suggestion and will, in large
part, adopt it. We recognize that financial statements other than for
the latest calendar year quarter may be available, and we will revise
the proposed language to require the filing of financial statements for
the most recent 12-month period, provided that the period ended no more
than 4 months prior to the date of the filing of the application.
Consumers Power suggests that we allow utilities to present their
financial statements to us in the format required by the Securities and
Exchange Commission (SEC). We will not adopt this suggestion. The
Commission's information needs are different than the information needs
of the SEC. The use of information prepared in a SEC format presents
problems from a number of perspectives: for instance, the consolidation
of certain majority-owned subsidiaries, the aggregation of detailed
financial information and the use of different reporting standards.
Information reported to the SEC may include the utility and certain
consolidated, majority-owned subsidiary companies. As a result, the
financial statements would include mixtures of financial information on
the regulated utility and the consolidated, majority-owned
subsidiaries, as if it were financial information of the utility. The
Income Statement would not, therefore, present the utility's stand-
alone results of operations. Further, information reported to the SEC
is aggregated in a summary fashion without the detailed financial
information presented on a basis consistent with the classifications in
the Uniform System of Accounts. (For instance, the Commission requires
that accumulated deferred income taxes be classified among four
accounts depending on the type of the deferral; the SEC, however,
allows deferred income taxes to be netted in a single amount.) Another
area of concern is the reliance upon different reporting standards. For
instance, the SEC allows currently maturing long-term debt to be
classified as a current liability; the Commission requires that long-
term debt, regardless of the maturity, to be classified as long-term
debt until retired. We have configured our information formats, which
include FERC Form No. 1, to meet our regulatory responsibilities.
Utilities reporting to us must submit their information to us in a form
more suited to our needs.10 Accordingly, we will continue to
require that utilities prepare the required financial statements
consistent with this Commission's FERC Form No. 1 and Uniform System of
Accounts.
\10\See Electronic Filing of FERC Form No. 1 and Delegation to
Chief Accountant; Notice of Intent to Act and Response to Comments,
59 FR 1687, 1689 (Jan. 12, 1994).
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Baltimore Gas & Electric, Consumers Power, EEI, Pennsylvania P&L,
Gulf States, Texas-New Mexico and UtiliCorp object to the submission of
the proposed projected cash flow statement in Exhibit E. These
commenters assert that these forecasts are unreliable and that the
filing of such information would expose utilities to potential
liability. They also note that the SEC allows but does not require the
filing of projected financial statements. Pennsylvania P&L suggests
that we change proposed Exhibit E by adding a line entitled either
``Interest Coverage'' or ``Times Interest Earned'' to provide a
location for the coverage ratio.
We agree with these comments. We will delete the requirement for
the projected cash flow statement. We will also revise Exhibit E,
Statement of Cash Flows and Interest Coverage, to require the
submission of a Statement of Cash Flows in the form prescribed in the
FERC Form No. 1, followed by the interest coverage calculation as
proposed in the NOPR. Adoption of the [[Page 4836]] FERC Form No. 1
format will relieve utilities of the necessity of compiling data in a
format that has limited applicability. Further, utilities may be able
to use the Statement as included in the FERC Form No. 1, depending upon
the timing of the filings, thus further reducing the burden of
compliance.
The final rule clarifies the interest coverage calculation
worksheet required in Exhibit E by adding a line entitled ``Interest
Coverage'' as suggested and a ``division'' sign at the end of the line
entitled ``Total Interest Expense'' and an ``equals'' sign at the end
of the line entitled ``Income Before Interest and Income Taxes.''
c. Sections 34.4 (g) and (h), Exhibits G and H. The NOPR proposed
to delete paragraphs (g) and (h). The Commission noted that the
information currently required by Sec. 34.4(g) is directed toward
competitively-bid securities placements, which the Commission intends
that its regulations should no longer require. The pre-issuance filing
contemplated by Sec. 34.4(h) will no longer be necessary, since the
Commission intends to authorize applicants to issue securities under
conditions specified under proposed Sec. 34.2. The Commission pointed
out that it will, therefore, only be necessary that applicants provide
the Commission with a report of their securities issuances after the
fact under the provisions of existing Sec. 131.43 and revised
Sec. 131.50.
No one commented on the proposed changes to Exhibits G and H; we
will adopt those changes as proposed.
6. Sec. 34.10--Reports
In the NOPR, the Commission proposed to revise its rules to require
applicants to file reports under Sec. 131.43 and Sec. 131.50 no later
than 30 days after the sale or placement of long-term debt or equity
securities or the entry into guarantees or assumptions of liabilities.
The Commission has received no comments regarding this proposal and
will adopt it unchanged.
7. Sec. 34.11--Unopposed Applications to Issue Securities and/or Assume
Liabilities
In the NOPR, the Commission proposed to revise part 34 by adding a
new Sec. 34.11 to provide for authorization of unopposed applications
for authorization of the issuance of securities or assumption of
liabilities upon the terms and conditions and for the purposes set
forth in the application unless, within 90 days after the date of the
application, the Commission issues an order delaying the effectiveness
of the transaction, setting the matter for hearing or taking other
action. The NOPR proposed the rule in order to eliminate needless
regulation and aid the processing of unopposed applications, while
preserving the right of interested parties to oppose the applications.
Baltimore Gas & Electric, Consumers Power, Detroit Edison, EEI,
Gulf States and Utilicorp commented on the proposed 90-day period for
automatic approval of security issuances (i.e., without Commission
action). Several commenters11 suggested different periods--30, 45
or 60 days after the date of the application, or 15 days after
publication of the notice. Utilicorp noted that the proposal more than
doubled the time presently taken to process most applications.
Utilicorp also noted that, if the Commission adopts an automatic
mechanism for the processing of these applications, utilities will have
to obtain written assurances for their lenders that the Commission has
a ``self executing'' rule, provide copies of the rule to the lenders
and then provide a ``date stamped'' copy of the filing made with the
Commission. The utilities would then have to prove that no one had
protested their applications and that the Commission did not issue an
order within the 90-day period that would preclude the automatic
issuance.
\11\The commenters are Baltimore Gas & Electric, Consumers
Power, Detroit Edison, EEI, Gulf States.
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Utilicorp's comments concerning an automatic approval mechanism are
well taken. Utilities and their lenders rely on the certainty that a
Commission order confers. The proposed automatic approval would
introduce an element of uncertainty into the approval process and place
a greater burden upon utilities to provide adequate assurances to their
lenders. At this juncture, we believe the uncertainty and the
concomitant burden upon lenders and utilities outweigh the time and
resources that the Commission would save in preparing and issuing
orders. Accordingly, we will not adopt the proposed automatic approval
mechanism.
8. Part 131--Forms
Section 131.50. The NOPR proposed to rename Sec. 131.50 to read
``Report of proposals received.'' The NOPR also proposed to delete the
current language of Sec. 131.50 and to revise the language of
Sec. 131.50 to read as follows:
Section 131.50 Report of Proposals Received. No later than 30 days
after the sale or placement of long-term debt or equity securities or
the entry into guarantees or assumptions of liabilities (collectively
referred to as ``placement'') pursuant to authority granted under part
34, the applicant shall file a summary of each proposal received for
the placement. Each proposal accepted shall be indicated. The
information to be filed shall include:
(a) Par or stated value of securities;
(b) Number of units (shares of stock, number of bonds) issued;
(c) Total dollar value of the issue;
(d) Life of the securities, including maximum life and average life
of sinking fund issues;
(e) Dividend or interest rate;
(f) Call provisions;
(g) Sinking fund provisions;
(h) Offering price;
(i) Discount or premium;
(j) Commission or underwriter's spread;
(k) Net proceeds to company for each unit of security and for the
total issue;
(l) Net cost to the company for securities with a stated interest
or dividend rate.
The revision of this regulation represents a reclassification of
information previously reported as Exhibit H under Sec. 34.4. The NOPR
noted that this information is necessary to analyze compliance with the
Commission's regulations and orders authorizing placement. No one
commented on this proposed revision, and we will adopt it.
C. Part 35--Filing of Rate Schedules
1. Sections 35.13(a)(2)(i) (A) and (B)--Rate Increases of Less Than
$200,000, Regardless of Customer Consent, and Rate Increases Below
$1,000,000, with Customer Consent
The Proposed Rule. The NOPR proposed revising the abbreviated
filing requirements of Secs. 35.13(a)(2)(i)(A) and (B), involving
certain rate increases of less than $200,000, regardless of customer
consent, and rate increases below $1,000,000, with customer consent.
The revised sections would require public utilities filing relatively
small rate increases for requirements services to submit more
information than the regulations currently require. This new
information would include, inter alia, a cost of service analysis for
an historical test year, a complete derivation of all allocation
factors and special assignments, and a complete calculation of revenues
for the test period and for the first twelve months after the proposed
effective date. The Commission's preliminary view was that the proposed
filing requirements would allow the Commission to process these
applications more efficiently and would eliminate unnecessarily
protracted proceedings (including, e.g., [[Page 4837]] extensive
discovery in proceedings set for trial-type hearing) that are
attributable solely to the fact that the existing filing requirements
for these applications require insufficient data from which to
determine whether the proposed rates are cost-justified.
The NOPR also proposed to afford filing utilities an opportunity to
file additional cost data and supporting testimony in the event that
the Commission suspends the proposed rate increase and orders a
hearing.
The NOPR retained the existing abbreviated filing requirements for
short-term and non-firm coordination sales rates in
Sec. 35.13(a)(2)(ii).
The NOPR also proposed to revise Sec. 35.13(h)(24) to require that
companies submit Statement AX (other recent and pending rate changes)
only if the proposed rate design tracks retail rates. This proposed
change was intended to streamline the public utility's rate
presentation and expedite Commission review by eliminating submission
of information not generally needed for Commission review.
Comments: Several commenters12 express concern that the
proposed regulations will increase the time and costs associated with
preparing rate filings, and thereby discourage utilities from entering
into small transactions for the sale or transmission of power, which
will in turn result in a less competitive bulk power market.
\12\Arizona Public Service, Atlantic Electric, Baltimore Gas &
Electric, Delmarva, LILCO, NEP, Pennsylvania P&L, Southern
Companies.
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Many commenters also express concerns or uncertainty about the
number and variety of filings subject to the proposed regulations.\13\
The commenters recommend that the Commission narrowly define the class
of rate filings subjects to the proposed rule to include only those
filings for which the Commission must have additional information to
properly and expeditiously perform its duties under the FPA.\14\
\13\E.g., Delmarva, Detroit Edison, NEP.
\14\Some commenters infer that a large number and variety of
filings would be subject to the new rules. EEI asserts that the
changed regulations would greatly increase the regulatory burden of
all applicants, while saving time and effort in only a small number
of cases. Some commenters conclude that the Commission proposed to
modify the abbreviated filing requirements for coordination rates.
Commenters such as NEP and Southern Companies focus on the increased
filing requirements for small rate increases.
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Other commenters express the view that the new filing requirements
are vague.15 EEI recommends that the regulations state with
greater specificity the information that public utilities must file.
\15\EEI and several other commenters infer that the Commission
is now requiring companies to submit Statements AA through BM.
Detroit Edison argues that it would be burdensome and expensive to
calculate thirteen-month average plant balances, and Southern
Companies interprets the proposed regulations to require the use of
end-of-year balances instead of thirteen-month averages.
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With respect to filings based on retail rate decisions, NYSEG
asserts that it is unclear what calculations would have to be provided
to show how all retail rate treatments are factored into the cost of
service. If the Commission changes the abbreviated filing requirements,
NYSEG requests that the Commission clarify its specific requirements
regarding information to be provided for filings based on retail rates.
The Commission's Response: We agree with the commenters that the
Commission should attempt to minimize regulatory burdens and improve
the flexibility accorded public utilities covered by its rules.
However, contrary to the statements of many commenters, the proposed
regulations do not change the abbreviated filing requirements for most
proposed rate increases. Neither do the proposed regulations require
companies to file comprehensive cost of service statements (Statements
AA-BM). Rather, the proposed regulations require only that a company
that files a small rate increase for non-coordination services support
the calculations it makes, explain why it makes those calculations, and
show the revenue impact of the proposed rates on its customers.
Based on concerns expressed, however, we will make several changes
to the proposed regulations to more clearly define the class of filings
subject to the rule and the information that must be submitted in order
for the Commission to perform its preliminary analyses of small, non-
coordination filings. Finally, the Commission reiterates that any
company may request waiver of the filing requirements for good cause.
Filings Covered by the Rule: Many of the commenters express
uncertainty concerning the types of rate increase filings that are
affected by the proposed regulations.
We agree with the commenters that the Commission should more
clearly define the class of filings subject to the new rule. The
Commission's intent is to create a new, abbreviated filing option for
small increases in rates for non-coordination, firm power and
transmission services, particularly small requirements rate increase
filings that are based on a fully distributed cost of service analysis
(sometimes known as a ``net plant'' cost of service).16 The
Commission will revise the regulations to identify the class of filings
covered by new Sec. 35.13(a)(2)(i) as power or transmission services
that are: (1) not covered by the filing requirements of
Sec. 35.13(a)(2)(ii); and (2) for which the rate increase being sought
is less than $200,000 (without customer consent) or less than $1
million (with customer consent).
\16\In most but not all cases, rates developed under a net plant
approach are customer-specific, in that costs are first allocated to
each wholesale customer group based on the demand and energy loads
it imposes on the company, after which customer group-specific rates
are developed based on the customer group's projected billing
determinants. See generally Southern Company Services, Inc., 61 FERC
61,339 at 62,337-38 (1992), reh'g denied, 63 FERC 61,217 (1993),
appeal pending, No. 93-1165 (D.C. Cir. filed Feb. 11, 1993).
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We will also change our regulations to permit utilities to file
under Sec. 35.13(a)(2)(ii) rate increases, without regard to the size
of the proposed increase, for firm coordination and interchange
services.
Filing Requirements: EEI maintains that if the Commission decides
to adopt new filing requirements for small rate increases, then greater
clarity and specificity in the filing requirements is needed to avoid
confusion and errors in responding to the changes. We agree. However,
we disagree with EEI that the Commission should or must explain, at the
level of detail used in the current Sec. 35.13(h), what is expected.
Such specificity would unduly increase the regulatory burden on most
utilities that file under this subparagraph. To meet EEI's concerns and
those of other commenters, we will make the following changes.
First, the final rule provides that filing utilities should submit
cost of service, allocation, revenue, fuel clause and rate design data
that are ``consistent with the requirements'' of other paragraphs of
part 35 that require similar information. The final rule also requires
filing utilities to explain in narrative form how and why various
calculations are made to develop the proposed rates.17
\17\Narrative statements should address the rate design and
allocation factors employed in the filing, explain all pro forma
adjustments to test period data, and describe specific costs or rate
components that are drawn from retail rate decisions.
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Second, the NOPR proposed to make Sec. 35.13(a)(2)(i) mandatory
rather than optional, thereby precluding utilities from electing to
file comprehensive Period I statements, as allowed under
Sec. 35.13(a)(1). The revised regulation makes clear that the filing
utility may elect to file under either paragraph.
Third, the revised regulation clarifies the two-stage filing
process proposed in the NOPR. A utility that elects to file
[[Page 4838]] under revised Sec. 35.13(a)(2)(i) need not submit a
comprehensive filing when it makes its initial submittal, but it must
support all calculations that are not derived directly from Form 1, and
explain how it has functionalized, classified and allocated its costs.
Should the Commission set the proposed increase for hearing, the filing
utility will be afforded a reasonable opportunity to file testimony and
exhibits to fully support the reasonableness of its proposed rates.
This approach minimizes regulatory burdens while allowing the applicant
to balance the expense of preparing a comprehensive filing versus the
risk of not initially sustaining its burden of proof with an
abbreviated filing.
Fourth, the NOPR used the terms ``historical test year'' and ``test
period'' interchangeably and without reference to the definition of
Period I applicable to other paragraphs of Sec. 35.13. The revised
regulation adds a definition for ``Test Period,'' deletes references to
the ``historical test year'' and provides that utilities that file
under this subparagraph must use as the test period the most recent
calendar year for which actual data are available. Utilities that elect
to use a non-calendar year test period must file rate increases under
Sec. 35.13(d).
The Commission notes that proposed Sec. 35.13(a)(2)(i)
inadvertently eliminated the requirement that utilities submit rate
design information and the general information now required for all
abbreviated rate change filings. The final rule requires submission of
the general information specified in paragraphs (b), (c)(2) and (c)(3)
of Sec. 35.13 and in Sec. 35.12(b)(2), while the information required
by Sec. 35.13(c)(1), Sec. 35.12(b)(5) and Sec. 35.13(h)(37) is elicited
as part of the revenue data, allocation data and rate design
information requirements.
The final rule also requires that filings under Secs. 35.13(a)(2)
(i) and (ii) comply with Commission precedent and policy.
2. Other Changes to Sec. 35.13
The Commission will eliminate Sec. 35.13(a)(2)(ii)(B) of the
proposed regulations\18\ and make corresponding editorial changes to
Sec. 35.13(a)(2)(iii)(A). Section 35.13(a)(2)(ii)(B) cross-references
rate decrease filings made under Sec. 35.27 pursuant to the 1987
reduction in federal corporate income tax rates under the Tax Reform
Act of 1986. However, Sec. 35.27 was eliminated in a previous
rulemaking.\19\ Therefore, this section is now superfluous.
\18\It is Sec. 35.13(a)(2)(iii)(B) in the proposed regulations.
\19\Eliminating Unnecessary Regulation, Order No. 541, 57 FR
21730 (May 22, 1992), III FERC Stats. & Regs. 30,943 (1992).
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A cross-reference to Sec. 35.13(a)(2)(ii) has been added to
Sec. 35.13(d)(1), mirroring the existing reference to subparagraph
(a)(2)(i). In addition, existing paragraph (d)(1), as printed in the
1994 Code of Federal Regulations, omits the word ``this'' prior to
``section'' as shown by brackets in the text below:
(d) Cost of service information--(1) Filing of Period I data. Any
utility that is required under Section (a)(1) of [ ] section to submit
cost of service information * * * The final rule corrects these
omissions.
D. Part 41--Accounts, Records and Memoranda: Sections 41.3 and 41.7
In the NOPR the Commission proposed to change its regulations to
provide that if a utility consents to a matter's being handled under
the shortened procedure under Sec. 41.3, that utility has waived any
right to subsequently request a hearing under Sec. 41.7 and may not
later request such a hearing. The Commission also re-stated its policy
that it will not assign proceedings for hearings when there are no
material facts in dispute.
Baltimore Gas & Electric, Duke Power, EEI and Southern Companies
commented on this proposed change. Baltimore Gas & Electric recognizes
that the proposed change would eliminate redundancy in the Commission's
regulations and supports the proposed change. Duke Power and EEI argue
that, rather than streamlining the Commission's procedures, the
proposed change will encourage utilities to contest more issues under
Sec. 41.7 in order to preserve the right to a full hearing.
We disagree. Persons subject to the Commission's accounting
requirements have the right of election under the Commission's
procedures and, under Sec. 41.7, have a right to seek a hearing on any
issue that they wish to contest. The proposed change in the
Commission's regulations would merely prevent such persons from
changing their minds in mid-proceeding and deciding to contest an issue
that they had previously recognized involved no disputed issue of
material fact. We do not think that requiring persons to make their
election of procedure at the outset of a proceeding will necessarily
lead to more hearings. Rather, it will more likely reduce the number of
hearings, because public utilities will no longer have the election to
bring to hearing an issue that they had previously considered not to be
worthy of a hearing.
Southern Companies challenges the Commission's reiteration of its
policy that it will not assign proceedings for hearings where no
material facts are in dispute. Southern Companies fears that the
Commission may use this policy to deprive a person of the due process
right to a hearing. Southern Companies' concern is misplaced. The
proposed change will not deprive anyone of the right to a trial-type
evidentiary hearing when such a hearing is warranted. However, as
Southern Companies recognizes, a trial-type evidentiary hearing is not
necessary if no material facts are in dispute.\20\
\20\See, e.g., General Motors Corp. v. FERC, 656 F.2d 791 (D.C.
Cir. 1981); Citizens for Allegan County, Inc. v. Federal Power
Commission, 414 F.2d 1125 (D.C. Cir. 1969).
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E. Proposed Procedural Modifications and Revised Definitions Under Part
292--Regulations Under Sections 201 and 210 of the Public Utility
Regulatory Policies Act of 1978 (PURPA)\21\ With Regard to Small Power
Production and Cogeneration
\21\16 U.S.C. 796(17)-(23), 824a-3.
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The Commission is revising and clarifying its procedural and
technical rules to reflect its experience with the qualifying
facilities (QF) program. By adopting these clarifying changes, the
Commission is satisfying its continuing PURPA obligation to review its
policies and rules that encourage cogeneration and small power
production, energy conservation, efficient use of facilities and
resources by electric utilities and equitable rates for electric
consumers.
1. Administration of the 90-Day Certification Period
When an applicant files an application for Commission certification
of qualifying status with the Secretary under Sec. 292.207 of the
Commission's regulations, Sec. 292.207(b)(5) provides that within 90
days of the filing of an application the Commission will issue an order
granting or denying the application, setting the matter for hearing, or
``tolling'' the time for issuance of an order. In the NOPR, the
Commission noted some confusion on the part of many applicants as to
when the 90-day period starts. The Commission proposed to codify its
practice by revising Sec. 292.207(b)(3)(ii) to provide that the 90-day
period for issuance of an order granting or denying an application for
Commission certification of the qualifying status of a facility does
not begin until an applicant has submitted all the information
[[Page 4839]] necessary to complete the application, along with the
appropriate filing fee.
Comments: Tenaska contends that the proposed clarification
perpetuates uncertainty, since there is no provision to notify an
applicant when the Commission considers the filing complete. Electric
Generation Association points out that, without an explicitly announced
beginning point for each application, no party can know when, if ever,
the 90-day period will expire. It suggests that setting a clear date
for determining when the Commission deems an application complete would
be consistent with the 60-day ``deficiency'' notification process for
electric rate filings under Sec. 35.2(c) of the Commission's
regulations. Independent Energy Producers suggests that the Commission
establish a maximum period for staff to send to an applicant any
questions regarding the application.\22\
\22\Some commenters advocate an initial period ending 10 to 30
days after the filing of the application, after which the
application would be treated as complete and no notification of a
deficiency could be made. Some commenters further suggest that the
number of deficiency inquiries be limited to two. NEP also suggests
that a copy of the deficiency letter be served on the utilities with
which the QF is expected to deal.
American Cogen, American Forest and Paper, American Iron and
Steel, Electric Generation Association, Independent Energy
Producers, SDG&E, Tenaska, and Texaco express concern that repeated
requests for additional information by the Commission's staff have
the effect of extending the process indefinitely. These commenters
suggest that the Commission treat an application for Commission
certification as automatically complete when a completed Form 556
has been filed and/or the application is otherwise literally
responsive to the Commission's regulations.
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SDG&E suggests that the Commission's Federal Register notice of
each supplemental filing that responds to a staff inquiry identify the
project, its location, when the Commission deems the application
complete, when the Commission will issue a decision or tolling order on
the application, or when the Commission will deem the application
granted by virtue of the passage of time.\23\
\23\Atlantic Electric and EEI want the Commission to issue
notices of all responses to deficiency inquiries. Electric
Generation Association also proposes that the Commission delete the
reference to the Commission's tolling the time for issuance of an
order. Electric Generation Association contends that tolling has
caused unnecessary delay in the processing of applications and that
the only basis for tolling the operation of the 90-day period should
be an incomplete application. As noted above, in this regard,
proposed Sec. 292.207(b)(3)(i) merely corresponds to the
Commission's existing 90-day action regulation at
Sec. 292.207(b)(5). Electric Generation Association's tolling policy
proposal is outside the scope of the instant proceeding.
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Commission Response: While the Commission intends to process a
pending application for Commission certification of qualifying status
as rapidly as possible, the Commission will not further restrict its
ability to evaluate such applications by providing a maximum period for
considering the sufficiency of the application.\24\ Likewise, the
Commission will not adopt the practice of formally notifying an
applicant with respect to deficiencies by a date certain;\25\ nor will
the Commission indicate by notice in the Federal Register when a filing
is complete.\26\
\24\This is also consistent with the Commission's policy
applicable to electric rate filings of not providing a maximum
period (within the 60-day statutory review period) for considering
the sufficiency of the application. Regarding the 60-day statutory
review period, see Duke Power Company, 57 FERC 61,215 at 61,713
(1991); see also Southern Company Services, Inc., 60 FERC 61,297 at
61,065-66 & n.12 (1992), aff'd sub nom. Alabama Power Company v.
FERC, 22 F.3d 270 (11th Cir. 1994) (any amendment or supplemental
filing establishes a new filing date for the filing in question).
The steps the Commission has taken elsewhere in this proceeding
to improve the QF application process, through clarifications and
the establishment of step-by-step procedures to follow in Form 556,
should result in more complete applications being filed in the first
place. However, in the end, the speed with which the Commission
processes an application depends, in addition to staff availability,
primarily on the quality of the submittal, its complexity, its
novelty, whether it is opposed, and the response time of the
applicant to any information inquiries.
\25\In uncontested proceedings, staff informally requests
additional information by telephone in order to speed the processing
of an application. In contested applications, staff must resort to
formal deficiency letters to obtain additional information.
\26\The Commission will continue to notice responses to
deficiencies in the Federal Register.
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However, the Commission will amend its regulations to provide that
the Commission will act within 90 days of the filing of the
application, or, if the application is supplemented or amended, within
90 days of the filing of the supplement or amendment. Commission action
may include finding the application deficient, granting or denying the
application, or tolling the time for action.
2. Improvements to the Self-Certification Process
In the NOPR, the Commission proposed to amend Sec. 292.207(a)(1) to
require that notices of self-certification be in the form of an
affidavit signed by the facility's owner, operator or authorized
representative. The Commission's intention was to provide interested
financing institutions, electric utilities and state regulatory
authorities with greater assurance that a self-certified cogeneration
or small power production facility conforms to the Commission's
ownership and technical criteria. The NOPR also proposed that a self-
certifying facility provide a copy of its notice of self-certification
to the utility with which the cogenerator or small power producer
intends to deal. These proposed revisions were intended to reduce
reliance on the alternative process through which the cogenerator or
small power producer submits an application for Commission
certification accompanied by a filing fee.
Comments: Southern Companies maintains that, in order for lenders
and investors to derive comfort from the affidavit requirement, the
Commission must ensure that a notice of self-certification with an
affidavit is accurate and reliable.\27\ SDG&E suggests that the reason
that more facilities have not taken advantage of the self-certification
process is that the process is inadequate.\28\ SDG&E does not think
that an affidavit is sufficient to provide the requisite level of
comfort to lenders and to utilities with which the self-certifying
facilities intend to interact.\29\ SDG&E points out that even under the
proposed self-certification procedure, there is no substantive
information requirement, no guarantee that submittals will contain the
minimum information required, and no expectation that any party or the
Commission will ensure that a self-certified facility meets the QF
criteria.\30\
\27\Among other comments, SDG&E asserts that it is reasonable,
in the absence of Commission review, to require greater specificity
as to what the affidavit and notice of self-certification should
pertain to. SDG&E also suggests that an affidavit requirement
implies that a prior self-certification submitted without an
affidavit is of dubious legal value. Electric Generation Association
maintains that there is no reason to require an affidavit, since
even a Commission determination on qualifying status is considered
void if it is based on erroneous facts. Electric Generation
Association further contends that the current regulations do not
suggest that a notice of self-certification signed by an officer or
partner of the developer is less trustworthy or less legally binding
than a Commission certification of qualifying status. NEP observes
that an affidavit will underscore the importance to the owner or
operator of accurately describing its facility. The CPUC suggests
that, in fairness to all interested parties, including the signatory
to the affidavit, the Commission should set forth more clearly the
contents of the notice of self-certification.
\28\Ridgewood observes that it is disputes about the
interpretation of the Commission's regulations by lenders, state
commissions and utilities that have prevented greater reliance on
the existing self-certification process.
\29\Florida P&L observes that a utility, before seriously
undertaking any negotiations for integrating a QF into the utility's
system, needs something more concrete than a notice of self-
certification with an affidavit. Niagara Mohawk proposes that a
notice of self-certification describe how a facility meets the QF
criteria.
\30\Southern California Edison notes that the affidavit does not
provide ongoing assurance that a facility will continue to meet the
QF criteria. In this regard, Florida P&L suggests that the
Commission adopt a standardized annual or biennial affidavit
reporting requirement. Niagara Mohawk also proposes that the
Commission allow a utility to periodically inspect the QF's
operations. These monitoring proposals are outside the scope of the
instant rulemaking proceeding. [[Page 4840]]
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Similarly, Curran, Corbett & Stiles submits that, since the
proposed self-certification process will continue to involve nothing
more than file-stamping a submittal, lenders, government agencies and
utilities will continue to demand proof of qualifying status for loan
approvals and other crucial transactions, and cogenerators and small
power producers will continue to apply for Commission
certification.\31\
\31\American Forest and Paper maintains that the affected
utility also will likely continue to want a Commission
certification. Tenaska predicts that lenders will not rely on an
affidavit, as long as the alternative, Commission certification
process is available. AGA and Utilicorp state that lenders will not
assume the risk to finance QF projects that do not undergo a full
Commission certification process.
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SDG&E suggests that the self-certification process would be more
meaningful if it were more like the full Commission certification
process. SDG&E urges the Commission to require that a notice of self-
certification incorporate the Form 556 information as the Commission
has proposed for applications for Commission certification.32
SDG&E also asks the Commission to amend Sec. 292.207 to provide that,
unless a person files an objection with the Commission within 90 days,
the utility must meet its QF obligations under Sec. 292.303.\33\
\32\Atlantic Electric and EEI also favor a requirement to
include Form 556 information. SDG&E contends that, contrary to what
the Commission had anticipated when it issued its existing QF
regulations, there has not always been a free flow of information
between utilities and potential QFs.
SDG&E also maintains that a utility which does not believe that
a self-certified facility is qualified does not have to purchase the
electrical output from the facility.
\33\Curran, Corbett & Stiles asks the Commission to state that a
notice of self-certification constitutes prima facie evidence that
the facility is a QF. Curran, Corbett & Stiles also suggests that
the Commission either indicate that the application conforms to the
requirements of Sec. 292.203 or, within a certain time period, issue
a specific finding to the contrary. American Cogen and Electrical
Generation Association suggest that the Commission reinforce the
self-certification process by stating in the preamble to this rule
and/or in Sec. 292.207 that self-certification has the equivalent
legal effect of a Commission certification. Independent Energy
Producers suggests that the Commission delineate what situations
call for Commission certification, in order to convince lenders to
rely more on self-certification.
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Arizona Public Service and SDG&E suggest that the Commission
require self-certifying cogenerators and small power producers to
provide copies of their submittals to electric utilities (a) with which
they intend to interconnect for the purpose of transmitting and selling
electric power; and (b) from which they intend to purchase
supplementary, standby, backup and maintenance power.\34\ Arizona
Public Service also suggests that self-certifying cogeneration and
small power producers specify their anticipated service needs so that
utilities may better plan and prepare their local and system
facilities, and obtain any necessary regulatory approvals.\35\
\34\Florida P&L notes that the Commission's current regulations
at Sec. 292.207(c)(1) require that a cogenerator or small power
producer that chooses to self-certify must provide the electric
utility purchaser with at least 90 days' advance notice of the
transaction.
\35\Detroit Edison suggests that a notice of self-certification
include a notice, suitable for publication in the Federal Register,
that sets out the pertinent data regarding the application. Detroit
Edison submits that publication of such a notice would allow
interested parties to bring errors in the application to the
Commission's attention. Detroit Edison also suggests that the
applicant provide the appropriate state commission and the affected
utility with a copy of any notice of self-certification, or
application for Commission certification or recertification filed
with the Commission. Similarly, Atlantic Electric, Arizona Public
Service, EEI, Florida P&L, LILCO, NEP and SDG&E suggest that either
the Commission or the applicant apprise affected parties (including
the regulatory commission of each state where the QF and the
affected utility is located) of any QF submittal or any Commission
deficiency letter, through Federal Register notice and/or by sending
each a copy of the document.
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Commission Response: As the commenters observe, some lenders,
regulators and utilities appear to have been unwilling to rely on the
self-certification process because they did not think that the process
provided them with sufficient information to independently verify the
qualifying status of the subject facility. Many of the commenters have
argued that simply adding an affidavit to the notice of self-
certification would not instill enough confidence to make the self-
certification process more authoritative.
The Commission continues to believe that self-certification should
be retained as an option; it is unnecessary to conduct a full review of
each facility, even in instances where outside lenders and investors
will be involved. However, in consideration of the various comments,
and in recognition of the various other clarifications being made in
this final rule, the Commission will not adopt the proposed affidavit
requirement. Instead, the Commission will modify the self-certification
process to: (a) Incorporate the Form 556 information requirement that
the Commission is also adopting for applications for Commission
certification; and (b) require that cogenerators and small power
producers provide copies of the notice of self-certification to each
affected state commission and to each affected electric utility.\36\
The self-certifying cogenerator or small power producer must also
specify the utility services that it intends to request (see item 3b of
Form 556).
\36\Affected state commissions are the regulatory commissions of
the states where the QF and any affected electric utilities are
located. An affected utility is an electric utility to which the QF
intends to interconnect, transmit and sell electric energy, or from
which the QF intends to purchase supplementary, standby, back-up or
maintenance power.
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If electric utilities do not agree that a notice of self-
certification is valid, they may challenge QF status by filing a
petition for a declaratory order. If lenders, etc. are not convinced,
they will continue to require that the potential QF facility obtain
Commission certification of QF status before financing a project.
The formal completion and submission of Form 556 to demonstrate
that a facility conforms with the Commission's QF criteria will not
constitute a substantive burden on those selecting the self-
certification process. A cogenerator or small power producer submitting
a notice of self-certification under the current regulations already
must analyze the characteristics of its facility to determine whether
it meets the Commission's qualifying criteria. The completion of Form
556 will assist both novice and experienced cogenerators and small
power producers. It will serve as a step-by-step guide to determining
whether a proposed facility qualifies for certification. Many notices
of self-certification recently filed with the Commission have
incorporated similar documentation.
Through the use of Form 556, the self-certification process will be
similar to the Commission certification process, because it will
incorporate sufficient substantive information to allow an affected
commission or electric utility to challenge the notice of self-
certification.
The self-certification process will largely remain a simple, quick
and economical procedure. There will continue to be no Commission
review or filing fee, and the process should promote discussions
between self-certifying cogenerators or small power producers and the
affected electric utilities and regulatory commissions. These
discussions should provide the parties an opportunity to timely and
informally resolve any problems. The final rule revises proposed
Sec. 292.207(a)(1)(ii) accordingly.
3. Revocation of Qualifying Status
Proposed Sec. 292.207(d)(1) provided that the Commission may revoke
the [[Page 4841]] qualifying status of a QF that it has certified under
Sec. 292.207, if the facility fails to comply with any of the facts or
representations that it presented in its application for Commission
certification.\37\ The NOPR further provided that, before undertaking
any substantial alteration or modification of a qualifying facility
that has been certified under Sec. 292.207, a small power producer or
cogenerator may apply to the Commission for a determination that the
proposed alteration or modification will not result in a revocation of
qualifying status. The NOPR provided that the small power producer or
cogenerator should accompany the application for recertification with
supporting material, notice and a filing fee.
\37\The Commission's regulations do not provide for revocation
of a notice of self-certification. Other entities (e.g., electric
utilities) may: (1) Move for revocation of a Commission
certification of QF status; or (2) file a petition for a declaratory
order that a self-certified or Commission-certified facility does
not comply with all applicable QF requirements. See, e.g., UNIGAS
Corp., 67 FERC 61,142 (1994).
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Comments: American Forest and Paper maintains that revocation of
qualifying status under proposed Sec. 292.207(d)(1) pertains only to
material facts or representations, and even then, only to reliance on
the Commission's order on qualifying status. It notes that the
Commission has held on a number of occasions that the failure of a
facility to operate in accordance with any of the facts or
representations presented in an application for Commission
certification does not necessarily affect the continued qualifying
status of the facility. Rather, the failure affects only the legal
force of the Commission's certification order that relied on those
facts and representations.\38\
\38\See, e.g., Sithe/Independence Power Partners, L.P., 61 FERC
61,212 at 61,786 (1992).
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EEI reads proposed Sec. 292.207(d)(1) as allowing any person to
request that the Commission revoke the qualifying status of a facility.
NEP suggests that the owners of qualifying facilities should provide
filings under Sec. 292.207(d)(2) to the utilities with which they
interconnect.
Finally, NYSEG and Niagara Mohawk argue that the Commission should
make it clear that a utility may deem a facility to be ineligible for
PURPA benefits even if the Commission has not decertified the facility.
They reason that, if a notice of self-certification is sufficient to
qualify facilities for PURPA benefits, and Commission certification is
not necessary, then utilities should be able to declare facilities
ineligible for PURPA benefits without any action on the Commission's
part. NYSEG and Niagara Mohawk also suggest that the Commission amend
Sec. 292.207(d)(1) to provide that, after gathering sufficient data
demonstrating that a facility is not a QF, a utility may file an
affidavit to that effect with the Commission.
Commission Response: The Commission agrees with American Forest and
Paper's assessment of the consequences of a facility's failing to
operate as represented in the cogenerator's or small power producer's
application for Commission certification. The Commission will amend
proposed Sec. 292.207(d)(1) to make it clear that a facility may
continue to be qualified despite changed circumstances, provided that
the facility continues to meet the qualifying criteria.\39\
\39\Under proposed Sec. 292.207(d)(1) any person with standing
to do so may request the Commission to revoke the qualifying status
of a facility. See Liquid Carbonic Industries Corp. v. FERC, 29 F.3d
697 (D.C. Cir. 1994) with regard to standing to contest a QF
certification.
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The Commission will not require owners of facilities to provide a
copy of a filing made under Sec. 292.207(d)(2) directly to each utility
that transacts business with the facility because the Commission will
publish notice of such filings in the Federal Register. The final rule
clarifies and revises Sec. 292.207(d)(1) accordingly.
Regarding Niagara Mohawk and NYSEG's argument that a utility may
deem a facility to be ineligible for PURPA benefits, we note that, in
Independent Energy Producers Association, Inc. v. California Public
Utilities Commission, 36 F.3d 848 (9th Cir. 1994), the court struck
down, as preempted by federal law, a CPUC program that allowed electric
utilities to suspend payment of contractually-authorized rates in favor
of lower, alternative rates when QFs do not meet the applicable
operating and efficiency standards. The court found that the Commission
has exclusive authority to determine whether a QF is in compliance with
the applicable operating and efficiency standards. Id. at 853-59. The
court added that it is the Commission's responsibility to decertify
QFs--not the state's responsibility. Id. at 855, 859. While the
Commission may take up this matter in the future, we will not delay
this proceeding in order to address it at this time.
4. Pre-Authorized Recertification
The Commission proposed at Sec. 292.207(a)(2) to provide for
streamlined Commission recertification of certain minor changes to
those facilities which the Commission had already accorded qualifying
status under Sec. 292.207(b). The NOPR proposed that a cogenerator or
small power producer would simply report such a change in the form of a
letter describing the change in sufficient detail to enable the
Commission to readily determine that the modification falls within the
scope of a list of pre-approved minor changes. A report of a pre-
authorized change would not require a filing fee.40
\40\The Commission proposed that if it approves the change(s),
it would return the report stamped ``approved.'' The proposed rule
further provided that if the Commission does not approve the
proposed change(s), it would treat the report as a full
Sec. 292.207(b) filing and assess a filing fee.
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Comments: Detroit Edison requests that the pre-authorized
recertification procedure provide for notice in the Federal Register
and/or service of the application for recertification upon each
affected utility and state commission. Detroit Edison submits that this
would provide state commissions and utilities with information for
system planning and would allow state commissions and utilities to
bring to the Commission's attention special circumstances regarding a
particular facility and/or factual errors in an application for
recertification. EEI, Atlantic Electric and NEP also recommend
publishing notices of recertification in the Federal Register and
request that the Commission direct cogenerators and small power
producers to provide copies of the notice directly to all affected
parties.41
\41\NEP also suggests that applicants also provide a copy of any
filing under Sec. 292.207(d)(2) to each of the utilities with which
the QF is expected to transact business.
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SDG&E would limit pre-authorized changes to those changes involving
name, installation or operation date, or change to power generation
equipment. It argues that, except for these changes, meaningful
evaluation of a facility's continued adherence to the Commission's
standards cannot occur unless the owner or operator of the facility
supplies sufficient information to conduct an analysis. Based on this
reasoning, SDG&E contends that the Commission should generally require
a cogenerator or a small power producer to apply for a Commission
determination under Sec. 292.207(d)(2) that a change to its facility
will not result in revocation of qualifying status. Alternatively,
SDG&E suggests that the cogenerator or small power producer provide
notice to the Commission of the change in the form of an affidavit. In
either case, SDG&E recommends that the cogenerator or small power
producer provide an updated Form 556 and a copy of the filing to each
affected utility.
EEI contends that some of the proposed pre-authorized changes can
[[Page 4842]] have a significant effect on purchasing and wheeling
utilities. EEI states, for example, that a change in the maximum net
power production capacity of a QF can affect utility obligations
regarding the amount of power to be purchased and the amount of backup
and maintenance power that the utility must provide to the QF; that a
location change can affect a utility's point of interconnection with
the QF, as well as a utility's transmission and distribution system
requirements; or that a change in the QF's fuel could affect the
facility's performance and reliability.
Southern California Edison is concerned that some of the proposed
pre-authorized changes (i.e., changes with regard to site, thermal
load, fuel use, plant size, cogeneration thermal host or prime-mover
technology) may result in a new QF project and may have a significant
effect on a contracting utility. It urges the Commission to delete
these changes from the Commission's list of automatically approved,
pre-certified changes.42
\42\Southern California Edison notes that the CPUC has
instructed utilities not to accept certain modifications under
existing power purchase contracts in the absence of corresponding
concessions from the cogenerator or small power producer. Southern
California Edison is concerned that the Commission's treatment will
conflict with the CPUC's directive.
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Southern Companies is concerned about the effects that a change in
location may have on utility planning, and on transmission and
distribution systems, in the absence of adequate notice to the utility.
Detroit Edison points out that a change in location of a QF may affect
the local utility's ability to accommodate the facility, especially
since the Commission's pre-authorized change proposal seems to
contemplate that a QF may move from the service territory of one
utility to that of another, or even move from one state to another.
On the other hand, Tenaska suggests that the Commission's list of
automatically approved, pre-certified changes should be even more
expansive. It proposes that the Commission permit a change in power
generation equipment whenever there is no material or substantial
change in capacity or operating characteristics of the facility.
Tenaska also urges that the Commission extend to coal, other fossil
fuels, and waste the pre-authorized changes permitted for oil and
natural gas usage by a cogeneration facility.
American Cogen and Electric Generation Association propose
additional pre-approvals: (a) For changes within an existing corporate
structure; (b) for changes in the equity interests (to ensure that the
facility continues to comply with the ownership requirements of
Sec. 292.206); and (c) for changes in the steam host that do not affect
levels of thermal output or the operating and efficiency values of the
facility.
EEI recommends that the Commission clarify that a self-certified
cogenerator or small power producer also may file a notice of self-
recertification with regard to the Commission's pre-authorized changes
and that such minor changes will not result in a self-certified
facility's losing its qualifying status.43
\43\EEI observes that proposed Sec. 292.207(a)(2)(i) limits
reports of pre-authorized minor changes to those QFs previously
certified by the Commission, and that this seems to suggest that a
self-certified facility might be subject to revocation of qualified
status as a consequence of the institution of similar minor changes.
In addition, EEI states that Sec. 292.207(a)(2)(ii) is confusing
because of its reference to the term ``application.'' According to
EEI, the term makes it appear to require that a Sec. 292.207(d)(2)
filing, which pertains to a change that will not result in the
revocation of qualifying status, is mandatory for a Commission
certified facility but discretionary for a self-certified facility.
Yet, EEI argues, Sec. 292.207(d)(2) seems to suggest that a filing
under that section is discretionary for all QFs.
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Commission Response: In consideration of the comments, the
Commission will adopt the proposed rule with the modifications
discussed below. The Commission will pre-authorize ownership changes
within a corporate family that do not affect the ultimate upstream
derivative ownership in the facility (Sec. 292.207(a)(2)(i)(A)).44
The Commission will also pre-authorize changes in the steam host when
there is no change in the thermal application or process
(Sec. 292.207(a)(2)(i)(M)), and extend its pre-authorization of changes
in oil and natural gas use by a cogeneration facility to other fuels
(Sec. 292.207(a)(2)(i)(E)).45
\44\We encourage applicants to describe such ownership changes
with the aid of a corporate relationship chart.
\45\Because there is no efficiency standard applicable to the
use of other fuels by a cogeneration facility, any change in the use
of such fuels also warrants pre-authorization.
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The Commission will not adopt EEI's suggestion that the Commission
extend the pre-authorized changes to the self-certification procedure.
The Pre-authorized Commission recertification procedure is not
available to a self-certified facility because, under self-
certification, the owner or operator of the facility is free to report
any change.
We are also deleting the proposed regulatory text which stated that
the Commission would return these submittals stamped ``approved.'' The
deleted text is inconsistent with the new procedure that pre-approves
certain types of changes.
Finally, because of concerns about the effect on utility planning
and utility systems, the Commission will require that cogenerators and
small power producers provide affected utilities and state commissions
a copy of any report of pre-authorized changes filed under
Sec. 292.207(a)(2).
The Commission declines to adopt the CPUC's proposal that it
indicate which modifications the Commission considers too fundamental
to include in a list of pre-approved changes. The intent of adopting a
list of pre-authorized changes in the final rule is to authorize
changes that are sufficiently minor for purposes of QF status that it
is unnecessary to obtain specific Commission approval each time such
changes are made. If a change is not included on the list, then the
pre-authorized change procedure cannot be used, and the cogenerator or
small power producer must apply for recertification or file a notice of
self-recertification.
The final rule revises Sec. 292.207(a)(2) accordingly.
5. Qualifying Transmission and Interconnection Equipment
The Commission proposed to amend the definition of the term
``qualifying facility'' to include transmission lines, transformers and
switchyards to reflect Commission precedent.46 As proposed,
cogenerators, small power producers and utilities could use such
equipment only to transmit qualifying power from the QF to the
purchasing electric utility and to transmit supplementary, standby,
backup and maintenance power from an electric utility to the QF.
\46\See, e.g., Clarion Power Company (Clarion), 39 FERC 61,317
(1987); Kern River Cogeneration Company, 31 FERC 61,183 (1985)
(Kern River); Malacha Power Project, Inc. (Malacha), 41 FERC 61,350
(1987); see also, Oxbow Geothermal Corporation, 67 FERC 61,193
(1994) (Oxbow) (granting recertification when the QF leased spare
transmission capacity to an adjacent QF and disclaiming FPA
jurisdiction over the lease).
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Comments: NEP contends that a generic rule that allows transmission
equipment to be a component of a QF is ill-advised. NEP and
Pennsylvania P&L suggest that the Commission should continue to
consider this issue on a case-by-case basis. NEP is concerned that,
under a generic rule, electric utilities may find themselves in the
difficult situation of needing to tap into QF transmission lines and
obtain wheeling in order to serve load growth in their own service
territories. NEP is also concerned that the presence of qualifying
transmission facilities might affect: (a) A utility's transmission and
distribution plans; (b) public safety; and (c) the environment.
Pennsylvania P&L is concerned that codification of the QF
transmission line [[Page 4843]] and interconnection lines precedent
could result in the exemption of more transmission lines from state
environmental siting review. It notes that the State of Pennsylvania
does not regulate QF-owned transmission lines.47 Southern
California Edison is concerned that the proposed definition may cause
conflicts with state and local authorities that regulate the
construction, ownership and/or operation of transmission facilities,
despite the Commission's clarification in the NOPR with respect to the
continued applicability of Federal, state and local siting and
environmental requirements to such equipment. Edison, Arizona Public
Service and EEI ask the Commission to clearly state in the final rule
that Federal, state and local siting requirements continue to apply to
QF-owned transmission lines.
\47\This is Pennsylvania's choice. Certification does not exempt
QFs from environmental siting requirements.
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EEI also observes that the proposed reference to the use of
qualifying transmission and interconnection equipment for ``qualified
power'' sales by QFs is ambiguous, since the term is undefined. EEI
further observes that the reference is unnecessary because the
Commission is only concerned about power sales by the QF portion of a
facility. Finally, EEI submits that one could interpret the proposed
definition of qualifying facility to prohibit a QF's use of qualifying
transmission and interconnection facilities to purchase power other
than supplementary, standby, maintenance and backup power for the non-
qualifying portions of a facility. EEI suggests that the Commission did
not intend to be so restrictive in its definition.
American Cogen, American Iron and Steel, General Electric,
Independent Energy Producers, and Texaco want to expand the permitted
uses of qualifying transmission and interconnection facilities to
include transmission and wheeling of a QF's power to other parties.
Texaco suggests that the Commission should include in the definition of
a qualifying facility any facilities that deliver electric energy to
third parties, such as thermal hosts or other entities, and any
facilities that provide transmission access under the provisions of the
Energy Policy Act of 1992.
American Cogen contends that, whether a QF is selling electric
energy at retail to industrial customers is irrelevant for the purpose
of determining QF status. American Cogen argues that it would make no
sense to deny qualifying status to the transmission and/or
interconnection portion of a facility merely because the facility is
engaged in power sales to end users. American Cogen says that the
Commission's inquiry has been focused on and should continue to focus
on whether a facility meets the fuel use standard, operating and
efficiency standards and ownership criteria. American Iron and Steel
contends that restricting the use of qualifying transmission and
interconnection equipment to transactions with utilities would be
contrary to precedent.48
\48\American Iron and Steel refers to PRI Energy Systems, Inc.,
(PRI Energy), 26 FERC 61,177 (1984); Oxbow Geothermal Corporation,
36 FERC 61,398 (1986); and Union Carbide Corp., 48 FERC 61,130,
reh'g denied, 49 FERC 61,209 (1989), affirmed sub nom., Gulf States
Utilities Co. v. FERC, 922 F.2d 873 (D.C. Cir. 1991) (Union
Carbide).
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American Iron and Steel also suggests that, since PURPA does not
bar retail sales where such sales are permissible under state law, the
Commission should clarify the definition of a QF to provide for
qualifying status of transmission and interconnection facilities and
similar facilities that provide power to non-utility parties.
Otherwise, American Iron and Steel argues, by precluding qualifying
transmission and interconnection facilities where a QF transmits
electric energy to retail customers, the Commission would place
restrictions on state authority over retail sales, a restriction that
Congress sought to prevent under PURPA.
AGA counters that the Commission should not permit the transmission
and wheeling of electric energy for and to third parties over
qualifying transmission facilities, because Sec. 210 of PURPA only
encourages the local generation of alternative energy. According to
AGA, PURPA does not encourage the transmission of alternative sources
of electric energy to third parties.
Commission Response: The Commission will codify its precedent
concerning qualifying transmission lines and interconnection equipment
at Sec. 292.101(b)(1). The Commission is not changing the case-by-case
disposition of applications for the certification of qualifying
facility status that include transmission lines and interconnection
facilities.
The Commission also agrees with the suggestions of several
commenters that it should more fully codify Commission precedent by
clarifying or expanding the defined uses of transmission lines and
interconnection facilities. PURPA does not preclude QFs from selling at
retail.49 However, transmission lines or interconnection
facilities that are found to be part of a QF--whether used for
wholesale or retail sales--may be used only for the purpose of
effectuating the QF's sale of power; transmitting other QFs' power;
transmitting standby, maintenance, supplementary and backup power to
other QFs; 50 or transmitting back-up power, etc. to the QF or its
thermal users in appropriate circumstances.51 In other words, the
final rule will allow the transmission and interconnection components
of the QF to serve the same users that are served by the power
production components of QFs, to serve other QFs, and to serve the
backup, etc. needs of the QF, and its thermal host, in appropriate
circumstances. The Commission's modified definition of qualifying
facility will, accordingly, recognize that QFs may use transmission
lines and interconnection facilities to exchange electric power without
regard to the nature of the purchaser of the QF's power.52
\49\See PRI Energy, supra, n.48.
\50\See Oxbow, supra, n.46.
\51\See Union Carbide, supra, n.48.
\52\Purchasers that receive electric energy over the QF's
transmission lines and interconnection facilities may be directly or
indirectly interconnected purchasing utilities as contemplated in,
e.g., Kern River; Western Massachusetts Electric Company, 59 FERC
61,091, reh'g denied, 61 FERC 61,182 (1992), and Sec. 292.303 (a)
and (d) of the Commission's regulations; they may also be affiliated
and unaffiliated thermal hosts in accord with, e.g., Kern River;
Alcon (Puerto Rico), 38 FERC 61,301 (1987), affirmed, Puerto Rico
Elec. Power Auth. v.FERC, 848 F.2d 243 (D.C. Cir. 1988); and Union
Carbide; or they may be retail customers, when permitted by state
law, in accord with PRI Energy.
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EEI's reference to the qualifying ``portion'' of an entire facility
is unclear. It is, therefore, difficult to evaluate EEI's concern that
the proposed revised definition of a QF may overly restrict the
allowable types of power purchases that qualifying transmission lines
and interconnection facilities may transmit. In any event, the
Commission, in this proceeding, is simply codifying its practice and
precedent concerning the transmission lines and interconnection
facilities of a QF.
With respect to Texaco's suggestion to expand the facilities
covered in the definition to those used to provide transmission access
under the provisions of the Energy Policy Act,53 the suggestion is
beyond the scope of this rulemaking.54
\53\The Energy Policy Act became effective on October 24, 1992.
Public Law No. 102-486, 106 Stat 2776 (1992). The Commission issued
the NOPR in this proceeding on November 16, 1992.
\54\However, the Commission's preliminary view is that a QF that
is a transmitting utility, see 16 U.S.C. 793(23), would not lose its
qualifying status if the Commission ordered the QF to provide
transmission services under FPA section 211.
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The Commission agrees with Southern California Edison, EEI and
[[Page 4844]] Arizona Power that it is appropriate to modify the
definition of qualifying facility to make it clear that Federal, state
and local siting and environmental requirements apply to such
transmission lines and interconnection facilities.
The final rule revises Sec. 292.101(b)(1) accordingly.
6. Power Production Capacity
In the NOPR, the Commission proposed to add a new Sec. 292.202(s),
which would codify Commission precedent regarding the power production
capacity of a QF. The Commission proposed to determine a QF's maximum
net sendout based on the safe and reliable operation of the facility.
The Commission also proposed to measure the QF's power production
capacity at the point of delivery to the transmission system of the
interconnected utility.55
\55\Net output determines whether small power production
facilities that are not eligible solar, wind, waste or geothermal
facilities as defined by section 3(17)(E) of the FPA, conform to the
80 MW size limit of Sec. 292.204(a) and whether their owners and
operators are eligible for regulatory exemptions provided at
Secs. 292.601 and 292.602 of the Commission's regulations. See,
e.g., Malacha Power Project, Inc., 41 FERC 61,350 (1987);
Massachusetts Refusetech, Incorporated, 25 FERC 61,406 (1983); Power
Developers, Inc., 32 FERC 61,101 (1985), rehearing denied, 34 FERC
61,136 (1986); and Penntech Papers, Inc., 48 FERC 61,120 (1989).
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Comments: Commenters recommended that the Commission measure power
production capacity at each point of interconnection with each
purchaser,56 or at the first point of interconnection with the
transmitting utility.57 The CPUC suggests that electric power
output must be net of any parasitic loads.
\56\Comments of American Cogen.
\57\Comments of Independent Energy Producers.
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Southern California Edison suggests that the Commission define
power production capacity in terms of the expected operating conditions
during the period when the purchasing utility most needs power, taking
into account factors such as ambient temperature at the time of system
peak load and the QF's power commitment.58 Southern California
Edison is also concerned that one could construe the proposed
Sec. 292.202(s) language to allow the owners and operators of QFs to
choose to purchase power to meet a facility's auxiliary load
requirements in order to artificially increase the amount of power
sendout.
\58\According to Southern California Edison, its QF power
purchase contracts specify the amount of electric power which it can
rely on at the time of its maximum system peak demands. Southern
California uses such contract capacity in its long-term system
planning because the QF capacity amount reflects expected operating
conditions rather than the most favorable operating conditions.
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General Electric suggests case-specific treatment for cogeneration
facilities that employ gasifiers.59
\59\A gasification system converts coal, waste and other by-
product materials to fuel gas, which may be burned in a power
production facility.
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On November 29, 1993, as supplemented on December 3, 1993, Granite
State Hydropower Association (Granite State Hydropower), whose members
own or operate approximately 40 small hydroelectric projects in New
Hampshire, filed an ``emergency'' motion for clarification or to reopen
this proceeding and rescind the proposal to codify decisions.60
Granite State Hydropower opposes codification of the Commission's
decisions in Power Developers, Inc.,61 and Turners Falls Limited
Partnership,62 at least insofar as it might apply to hydroelectric
small power production facilities that are in operation when such
codification might take effect.63 Granite State Hydropower
requests that the Commission either rescind the proposed rule or
clarify that it would apply such a change in eligibility requirements
to future hydroelectric small power production facilities only.
\60\We shall treat their motion as a comment on the NOPR.
\61\32 FERC 61,101 (1985) (Power Developers).
\62\55 FERC 61,136 (1991) (Turners Falls).
\63\According to Granite State Hydropower, the New Hampshire
Public Utility Commission (New Hampshire Commission) has interpreted
the eligibility restrictions of Turners Falls to have, in effect,
overruled the New Hampshire Commission's 1981 regulations
implementing PURPA and certain of this Commission's Part 292
regulations.
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Commission Response: The Commission notes that in two pending
proceedings 64 issues have been raised concerning the policy set
forth in Turners Falls. The Commission is reviewing those issues and
will address them in those proceedings. The Commission is not prepared
at this time to issue a final rule regarding the policy set forth in
Turners Falls. The Commission may, in the future, codify its policy on
this matter after it has had more experience with the issue. The
Commission will not adopt the proposed definition of power production
capacity at this time.
\64\Carolina Power & Light Company, v. Stone Container Corp.,
Docket Nos. EL94-62-000 and QF85-102-005; Connecticut Valley Light &
Power Company v. Wheelabrator Claremont Company, Docket Nos. EL94-
10-000 and QF86-177-001.
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7. Increased Specificity of the Qualifying Facility Filing
Requirements: Form 556
In the NOPR, the Commission proposed a standardized application
form (Form 556) to facilitate successful applications for Commission
certification of qualifying status. The Commission intended that Form
556 would also make small power producers and cogenerators more aware
of the QF standards that apply to their facilities; under the current
regulations one must examine the history of related cases and the
language of the pertinent regulations to be sure of the specific
standards that apply to particular facilities. To make this effort less
burdensome to applicants, Form 556 allows cogenerators and small power
producers to report the specific characteristics of their facilities.
The form also provides for the step-by-step application of pertinent
regulations to their facilities. When accurately completed, Form 556
should readily reveal whether a facility substantially complies with
the applicable criteria, and reduce the number of Staff inquiries for
more information from applicants.
Comments: With respect to the general requirement for Form 556,
SDG&E suggests changing the title of Form 556 to make it clear that it
applies to proposed, as well as to existing facilities. American Cogen
cautions that verifying the useful thermal output of proposed
facilities (item 14a): (a) Will be an extremely cumbersome procedure;
(b) will, of necessity, be based on approximations; and (c) may raise
utility concerns, prompt premature interventions, and cause
administrative difficulties.
Southern California Edison recommends that applicants include an
updated Form 556 with each filing submitted under Sec. 292.207(d)(2) in
connection with a substantial modification to a facility. AGA urges the
Commission to dispense with the detailed information requirements and
request only the most basic technical information.65 American
Forest and Paper maintains that identification of the utility that will
purchase and/or wheel the facility's qualified power (item 3b) is
unnecessary, since that information has nothing to do with qualifying
status.
\65\While the Commission notes that AGA's suggestion that the
Commission change its policy and rely on minimal information is
beyond the scope of this proceeding, its proposal would undercut the
Commission's efforts to reduce the incidence of incomplete filings.
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Arizona Public Service proposes that the QF specify the name of
each affected utility customer, as well as the magnitude of its
displaced load. SDG&E proposes that the applicant describe in writing
the operation of the principal components of the facility, and that the
applicant also address supplementary firing devices and incorporate a
detailed [[Page 4845]] thermodynamic heat balance diagram.66 SDG&E
recommends that Form 556 require an applicant to more narrowly specify
the facility's electric power production capacity in terms of the
qualified portion of the facility instead of simply on a stand-alone
basis (item 4b).
\66\This information should be provided in Form 556, items 4a
and 10.
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American Forest and Paper asks the Commission to delete the
proposed inquiry into the total energy input of a facility (items 4d
and 5). It notes that, for a small power production facility, item 7
addresses compliance with the fossil fuel use limits and that, for a
cogeneration facility, the fuel used is relevant only for compliance
with the efficiency standard. According to American Forest and Paper,
item 11, concerning operating and efficiency values for cogeneration,
should apply only to oil or natural gas fueled cogeneration facilities.
EEI recommends that the Commission broaden its consideration of
waste energy input (item 4d) to include the Commission's ``no current
commercial value'' test or a United States Department of the Interior,
Bureau of Land Management (BLM) waste determination. SDG&E recommends
that the Commission add new item 4e, which would require a description
of the QF's point of delivery with the purchasing utility. It also
suggests that Form 556 require an applicant to present the facility's
energy input (item 5) in terms of ``lower heating value.''67
\67\Lower heating value refers to the amount of useful heat
energy that can be obtained during the combustion process, since the
latent heat of water vaporization in the combustion of hydrocarbon
fuels is not recoverable. Order No. 69, FERC Stats. and Regs.,
Regulations Preambles 1977-1981 30,134 at 30,937. Section
292.202(m) requires that one use lower heating value to measure the
energy input of oil or natural gas. SDG&E also asks the Commission
to require an applicant to specify the conversion factor that it
uses to convert the higher heating value to the lower heating value.
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EEI suggests that the Commission make its determination of the
amount of total energy input into a small power production facility
(Item 7) in terms of Btu/lb. or Btu/cubic ft. of gas at standard
temperature and pressure and that Form 556 require an applicant to
specify the annual Btu consumption of primary fuel. EEI notes that Form
556 does not define eligible and non-eligible small power production
facilities (Item 8).\68\
\68\Under section 3(17)(E) of the FPA, eligible facilities are
certain solar, wind, waste and geothermal powered small power
production facilities that are not capped at the PURPA 80 MW size
limit, for which a filing regarding QF status had been submitted to
the Commission by the end of 1994 and for which the construction
must generally commence before the end of 1999.
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American Cogen maintains that a cogeneration system cycle diagram
depicting the physical arrangement of system components (item 10) is
often premature and burdensome, since certification often occurs before
selecting a general contractor and completing the detailed layout.
American Cogen also contends that small facilities, under 2 MW, should
be exempt from the cycle diagram requirement. The CPUC, observing that
items 10 and 14 address cogeneration system input and output values,
suggests that it would be useful to directly relate each input and
output value to the cycle diagram to show more clearly what each value
represents.\69\ SDG&E suggests that, for absorption chiller thermal
applications, there should be specification of the heat that will be
sent to the chiller's cooling tower, and any factor converting the
chilled water in terms of net Btu cooling output to net heat input to
the chiller, as well as the relevant flow rates, temperature, pressure,
and enthalpy.
\69\The Commission agrees that there should be a correlation
between the input and output information provided in items 10 and
14.
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SDG&E suggests that the Commission should require an applicant to
specify the entity that will purchase the useful thermal energy output
from the facility and any affiliation such entity may have with the
cogenerator (item 12). SDG&E further recommends that the description of
any heat dump, exhaust bypass or other such device for dumping,
transferring or applying heat to something other than the designated
useful thermal energy output application, be provided in writing along
with a simple diagram (item 13). AGA contends that, since distribution
heat losses are an inherent and unavoidable characteristic of thermal
consumption and are not a function of how thermal energy is created,
Form 556 should not call for calculations of distribution heat losses.
EEI proposes that, if the Commission decides that applicants must
include a completed Form 556 with all QF related filings, the
Commission specify the type of filing that the Form 556 submission
pertains to (e.g., Commission recertification, self-recertification, or
pre-authorized change). EEI also suggests a requirement that, at all
times, proper and accurate metering or other measuring and recording
will be conducted to verify continuing compliance with the operating
and efficiency standards. American Forest and Paper contends that the
routine Federal Register notice accorded applications for Commission
certification should be sufficient to alert nearby utilities and other
interested parties about potential QF obligations.
Commission Response: Applications for Commission certification
under Sec. 292.207(b) must include Form 556. Further, because the final
rule will require filings under Sec. 292.207(d)(2) to conform to the
requirements of Sec. 292.207(b), filings under Sec. 292.207(d)(2) will
include a completed and current Form 556. The Commission will also
require that notices of self-certification under Sec. 292.207(a)(1)
include a completed Form 556. However, the final rule does not require
applicants to include Form 556 with preauthorized change filings under
Sec. 292.207(a)(2). To do so would be inconsistent with the notion that
preauthorized changes do not require additional Commission review.
Concerning EEI's comments about verification of compliance with
operating and efficiency standards, the Commission notes that
cogenerators and small power producers are responsible for installing
adequate monitoring equipment to ensure compliance with the
Commission's regulations.
In response to American Forest and Paper's comment that Federal
Register notice should suffice for applications for Commission
certification, as we noted above, the adoption of Form 556 is intended
to benefit QFs by facilitating successful applications for Commission
certification and making cogenerators and small power producers more
aware of QF standards. American Forest and Paper's comments concerning
notice to affected utilities does not account for these benefits.
Moreover, as discussed elsewhere in this final rule, the Commission is
requiring a completed Form 556 for each self-certification filing,
which, at revised item 3b, will specify the purchasing and wheeling
utilities, if known. Since the Commission does not publish notices of
self-certification in the Federal Register, the Commission will require
that applicants provide copies of notices of self-certification to each
affected utility and state commission.
We decline to adopt American Cogen's proposal to exempt facilities
under 2 MW from the cycle diagram requirement. A cycle diagram is a
minimal showing of the operation of the cogeneration process.
We decline to adopt SDG&E's suggestion that applicants specify
several factors related to absorption chiller thermal applications. The
Commission has held that PURPA does not require the thermal use to be
the [[Page 4846]] most efficient; the requirement is that it be
``useful.''\70\
\70\See Bayside Cogeneration, L.P., 67 FERC 61,290 at 62,007 &
n. 7 (1994).
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Concerning AGA's comment that Form 556 should not require
calculations of distribution heat losses, the Commission recognizes
that accounting for inefficiencies of heating and cooling equipment is
burdensome and unnecessary. Form 556 will not require that applicants
specify this information.
The Commission will publish Form 556 in Part 131 of the
Commission's regulations. To help focus attention on the relevant
standards, the Commission will divide the form into three parts. Part
A, entitled ``General Information To Be Submitted By All Applicants''
(items 1-6), covers: (a) The identity of the applicant; (b) the type of
facility (small power or cogeneration); (c) the expected or actual
installation and operation dates, (d) the fuel input and power output;
and (e) the identity of the relevant utilities with which the facility
will transact business. Part B, entitled ``Description Of the Small
Power Production Facility'' (items 7-8), concerns certain restrictions
on use of oil, natural gas and coal and the one-mile limit on common
fuel supplies shared by multiple facilities. Part C, entitled
``Description Of the Cogeneration Facility'' (items 9-15), concerns
compliance with, inter alia, the operating and/or efficiency standards,
and contains sections that specifically pertain to topping-cycle (items
13-14b) and bottoming-cycle (item 15) facilities.
To make Form 556 easier to use, the Commission is eliminating
redundancies and, wherever possible, cross-referencing items to related
sections of the Commission's regulations or stating the underlying FPA
or Commission requirement.
The Commission is also modifying the title of Form 556 to indicate
that applicants must complete up-to-date Forms 556 for both existing
and proposed facilities.\71\ The Commission is requiring a description
of the operation of the principal components of the facility (item 4a).
The Commission is clarifying the reference to eligible small power
production facilities (item 8) with an explanation and a reference to
section 3(17)(E) of the Federal Power Act. The Commission is also
requiring that an applicant specify the identity of the thermal host;
but the Commission is not requiring that in all cases applicants must
divulge their affiliation with the cogenerator (item 13).\72\
\71\The Commission is not requiring owners and/or operators of
facilities that have applications for certification pending before
the Commission, or that the Commission has already certified, or
that have already filed a notice of self-certification to file Form
556 unless they file for Commission recertification or self-
recertification after the effective date of this final rule.
With respect to facilities not yet built or operating, small
power producers and cogenerators must present the relevant
information, to the extent possible, in the form of planned
compliance. If the small power producer or cogenerator does not
supply sufficient information, the Commission will not be able to
certify the facility, or the information in a notice of self-
certification will not be adequate to ensure that the facility is a
QF.
\72\The affiliate relationship between the cogenerator and the
thermal host is not relevant unless the thermal application or
process, or the end product produced with the aid of the thermal
output from the facility, is not common. Since most thermal
applications or processes, and/or the end products produced with the
aid of such, are common, this information is usually not necessary.
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The Commission is also not requiring applicants to specify the
utility load that a QF will displace, since it is sufficient for
utility planning and system operating purposes that applicants identify
all of the utilities with which they expect to transact business. The
Commission's practice has long required that applicants provide
information on thermal delivery losses and any thermal energy return,
in order to determine the amount of the useful thermal energy output of
the facility (item 14a). Experienced cogenerators have routinely
provided this information. The Commission is not eliminating this
critical requirement.\73\ The final rule clarifies Form 556
accordingly.
\73\Section 292.202(h), as revised in this final rule, defines
thermal energy in terms of thermal energy: (1) Which is made
available to an industrial or commercial process (net of any heat
contained in condensate return and/or makeup water); (2) which is
used in a heating application (e.g., space heating, domestic hot
water heating); or (3) which is used in a space cooling application
(i.e., steam or hot water used by an absorption chiller). Item 14a
will contain these three categories.
Line losses and heat exchanging equipment losses must be
deducted from the total thermal energy actually consumed. For
example, any thermal energy rejected by an absorption system at the
input to the chiller must be deducted from the useful thermal
output, since what is rejected is not used for cooling purposes.
Also, the proper location of the metering equipment at the host site
can eliminate the need to calculate line losses.
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F. Proposed Technical Modifications for Qualifying Small Power
Production and Cogeneration Facilities Under Part 292
1. Calendar Year Fossil Fuel Use and Operating and Efficiency Value
Calculations
The Commission's current rules require cogeneration facilities to
meet the operating and efficiency standards on a calendar year
basis.\74\ Small power production facilities must meet a similar
requirement with respect to the proportion of fossil fuel use.
\74\See, e.g., Everett Energy Corporation, 45 FERC 61,314
(1988).
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The NOPR proposed to convert the existing calendar year operating
and efficiency standards (for cogeneration facilities\75\) and the
current calendar year fossil fuel standard (for small power production
facilities\76\) to 12-month standards, because many QFs have
experienced difficulty meeting the standards during the first calendar
year of operation. For example, if a cogeneration facility first
produces electric energy late in the year, it may not have enough time
under normal operation during the remainder of the calendar year to
meet the Commission's operating and/or efficiency standards. Likewise,
it may miss the peak thermal usage of its host(s), and so may be unable
to comply with the Commission's operating and/or efficiency standards
for that calendar year.
\75\The current operating standard requires all topping-cycle
cogeneration facilities to have at least a 5 percent operating value
with regard to useful thermal energy output (Sec. 292.205(a)). Oil
or gas-fired topping-cycle cogeneration facilities are also subject
to an efficiency standard (Sec. 292.205(a)). The useful electric
power output of the facility plus one-half the useful thermal energy
output must be no less than 42.5 percent of the total energy input
of natural gas or oil. If the useful thermal energy output is less
than 15 percent of the total energy output (i.e., the operating
value is less than 15 percent), the efficiency value must be 45
percent rather than 42.5 percent. For supplementary fired bottoming-
cycle facilities, the useful electric power output must be at least
45 percent of the total oil and natural gas input
(Sec. 292.205(b)(1)).
\76\The use of coal, oil and natural gas by qualifying small
power production facilities is limited to certain purposes and
cannot exceed 25 percent of the total fuel input
(Sec. 292.204(b)(2)).
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In the NOPR, the Commission proposed to base its determination of
whether a QF meets the Commission's technical standards in its first
year of operation by examining the facility's operation for a period of
12 consecutive months beginning with the date on which the QF first
produces electric energy. The Commission proposed to base subsequent
determinations upon each ensuing 12-month period. Accordingly, the
Commission proposed to replace the phrase ``during any calendar year''
in Secs. 292.204(b)(2), 292.205(a) and 292.205(b) with the phrase ``on
a consecutive 12-month basis beginning with the date the facility first
produces electric energy.''
Comments: American Forest and Paper suggests a 60 to 90-day grace
period beginning with the first production of electric energy to permit
the completion of facility testing. Upon commercial operation, the 12-
month standard would apply. Independent Energy Producers suggests that
the Commission apply the new 12-month [[Page 4847]] standard to
consecutive 12-month periods, rather than to rolling 12-month periods
beginning with each month.
Pennsylvania P&L suggests that the Commission apply the 12-month
standard only to new QFs in order to minimize administrative problems
with existing QFs whose power purchase contracts may be based on
calendar year periods. SDG&E and Southern California Edison suggest
that the Commission continue to apply the existing calendar year
standard, beginning with the first full calendar year of a QF's
operation and apply the new 12-month standard only to the initial
period of operation.\77\ SDG&E and Southern California Edison believe
that this would respond to the Commission's concern about the
difficulties QFs initially encounter in their operation and make it
easier for utilities to monitor the operation of a large number of
QFs.\78\
\77\Southern California Edison also suggests that, since certain
combined-cycle configurations have characteristics of both topping-
cycle and bottoming-cycle facilities, the Commission should make the
operating and efficiency standards for combined-cycle facilities the
same as for topping-cycle facilities. The Commission considers
combined-cycle installations to be topping-cycle facilities subject
to the operating and efficiency standards applicable to such
facilities.
Southern California Edison suggests that the Commission should
also require combined cycle facilities to calculate the efficiency
value to take into account total energy input. The Commission
includes the total energy input of only oil or natural gas to such
topping cycle facilities in the calculation of the efficiency value.
\78\SDG&E also contends that the current operating and
efficiency standards have failed to encourage alternative energy
development and conservation and suggests that the Commission should
initiate a new rulemaking proceeding to raise the operating and the
efficiency standards. At this juncture, however, the Commission is
primarily concerned with codifying QF precedent and otherwise
streamlining its QF regulations. It is not prepared to initiate
another generic QF proceeding at this time.
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Commission Response: American Forest and Paper's proposal to
establish a 60-90 day grace period for new facilities is beyond the
scope of this proceeding and the Commission will not adopt it.
The Commission is revising its regulations to require that the
technical standards be measured during the first year of operation, on
a consecutive 12-month basis beginning with the date the facility first
produces electric energy. A new facility can fail to meet the technical
standards in any period from one to 11 months as long as the facility
meets the technical standards for the 12-month period. Compliance with
the technical standards will be required on a calendar year basis
beginning with the first full calendar year of operation following the
date of initial electric power production.\79\ This should simplify
compliance with contracts and regulations. The final rule revises the
Commission's operating, efficiency and small power fuel use standards
accordingly.
\79\Under this approach, small power producers and cogenerators
will account for the early period of a QF's operation under both the
12-month standard and the calendar year standard. For example, with
respect to a facility that first produces power on July 1, 1994,
conformance with the 12-month standard will be necessary for the 12-
month period ending June 30, 1995. In addition, conformance with the
calendar year standard will be necessary for that facility for the
calendar year ending December 31, 1995.
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2. Clarification of the Sequential Use of Energy Requirement
In the NOPR, the Commission proposed to clarify its requirements
pertaining to cogeneration facilities' sequential use of energy and
useful thermal energy output. The Commission, therefore, proposed to
define sequential use of energy in a new Sec. 292.202(t); in the final
rule, this new section is designated Sec. 292.202(s). The NOPR also
proposed to codify Commission precedent that: (a) A topping-cycle
installation must subsequently use some of the reject heat from the
electric power production process for a useful thermal purpose; and (b)
that the useful portion of thermal energy output refers to the heat
used in a heating or cooling application or made available to a
commercial or industrial process.\80\ In the case of a bottoming-cycle
cogeneration installation, where all of the energy is first used for a
commercial or industrial process, the Commission proposed that the
facility must subsequently use some of the reject heat to produce
electric power.
\80\Under the Commission's proposal, a topping-cycle cogenerator
applicant would provide a mass, heat balance (cycle) diagram to
demonstrate sequentiality, an adequate level of useful thermal
energy output, and conformance with the operating and efficiency
standards. Cycle diagrams delineate average annual hourly energy
flows at various points of the cogeneration facility (including
points of fuel input and working fluid input), accounting for hourly
and seasonal variations, and conditions such as temperature,
pressure and enthalpy (heat content) at these inputs, at the outputs
of the prime movers, and at delivery points to the thermal
application/process, and account for losses between the cogenerator
and the host.
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Comments: EEI refers to a multiple turbine cogeneration
configuration in which some of the turbines are sequentially producing
electric power and useful thermal output, and other turbines are only
producing electric power. EEI contends that the latter turbines should
not qualify because they do not save fuel. Southern Companies also
maintains that sequential energy use must remain central to the
qualifying cogeneration facility concept. AGA approves of the
Commission's discussion in the NOPR on this matter, because it
contemplates that useful thermal energy will be extracted at any point
along a chain of linked turbines rather than from every turbine in a
multi-turbine topping-cycle installation.
SDG&E asks the Commission to specify a minimum percentage threshold
for sequentially produced useful thermal energy output. It submits that
the setting of a minimum threshold would better promote the
conservation and efficiency goals of PURPA. SDG&E also recommends that
the Commission exclude from the operating and efficiency values of a
facility the incremental electrical and thermal output related to any
supplementary firing in a combined-cycle (topping-cycle) extraction
turbine configuration. SDG&E contends that to allow supplementary
firing when only a token portion of the thermal input is converted to
useful thermal energy output is not an efficient use of energy.
American Cogen suggests that the Commission require facilities to
account for inefficiencies in the thermal host's equipment with greater
specificity. However, if the Commission's intent is to net out such
inefficiencies from the useful thermal energy output at each point of
interconnection with the thermal process or application, American Cogen
contends that accounting for such inefficiencies is onerous and should
not be adopted. Electric Generation Association raises similar
concerns. Independent Energy Producers suggests that the Commission use
an approach similar to that proposed for waste fuels and provide a non-
exclusive list of useful thermal purposes to help reduce any
uncertainty.
SDG&E is concerned that the proposed revised definition of useful
thermal energy output does not exclude heat dumped or rejected after
delivery to the process, and that space and domestic water heating and
cooling uses have not been included in useful thermal energy
output.\81\ SDG&E also suggests that a modified independent business
purpose test be applied to determine the usefulness of novel thermal
applications or processes.
\81\(See Electrodyne Research Corporation, 32 FERC 61,102
(1985) (Electrodyne)).
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Commission Response: With regard to the concerns of EEI, Southern
Companies and American Cogen, the Commission's final rule both
maintains the sequential use of energy concept and permits a QF to
extract useful thermal energy at any point along a chain of
[[Page 4848]] turbines as long as the turbines are linked in a
sequential energy flow. While SDG&E believes that the proposed
definition of sequential use of energy was too vague, the Commission
notes that the new definition explicitly considers the operating
standard with respect to topping-cycle cogeneration facilities. Under
the operating standard, 5 percent of the total energy output of a
topping-cycle cogeneration facility must be useful thermal energy
output in order for a facility to meet the sequentiality requirement.
The Commission agrees with American Cogen and Electric Generation
Association that it is unduly burdensome for cogenerators to compile
data on net useful thermal energy output that accounts for host
equipment inefficiencies, and that this requirement would not be
consonant with streamlining the QF regulations. It is not practical to
account for inefficiencies related to each piece of host equipment. The
Commission, however, agrees with SDG&E's proposal to clarify the
definition of useful thermal energy output to clearly account for such
common applications as space heating and space cooling, and domestic
water heating.
The Commission declines to adopt Independent Energy Producers'
proposal to create a non-exclusive list of useful thermal energy output
applications and processes similar to the proposed list for waste
fuels. Since, by design, most thermal applications and processes are
common and, therefore, presumptively useful, a listing of permitted
thermal applications/processes would be virtually impossible to
compile. Also, any such list would likely exclude unforeseen variations
of previously allowed thermal applications/processes that would also
fall within the presumptively useful category.
SDG&E has raised a concern about separate firing in combined cycle
facilities, in which fuel is used to produce steam, some of which is
directly used in the thermal application/process and some of which is
used in an extraction turbine generator to produce additional electric
energy and subsequently additional thermal output. As long as the
direct and indirect use of thermal output amounts to 5 percent of the
facility's total energy output, the facility meets the operating
standard and the sequential use of energy requirement. The Commission
does not allow the use of duct burners (i.e., separate firing of heat
recovery boilers) solely to produce electric power in condensing
turbine configurations.\82\ In response to SDG&E's suggestion to modify
the independent business purpose test, the Commission, has not proposed
to modify its Electrodyne standard in this proceeding. Thus, SDG&E's
proposal is beyond the scope of the instant proceeding.
\82\See Adolf Coors Company, 34 FERC 61,209 (1986).
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The final rule adopts Sec. 292.202(s) accordingly.
3. Section 292.204(a)--Criteria for Small Power Production Facilities
In the NOPR, the Commission proposed to amend Sec. 292.204(a) of
its regulations to reflect the addition by Congress of subsection
3(17)(E) of the Federal Power Act (FPA) pursuant to the Solar, Wind,
Waste, and Geothermal Power Production Incentives Act of 1990, as
subsequently amended in 1991 (the Incentives Act). Subsection 3(17)(E)
temporarily removed the otherwise applicable subsection 3(17)(A) 80 MW
size limitation on eligible small power production facilities.
Eligible facilities are those solar, wind, waste and geothermal
powered small power production facilities for which either a notice of
self-certification, or an application for Commission certification, was
submitted to the Commission by December 31, 1994. In addition,
construction of eligible facilities must commence not later than
December 31, 1999, or, if not by then, reasonable diligence must be
exercised toward the completion of such facilities taking into account
all factors relevant to their construction.
Comments: EEI suggests that the Commission require that operators
of eligible facilities provide evidence that they have made a good
faith effort toward the timely completion of such facilities by
December 31, 1999, taking into account all factors relevant to their
construction, in order to maintain eligibility for exemption from the
size restriction.
Independent Energy Producers expresses concern that under the
Incentives Act, as amended, existing small power production facilities
of greater than 80 MW may lose their qualifying status if they must be
recertified subsequent to December 31, 1994. They request that the
Commission clarify that recertification of an existing eligible solar,
wind, waste or geothermal small power production facility larger than
80 MW after December 31, 1994, will not endanger that project's
qualifying status. Independent Energy Producers asserts that it would
be unreasonable to interpret the Incentives Act, as amended, to take
away existing benefits from a project which otherwise meets all
eligibility requirements simply because it undergoes modification or
some other change in circumstances, not related to the size cap,
requiring a subsequent filing some time during the project's useful
life. Such modifications include minor changes in a project's size,
transmission routing, or ownership and occur frequently, according to
Independent Energy Producers.
Commission Response: In adding Subsection 3(17)(E) to the FPA,
Congress only required that applicants exercise reasonable diligence
toward the completion of construction of eligible small power
production facilities, in those instances when construction has not
commenced by December 31, 1999. In deciding to allow eligible small
power producers to start construction after December 31, 1999, Congress
obviously considered the potential for delays, yet, notably, it did not
establish a requirement that construction be completed by any
particular date. Therefore, it would not be appropriate for the
Commission to adopt EEI's suggestion to require in all cases eligible
small power producers to demonstrate reasonable diligence to complete
construction of eligible facilities by December 31, 1999.
In response to Independent Energy Producers, we do not believe that
an eligible solar, wind waste or geothermal facility will lose QF
status if, subsequent to December 31, 1994, such facility either files
a notice of self-recertification or an application for Commission
recertification, as long as the project is not fundamentally altered
from the project described in the notice of self-certification or
application for Commission certification filed prior to January 1,
1995.\83\
\83\At this juncture, the Commission believes it is appropriate
to determine whether a project has been fundamentally altered on a
case-by-case basis.
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The Commission will retain the proposed regulatory text for 18 CFR
292.204(a).
4. Waste
In the NOPR the Commission proposed to drop the existing definition
of ``waste'' as a by-product material.\84\ [[Page 4849]] The Commission
intended to make it easier to determine the energy sources that certain
qualifying small power production facilities can use. To make it easier
to certify a qualifying facility, the Commission also proposed to list
specific energy sources that it had previously approved for treatment
as waste.\85\
\84\PURPA does not define the term ``waste.'' In the preamble to
its final rule implementing PURPA, the Commission defined waste as
``by-product materials other than biomass.'' FERC Stats. and Regs.,
Regulations Preambles, 1977-1981 30,134 at 30,934. In Kenvil
Energy Corporation (Kenvil), 23 FERC 61,139 (1983), the Commission
found that, to be waste, an energy source must be both a by-product
and have no commercial value. Subsequently, the Commission found
that applying the by-product test is not only cumbersome, but also
is not needed to address the issue of what constitutes waste. For
example, in Big Horn Energy Partners, 38 FERC 61,265, order on
rehearing, 40 FERC 61,305 (1987) (Big Horn), the Commission
certified as waste, coal which was not a true by-product of the coal
mining operation but was simply not extracted because it was
unwanted.
Section 292.202(a) defines ``biomass'' as any organic material
not derived from fossil fuels.
\85\The Commission intended that its waste list not be
exclusive.
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Comments: EEI and Southern Companies are concerned that eliminating
the by-product test in the revised definition of waste may encourage
the deliberate creation of a waste material. Each recommends that an
energy source not qualify as waste unless it would otherwise exist in
the absence of the QF that will rely on it.
American Iron and Steel, Utility Systems Florida, Anthracite IPPs
and Independent Energy Producers suggest that whether the owner or
operator of a QF pays for the energy source, incurs costs associated
with its removal and transportation to the QF, and adds value by way of
upgrade, should not affect the determination of commercial value.
American Iron and Steel proposes that the Commission consider
commercial value in the context of its value to potential purchasers
other than owners and operators of QFs. Anthracite IPPs observes that
upgrades, such as cleaning and washing, might be necessary before a QF
can use a waste. Utility Systems Florida notes that almost everything
has some commercial value after it is cleaned, and suggests that the
Commission define waste in terms of an energy source that is both an
environmental hazard and has little or no commercial value.
American Iron and Steel, EEI and Southern Companies urge the
Commission to state that, once the Commission determines that a QF's
energy source is waste, the Commission will continue to treat that
energy source as waste even if the waste subsequently acquires
commercial value. They maintain that this approach is necessary to
maintain the QF's qualifying status.
The CPUC, EEI and Southern Companies propose that the Commission
periodically review and update its list of waste materials.86
Anthracite IPPS and Applied Energy argue that it is unnecessary to
limit petroleum coke and used rubber tires to that which cannot be
commercially marketed, since the Commission has already listed each
item as waste.87 American Iron and Steel suggests that the
Commission specifically list coke oven gas and blast furnace gas as
waste.88
\86\The CPUC notes that the proposed waste list is based upon
market data for the period 1987 through 1991. EEI is concerned that
technology may quickly cause a listed waste to acquire some economic
value. Southern Companies, concerned about delay, recommends that
the Commission establish a list of wastes but not include the list
in the Commission's regulations. Southern Companies suggests that
the Commission invite public comment on the list and update the list
periodically.
\87\Anthracite IPPs cites Sunlaw Energy Corp., 37 FERC 62,255
(1986) and Exeter Energy Limited Partnership, 48 FERC 62,135
(1985). Applied Energy cites Ultrapower, Inc., 34 FERC 62,144
(1986), GWF Power Systems Company, Inc., 45 FERC 62,159 (1988), and
the Commission's discussion of petroleum coke without regard to its
commercial value at FERC Stats. and Regs., Regulations Preambles
1977-1981 30,134 at 30,934. In that latter discussion, the
Commission also referred to refinery gas and plastics as additional
examples of waste.
\88\American Iron and Steel states that these gases cannot be
marketed outside the steel industry due to low Btu content,
intermittent production, and capture and storage problems. It also
suggests that the Commission consider including as waste steel
industry process gases such as Corex off-gas and direct steel making
off-gas.
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Ridgewood and RW Partners suggest that the Commission include on
the list of waste environmentally problematic substances such as used
crankcase oil and other used petroleum products.89 Anthracite IPPs
recommends that the Commission include on the waste list coal
``fines,'' regardless of their BTU content.90 It argues that fines
are extremely difficult to handle because of their small particle size
and their tendency to become difficult to handle when wet.91
Anthracite IPPs also proposes that the list be expanded to include
subbituminous coal or blends of bituminous and subbituminous coal,
regardless of whether such material is in place or is a refuse.92
\89\Ridgewood, RW Partners, Utility Systems Florida, Donald L.
Warner and Steven Anthony Duff maintain that listing used crankcase
oil as waste would provide an incentive for its proper disposal,
reduce its role as an environmental nuisance, encourage its
recycling for use in electric generation, help reduce oil imports,
and remove skepticism among lenders as to the status of self-
certified facilities that rely on it.
\90\Fines are small or powdery-sized particles of coal that
result from coal mining, sizing or processing operations.
\91\Anthracite IPPs further states that utilities do not
specifically purchase fines, and that fines are typically in the
form of silt comprised of coal fines and ash materials from coal
washing operations and are disposed of in settling or slurry ponds.
\92\Subbituminous coal has a lower heat content than bituminous
coal, averaging 9,000 Btu/lb.
Anthracite IPPs also proposes that the Commission regard as
waste: (1) Top or bottom anthracite coal, and (2) subbituminous and
bituminous coal that the United States Department of the Interior's
Bureau of Land Management (BLM) has determined to be waste,
including any of this coal with the same characteristics that may
extend onto non-Federal or Indian land not under the BLM's
jurisdiction. Anthracite IPPs notes that, since BLM jurisdiction
only extends to Federal or Indian lands, the waste list's reference
to BLM approved wastes on such lands is redundant.
Anthracite IPPs also wants the Commission to provide in its
regulations that any coal source not listed as a waste in the
Commission's regulations may qualify as waste upon a showing that it
has no commercial value. Anthracite IPPs also wants all references
to Btu or ash content to refer to average values so that variations
in Btu or ash content will not preclude a potential fuel source from
qualifying.
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Commission Response: The Commission is simplifying the qualifying
status determination of facilities that use waste energy inputs in two
ways. First, the Commission is publishing a list of waste energy inputs
that the Commission has previously approved. Second, the Commission is
streamlining its waste determination process for those energy inputs
that do not appear on the list, by changing its two-part Kenvil
approach (i.e., application of a ``by-product test'' in conjunction
with a ``little or no current commercial value'' test) to require only
that the proposed waste fuel source have little or no current
commercial value.
Section 292.204(b) requires that, for a waste-fueled qualifying
small power production facility, 75 percent or more of the total energy
input to the facility must be waste.93 Determining whether a
facility meets this criterion will entail an evaluation of the average
quality characteristics of the fuel, if the fuel is a waste fossil fuel
energy input to a facility, or a description of the facility's energy
input if it is not using a waste fossil fuel.
\93\Section 292.204 reads in relevant part, as follows:
(b) Fuel use. (1)(i) The primary energy source of the facility
must be biomass, waste, renewable resources, geothermal resources,
or any combination thereof, and 75 percent or more of the total
energy input must be from these sources.
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The final rule will provide that even if the owner and/or operator
of a QF pays for a material and incurs expenses to transport and
upgrade it, the material is a waste if no other sector of the Nation's
economy uses the material; but, if there is a demand for the material,
other than in the QF industry, the material is considered to have
commercial value and is, therefore, not waste under the ``little or no
commercial value'' test. The Commission will not consider value to the
cogenerator or small power producer as commercial value. Should a waste
material acquire commercial value after the Commission has certified a
facility that uses such material, or after a small power
[[Page 4850]] producer or cogenerator has filed a notice of self-
certification referring to such material, the facility will not lose
its qualifying status because the material from which it generates
electric energy has acquired commercial value.94
\94\The Commission rejects Southern Companies' suggestion that
the Commission publish updated lists of waste materials without
revising its regulations. Under Southern Companies' recommended
procedure, there would still be notice and comments and the
Commission would still frequently have to update its list of waste
materials. The Commission would be taking on an additional
administrative burden without saving any time.
It would be impractical to establish a special update procedure
for the waste list. Since various materials may gain or lose
commercial value over time, a detailed listing of waste materials
could require frequent revisions of the Commission's regulations.
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The requirement that the waste energy input exist in the absence of
the QF industry will allow the Commission to regard as waste those
materials that are not by-products of industrial processes but are
nevertheless unwanted, while precluding the creation of contrived
energy inputs for the sole purpose of having the Commission view them
as ``waste.''
It is virtually impossible to develop a simplified determination
procedure that will work perfectly to determine what is waste. There
may, for example, be substances that the Commission has not listed as
waste and do not qualify as waste under the ``no commercial value''
component of the test that, nevertheless, may truly be waste. The
Commission will consider reasonable proposals for the special treatment
of specific materials as ``waste,'' on a case-by-case basis.
The Commission will list petroleum coke and used rubber tires as
waste, without reference to their commercial marketability.95 The
Commission will also add refinery off-gas and plastic to the list of
those materials that it regards as waste. The Commission will consider
the average Btu and ash content of coal located in refuse ponds when
determining whether it is waste.
\95\Petroleum coke is a by-product of the oil refining process
that is very low in volatile matter, usually high in sulfur content,
and an environmentally hazardous waste. Used rubber tires, while
high in heat content, are not burned in conventional boilers, do not
represent an energy source for electric utilities, and are
detrimental to the environment.
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The Commission notes that it currently accepts BLM determinations
regarding waste coal located both within BLM's jurisdiction and located
on non-Federal or non-Indian lands outside of BLM's jurisdiction,
provided that applicants show that the latter refuse is an extension of
a portion of the relevant coal seam (e.g., top or bottom coal) or other
refuse source (e.g., refuse pile) determined to be waste by BLM.
However, since reference to Federal or Indian lands serves to clarify
the extent of BLM's jurisdiction for all applicants, the Commission
sees no reason to modify the regulatory text in this regard.96
\96\See Big Horn.
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The Commission will not list as waste: Anthracite and bituminous
coal fines; subbituminous coal; blends of bituminous and subbituminous
coal having an average heat value greater than 9,500 Btu per pound with
an average of 25 percent or more ash content; or used crankcase oil or
other used petroleum products.97
\97\Some Anthracite and bituminous coal fines, when dried and
where transportation distances are short, have a high Btu content
and commercial value. Some public utilities and various other
entities use anthracite silt ponds as a source of fuel. See
Electrodyne. Form 423 data for 1992 suggest that electric utilities
purchase subbituminous coal with a heat content of 9,500 Btu per
pound and an ash content of more than 25 percent.
Used crankcase oil is currently reprocessed for use as an
industrial boiler fuel, in asphalt production and cement kilns. It
is also refined for use in lubricants and for reuse as motor oil.
The Commission lacks sufficient information to support a generic
finding that hot gases, such as oxygen furnace off-gas and hot blast
furnace air, have no commercial value.
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In this proceeding, the Commission does not intend to make generic
rulings on specific materials that it has not previously considered.
With respect to materials which the Commission has not listed as
``waste,'' an applicant is always free to submit a showing that in a
particular case the material has little or no current commercial value
and would not exist in the absence of the QF industry.
Finally, in light of the Commission's treatment of waste natural
gas for cogeneration purposes,98 the final rule will provide that
a cogeneration facility may use a waste that meets the definition of
Sec. 292.202(b) as an energy input without considering the waste fuel's
energy input to the cogeneration facility in computing its efficiency
value under Sec. 292.205.
\98\Red Top Cogeneration Project, L.P., 62 FERC 61,205, reh'g
denied, 65 FERC 61,044 (1993).
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The Commission agrees with Anthracite IPPs' suggestions that any
coal source not listed as a waste in the Commission's regulations may
qualify as waste upon a showing that it has little or no commercial
value and that all references to Btu or ash content refer to average
values.
The final rule revises and clarifies Secs. 292.202(b) and 292.205
accordingly.
G. Part 294--Procedures for Shortages of Electric Energy and Capacity
Under Section 206 of Public Utilities Regulatory Policies Act
In the NOPR, the Commission proposed to modify Sec. 294.101(b) to
provide that a public utility need not file with the Commission a
contingency plan for accommodating shortages of electric energy or
capacity affecting its firm power wholesale customers, or modify such a
contingency plan already on file with the Commission, if the public
utility includes certain provisions in the appropriate wholesale rate
schedule. The Commission also proposed to modify Sec. 294.101 by adding
a new paragraph (f), which would provide that, if a public utility
includes in its rate schedule provisions that it will report
anticipated shortages of electric energy or capacity to appropriate
state regulators and to its wholesale customers, then the public
utility need only report to the Commission the nature and projected
duration of the anticipated capacity or energy supply shortage and
furnish a list of the firm power or wholesale supply customers likely
to be affected by the shortage.
EEI, NEP and Southern Companies support the proposed revisions to
the Commission's reporting requirements. Baltimore Gas & Electric asks
the Commission to eliminate the requirement to report to the Commission
anticipated shortages of electric energy and/or capacity for those
public utilities that file an Integrated Resource Plan or least-cost
plan containing the required information with their State regulatory
authorities.
The Commission declines to adopt Baltimore Gas & Electric's
suggestion. As the Commission noted in the NOPR, section 202(g) of the
FPA requires that public utilities file contingency plans for shortages
with the Commission as well as with any appropriate state regulatory
authority. To satisfy section 202(g), it is not enough for public
utilities to file contingency plans with state regulatory authorities
only; they must also file with this Commission contingency plans that
affect wholesale customers.
The proposed rule simply gives a public utility the option of not
separately reporting its contingency plans if it already includes
certain provisions in its wholesale rate schedules. Otherwise, the
public utility must file a brief statement, summarizing the public
utility's contingency plans. If a public utility does not avail itself
of the new rate schedule option, it will merely have to summarize how,
under [[Page 4851]] the plan that it files with the state, it will
treat its wholesale customers in the event of a shortage of electric
energy. The Commission does not consider this requirement burdensome,
and the requirement will satisfy the Commission's obligation to ensure
that a public utility will treat its wholesale customers in a fair and
non-discriminatory manner in the event of a shortage of electric
energy. Accordingly, the Commission adopts the changes to part 294 as
proposed in the NOPR.
H. Part 382--Annual Charges
The proposed rule would modify Secs. 382.102 and 382.201, which
pertain to the requirement that public utilities report total annual
adjusted sales for resale megawatt-hours and total annual coordination
sales megawatt-hours for the purposes of computing annual charges.
Under the proposed rule, public utilities that are exempt from filing
Form 1 would be subject to the annual charge regulations and would be
assessed annual charges.99 The proposed rule also would change
definitions in the annual charge regulations to allow for calculation
of annual charges consistent with the classification of transactions
volumes as reported on Form 1. The proposed rule would also revise the
regulations to state how the Commission proposes to calculate annual
charges.
\99\The Commission has determined that the annual charge
obligation also applies to all public utility power marketers.
Morgan Stanley Capital Group, Inc., 69 FERC 61,175 (1994), reh'g
pending.
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Comments: EEI requests a fuller explanation of the Commission's
proposed changes in the calculation of annual charges and of how those
contemplated changes will interact with the elimination of certain
filing fees proposed in Docket No. RM92-17-000.100 EEI also
recommends that the Commission bill applicants directly for filings
that are unusually extensive or that require an extraordinary amount of
the Commission's time and effort to process.
\100\Subsequent to the filing of EEI's comments, the Commission
issued a final rule in Docket No. RM92-17-000 revising its filing
fee structure. See Elimination of Filing Fees, Order No. 548, 58 FR
2968 (Jan. 7, 1993), III FERC Stats. & Regs. 30,960 (1993).
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NEP expresses concern that the proposed change in the formula for
calculating utilities' annual charges may produce dramatic increases in
the assessments on individual public utilities. NEP asks the Commission
to defer adoption of the proposed change in the annual charge formula
until the utilities have an opportunity to assess the likely effect of
the change.
Southern Companies comments that public utilities, whether or not
they file a Form 1, should pay annual charges.
Commission's Response: With respect to EEI's comments, the rule
eliminating certain filing fees does not affect the fact that utilities
are assessed annual charges. With respect to EEI's and NEP's comments,
the proposed rule changed some definitions and explained how
transaction volumes would be reported. However, the proposed rule does
not change the formula for calculating annual charges. The proposed
rule is clarifying in nature, linking the reporting of transaction
volumes to specific statistical classifications on Form 1.
We will deny NEP's request that we defer adopting the change in the
annual charge regulations. Public utilities have had approximately two
years since the issuance of the NOPR to assess the effect of the
change. Further deferral of action is unwarranted.
Accordingly, we will adopt the final rule as proposed.
I. Part 385--Rules of Practice and Procedure
The proposed rule deleted Rule 717, Sec. 385.717, which expired by
its own terms on May 21, 1986, and deleted cross-references to Rule 717
contained in other rules. EEI supports the deletion of Rule 717, and
there were no comments opposing the deletion of Rule 717. Accordingly,
we will adopt the final rule as proposed.
IV. Environmental Statement
Commission regulations require that an environmental assessment or
an environmental impact statement be prepared for any Commission action
that may have a significant adverse effect on the human
environment.101 The Commission has categorically excluded certain
actions from this requirement as not having a significant effect on the
human environment.102 No environmental consideration is necessary
for the promulgation of a rule that is clarifying, corrective, or
procedural or that does not substantially change the effect of
legislation or regulations being amended or applies to accounting
orders, the establishment of just and reasonable rates, the issuance
and purchase of corporate securities or corporate regulation.103
The final rule is clarifying and procedural in nature. It merely makes
clerical and clarifying changes and deletes reporting requirements and
regulations that the Commission has decided are no longer necessary or
that refer only to: (a) The establishment of just and reasonable rates;
or (b) the issuance and purchase of corporate securities.
\101\Regulations Implementing National Environmental Policy Act,
52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations
Preambles 1987-1990, 30,783 (1987).
\102\18 CFR 380.4.
\103\18 CFR 380.4(a)(2)(ii), 380.4(a)(15)-(16).
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Section 201 of PURPA includes ``waste'' as an allowable primary
energy source for qualifying small power production facilities. To the
extent the Commission is revising the definition of ``waste,''
incorporating an illustrative list of waste energy sources, this action
merely codifies current Commission practice; it does not substantially
change the effect of the underlying legislation.
Accordingly, neither an environmental assessment nor an
environmental impact statement is necessary.
V. Regulatory Flexibility Certification
The Regulatory Flexibility Act104 requires rulemakings to
either contain a description and analysis of the impact the proposed
rule will have on small entities or to certify that the rule will not
have a substantial economic impact on a substantial number of small
entities. The final rule removes unnecessary and obsolete regulations.
The only additional reporting requirements that the Commission is
adopting will serve to reduce discovery burdens and improve processing
of filings. The Commission's newly adopted regulations governing QFs
merely clarify and codify Commission precedent. Finally, since the
final rule is designed to reduce regulatory burdens, the Commission
expects that any impact on small entities affected by the final rule
will be beneficial. Accordingly, the Commission certifies that these
proposed rules, if adopted, will not have ``a significant economic
impact on a substantial number of small entities.''
\104\5 U.S.C. 601-612.
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The Small Business Administration supports the substance of the
proposed rule and, specifically, agrees that the proposed rule will be
beneficial to QFs. However, the Small Business Administration maintains
that the Commission should perform a regulatory flexibility analysis
under the Regulatory Flexibility Act. According to the Small Business
Administration, unless the Commission can demonstrate that the
beneficial effects of the rule will not be significant, the Commission
must prepare a final regulatory flexibility analysis pursuant to
section 604 of the Regulatory Flexibility Act. The Small Business
Administration contends that such an analysis may lead to further
[[Page 4852]] methods of reducing the regulatory burdens imposed on
small generators of electricity.
The Commission finds that the proposed rules will assist small
businesses in a significant but unquantifiable manner and that further
regulatory flexibility analysis is unnecessary.
VI. Information Collection Statement
The Office of Management and Budget's (OMB) regulations105
require that OMB approve certain information collection requirements
imposed by an agency. The information collection requirements in the
final rule are contained in FERC-516 ``Electric Rate Filings'' (1902-
0096), FERC-523 ``Applications to Issue Securities'' (1902-0043), FERC
525 ``Financial Audits'' (1902-0092), FERC-556 ``Application for
Certification of Qualifying Status as a Small Power Production Facility
or Cogeneration Facility'' (1902-0075), FERC-582 ``Oil, Gas and
Electric Fees and Annual Charges'' (1902-0132) and FERC-585 ``Reports
on Electric Energy Shortages and Contingency Plans Under PURPA 206''
(1902-0138).
\105\5 CFR 1320.12.
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The respondents are: Utilities and persons wishing to issue
securities, or assume obligations or liabilities as a guarantor,
endorser, or surety, in accordance with sections 19, 20 and 204 of the
FPA; to file rate schedules showing all rates and charges pertaining to
any transmission or sale of electric energy in interstate commerce in
accordance with sections 15, 19, 20, 205, 206 and 207 of the FPA;
ensure their financial records comply with accounting, financial
reporting and other regulations established under mandates of the FPA;
submit contingency plans with regard to shortages of electric energy or
capacity: submit payment for charges of costs incurred by the
Commission to process industry filings; and to obtain Commission
certification or file a notice of the qualifying status of their small
power production and cogeneration facilities.
The Commission uses the data collected in these information
requirements to carry out its regulatory responsibilities pursuant to
the Federal Power Act, Public Utility Regulatory Policies Act of 1978,
and the Interstate Commerce Act. The Commission's Office of Electric
Power Regulation uses the data for determination of electric rate
filings submitted by industry, applications for certification of
qualifying cogeneration and small power production facilities and
appropriate procedures in the event of shortages of electric energy.
The Office of Financial Management uses the data for compilation of
annual charges. The Office of the Chief Accountant uses the data to
ensure that industry has followed the appropriate procedures for
issuing securities or assumptions of liabilities obligations and to
ensure that jurisdictional companies comply with the Uniform System of
Accounts. Respondents would be public utilities, licensees or QF
applicants who desire certification of their facility.
The Commission is submitting to the Office of Management and Budget
a notification of these changes. Interested persons may obtain
information on these reporting requirements by contacting the Federal
Energy Regulatory Commission, 941 North Capitol Street NE., Washington,
DC 20426 (Attention: Michael Miller, Information Services Division,
(202) 208-1415). Comments on the requirements of this final rule can
also be sent to the Office of Information and Regulatory Affairs of OMB
(Attention: Desk Officer for Federal Energy Regulatory Commission).
FAX: (202) 395-5167.
List of Subjects
18 CFR Part 2
Administrative practice and procedure, Electric power, Natural gas
pipelines, Reporting and recordkeeping requirements.
18 CFR Part 34
Electric power, Electric utilities, Reporting and recordkeeping
requirements, Securities.
18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
18 CFR Part 41
Administrative practice and procedure, Electric utilities,
Reporting and recordkeeping requirements, Uniform System of Accounts.
18 CFR Part 131
Electric power.
18 CFR Part 292
Electric power plants, Electric utilities, Natural gas, Reporting
and recordkeeping requirements.
18 CFR Part 294
Electric utilities, Reporting and recordkeeping requirements.
18 CFR Part 382
Administrative practice and procedure, Electric power, Pipelines,
Reporting and recordkeeping requirements.
18 CFR Part 385
Administrative practice and procedure, Electric power, Penalties,
Reporting and recordkeeping requirements.
By the Commission.
Lois D. Cashell,
Secretary.
In consideration of the foregoing, the Commission is amending parts
2, 34, 35, 41, 131, 292, 294, 382, and 385, Chapter I, Title 18, Code
of Federal Regulations, as set forth below.
PART 2--GENERAL POLICY AND INTERPRETATIONS
1. The authority citation for Part 2 is revised to read as follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 16 U.S.C. 791a-825r,
2601-2645; 42 U.S.C. 4321-4361, 7101-7352.
2. In Sec. 2.4, paragraph (d) is removed and paragraphs (e), (f),
(g) and (h) are redesignated paragraphs (d), (e), (f) and (g),
respectively.
PART 34--APPLICATION FOR AUTHORIZATION OF THE ISSUANCE OF
SECURITIES OR THE ASSUMPTION OF LIABILITIES
3. The authority citation for Part 34 is revised to read as
follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
4. In Sec. 34.1, paragraphs (c)(1) and (c)(2) are revised to read
as follows:
Sec. 34.1 Applicability; definitions; exemptions in case of certain
State regulation, certain short-term issuances and certain qualifying
facilities.
* * * * *
(c) Exemptions. (1) If an agency of the State in which the utility
is organized and operating approves or authorizes, in writing, the
issuance of securities prior to their issuance, the utility is exempt
from the provisions of sections 19, 20 and 204 of the Federal Power Act
and the regulations under this part, with respect to such securities.
(2) This part does not apply to the issue or renewal of, or
assumption of liability on, a note or draft maturing one year or less
after the date of such issue, renewal, or assumption of liability, if
the aggregate of such note or draft and all other then-outstanding
notes and drafts of a maturity of one year or less on which the utility
is primarily or [[Page 4853]] secondarily liable, is not more than 5
percent of the par value of the other then-outstanding securities of
the utility as of the date of issue or renewal of, or assumption of
liability on, the note or draft. In the case of securities having no
par value, the par value for the purpose of this part is the fair
market value, as of the date of issue or renewal of, or assumption of
liability on, the note or draft.
* * * * *
5. Section 34.2 is revised to read as follows:
Sec. 34.2 Placement of securities.
(a) Method of issuance. Upon obtaining authorization from the
Commission, utilities may issue securities by either a competitive bid
or negotiated placement, provided that:
(1) Competitive bids are obtained from at least two prospective
dealers, purchasers or underwriters; or
(2) Negotiated offers are obtained from at least three prospective
dealers, purchasers or underwriters; and
(3) The utility:
(i) Accepts the bid or offer that provides the utility with the
lowest cost of money for securities with fixed or variable interest or
dividend rates, or
(ii) Accepts the bid or offer that provides the utility with the
greatest net proceeds for securities with no specified interest or
dividend rates, or
(iii) The utility has filed for and obtained authorization from the
Commission to accept bids or offers other than those specified in
paragraphs (a)(3)(i) or (a)(3)(ii) of this section.
(b) Exemptions. The provisions of paragraph (a) of this section do
not apply where:
(1) The securities are to be issued to existing holders of
securities on a pro rata basis;
(2) The utility receives an unsolicited offer to purchase the
securities;
(3) The securities have a maturity of one year or less; or
(4) The securities are to be issued in support of or to guarantee
securities issued by governmental or quasi-governmental bodies for the
benefit of the utility.
(c) Prohibitions. No securities will be placed with any person who:
(1) Has performed any service or accepted any fee or compensation
with respect to the proposed issuance of securities prior to submission
of bids or entry into negotiations for placement of such securities; or
(2) Would be in violation of section 305(a) of the Federal Power
Act with respect to the issuance.
6. In Sec. 34.3, the heading and introductory text are revised, the
word ``and'' is added at the end of paragraph (e)(5), the phrase ``;
and'' is removed at the end of paragraph (e)(6), and replaced by a
period, paragraphs (e)(7), (f) and (g) are removed and paragraphs (h),
(i), (j), (k), (l), (m) and (n) are redesignated as paragraphs (f),
(g), (h), (i), (j), (k) and (l), respectively to read as follows:
Sec. 34.3 Contents of application for issuance of securities.
Each application to the Commission for authority to issue
securities shall contain the information specified in this section. In
lieu of filing the information required in paragraphs (e), (i) and (j)
of this section, a specific reference may be made to the portion of the
registration statement filed under Sec. 34.4(f), which includes the
information required in these paragraphs.
* * * * *
7. In Sec. 34.4, paragraph (a) is revised, paragraphs (c), (g) and
(h) are removed, paragraphs (d) and (e) are redesignated as paragraphs
(c) and (d), respectively, and revised, and a new paragraph (e) is
added to read as follows:
Sec. 34.4 Required exhibits.
(a) Exhibit A. The applicant must file the statement of corporate
purposes from its articles of incorporation.
* * * * *
(c) Exhibit C. The Balance Sheet and attached notes for the most
recent 12-month period for which financial statements have been
published, provided that the 12-month period ended no more than 4
months prior to the date of the filing of the application, on both an
actual basis and a pro forma basis in the form prescribed for the
``Comparative Balance Sheet'' of FERC Form No. 1, ``Annual Report for
major electric utilities, licensees and others.'' Each adjustment made
in determining the pro forma basis must be clearly identified.
(d) Exhibit D. The Income Statement and attached notes for the most
recent 12-month period for which financial statements have been
published, provided that the 12-month period ended no more than 4
months prior to the date of the filing of the application, on both an
actual basis and a pro forma basis in the form prescribed for the
``Statement of Income for the Year'' of FERC Form No. 1, ``Annual
Report for major electric utilities, licensees and others.'' Each
adjustment made in determining the pro forma basis must be clearly
identified.
(e) Exhibit E. A Statement of Cash Flows and Computation of
Interest Coverage on an actual basis and a pro forma basis for the most
recent 12-month period for which financial statements have been
published, provided that the 12-month period ended no more than 4
months prior to the date of the filing of the application. The
Statement of Cash Flows must be in the form prescribed for the
``Statement of Cash Flows'' of the FERC Form No. 1, Annual Report for
major electric utilities, licensees and others,'' followed by a
computation of interest coverage, in the form of the following
worksheet:
------------------------------------------------------------------------
OMB
control
Actual No. 1902-
Federal Energy Regulatory Commission worksheet for the 0043, pro
for computation of interest coverage year forma for
ended mm- the year
dd-yy ended mm-
dd-yy
------------------------------------------------------------------------
Net income
Add: Interest on Long-Term Debt, Interest on
Short-Term Debt, Other Interest Expense, Total
Interest Expense
Federal and State Income Taxes
Income Before Interest and Income Taxes
Computation of Interest Coverage
Total Interest Expense Income Before
Interest and Income Taxes = Interest Coverage
------------------------------------------------------------------------
* * * * *
8. Section 34.10 is revised to read as follows:
Sec. 34.10 Reports.
The applicant must file reports under Sec. 131.43 and Sec. 131.50
of this chapter no later than 30 days after the sale or placement of
long-term debt or equity securities or the entry into guarantees or
assumptions of liabilities pursuant to authority granted under this
part.
PART 35--FILING OF RATE SCHEDULES
9. The authority citation for Part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
10. In Sec. 35.13, paragraph (a)(2)(i) is revised, paragraphs
(a)(2)(ii) and (a)(2)(iii) are redesignated as paragraphs (a)(2)(iii)
and (a)(2)(iv) and newly designated (a)(2)(iii) is revised, a new
paragraph (a)(2)(ii) is added, paragraph (d)(1) introductory text is
revised and paragraph (h)(24) is amended to add a
[[Page 4854]] sentence at the end of the paragraph, to read as follows:
Sec. 35.13 Filing of changes in rate schedules.
(a) General rule. * * *
(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 Sec. 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
Sec. 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 requirements 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 Sec. 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
Sec. 35.12(b)(5).
(6) The information required in paragraphs (b), (c)(2) and (c)(3)
of this section and in Sec. 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
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
short-term 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 Sec. 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 changes other than rate increases. Any
utility that files a rate schedule 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.
* * * * *
(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:
* * * * *
(h) Cost of service statements. * * *
(24) Statement AX--Other recent and pending rate changes. * * *
Notwithstanding any other provision of this section, Statement AX is
required to be filed only if the proposed rate design tracks retail
rates.
* * * * *
PART 41--ACCOUNTS, RECORDS AND MEMORANDA
11. The authority citation for Part 41 is revised to read as
follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 42 U.S.C. 7101-7352.
12. Section 41.3 is amended by adding a sentence at the end of the
section to read as follows:
Sec. 41.3 Facts and argument.
* * * If a person consents to the matter being handled under the
shortened procedure, that person has waived any right to subsequently
request a hearing under Sec. 41.7 and may not later request such a
hearing.
13. Section 41.7 is revised to read as follows:
Sec. 41.7 Assignment for oral hearing.
Except when there are no material facts in dispute, when a person
does not consent to the shortened procedure, the Commission will assign
the proceeding for hearing as provided by subpart E of part 385 of this
chapter. Notwithstanding a person's not giving consent to the shortened
procedure, and instead seeking assignment for hearing as provided for
by subpart E of part 385 of this chapter, the Commission will not
assign the proceeding for a hearing when no material facts are in
dispute. The Commission may also, in its discretion, at any stage in
the proceeding, set the proceeding for hearing.
PART 131--FORMS
14. The authority section for Part 131 is revised to read as
follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
15. Subchapter D is amended by revising the heading of the
subchapter, by revising Sec. 131.50 and by adding Sec. 131.80, to read
as follows: [[Page 4855]]
Subchapter D--Approved Forms, Federal Power Act and Public Utility
Regulatory Policies Act of 1978
PART 131--FORMS
* * * * *
Sec. 131.50 Reports of proposals received.
No later than 30 days after the sale or placement of long-term debt
or equity securities or the entry into guarantees or assumptions of
liabilities (collectively referred to as ``placement'') pursuant to
authority granted under Part 34 of this chapter, the applicant must
file a summary of each proposal or proposals received for the
placement. The proposal or proposals accepted must be indicated. The
information to be filed must include:
(a) Par or stated value of securities;
(b) Number of units (shares of stock, number of bonds) issued;
(c) Total dollar value of the issue;
(d) Life of the securities, including maximum life and average life
of sinking fund issue;
(e) Dividend or interest rate;
(f) Call provisions;
(g) Sinking fund provisions;
(h) Offering price;
(i) Discount or premium;
(j) Commission or underwriter's spread;
(k) Net proceeds to company for each unit of security and for the
total issue;
(l) Net cost to the company for securities with a stated interest
or dividend rate.
Sec. 131.80 FERC Form No. 556, Certification of qualifying facility
status for an existing or a proposed small power production or
cogeneration facility.
(See Sec. 292.207 of this chapter.)
FERC FORM 556, OMB No. 1902-0075 Expires ________
Certification of Qualifying Facility Status for an Existing or a
Proposed Small Power Production or Cogeneration Facility
(To be completed for the purpose of demonstrating up-to-date
conformance with the qualification criteria of Section 292.203(a)(1) or
Section 292.203(b), based on actual or planned operating experience)
General instructions: Part A of the form should be completed by all
small power producers or cogenerators. Part B applies to small power
production facilities. Part C applies to cogeneration facilities. All
references to sections are with regard to Part 292 of Title 18 of the
Code of Federal Regulations, unless otherwise indicated.
Part A--General Information To Be Submitted by all Applicants
1a. Full name:
Docket Number assigned to the immediately preceding submittal filed
with the Commission in connection with the instant facility, if any:
QF______-______-______.
Purpose of instant filing (self-certification or self-
recertification (Section 292.207(a)(1)), or application for Commission
certification or recertification (Sections 292.207 (b) and (d)(2))):
1b. Full address of applicant:
1c. Indicate the owner(s) of the facility (including the percentage
of ownership held by any electric utility or electric utility holding
company, or by any persons owned by either) and the operator of the
facility. Note that any combination of direct and/or indirect electric
utility or electric utility holding company ownership cannot exceed 50
percent of the total ownership (Sections 292.206 and 292.202(n)). For
non-electric utility owners, identify the upstream owners, including
owners holding 10 percent or more of the equity interest of such non-
electric utility owners. Additionally, state whether or not any of the
non-electric utility owners or their upstream owners are engaged in the
generation or sale of electric power, or have any ownership or
operating interest in any electric facilities other than qualifying
facilities. In order to facilitate review of the application, the
applicant may also provide an ownership chart identifying the upstream
ownership of the facility. Such chart should indicate ownership
percentages where appropriate.
1d. Signature of authorized individual evidencing accuracy and
authenticity of information provided by applicant:
2. Person to whom communications regarding the filed information
may be addressed:
Name:
Title:
Telephone number:
Mailing address:
3a. Location of facility to be certified:
State:
County:
City or town:
Street address (if known):
3b. Indicate the electric utilities that are contemplated to
transact with the qualifying facility (if known) and describe the
services those electric utilities are expected to provide: utilities
interconnecting with the facility and/or providing wheeling service
(Section 292.303(c) and (d)): utilities purchasing the useful electric
power output (Sections 292.101(b)(2), 292.202(g) and 292.303(a)):
utilities providing supplementary power, backup power, maintenance
power, and/or interruptible power service (Sections 292.101(b) (3) and
(8), 292.303(b) and 292.305(b)):
4a. Describe the principal components of the facility including
boilers, prime movers and electric generators, and explain their
operation. Include transmission lines, transformers and switchyard
equipment, if included as part of the facility.
4b. Indicate the maximum gross and maximum net electric power
production capacity of the facility at the point(s) of delivery and
show the derivation.
4c. Indicate the actual or expected installation and operation
dates of the facility, or the actual or expected date of completion of
the reported modification to the facility:
4d. Describe the primary energy input (e.g., hydro, coal, oil
(Section 292.202(l)), natural gas (Section 292.202(k)), solar,
geothermal, wind, waste, biomass (Section 292.202(a)), or other). For a
waste energy input that does not fall within one of the categories on
the Commission's list of previously approved wastes, demonstrate that
such energy input has little or no current commercial value and that it
exists in the absence of the qualifying facility industry (Section
292.202(b)).
5. Provide the average annual hourly energy input in terms of Btu
for the following fossil fuel energy inputs, and provide the related
percentage of the total average annual hourly energy input to the
facility (Section 292.202(j)). For any oil or natural gas fuel, use
lower heating value (Section 292.202(m)):
Natural gas:
Oil:
Coal (applicable only to a small power production facility):
6. Discuss any particular characteristic of the facility which the
cogenerator or small power producer believes might bear on its
qualifying status.
Part B--Description of the Small Power Production Facility
7. Describe how fossil fuel use will not exceed 25 percent of the
total annual energy input limit (Sections 292.202(j) and 292.204(b)).
Also, describe how the use of fossil fuel will be limited to the
following purposes to conform to Federal Power Act Section 3(17)(B):
Ignition, start-up, testing, flame stabilization, control use, and
minimal amounts of fuel required to alleviate or prevent unanticipated
equipment outages and emergencies directly affecting the
public. [[Page 4856]]
8. If the facility reported herein is not an eligible solar, wind,
waste or geothermal facility, and if any other non-eligible facility
located within one mile of the instant facility is owned by any of the
entities (or their affiliates) reported in Part A at item 1c. above and
uses the same primary energy input, provide the following information
about the other facility for the purpose of demonstrating that the
total of the power production capacities of these facilities does not
exceed 80 MW (Section 292.204(a)):
Facility name, if any (as reported to the Commission):
Commission Docket Number: QF______-______-______
Name of common owner:
Common primary energy source used as energy input:
Power production capacity (MW):
An eligible solar, wind, waste or geothermal facility, as defined
in Section 3(17)(E) of the Federal Power Act, is a small power
production facility that produces electric energy solely by the use, as
a primary energy input, of solar, wind, waste or geothermal resources,
for which either an application for Commission certification of
qualifying status (Section 292.207(b)) or a notice of self-
certification of qualifying status (Section 292.207(a)) was submitted
to the Commission not later than December 31, 1994, and for which
construction of such facility commences not later than December 31,
1999, or if not, reasonable diligence is exercised toward the
completion of such facility, taking into account all factors relevant
to construction of the facility.
Part C--Description of the Cogeneration Facility
9. Describe the cogeneration system (Sections 292.202(c) and
292.203(b)), and state whether the facility is a topping-cycle (Section
292.202(d)) or bottoming-cycle (Section 292.202(e)) cogeneration
facility.
10. To demonstrate the sequentiality of the cogeneration process
(Section 292.202(s)) and to support compliance with other requirements
such as the operating and efficiency standards (item 11 below), provide
a mass and heat balance (cycle) diagram depicting average annual hourly
operating conditions. Also, provide:
Using lower heating value (Section 292.202(m)), all fuel flow
inputs in Btu/hr., separately indicating fossil fuel inputs for any
supplementary firing in Btu/hr. (Section 292.202(f)):
Average net electric output (kW or MW) (Section 292.202(g));
Average net mechanical output in horsepower (Section 292.202(g));
Number of hours of operation used to determine the average annual
hourly facility inputs and outputs; and
Working fluid (e.g., steam) flow conditions at input and output of
prime mover(s) and at delivery to and return from each useful thermal
application:
Flow rates (lbs./hr.):
Temperature (deg.F):
Pressure (psia):
Enthalpy (Btu/lb.):
11. Compute the operating value (applicable to a topping-cycle
facility under Section 292.205(a)(1)) and the efficiency value
(Sections 292.205(a)(2) and Section 292.205(b)), based on the
information provided in and corresponding to item 10, as follows:
Pt=Average annual hourly useful thermal energy output
Pe=Average annual hourly electrical output
Pm=Average annual hourly mechanical output
Pi=Average annual hourly energy input (natural gas or oil)
Ps=Average annual hourly energy input for supplementary firing
(natural gas or oil)
Operating standard=5% or more
Operating value=Pt/(Pt+Pe+Pm)
Efficiency standard applicable to natural gas and oil fuel used in
a topping-cycle facility:
=45% or more when operating value is less than 15%, or 42.5% or more
when operating value is equal to or greater than 15%.
Efficiency value=(Pe+Pm+0.5Pt)/(Pi+Ps)
Efficiency standard applicable to natural gas and oil fuel used for
supplementary firing component of a bottoming-cycle facility:
=45% or more
Efficiency value=(Pe+Pm)/Ps
For Topping-Cycle Cogeneration Facilities
12. Identify the entity (i.e., thermal host) which will purchase
the useful thermal energy output from the facility (Section
292.202(h)). Indicate whether the entity uses such output for the
purpose of space and water heating, space cooling, and/or process use.
13. In connection with the requirement that the thermal energy
output be useful (Section 292.202(h)):
For process uses by commercial or industrial host(s), describe each
process (or group of similar processes using the same quality of steam)
and provide the average annual hourly thermal energy made available to
the process, less process return. For a complex system, where the
primary steam header at the host-side is divided into various sub-uses,
each having different pressure and temperature characteristics,
describe the processes associated with each sub-use and provide the
average annual hourly thermal energy delivered to each sub-use, less
process return from such sub-use. Provide a diagram showing the main
steam header and the sub-uses with other relevant information such as
the average header pressure (psia), the temperature (deg.F), the
enthalpy (Btu/lb.), and the flow (lb./hr.), both in and out of each
sub-use. For space and water heating, describe the type of heating
involved (e.g., office space heating, domestic water heating) and
provide the average annual hourly thermal energy delivered and used for
such purpose. For space cooling, describe the type of cooling involved
(e.g., office space cooling) and provide the average annual hourly
thermal energy used by the chiller.
For Bottoming-Cycle Facilities
14. Provide a description of the commercial or industrial process
or other thermal application to which the energy input to the system is
first applied and from which the reject heat is then used for electric
power production.
PART 292--REGULATIONS UNDER SECTIONS 201 AND 210 OF THE PUBLIC
UTILITY REGULATORY POLICIES ACT OF 1978 WITH REGARD TO SMALL POWER
PRODUCTION AND COGENERATION
16. The authority citation for Part 292 is revised to read as
follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
17. In Sec. 292.101, paragraph (b)(1) is revised to read as
follows:
Sec. 292.101 Definitions.
* * * * *
(b) Definitions. * * *
(1) Qualifying facility means a cogeneration facility or a small
power production facility that is a qualifying facility under Subpart B
of this part.
(i) A qualifying facility may include transmission lines and other
equipment used for interconnection purposes (including transformers and
switchyard equipment), if:
(A) Such lines and equipment are used to supply power output to
directly and indirectly interconnected electric utilities, and to end
users, including thermal hosts, in accordance with state law; or
(B) Such lines and equipment are used to transmit supplementary,
standby, maintenance and backup power to the qualifying facility,
[[Page 4857]] including its thermal host meeting the criteria set forth
in Union Carbide Corporation, 48 FERC 61,130, reh'g denied, 49 FERC
61,209 (1989), aff'd sub nom., Gulf States Utilities Company v. FERC,
922 F.2d 873 (D.C. Cir. 1991); or
(C) If such lines and equipment are used to transmit power from
other qualifying facilities or to transmit standby, maintenance,
supplementary and backup power to other qualifying facilities.
(ii) The construction and ownership of such lines and equipment
shall be subject to any applicable Federal, state, and local siting and
environmental requirements.
* * * * *
18. In Sec. 292.202, paragraphs (b), (d), (e) and (h) are revised
and paragraph (s) is added to read as follows:
Sec. 292.202 Definitions.
* * * * *
(b) Waste means an energy input that is listed below in this
subsection, or any energy input that has little or no current
commercial value and exists in the absence of the qualifying facility
industry. Should a waste energy input acquire commercial value after a
facility is qualified by way of Commission certification pursuant to
Sec. 292.207(b), or self-certification pursuant to Sec. 292.207(a), the
facility will not lose its qualifying status for that reason. Waste
includes, but is not limited to, the following materials that the
Commission previously has approved as waste:
(1) Anthracite culm produced prior to July 23, 1985;
(2) Anthracite refuse that has an average heat content of 6,000 Btu
or less per pound and has an average ash content of 45 percent or more;
(3) Bituminous coal refuse that has an average heat content of
9,500 Btu per pound or less and has an average ash content of 25
percent or more;
(4) Top or bottom subbituminous coal produced on Federal lands or
on Indian lands that has been determined to be waste by the United
States Department of the Interior's Bureau of Land Management (BLM) or
that is located on non-Federal or non-Indian lands outside of BLM's
jurisdiction, provided that the applicant shows that the latter coal is
an extension of that determined by BLM to be waste.
(5) Coal refuse produced on Federal lands or on Indian lands that
has been determined to be waste by the BLM or that is located on non-
Federal or non-Indian lands outside of BLM's jurisdiction, provided
that applicant shows that the latter is an extension of that determined
by BLM to be waste.
(6) Lignite produced in association with the production of montan
wax and lignite that becomes exposed as a result of such a mining
operation;
(7) Gaseous fuels, except:
(i) Synthetic gas from coal; and
(ii) Natural gas from gas and oil wells unless the natural gas
meets the requirements of Sec. 2.400 of this chapter;
(8) Petroleum coke;
(9) Materials that a government agency has certified for disposal
by combustion;
(10) Residual heat;
(11) Heat from exothermic reactions;
(12) Used rubber tires;
(13) Plastic materials; and
(14) Refinery off-gas.
* * * * *
(d) Topping-cycle cogeneration facility means a cogeneration
facility in which the energy input to the facility is first used to
produce useful power output, and at least some of the reject heat from
the power production process is then used to provide useful thermal
energy;
(e) Bottoming-cycle cogeneration facility means a cogeneration
facility in which the energy input to the system is first applied to a
useful thermal energy application or process, and at least some of the
reject heat emerging from the application or process is then used for
power production;
* * * * *
(h) Useful thermal energy output of a topping-cycle cogeneration
facility means the thermal energy:
(1) That is made available to an industrial or commercial process
(net of any heat contained in condensate return and/or makeup water);
(2) That is used in a heating application (e.g., space heating,
domestic hot water heating); or
(3) That is used in a space cooling application (i.e., thermal
energy used by an absorption chiller).
* * * * *
(s) Sequential use of energy means:
(1) For a topping-cycle cogeneration facility, the use of reject
heat from a power production process in sufficient amounts in a thermal
application or process to conform to the requirements of the operating
standard; or
(2) For a bottoming-cycle cogeneration facility, the use of reject
heat from a thermal application or process, at least some of which is
then used for power production.
19. In Sec. 292.204, paragraphs (a)(1) and (b)(2) are revised to
read as follows:
Sec. 292.204 Criteria for qualifying small power production
facilities.
(a) Size of the facility.--(1) Maximum size. There is no size
limitation for an eligible solar, wind, waste or facility, as defined
by section 3(17)(E) of the Federal Power Act. For a non-eligible
facility, the power production capacity for which qualification is
sought, together with the power production capacity of any other non-
eligible small power production facilities that use the same energy
resource, are owned by the same person(s) or its affiliates, and are
located at the same site, may not exceed 80 megawatts.
* * * * *
(b) Fuel use. * * *
(2) Use of oil, natural gas and coal by a facility, under section
3(17)(B) of the Federal Power Act, is limited to the minimum amounts of
fuel required for ignition, startup, testing, flame stabilization, and
control uses, and the minimum amounts of fuel required to alleviate or
prevent unanticipated equipment outages, and emergencies, directly
affecting the public health, safety, or welfare, which would result
from electric power outages. Such fuel use may not, in the aggregate,
exceed 25 percent of the total energy input of the facility during the
12-month period beginning with the date the facility first produces
electric energy and any calendar year subsequent to the year in which
the facility first produces electric energy.
20. In Sec. 292.205, paragraphs (a)(1), (a)(2)(i) introductory
text, and (b)(1) are revised to read as follows:
Sec. 292.205 Criteria for qualifying cogeneration facilities.
(a) Operating and efficiency standards for topping-cycle
facilities.
(1) Operating standard. For any topping-cycle cogeneration
facility, the useful thermal energy output of the facility must be no
less than 5 percent of the total energy output during the 12-month
period beginning with the date the facility first produces electric
energy, and any calendar year subsequent to the year in which the
facility first produces electric energy.
(2) Efficiency standard. (i) For any topping-cycle cogeneration
facility for which any of the energy input is natural gas or oil, and
the installation of which began on or after March 13, 1980, the useful
power output of the facility plus one-half the useful thermal energy
output, during the 12-month period beginning with the date the facility
first produces electric energy, and any calendar year subsequent to the
year in which the facility first produces electric energy, must:
* * * * *
(b) Efficiency standards for bottoming-cycle facilities. (1) For
any bottoming-cycle cogeneration facility for which [[Page 4858]] any
of the energy input as supplementary firing is natural gas or oil, and
the installation of which began on or after March 13, 1980, the useful
power output of the facility during the 12-month period beginning with
the date the facility first produces electric energy, and any calendar
year subsequent to the year in which the facility first produces
electric energy must be no less than 45 percent of the energy input of
natural gas and oil for supplementary firing.
* * * * *
21. In Sec. 292.207, paragraphs (a), (b) and (d) are revised to
read as follows:
Sec. 292.207 Procedures for obtaining qualifying status.
(a) Self-certification and pre-authorized Commission
recertification.--(1) Self-certification. (i) A small power production
facility or cogeneration facility that meets the applicable criteria
established in Sec. 292.203 is a qualifying facility.
(ii) The owner or operator of a facility or its representative
self-certifying under this section must file with the Commission, and
concurrently serve on each electric utility with which it expects to
interconnect, transmit or sell electric energy to or purchase
supplementary, standby, back-up and maintenance power, and the State
regulatory authority of each state where the facility and each affected
utility is located, a notice of self-certification which contains a
completed Form 556.
(iii) Subsequent notices of self-recertification for the same
facility may reference prior notices or prior Commission
certifications, and need only refer to changes which have occurred with
respect to the facility since the prior notice or the prior Commission
certification.
(iv) Notices of self-certification or self-recertification will not
be published in the Federal Register.
(2) Pre-authorized Commission recertification. (i) For purposes of
paragraph (b) of this section, the following alterations or
modifications are not considered substantial alterations or
modifications and will not result in revocation of qualifying status
previously granted by the Commission pursuant to paragraph (b) of this
section:
(A) A change which does not affect the upstream ownership of the
facility;
(B) A change in the installation or operation date;
(C) A change in the manufacturer of the power generation equipment
selected for the facility's installation when there is no change in
capacity or operating characteristics;
(D) A change in the location of a cogeneration facility, or a small
power production facility, if the new location would not cause the
facility to violate the 80 MW limitation of Sec. 292.204(a)(1);
(E) A decrease in the amount of natural gas or oil or any change in
the amount of other fuel used by a cogeneration facility, provided that
the efficiency value and the operating value calculation for the
facility remain at or above the values stated when the certification or
recertification order was issued;
(F) A decrease in the amount of fossil fuel used by a small power
production facility;
(G) A change in the primary energy source of a small power
production facility, provided that the facility continues to comply
with the requirements of Sec. 292.204;
(H) An additional use of a cogeneration facility's thermal output,
if the original uses are as stated when the certification order was
issued;
(I) An increase in the efficiency value of a cogeneration facility
or an increase in the operating value of a cogeneration facility
determined in accordance with Sec. 292.205;
(J) A decrease in the power production capacity of a small power
production facility;
(K) A change in the power production capacity of a cogeneration
facility if the efficiency value and the operating value calculation
for the facility remain at or above the values stated when the
certification or recertification order was issued; or
(L) A change in the purchaser of the cogeneration facility's
thermal output, when there is no change in the specified thermal
application or process.
(ii) The owner or operator of a qualifying facility that has been
certified under paragraph (b) of this section must file with the
Commission notice of each change listed in this subsection, and must
concurrently serve a copy of such notice on each electric utility with
which it expects to interconnect, transmit or sell electric energy to,
or purchase supplementary, standby, back-up and maintenance power, and
the State regulatory authority of each state where the facility and
each affected electric utility is located.
(b) Optional procedure--(1) Application for Commission
certification. In lieu of the certification procedures in paragraph (a)
of this section, an owner or operator of a facility or its
representative may file with the Commission an application for
Commission certification that the facility is a qualifying facility.
The application must be accompanied by the fee prescribed by part 381
of this chapter.
(2) General contents of application. The application must include a
completed Form 556.
(3) Commission action. (i) Within 90 days of the later of the
filing of an application or the filing of a supplement, amendment or
other change to the application, the Commission will either: inform the
applicant that the application is deficient; or issue an order granting
or denying the application; or toll the time for issuance of an order.
Any order denying certification shall identify the specific
requirements which were not met. If the Commission does not act within
90 days of the date of the latest filing, the application shall be
deemed to have been granted.
(ii) For purposes of paragraph (b) of this section, the date an
application is filed is the date by which the Office of the Secretary
has received all of the information and the appropriate filing fee
necessary to comply with the requirements of this Part.
(4) Notice. (i) Applications for certification filed under
paragraph (b) of this section must include a copy of a notice of the
request for certification for publication in the Federal Register. The
notice must state the applicant's name, the date of the application, a
description of the facility for which qualification is sought and, if
known, the names of the electric utilities to which the facility
expects to interconnect, transmit or sell electric energy, or from
which the facility expects to purchase supplementary, standby, back-up
and maintenance power. This description must include:
(A) A statement indicating whether such facility is a small power
production facility or a cogeneration facility;
(B) The primary energy source used or to be used by the facility;
(C) The power production equipment and capacity of the facility;
and
(D) The location of the facility.
(ii) The notice must be in the following form:
(Name of Applicant)
Docket No. QF-
NOTICE OF APPLICATION FOR COMMISSION CERTIFICATION OF QUALIFYING STATUS
OF A (SMALL POWER PRODUCTION) (COGENERATION) FACILITY
On (date application was filed), (name and address of applicant)
filed with the Federal Energy Regulatory Commission an application
for certification (or recertification) of a facility as a qualifying
(small power production) (cogeneration) facility pursuant to
Sec. 292.207(b) of the [[Page 4859]] Commission's regulations. No
determination has been made that the submittal constitutes a
complete filing.
[Description of facility.]
[Names of the electric utilities with which the facility expects to
interconnect, transmit or sell electric energy to, or purchase
supplementary, standby, back-up and maintenance power (if known).]
Any person who wishes to be heard or to object to granting
qualifying status should file a motion to intervene or protest with
the Federal Energy Regulatory Commission, 825 North Capitol Street,
NE., Washington, DC 20426, in accordance with rules 211 and 214 of
the Commission's Rules of Practice and Procedure. A motion or
protest must be filed within ______ days after the date of
publication of this notice and must be served on the applicant.
Protests will be considered by the Commission in determining the
appropriate action to be taken but will not serve to make
protestants parties to the proceeding. A person who wishes to become
a party must file a motion to intervene. Copies of this application
are on file with the Commission and are available for public
inspection.
* * * * *
(d) Revocation of qualifying status (1)(i) If a qualifying facility
fails to conform with any material facts or representations presented
by the cogenerator or small power producer in its submittals to the
Commission, the notice of self-certification of the qualifying status
of the facility, pre-authorized Commission re-certification notice, or
Commission order certifying the qualifying status of the facility may
no longer be relied upon. At that point, if the facility continues to
conform to the Commission's qualifying criteria under this part, the
cogenerator or small power producer may file either a notice of self-
recertification of qualifying status pursuant to the requirements of
paragraph (a)(1) of this section, a pre-authorized Commission
recertification notice pursuant to the requirements of paragraph (a)(2)
of this section, or an application for Commission recertification
pursuant to the requirements of paragraph (b) of this section, as
appropriate.
(ii) The Commission may, on its own motion or on the motion of any
person, revoke the qualifying status of a facility that has been
certified under paragraph (b) of this section, if the facility fails to
conform to any of the Commission's qualifying facility criteria under
this part.
(iii) The Commission may revoke the qualifying status of a self-
certified qualifying facility upon the filing of a petition for a
declaratory order that the self-certified qualifying facility does not
meet applicable requirements for qualifying facilities.
(2) Prior to undertaking any substantial alteration or modification
of a qualifying facility which has been certified under paragraph (b)
of this section, a small power producer or cogenerator may apply to the
Commission for a determination that the proposed alteration or
modification will not result in a revocation of qualifying status. This
application for Commission recertification of qualifying status should
be submitted in accordance with paragraph (b) of this section.
PART 294--PROCEDURES FOR SHORTAGES OF ELECTRIC ENERGY AND CAPACITY
UNDER SECTION 206 OF THE PUBLIC UTILITY REGULATORY POLICIES ACT OF
1978
22. The authority citation for Part 294 is revised to read as
follows:
Authority: 5 U.S.C. 553; 16 U.S.C. 791a-825r; 42 U.S.C. 7107-
7352.
23. In Sec. 294.101, paragraphs (b)(5) and (f) are added as
follows:
Sec. 294.101 Shortages of electric energy and capacity.
* * * * *
(b) Accommodation of shortages. * * *
(5) Notwithstanding any other provision of this section, a public
utility need not file the statement with the Commission if the public
utility provides in its rate schedules to firm power wholesale
customers that:
(i) During electric energy and capacity shortages it will treat
without undue discrimination or preference, prejudice, or disadvantage
firm power wholesale customers; and
(ii) It will report any modifications to its contingency plans for
accommodating shortages within 15 days to:
(A) The appropriate State regulatory agency and
(B) To the affected wholesale customers.
* * * * *
(f) Report of anticipated shortage. Notwithstanding any other
provision of this part, if a public utility provides in its rate
schedule that it will make such reports to the appropriate state
regulatory agency and to its firm power wholesale requirements
customers, then it need only report to the Commission the nature and
projected duration of the anticipated capacity or energy supply
shortage and supply a list of the firm power wholesale customers
affected or likely to be affected by the shortage. Upon receiving the
public utility's report of anticipated shortage of electric energy or
capacity, the Commission will decide what further reports, if any, to
require.
PART 382--ANNUAL CHARGES
24. The authority citation for part 382 is revised to read as
follows:
Authority: 5 U.S.C 551-557; 15 U.S.C 717-717w, 3301-3432; 16
U.S.C. 791a-825r, 2601-2645; 42 U.S.C. 7101-7352; 49 U.S.C. 60502;
49 App. U.S.C. 1-85.
25. In Sec. 382.102, paragraphs (h), (i), (j) and (k) are revised,
paragraphs (l), (m) and (n) are removed, and paragraphs (o), (p), (q),
(r) and (s) are redesignated (l), (m), (n), (o) and (p), respectively
to read as follows:
Sec. 382.102 Definitions.
* * * * *
(h) Long-term firm sales and transmission activities means the
portion of the Commission's electric regulatory program devoted to the
regulation of long-term firm sales and transmission.
(1) Long-term firm sales are the jurisdictional sales of capacity
and energy under contracts that do not anticipate service
interruptions, and are of five years or more duration. The capacity and
energy must be available to a resale customer at all times during the
period covered by a commitment, even under adverse conditions. This
includes sales supplying the full requirements or partial requirements
of a customer, and sales of energy from unit or system capacity of a
long-term duration (five years or more) under contracts that do not
anticipate service interruptions when capacity is operationally
available. These sales are those reported in the FERC Form No. 1 in
Account 447 as Sales-for-Resale transactions with statistical
classifications of RQ, LF or LU or sales determined on a basis
consistent with FERC Form No. 1 reporting for those public utilities
exempt from Sec. 141.1 of this chapter.
(2) Long-term firm transmission is jurisdictional transmission of
capacity and energy under contracts that do not anticipate service
interruptions, and are of one year or more duration. This transmission
is that reported in the FERC Form No. 1 in Account 456 as Transmission
for Others transactions with the statistical classification of LF or
transmission for others determined on a basis consistent with FERC Form
No. 1 reporting for those public utilities exempt from Sec. 141.1 of
this chapter. All MWhs attributable to sales and transmission
transactions are to be reported in their respective accounts on the
FERC Form No. 1 irrespective of the method of billing. [[Page 4860]]
(i) Short-term sales and transmission and exchange activities means
the portion of the Commission's electric regulatory program consisting
of the regulation of all jurisdictional sales, exchange and
transmission of capacity and energy except those described in paragraph
(h) of this section. This includes exchange delivered as reported in
the FERC Form No. 1 in Account 555 as Gross Exchange Delivered
transactions with the statistical classification of EX or gross
exchange delivered determined on a basis consistent with FERC Form No.
1 reporting for those public utilities exempt from Sec. 141.1 of this
chapter. All MWhs attributable to sales and transmission transactions
are to be reported in their respective accounts in the FERC Form No. 1
irrespective of the method of billing.
(j) Long-term firm sales and transmission megawatt-hours means the
number of megawatt-hours of electrical energy associated with the
transactions described in paragraph (h) of this section, and the rates,
charges, terms and conditions of which are regulated by the Commission.
(k) Short-term sales and transmission and exchange megawatt-hours
means the number of megawatt-hours of electrical energy associated with
the transactions described in paragraph (i) of this section, the rates,
charges, terms and conditions of which are regulated by the Commission.
* * * * *
26. In Sec. 382.201, paragraph (a) and (b) are revised and the
worksheet in paragraph (b)(4)(ii) is removed, to read as follows:
Sec. 382.201 Annual charges under Parts II and III of the Federal
Power Act and related statutes.
(a) Determination of costs to be assessed against public utilities.
The adjusted costs of administration of the electric regulatory
program, excluding the costs of regulating the Power Marketing Agencies
and any electrical programs for which separate application fees are
collected, will be apportioned between long-term firm sales and
transmission activities and short-term sales and transmission and
exchange activities in proportion to the total staff time dedicated to
each. The amount apportioned to long-term firm sales and transmission
activities will constitute long-term firm sales and transmission costs,
and the amount apportioned to short-term sales and transmission and
exchange activities will constitute short-term sales and transmission
and exchange costs.
(b) Determination of annual charges to be assessed against public
utilities. (1) The long-term firm sales and transmission costs
determined under paragraph (a) of this section will be assessed against
each public utility based on the proportion of the long-term firm sales
and transmission megawatt-hours of each public utility in the
immediately preceding reporting year (either a calendar year or fiscal
year, depending on which accounting convention is used by the public
utility to be charged) to the sum of the long-term firm sales and
transmission megawatt-hours in the immediately preceding reporting year
of all public utilities being assessed annual charges.
(2) The short-term sales and transmission and exchange costs
determined under paragraph (a) of this section will be assessed against
each public utility based on the proportion of the short-term sales and
transmission and exchange megawatt-hours of each public utility in the
immediately preceding reporting year (either a calendar year or fiscal
year, depending on which accounting convention is used by the public
utility to be charged) to the sum of the short-term sales and
transmission and exchange megawatt-hours in the immediately preceding
reporting year of all public utilities being assessed annual charges.
(3) The annual charges assessed against each public utility will be
the sum of the amounts determined in paragraphs (b)(1) and (b)(2) of
this section.
(4) Reporting requirement. For purposes of computing annual
charges, a public utility, as defined in Sec. 382.102(b) must submit
under oath to the Office of the Secretary by April 30 of each year an
original and conformed copies of the following information (designated
as FERC Reporting Requirement No. 582):
(i) The total annual long-term firm sales for resale and
transmission megawatt-hours as defined in Sec. 382.102(j); and
(ii) The total annual short-term sales, transmission and exchange
megawatt-hours as defined in Sec. 382.102(k).
* * * * *
PART 385--RULES OF PRACTICE AND PROCEDURE
27. The authority citation for Part 385 continues to read as
follows:
Authority: 5 U.S.C. 551-557; 15 U.S.C. 717-717z, 3301-3432; 16
U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; 49
U.S.C. 60502; 49 App. U.S.C. 1-85.
Sec. 385.702 [Amended]
28. In Sec. 385.702, paragraph (b) is removed, and paragraph (c) is
redesignated paragraph (b).
Sec. 385.708 [Amended]
29. In Sec. 385.708, in paragraph (b)(1), the phrase ``and, if
appropriate under Rule 717, a written revised initial decision'' is
removed; in paragraph (b)(2)(i), the phrase ``or oral revised initial''
is removed; in paragraph (b)(3), the phrase ``or, if appropriate under
Rule 717, any revised initial decision'' is removed; in paragraph
(b)(4), the phrase ``as appropriate'' is removed and the phrase ``or
revised initial'' is removed in both places where it appears; in
paragraph (c), in the heading the phrase ``and revised initial'' is
removed; in paragraph (c)(1), the phrase ``or, if appropriate, the
revised initial decision'' is removed; in paragraph (c)(2), the phrase
``or revised initial'' is removed; and in paragraph (d), in the heading
the phrase ``and revised initial'' and in the text the phrase ``or, if
appropriate under Rule 717, a revised initial decision'' are removed.
30. In Sec. 385.711, in the heading the phrase ``or revised
initial'' is removed, and in paragraph (a)(1)(i), the phrase ``In
proceedings not subject to Rule 717,'' is removed, and the word ``Any''
is capitalized.
Sec. 385.712 [Amended]
31. In Sec. 385.712, in the heading the phrase ``and revised
initial'' is removed and in paragraph (a) the phrase ``or revised
initial'' is removed.
Sec. 385.713 [Amended]
32. In Sec. 385.713, in paragraph (a)(2)(i), the phrase ``or, if
appropriate under Rules 717 and 711, to a revised initial decision'' is
removed; in paragraph (a)(2)(iv), the phrase ``or revised'' is removed;
and in paragraph (a)(3), the phrase ``or any revised initial decision
under Rule 717'' is removed.
Sec. 385.717 [Removed]
33. Section 385.717 is removed.
[FR Doc. 95-1449 Filed 1-24-95; 8:45 am]
BILLING CODE 6717-01-P
