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AVERAGE SYSTEM COST

METHODOLOGY

ADMINISTRATOR'S RECORD

OF

DECISION

BONNEVILLE POWER ADMINISTRATION

U.S. DEPARTMENT OF ENERGY

June 1984

1984 AVERAGE SYSTEM COST

METHODOLOGY PROPOSAL

(BPA File No. ASC-83)

BONNEVILLE POWER ADMINISTRATION

U.S. DEPARTMENT OF ENERGY

JUNE 1984

ADMINISTRATOR'S RECORD OF DECISION

[TABLE OF CONTENTS]{.underline}

\[page numbers refer to original document\]

[Chapter]{.underline} [Page]{.underline}

Introduction 1

Chapter 1 (Background) 4

A. Relevant Statutory Provisions 4

B. The Current Average System Cost Methodology 10

Chapter Two (Initiation of the Current Consultation Proceeding) 15

A. Procedural History 15

B. The Nature Of Consultation Proceedings Under Section 5(c) 20

C. The Timing Of The Current Consultation Proceeding 25

D. Allegations Of Bias Or Predisposition 27

Chapter Three (BPA's Proposal of February 3, 1984) 30

Chapter Four (Resolution of Substantive Issues 33

I. THE SOURCE OF DATA FOR THE AVERAGE SYSTEM COST\
METHODOLOGY 33

A. Summary of Proposals 33

B. Decision 34

II\. DETERMINATION OF WHETHER TRANSMISSION COSTS SHOULD BE CONSIDERED
RESOURCE COSTS WITHIN THE MEANING OF\
SECTION 5(c) 36

A. Summary of Proposals 36

B. Evaluation of Positions 39

C. Decision 40

III\. SUBSIDIZATION OF CONSTRUCTION WORK IN PROGRESS 44

A. Summary Of Proposals 44

B. Evaluation Of Positions 46

C. Decision 47

IV\. TREATMENT OF EQUITY RETURN 48

A. Summary Of Proposals 48

B. Discussion of Positions And Decision 53

V. TREATMENT OF INCOME TAXES IN THE RESIDENTIAL EXCHANGE 56

A. Summary Of Proposals 56

B. Analysis Of Positions And Decision 58

1\. Statutory Analysis 58

2\. Legal And Policy Analysis 59

3\. Conclusion 63

VI\. DETERMINATION OF GENERATING RESOURCES INCLUDABLE\
IN THE COMPUTATION OF AVERAGE SYSTEM COST 64

A. Summary of Positions 64

B. Discussion Of Positions And Decision 66

VII\. TREATMENT OF AFFILIATED FUEL COSTS IN CALCULATING ASC 67

A. Summary of Positions 67

B. Discussion of Positions And Decision 68

VIII\. CONSERVATION COSTS INCLUDABLE IN THE CALCULATION\
OF ASC 69

A. Summary Of Positions 69

B. Discussion Of Positions And Decision 72

IX\. FUNCTIONALIZATION BETWEEN SUBSIDIZED AND\
NONSUBSIDIZED ACCOUNTS 75

A. Summary of Positions 75

B. Discussion of Positions 78

C. Decision 79

Chapter Five (BPA Review Procedures) 86

A. Summary of Proposals 86

B. Decision 87

Chapter Six (Implementation of The Reformed Methodology) 93

A. Summary Of Positions 93

B. Decision 94

Chapter Seven (Findings And Conclusion 95

INDEX TO THE OFFICIAL RECORD

ABBREVIATIONS OF COMMENTING PARTIES

AVERAGE SYSTEM COST METHODOLOGY

**INTRODUCTION**

This Record of Decision culminates the statutory consultation proceeding
begun last October 7, 1983. 48 Fed. Reg. 45829. A comprehensive record
of some 7,000 pages has been compiled through public comments, hearings
and negotiation sessions. The record has been of considerable utility in
probing the arguments of interested parties on the determination of a
methodology for calculating the average system cost of resources (ASC)
which sets the residential exchange subsidy paid by Bonneville Power
Administration (BPA) to certain Pacific Northwest electric utilities.

Significant features of the ASC methodology adopted in this Record of
Decision include:

1\. Retention of the so-called jurisdictional approach under which
retail rate orders of regulatory agencies are used as the primary source
of data for computing the ASC for utilities participating in the
residential exchange. However, BPA will carry out its statutory role
through an independent determination of the validity of all data
submitted in ASC filings recognizing the different purposes of ASC
filing review and retail rate regulation. This independent determination
will require greater involvement in retail rate cases of utilities
participating in the residential exchange program.

2\. Inclusion of transmission costs in the calculation of ASC, with a
review of all future transmission plant additions to ensure that they
are not redundant of the existing transmission grid.

3\. Exclusion of all Construction Work In Progress from the calculation
of ASC.

4\. Use of a participating utility's weighted cost of debt securities to
determine a return component of ASC. This is intended to eliminate the
potential for utilities to recover terminated power plant costs
indirectly through their jurisdictionally allowed equity returns and
capital structures.

5\. Exclusion of income taxes from ASC, meaning that BPA will no longer
subsidize the income taxes of participating utilities. Income taxes are
not a cost of resources within the meaning of Section 5(c) of the
Northwest Power Act.

6\. Simplification of procedures for functionalizing (separating) costs
between subsidized generation and transmission accounts, and
nonsubsidized distribution and "other" accounts.

7\. Clarification of Section VI, *Change In Average System Cost
Methodology*, of the current ASC Methodology to better reflect the
purpose of the rule. Once an ASC Methodology is adopted in a
record-building proceeding, the Administrator may retain that
methodology for at least one year after implementation so that
experience may be gained thereunder before it is subject to further
revision or change.

8\. Changes in the timetable for BPA review of individual ASC filings to
permit more thorough analysis.

9\. "Phase-in" of the reformed ASC methodology in order to minimize the
retail rate effects of the change in methodology. Under the phase-in,
the new methodology would be implemented by the Commission on July 1,
1984, the date on which participating utilities qualify to exchange 90
percent of their residential loads under Section 5(c) of the Northwest
Power Act. However, for the ensuing 12-month period, the actual ASC
subsidy for each participating utility would be determined as the
average of the ASC in effect on July 1, 1984, and the ASC calculated
under the new methodology. On July 1, 1985, the new methodology would
become the exclusive means of determining the ASC of each participating
utility.

10\. Each exchanging utility is required to file under the new
methodology within 20 days after implementation by the Federal Energy
Regulatory Commission. Any utility failing to do so, will have its ASC
deemed equal to zero until compliance occurs.

Of the ten major utilities participating in the residential exchange
program, the revised ASC methodology will substantially affect only
three: Portland General Electric Co., Pacific Power & Light Co., and
Utah Power & Light Co. Four of the other seven are presently in a
"deeming" *See* page 6, below) status because their existing ASC is less
than or equal to BPA's priority firm power rate. Under the revised
methodology adopted in this decision, BPA estimates that it will
continue to pay a residential exchange subsidy of approximately \$170
million per year through the residential exchange program.

**CHAPTER ONE**

**BACKGROUND**

**A. Relevant Statutory Provisions**

Section 5(c)(1) of the Northwest Power Act, 16 U.S.C. §839c(c)(1),
provides that BPA shall acquire certain amounts of power offered for
sale by Pacific Northwest electric utilities. In exchange, BPA offers to
sell "an equivalent amount of electric power to such utility for resale
to that utility's residential users within the region.[^1] *See*,
*generally*, H.R. Rep. No. 976, Part I, 96th Cong., 2d Sess. at 60
(1980). Sales to the utility may not be restricted below the amount of
power acquired from the utility. *See* section 5(c)(6).

The residential exchange is not a conventional power transaction. There
is no power transferred either to or from BPA.[^2] System schedulers do
not dispatch the exchange; line losses are not incurred. "In practice,
only dollars are exchanged, not electric power." *Public Utility
Commissioner of Oregon v. BPA*, Civil No. 84-270-PA, slip op. at 6 (D.
Or. March 21, 1984). "In essence, what really happens is \[that) BPA
writes a check to the utility; no power actually flows back and forth."
Comments of Portland City Commissioner Lindberg, R. 716. "You \[BPA\]
pay 150 or 250 million dollars a year, and you don't get any kilowatts
or kilowatt hours for it, but you keep paying." Oral comments of Pacific
Power & Light Co. (R. 2325).

The power sale concept was created by Congress for BPA ratemaking
purposes. *E.g.*, section 7(b)(1).[^3] Practically speaking, the purpose
of the residential exchange is to provide a subsidy to exchanging
utilities. Costs subsidized by BPA do not have to be recovered in the
retail rates charged to the residential customers of exchanging
utilities.

BPA exchange power is priced at the same rate as that for general
requirements sales to preference customers (the "priority firm rate").
*See*, section 7(b)(1) of the Northwest Power Act, 16 U.S.C.
§839e(b)(1). In contrast, the amount paid by BPA to the participating
utility is not a conventional power rate. Section 5(c)(1) states that
BPA is to pay "the average system cost of that utility's resources." 16
U.S.C. §839c(c)(1). Section 5(c)(7) of the Northwest Power Act gives
BPA's Administrator the discretionary authority to determine average
system cost (ASC) on the basis of the methodology to be established in
consultation proceedings. 16 U.S.C. §839c(c)(7). The only express
statutory limits on the Administrator's authority are found in section
5(c)(7)(A), (B) and (C),

The residential exchange subsidy, sometimes referred to as "wholesale
rate parity" with BPA's wholesale preference customers, was intended to
give residential ratepayers of investor-owned utilities a form of access
to low-cost Federal hydroelectric resources. Wholesale rate parity was
the first attribute of the residential exchange originally intended by
Congress.[^4]

Under section 5(c) of the Northwest Power Act, wholesale rate parity was
to work in two directions. Whenever the BPA priority firm rate is lower
than a participating utility's ASC, BPA would pay a subsidy to that
utility. However, that exchanging utility could owe an exchange payment
to BPA when its ASC was lower than BPA's wholesale preference rate. This
symmetry was destroyed by the residential purchase and sale contracts
executed by BPA and the utilities participating in the residential
exchange. Under the so-called "deemer" clause found in section 10 of
these contracts, the exchanging utility has a unilateral right to "deem"
its average system cost equal to BPA's preference rate whenever it might
otherwise owe money to BPA under the residential exchange.[^5] The
residential exchange only works to the advantage of participating
utilities; it never lowers the rates of BPA customers. Because of the
deemer clause, exchanging investor-owned utilities now have the
assurance that their resource costs will be equal to, or actually less
than, BPA's wholesale preference rate. Instead of creating wholesale
rate parity, the deemer provision of residential exchange contracts may
actually reverse the rate disparity that Congress sought to eliminate.
*See* comments of Public Power Council (May 13, 1983) (R. 84-85).[^6]

In section 5(c)(7), Congress provided an express mechanism for
formulation of an electric utility's "average system cost" (ASC).
Section 5(c)(7) states:

> The 'average system cost' for electric power sold to the Administrator
> under this subsection shall be determined by the Administrator on the
> basis of a methodology developed for this purpose in consultation with
> the Council, the Administrator's customers, and appropriate State
> regulatory bodies in the region. Such methodology shall be subject to
> review and approval by the Federal Energy Regulatory Commission. Such
> average system cost shall not include \--
>
> \(A\) the cost of additional resources in an amount sufficient to
> serve any new large single load of the utility;
>
> \(B\) the cost of additional resources in an amount sufficient to meet
> any additional load outside the region occurring after the effective
> date of this Act; and (C) any costs of any generating facility which
> is terminated prior to initial commercial operation.

Section 5(c)(7) requires that the ASC subsidy (1) be determined by the
Administrator, (2) be based upon a rate formula methodology developed by
the Administrator in consultation with the Northwest Power Planning
Council, BPA customers, and state regulatory bodies, (3) be subject to
review and approval by the Federal Energy Regulatory Commission (FERC),
and (4) not include costs identified in section 5(c)(7)(A), (B), and
(C).

The ASC methodology established by the BPA Administrator pursuant to
section 5(c)(7) of the Northwest Power Act is a "rate formula." *Public
Utility Commissioner of Oregon v. BPA*, Civil No. 84-270-PA, slip. op.
at 6 (D. Or. March 21, 1984). The methodology is an administrative rule
of both BPA and FERC. *See* 18 C.F.R. §35.13a (1983 ed.).

Under the methodology, exchanging utilities make proposed ASC filings
with BPA, which reviews the filings for conformity with the ASC
methodology and the requirements of section 5 of the Northwest Power
Act. The BPA Administrator then determines the appropriate ASC for the
filing utility. The utility receives an exchange subsidy according to
the ASC determined by the Administrator and approved by FERC.

Through June of 1985, BPA's rates for service to direct-service
industrial (DSI) customers are to recover, inter alia, the "net costs
incurred by the Administrator pursuant to section 5(c) of this Act ...
to the extent that such costs are not recovered through rates applicable
to other customers." *See*, section 7(c)(1)(A). However, beginning in
July of 1985, a new ratemaking methodology for recovering the net cost
of the residential exchange is to be established. Then, residential
exchange costs may have a greater effect on the rates of all customer
classes.

The ASC methodology must be designed so that BPA does not become the
"deep pocket" to which participating utilities may shift excessive or
improper resource costs. The methodology should give participating
utilities an incentive to minimize their costs. Otherwise, BPA could be
faced with either of two statutorily impermissible alternatives. First,
BPA may not be able to set reasonable rates for its customers, who must
pay the cost of the subsidy through their rates. Second, if net exchange
costs cause rates to rise to the level where loads decline, BPA may not
be able to satisfy the requirement of section 7(a) of the Northwest
Power Act that its rates recover total revenue requirement. BPA is a
self-financing government agency, which must recover its costs through
rates for sales of electric power and energy. *See* 16 U.S.C. §§832f,
838g and 839e(a). The residential exchange subsidy should not be borne
by the Federal Treasury.

Consistent with its role in reviewing BPA rates under section 7(a)(2) of
the Northwest Power Act, 16 U.S.C. §839e(a)(2), BPA believes that FERC's
role in reviewing the ASC methodology is to ensure that subsidy payments
do not inhibit BPA's ability to meet its revenue requirement, which
includes repaying all Federal Treasury investments in the Columbia River
Power and Transmission Systems. Currently, the gross cost of the
residential exchange program is the largest single component of BPA's
revenue requirement. While the Northwest Power Act and its legislative
history are virtually silent on the Commission's substantive role in
reviewing the ASC methodology, clearly that role cannot be to increase
the level of subsidy paid by an agency of the Federal government to
profit-making, investor-owned utilities. Such a role would be
antithetical to the traditional review exercised by the FERC over
Federal power marketing agencies. FERC should narrowly construe statutes
that serve to increase BPA's revenue requirement.

**B. The Current Average System Cost Methodology**

The first average system cost methodology (1981 methodology) was
established pursuant to section 5(c)(7) on August 26, 1981, in an
Administrator's Record of Decision. That decision was based on a
settlement agreement, which had resolved nearly all issues raised by
parties in the consultation proceeding.

The Administrator filed the 1981 methodology with FERC on August 27,
1981. The Commission approved the 1981 methodology, on an interim basis,
on October 14, 1981. 46 Fed. Reg. 50,517-538 (1981) (corrected at 46
Fed. Reg. 55,952-954). Final Commission approval was received on October
17, 1983, in an order that made no substantive change to the methodology
proposed by BPA. 48 Fed. Reg. 46,970. Total residential exchange
subsidies paid under the 1981 ASC methodology are depicted in the
following table:

**UTILITY TOTAL SUBSIDY SINCE 1981**

> Portland General Electric Co. \$163,613,383
>
> Pacific Power & Light Co. 155,667,709
>
> Utah Power & Light Co. 38,705,912
>
> Idaho Power Co. 34,872,411
>
> Puget Sound Power & Light Co. 25,439,382
>
> Washington Water Power Co. 6,030,216
>
> C.P. National Co. 2,810,066
>
> Montana Light & Power Co. 40,055
>
> Montana Power Co. (120,047)
>
> Publicly Owned Utilities (12) [8,445,075]{.underline}
>
> TOTAL SUBSIDY PAID BY BPA \$435,504,162

Under the 1981 methodology, a preliminary "Appendix 1" must be filed
with BPA by each participating utility whenever that utility commences a
retail rate change proceeding before a regulatory authority. 1981
Methodology, §III. Appendix 1 is a form that identifies the "Contract
System Costs" and "Contract System Load" used in the calculation of ASC.
Later, the Appendix 1 is revised when the regulatory authority approves
final retail rates. The ASC of each participating utility includes the
costs approved by the regulator.

BPA reviews each Appendix 1 for conformance with criteria specified in
the 1981 methodology. The first Appendix 1 filed by a utility is subject
to review for 180 days following the effective date of its residential
exchange contract. Subsequent Appendix l filings are subject to review
for 120 days from the start of the relevant exchange period. BPA
customers and other interested persons are provided an opportunity to
submit comments on each Appendix 1 filed. 1981 Methodology, §IV(D). All
such comments are due no later than 20 days prior to the end of BPA's
review period. If BPA has not issued a report by the last date of the
review period, then the ASC proposed on the basis of a utility's revised
Appendix 1 becomes the ASC for the relevant exchange period.

The ASC filings of exchanging utilities are rates which, in the instance
of investor-owned utilities, are also subject to review by FERC under
Part II of the Federal Power Act, 16 U.S.C. §.824(a), et seq. *See*
*generally*, "Filing of rate schedules for sales of electric power under
the Pacific Northwest Electric Power Planning and Conservation Act," 18
C.F.R. § 35.13a(c)(2). *See* also 16 U.S.C. §839f(g). These regulations
define ASC filings as rates, 18 C.F.R. 35.13a(c), and waive Federal
Power Act regulations in instances of inconsistency, 18 C.F.R.
§35.13a(c)(2). *See* *Public Utility Commissioner of Oregon v. BPA*,
slip op. at 6. Each utility subject to FERC jurisdiction must file BPA's
written report, the ASC determined by BPA, and the revised Appendix 1
with FERC within 15 days of BPA's determination. During the period
between the date of BPA's determination and the date of the final FERC
order, the ASC determined by BPA is used, subject to later refund.

Reliance on state regulatory agencies to determine the level of costs
included in the ASC of a participating utility, the "jurisdiction
costing approach," has caused several problems of administration for
BPA. Routinely, the orders of regulatory agencies do not contain the
specific numbers necessary for ASC computation. In such instances,
values for ASC accounts must be imputed.

Another drawback to the jurisdictional approach, as it is presently
used, is that state rate regulators are not responsible for enforcing
the requirements of section 5(c). Instead, they are charged by state law
or local ordinance with setting reasonable rates, which maintain the
financial health and stability of the regulated utility. The interests
of utility ratepayers and shareholders are commonly viewed as
antagonistic. The courts have accorded regulators the latitude of a
"zone of reasonableness" in which to set rate that balance these
interests. *Federal Power Commission v. Natural Gas Pipeline Company*,
317 U.S. 575, 585 (1942). However, the choice of rates within this zone
undoubtedly is affected by BPA's obligation under the 1981 methodology
to provide whatever subsidy payment a retail rate order dictates.

With a subsidy from BPA in the picture, higher retail rates do not
necessarily produce higher bills for residential ratepayers. This
phenomenon favors the establishment of retail sales at the upper end of
the zone. A participating utility may not be given an adequate incentive
to control its costs. Yet, BPA simply cannot intervene and participate
in every regional rate proceeding to protect the interests of its own
customers and its ability to recover revenue requirement.[^7] Also, BPA
would not want to influence the ratemaker since the purpose of the
action taken by both parties is different.

There have been instances when serious concern has been raised that
costs approved for retail ratemaking purposes, and thus added to the
residential exchange subsidy under the 1981 methodology, have included
terminated plant costs prohibited under section 5(c)(7)(C). In one case,
terminated plant costs were removed from an ASC filing during BPA
review. *See* BPA's Average System Cost Report for Portland General
Electric Company, Jurisdiction: Oregon (May 13, 1983). In another case,
terminated plant issues were debated but became moot when another
adjustment was made by BPA to an ASC filing. *See*, Average System Cost
Report for Pacific Power & Light Company, Jurisdiction: Oregon (November
2, 1983).

Terminated plant issues, in particular, caused all BPA's DSI customers
to request a change in ASC methodology by invoking section VI of the
1981 methodology. (R. 82, 88). BPA's public agency customers also
requested a new consultation proceeding. (R. 83, 84).

**CHAPTER TWO**

**INITIATION OF THE CURRENT CONSULTATION PROCEEDING**

**A. Procedural History**

This proceeding has its antecedents in a BPA review of an ASC filing by
Pacific Power & Light Company (PP&L) regarding which it had been alleged
that terminated power plant costs had been unlawfully included. After
analyzing circumstantial evidence on the issue, BPA concluded that it
could not specifically identify any such costs in the filing. Probative
data were not available to establish precisely what the Oregon Public
Utility Commissioner had done in a cryptic rate order. In the BPA report
on PP&L's ASC filing, dated December 27, 1982, BPA noted that:

> BPA has an express duty to comply with Section 5(c)(7)(C) of the
> Regional Act. This section requires BPA to exclude from Average System
> Cost any costs of generation facilities that are terminated prior to
> date of commercial operation. Our review did not identify cost
> associated with terminated plant in PP&L's rate base, cost of capital,
> expenses, or the effect of such costs on PP&L'S filed Average System
> Cost. However, we have concerns. The present Average System Cost
> Methodology is designed in such a way that the cost of capital, return
> on equity, and extraordinary gains and losses could conceal terminated
> plant costs. We think it would be appropriate to revise the Average
> System Cost Methodology to demonstrate clearly that the requirements
> of Section 5(c)(7)(C) (16 U.S.C. §839c(c)(7)(C)) are being met. BPA
> plans to initiate a consultation process to revise the Average System
> Cost Methodology. (ASC report of December 27, 1982, at 1, FERC Docket
> No. ER83-266-000.)

BPA's public agency customers took the lead in urging that the 1981 ASC
methodology be reformed in a consultation proceeding under section 5(c)
of the Northwest Power Act. In a letter of May 13, 1983 (R. 84), the
manager of the Public Power Council (PPC), representing 115 BPA
preference customers, stated:

> The PPC has a long range stake in Bonneville's fiscal integrity. We
> share your desire to put Bonneville on better financial footing. It
> has been a year and a half since the Federal Energy Regulatory
> Commission (FERC), approved the average system cost (ASC) methodology
> on an interim basis. In that year and a half Bonneville has seen the
> cost of the Exchange go from a 1981 estimate of gross exchange cost of
> \$350 million to \$500 million to an estimate of 51.05 billion for FY
> 1985. ... In the initial 1983 rate proposal, the Exchange is more than
> 20 percent of the cost of the priority firm rate. As the Exchange has
> grown, so too have BPA's deficits (\$376 million this year).
>
> The cost of the Exchange is now too great a burden for either the
> direct service industries or for your preference customers. The ASC
> methodology has also encouraged "game playing" by some private
> utilities at the state public utility commissions. As Administrator,
> you have within your power the ability to control the cost of the
> exchange, both through better enforcement and through a change in the
> Average System Cost (ASC) methodology. It has been more than a year
> since FERC approved BPA's proposed methodology. It is time to
> recognize that the original ASC methodology simply isn't working.
>
> The Exchange has given region's exchanging private utilities far more
> than the framers of the Regional Power Act ever contemplated. The
> Exchange was to make cheaper federal generation available to the
> residential customers of the investor-owned utilities, and thereby
> achieve parity in the cost of generation. Thanks to the existing ASC
> methodology, plus the cost of escalation in the Washington Public
> Power Supply System Plants, the rates of many of the region's
> consumer-owned utilities are now higher than those of the neighboring
> investor-owned utilities.

\* \* \*

> The past year's experience under the interim methodology has taught us
> that the methodology is greatly in need of repair. Therefore, we
> strongly urge you to exercise your right under Section IV \[sic\] of
> the ASC methodology to initiate a consultation process to amend the
> existing methodology.

Similarly, BPA's direct service industrial customers, by letters dated
April 13, 1983, and August 16, 1983, stated that "BPA must immediately
move to reopen and revise the ASC methodology" (R. 82, 88).

BPA's administrative rules governing the residential exchange subsidy
include section VI of the 1981 ASC methodology, which requires the
Administrator to initiate a statutory consultation proceeding "upon
written request from three-quarters of the utilities who are parties to
contracts pursuant to section 5(c) of the Regional Act, or from
three-quarters of his preference customers, or from three-quarters of
Bonneville's direct-service industry customers..." 18 C.F.R.
§35.13a(d)(6) (1983 ed.).

On October 7, 1983, BPA initiated the present consultation proceeding by
publishing a "Request for Recommendations" in the *Federal Register*. 48
Fed. Reg. 45829 (1983). This notice listed 17 issues for comment and
encouraged additional comments on issues related to the development of a
reformed ASC methodology. Voluminous responses were received by November
7, 1984. (*See* R. 129-442.)

On February 3, 1984, after reviewing the comments received in response
to BPA's earlier *Federal Register* notice, BPA published a "Proposed
Methodology for Determining the Average System Cost of Resources for
Electric Utilities Participating in the Residential Exchange." 49 Fed.
Reg. 4230 (1984). The notice stated in part

> The procedures adopted by BPA in this ongoing consultation are
> intended to facilitate the compilation of a full record on which the
> Administrator will base this decision. Comments have already been
> filed by groups including investor-owned utilities, state regulatory
> agencies, preference customers and DSI customers. This notice solicits
> a new round of initial and reply comments from interested members of
> the public. After completion of the noticed procedures, which include
> negotiation of stipulated agreements, the Administrator intends to
> establish a new improved ASC methodology. The new ASC methodology,
> accompanied by a Record of Decision, will be submitted for review and
> approval by FERC.

\* \* \*

> After the written comment stage, an opportunity will be provided for
> oral presentations before the Administrator, which will be transcribed
> for inclusion in the record. ... During any stage of the proceeding,
> negotiated resolutions of issues, raised by BPA or by commenters, may
> be incorporated into the record by means or written stipulations.

\* \* \*

> It is inevitable that BPA's proposal will not satisfy every commenter.
> Also, comments will raise other issues that may not have been apparent
> to BPA. We stress the importance of written comments which precisely
> state each commenter's position on issues of concern. BPA intends that
> a complete record be compiled. \[49 Fed. Reg. at 4233.\]

This notice provided for the filing of comments on the proposal until
March 15, 1984, with reply comments due April 9, 1984. These dates were
later extended by BPA to March 19 and April 13, 1984, respectively, at
the request of BPA's investor-owned utility customers (R. 2936).
Extensive written comments and reply comments were filed by all
interested parties. (*See* R. 443-185A, 721-853.)

By letter dated February 17, 1984, BPA announced that between February
24 and March 1, 1984, public meetings would be held in Spokane and
Seattle, Washington; Portland, Oregon; and Idaho Falls, Idaho, to
clarify technical aspects of the proposed methodology. Extensive
discussions occurred at these sessions, which were transcribed and
included in the record. (*See* R..915-943 (Spokane), R. 975-1062
(Seattle), R. 944-974 (Portland), and R. 1063-1150 (Idaho Falls)).

On March 2, 1984, BPA issued a letter announcing that a public meeting
would be held on April 20, 1984 "to discuss all issues relating to the
BPA proposal, initial comments, reply comments and possible settlement
of any issue" (R. 2936). BPA noted that the meeting would be
transcribed, that additional meetings would be scheduled with the
Regional Council and State regulatory commissions, and that BPA would
consider requests for meetings with smaller groups of parties. Many
parties participated in the April 20, 1984, meeting. Representatives of
the investor-owned utilities walked out of the meeting, in a public
demonstration against BPA's proposed methodology, before all
participants had made their presentations. (*See* R. 2938.)

Additional public meetings were held between April 23 and 27, 1984. (R.
1493-2221). These transcribed sessions involved extensive face-to-face
negotiations between all the parties present. Additional negotiating
sessions were conducted between April 30 and May 4, 1984. (R.
2222-2180). Transcripts of each meeting are included in the record of
this proceeding. (R. 1317-2810) BPA's investor-owned utility customers
refused to participate in any of these negotiations with BPA staff on
resolution of issues pertaining to possible ASC methodologies. Instead,
these utilities merely sent an "observer" to these public sessions.

On April 30, 1984, the BPA Administrator heard extensive oral
presentations by all interested parties. (R. 2228).

On May 15, 1984, following review of the voluminous record compiled at
that time, BPA staff released a new proposed ASC methodology (R. 2945
-2973). The staff proposal summarized the consultation proceeding, the
proposal negotiated by interested parties, and a possible phase-in of
the new methodology in order to minimize the effect of a methodological
change on the retail ratepayers of exchanging utilities. A fourth and
final round of public comments was solicited, to be received, by May 25,
1984. (R.2982).

On May 17, 1984, BPA mailed a draft index of the official record to all
parties, requesting comments on possible corrections or supplementation.
(R. 2974).

This decision determines a new ASC methodology, based on a thorough
review of some 7,000 pages of record.

**B. The Nature Of Consultation Proceedings Under Section 5(c)**

The Northwest Power Act gives the Administrator discretionary authority
to determine the ASC of each exchanging utility, based on a methodology
he develops in consultation with the Pacific Northwest Planning Council,
BPA customers and various regulatory agencies in the Northwest. The
consultation process has involved a combination of written proposals and
comments, legislative-style hearings, informal meetings and face-to-face
negotiations\--all transcribed or summarized for the record. Several
parties, primarily BPA's investor-owned utility customers, have
commented that this consultation proceeding was not in accordance with
BPA's administrative rule governing-the residential exchange, section VI
of the 1981 methodology (18 C.E.R. §35.13a(d)(6)). These comments were
predicated on an allegation that the ongoing proceeding was somehow
fatally different from the proceeding that led up to the Administrator's
decision on the 1981 ASC methodology. (*E.g.*, letter of A.
Alexanderson, R. 119.) These claims are incorrect. The consultation
process is consistent with governing statutes and regulations.

Section 5(c)(7) of the Northwest Power Act, 16 U.S.C. §839c(c)(7), does
not define "consultation" or in any way limit the term to any particular
form of proceeding. It is reasonably clear from the statute that formal
evidentiary hearings are not required. Neither are negotiations an
essential part of the process. When Congress intended either of these
two procedures necessarily to apply it said so in sections 7(i) and 7(1)
of the Northwest Power Act. 16 U.S.C. §839e(i) and 16 U.S.C. §839e(1).
The statute leaves it to the discretion of the Administrator to choose
the public process best suited to administering the residential exchange
program.

Section VI of the 1981 ASC methodology, which governs changes to that
methodology, does not constrain the Administrator to a particular form
of proceeding. That rule merely states "\[t\]he Administrator, at his or
her discretion, \* \* \* shall initiate a consultation process as
provided in section 5(c) of the \[Northwest Power) Act." The methodology
simply anticipates that, prior to a revision or reformation of the
methodology, a public proceeding will occur in which the views of the
public (particularly those of the three statutorily designated groups)
will be considered by the Administrator. FERC has held that section VI
of the 1981 methodology is a BPA administrative rule not subject to FERC
review. *See* 48 Fed. Reg. 46,972 (1983).

There is nothing inherent in the word "consultation" that would force a
different conclusion. The essence of consultation is provision of an
opportunity to receive information and advice from another.
"Consultation" is a council or conference, as between two persons,
usually to consider a special matter. It is the act of consulting.
"Consult" means to ask advice of, to seek the opinion of, or to apply to
someone or something for information. *Webster's Third New International
Dictionary of the English Language Unabridged*, G.&C. Merriam Company,
Springfield, Mass. (1976).

Precedents involving statutes requiring consultation prior to decision
establish that "consultation" can occur in various ways. *Mid-America
Regional Council v. Mathews*, 416 F.Supp. 896, 903-904 (W.D.Mo. 1976),
involved a statute requiring the Secretary of Health, Education and
Welfare to consult with governors of affected states prior to
designating an entity as a "health systems agency." In *Mid-America* the
secretary had given affected governors the opportunity to review the
applications for designation and to submit their written recommendations
and comments to HEW. Plaintiffs argued that the secretary's procedures
were insufficient. Rejecting plaintiffs' position, the court concluded
that the provision regarding consultation was intended only to ensure
that HEW received the written recommendations, criticisms and views of
the governors and did not mean that HEW had to provide conferences or
negotiate the designation with the governors:

> \[the\] Congressional requirement was only intended to insure that the
> agency received the recommendations and views of the Governors and did
> not mean that the agency, which was heavily burdened to implement the
> Act within the appropriate time frame, was required to provide at any
> time, conference or negotiation meetings to the Governors and their
> staffs. \[416 F.Supp. at 904.\]

*See* *also*, *National Wildlife Federation v. Coleman*, 529 F.2d 359,
371-72 (5th Cir. 1976); and *Town of Milton v. Massachusetts Bay
Transportation Authority*, 253 N.E.2d 844 (Mass. 1969). "Consultation"
is not synonymous with "consensus."

The procedures adopted by BPA in this consultation proceeding were
intended to facilitate the compilation of a full record on which to base
this decision. The procedures were similar to those used in the
determination of the 1981 ASC methodology. *See* Administrator's 1981
Record of Decision at 10. In each proceeding, BPA has used a combination
of notice and comment rulemaking procedures and negotiations. Rulemaking
procedures allow BPA to build a written record on which the average
system cost methodology must be based. This is absolutely essential if
the methodology is later challenged before FERC or the Court of Appeals.
If the revised ASC methodology is based on the written record, BPA would
be able to rebut any allegations that the methodology is somehow
"arbitrary or capricious." BPA's investor-owned utility customers, for
example, first threatened suit last November even before an ASC
methodology proposal had been promulgated (R. 380). Since then, they
have filed three lawsuits in Federal District Court and in the Ninth
Circuit Court of Appeals.[^8] Litigation seems inevitable over any
methodology that might be determined in this proceeding.

There are similarities between the 1981 consultation and the present
one, yet definite improvements have been made. The 1981 consultation
proceeding was essentially an experiment with a novel residential
exchange concept in a new statute. The Administrator was placed under a
statutory deadline in which to determine the first ASC methodology, 1981
decision at 1-2,"and only a small record was compiled during the course
of the proceeding.

To build a comprehensive record in the current consultation, BPA first
asked the public to respond to 17 questions regarding problems with the
existing methodology. Then, based on those responses, BPA published a
written proposal on February 3, 1984. (R. 8.). Interested members of the
public commented on the proposal and then submitted reply comments
responding to each other. (R. 443-850). Written comments were solicited
again on May 15 and 17, 1984. (R. 2945, 2982). In all, four
opportunities for written comments have been provided in the current
consultation, as opposed to a single opportunity in 1981.

Negotiations have played an equal part in the process of building a
record. Negotiations often occur during rulemaking proceedings, but do
not make the resulting rule a contract. BPA has met to discuss possible
methodologies with private utility chief executives, public power
representatives and industrial customer groups. Minutes of these
meetings are included in the record. BPA staff traveled throughout the
region to explain their proposed methodology in four transcribed public
sessions. (R. 915-1150). On April 20, 1984, BPA held a public comment
forum where a wide range of views was expressed. (R. 1317).
Unfortunately, BPA's investor-owned utilities staged a walk-out at this
proceeding, choosing not to listen to comments pro and con.

Beginning on April 20, 1984; and extending over the ensuing three weeks,
BPA staff and customer and public representatives negotiated
face-to-face on a possible compromise methodology. Investor-owned
utilities sent a representative to the negotiations; however, he was
instructed not to participate. (R. 1393-2810). All negotiation sessions
were transcribed and have been incorporated into the record. *Id.* BPA
staff distributed a negotiated methodology for public comment on May 15,
1984. (R. 2945).

Essentially, criticism about the adequacy of the current consultation
proceeding has come from parties who have alleged that the proceeding
lacked essential ingredients of face-to-face discussions and
negotiations. Yet, these same parties have elected to boycott the
discussions and negotiation sessions that have formed an intregal part
of the process. Instead of a valid criticism, this is more an attempt by
one group of BPA customers to filibuster a proceeding convened at the
request of BPA's public agency and DSI customers. However, the
consultation process cannot be made subject to the veto of any customer
group.

**C. The Timing Of The Current Consultation Proceeding**

BPA began the ASC methodology proceeding two years after FERC first
approved the 1981 methodology. This is consistent with the BPA
administrative rule governing changes in the 1981 methodology. *See*
section VI.

The intent of this rule was to keep the 1981 methodology in place for
one year in which to gain experience. Several commenters have suggested
that the rule should be construed to preclude methodological changes
until one year after [final]{.underline} FERC approval of the 1981
methodology. However, it was never BPA's intent to retain the 1981
methodology longer than the one year of experience, whether or not
abuses arose\--as they have. This construction of the rule is reflected
in BPA's October 7, 1983, *Federal Register* notice, 48 Fed. Reg. at
45830, which states:

> ...the new consultation process has been initiated no sooner than 1
> year after the previous methodology was adopted by BPA on August 26,
> 1981, and approved by the FERC on October 14, 1981. *See* 46 Fed.Reg.
> 50,517 (1981), corrected at 46 Fed.Reg. 55,952 (1981). Although the
> FERC approval was granted on an interim basis, this action satisfies
> the requirements of 18 C.E.R. 35.13a(d)(6). \[R. 4-A6\].

After nearly two years of experience, BPA realized there were serious
problems with the existing methodology. The methodology was too
contentious and open for abuse. Although a number of appeals have
recently been settled, every one of 60 submittals was contested before
FERC and four lawsuits were filed with the U.S. Court of Appeals for the
Ninth Circuit.

The existing methodology had also been abused. Last year, BPA had to
revise submittals by Portland General Electric Company because they
contained the costs of terminated nuclear plants. Inclusion of these
costs is prohibited by the Northwest Power Act. As noted earlier, BPA's
customers insisted that the consultation proceeding be instituted in
1983. The Public Power Council noted in May of 1983 that it had been
more than one year since FERC had approved the 1981 methodology and that
a new consultation proceeding should be commenced under section VI. (R.
84-85).

For all of these reasons, BPA decided to initiate an open, public
process to review the 1981 methodology and attempt to develop a new
methodology which would result in less contentious submittals and
eliminate the abuses. The consultation proceeding was initiated on
October 7, 1983 (48 Fed. Reg. 45,829)\--nearly two years after FERC
first approved the 1981 methodology. (R. 2).

**D. Allegations Of Bias Or Predisposition**

On March 9, 1984, the Public Utility Commissioner of Oregon, Pacific
Power & Light Company, Portland General Electric Company, and CP
National Corporation filed a complaint for declaratory and injunctive
relief in the United States District Court for the District of Oregon,
Civil No. 84-270-PA. The parties alleged that the Administrator was
"absolutely committed" to changing the ASC methodology rule to the
parties' economic detriment. (R. 6711). The parties based their
allegations solely upon two affidavits one by a Pacific Power Light
Company executive, Mr. David Bolender, and the other by a Portland
General Electric Company executive, Mr. Robert Short. (R. 6721, 6725).
Both affidavits claim to recount excerpts of conversations that took
place in private meetings with the Administrator.

The action in District Court was dismissed for lack of jurisdiction on
March 21, 1984. The parties then appealed the District Court decision
and filed an original "complaint" in the United States Court of Appeals
for the Ninth Circuit, No. 84-7185. These parties did not raise an
allegation of bias on the part of the Administrator during the entire
administrative consultation proceeding. On the last day of the final
comment period, Portland General Electric Company submitted into the
record a letter stating that "Mr. Johnson should disqualify himself and
management reporting to him from making any decision to change the ASC
methodology" (R. 6708).

On March 29, 1984, the Administrator addressed the controversy over
allegations that he was somehow biased. (R. 1116). In letters to each of
the two affiants mentioned above, the Administrator offered to submit to
a transcribed question-and-answer session on questions of bias, which
was to be included in the record of the ASC methodology proceeding:

> I strongly disagree with your characterizations of my statements in
> the affidavits and with your use of my statements out of context. I
> propose the following procedures to assure that the record in BPA's
> consultation proceeding may be made clear regarding any alleged
> predisposition on my part.
>
> I am willing to respond to questions posed by a single representative
> of your mutual choice in a transcribed session lasting approximately
> one hour. All questions must relate to your allegations of my improper
> bias in the consultation proceeding... BPA will provide the court
> reporter for this question-and-answer session which will occur in my
> office. The transcript will be included in the record of the
> consultation proceeding...
>
> In return, I request each of you \[the two affiants\] to submit to a
> question-and-answer session with the same ground rules. Topics of
> inquiry would concern your allegations regarding my improper bias on
> issues concerning the average system cost methodology and our
> conversations relating to this matter. ... Transcripts of these
> sessions would also be included in the record of the consultation
> proceeding.

In response, the affiants refused the Administrator's offer to
supplement the administrative record with the answers of the
Administrator and the two affiants to questions regarding allegations of
bias. (R. 117). Also, the affiants declined to respond to a follow-up
inquiry from BPA's General Counsel, which asked them to suggest
alternative "ground rules" if they found the Administrator's
question-and-answer procedures unacceptable for any reason. (R. 118).

The record clearly reflects the Administrator's intention to determine
an ASC methodology based on the record compiled in this proceeding. In
public comments of April 20, 1984, he stated:

> My mind is not made up, therefore, the Administrator's mind is not
> made up. We have laid out a proposal. That proposal has started a
> debate. It is a heated debate; I respect that. This is very important
> to everyone assembled in this room, and I will be reading all the
> comments that are made, and there will be oral arguments about a week
> from now, and I will be here to listen to that, and I will certainly
> take account of everything that is said here today, and I can only
> make a decision in the final cut on the record. In other words, on the
> good, reasoned logic and the persuasion of those people, not only
> assembled here today, but others who have elected to speak to this
> important subject. \[R. 1324.\]

This decision follows the prescription of that public statement.

**CHAPTER THREE**

**BPA'S PROPOSAL OF FEBRUARY 3, 1984**

Because the so-called jurisdictional costing approach was not yielding
satisfactory results under the 1981 ASC methodology, BPA proposed to
replace it with a uniform cost approach in a new ASC methodology.
Aspects of the 1981 methodology not addressed in the proposal were to
remain unchanged.

BPA proposed a new source of ASC data that was intended to reduce
controversy and facilitate ease of administration. As the new source of
data for computation of residential exchange subsidies BPA proposed the
FERC Form No. 1, a compilation of financial and operating information
prepared annually in accordance with FERC's Uniform System of Accounts
for Public Utilities and Licensees (18 C.F.R. Part 101).

For each exchange period under the proposed methodology, *i.e.*, each
calendar year, the participating utility would only include in its ASC
actual costs documented in that Form 1. There were to be limited
exceptions. First, equity return and taxes for participating
investor-owned utilities would be determined in accordance with
procedures described later in this notice. Second, fuel purchases from
utility affilates pose special regulatory problems which were also to be
treated separately. Third, participating utilities not required to
submit Form 1 were to submit audited, actual data in a calendar-year
format comparable to FERC Form 1.

Each participating utility would receive one determination of its ASC
"in each year." *See* section 5(c)(1) of the Northwest Power Act. This
was to replace the multiple determinations in each year now made by BPA
for each jurisdiction in which a participating utility provides retail
residential service.

The February 3, 1984, proposal had characteristics similar to ratemaking
based on an historical, calendar test year incorporating end-of-year
data. Each participating utility was to be permitted to include the same
types of costs in ASC, based on actual data from the same calendar-year
period. It was to have been uniform in comparison to the current
methodology, which relies on data from retail rate proceedings
throughout the Northwest, each using different ratemaking methodologies
and test years.

However, the proposal noted that BPA would not accept at face value the
numbers included in FERC Form 1 accounts by participating utilities.
Filings would continue to be scrutinized by BPA and all improper costs
were to be disallowed. Each ASC filing would contain a statement, signed
by the participating utility's auditor, stating that all data submitted
by the utility were compiled in strict compliance with FERC's Uniform
System of Accounts and with procedures for reporting the costs of
conservation and affiliate fuel transactions. Any filing which does not
contain this auditor's statement would not be accepted by BPA for
determination of ASC.

Other significant features of this proposal were:

1\. Inclusion of transmission costs in ASC, but only up to the level of
transmission costs included in the BPA priority firm rate.

2\. Exclusion of Construction Work In Progress from the calculation of
ASC.

3\. Inclusion only of generating costs incurred in the production of
electric power and energy to meet retail loads.

4\. Inclusion in ASC of conservation costs.

5\. Use of a national average for return on equity for use in
determining the equity return allowance for participating investor-owned
utilities.

6\. Inclusion in ASC of fuel costs with safeguards to protect against
unreasonable profits to utility affiliates.

7\. Inclusion of investor-owned utility income taxes only at the
participating utility's effective tax rate.

**CHAPTER FOUR**

**RESOLUTION OF SUBSTANTIVE ISSUES**

**I. THE SOURCE OF DATA FOR THE AVERAGE SYSTEM COST METHODOLOGY**

**A. Summary Of Positions**

The 1981 methodology is based on the "Jurisdictional Cost Approach," an
approach based on findings of retail ratesetting bodies modified by
specific instructions required by the Northwest Power Act. BPA has had
several problems with the jurisdictional approach. The primary drawback
to the jurisdictional approach is that state regulators are not
responsible for enforcing the requirements of section 5(c). *See*
*supra* at 12-14.

BPA proposed to replace the jurisdictional cost approach with a uniform
costing approach in the proposal of February 3, 1984. The proposal
relied on FERC Form 1, a compilation of financial and operating
information prepared annually in accordance with FERC's Uniform System
of Accounts for Public Utilities and Licenses. (18 C.F.R. Part 101). The
uniform costing approach has characteristics similar to ratemaking based
on an historical, calendar test year incorporating end-of-year data.
Each participating utility would be permitted to include the same types
of costs in ASC, based on actual data from the same calendar-year
period. This approach would have eliminated the frequent debate
concerning projections of costs, loads, and sales for resale credits.
Filings would still require scrutiny to eliminate improper costs and to
ensure proper functionalization.

The uniform cost approach and BPA reliance on FERC Form 1 was criticized
by almost everyone because it relied on historical data and did not
match cost data in BPA's PF rate. Puget, Derick, R. 2348-2349; PNGC,
Johnson, R. 1515; PGE, R. 705; Puget, R. 623; Utah, R. 615; IPC, R. 634;
MPC, R. 645; WWP, R. 499; Hemmingway, R. 602; OPUC, R. 166A.

BPA's staff proposal of May 15, 1984, retains the so-called
jurisdictional approach. The negotiating parties and comments received
by investor-owned utilities unanimously supported the jurisdictional
approach. The staff proposal clarified two important elements of BPA's
statutory role: (a) independent determination of costs, regardless of
the findings of retail rate regulators; and (b) greater involvement by
BPA in retail rate cases of utilities participating in the residential
exchange program.

**B. Decision**

Jurisdictional cost data ensures that an exchanging utility will be able
to include its current costs in ASC and also provides -a matching of the
costs between the BPA priority firm rate and the ASC. If handled
correctly, its use avoids the necessity of elaborate and
administratively burdensome "true-ups" or attrition allowances which
might be required if historical cost data, such as those contained in
FERC Form 1, were used.

Jurisdictional costs have been subjected to an initial review during the
regulatory process, even though this regulatory review is not designed
to determine whether the costs are appropriate for inclusion in ASC. In
contrast, the cost data included in the FERC Form 1 are subject to
virtually no regulatory scrutiny.

The jurisdictional approach also provides regional customers the
opportunity to participate in the initial review of the costs used in
the ASC. The DSIs routinely participate in state ratemaking proceedings.
This opportunity would be lost if FERC Form 1 data were used.

BPA must assume the responsibility of reviewing all costs and loads for
appropriateness according to section 5(c). The Administrator is
responsible for ASC determination and this responsibility cannot be
delegated to state regulatory officials. If the costs are based on
substantive commission findings, there is a rebuttable presumption under
the 1981 methodology that these costs are appropriate contract system
costs. If, however, costs are challenged by a party or by BPA, the
Administrator may disallow those costs based on an independent review.
The exchanging utility is ultimately responsible to substantiate the
accuracy and reasonableness of its ASC filing.

**II. DETERMINATION OF WHETHER TRANSMISSION COSTS SHOULD BE CONSIDERED
RESOURCE COSTS WITHIN THE MEANING OF SECTION 5(c)**

**A. Summary of Positions**

Transmission investments and expenses were included in the 1981 ASC
methodology as the outcome of a negotiated settlement. The
Administrator's 1981 decision is silent on the justification for
inclusion of such transmission costs, except to note certain practical
considerations unique to the first ASC consultation proceeding. Neither
does FERC Order No. 337 address the merits of including transmission
costs in ASC.

In the proposal of February 3, 1984 (R. 15-17), it was concluded that
Congress did not require BPA to subsidize participating utilities for
their transmission costs. For reasons of equity alone, BPA proposed the
inclusion in the ASC methodology of a transmission "adder," which could
not exceed the level of transmission costs included in the BPA priority
firm rate. BPA transmission costs would be an upper limit, or cap, on
the proposed transmission adder. Participating utilities that elected to
use the adder would be required to include in their ASC filing FERC Form
1 account data on costs functionalized to transmission. No radial line
costs were to be included in the adder. All wheeling revenues would have
been credited against FERC Form 1 transmission costs.

Comments on transmission costs for the ASC proposal ranged from
excluding all transmission costs (ICUA, R. 6552; DSI, R. 6593) to
including all transmission costs as under the 1981 methodology. (PGE, R.
707; Puget, R. 625).

Comments suggesting exclusion of all transmission costs were based on
the argument that transmission facilities are not "resources" as used in
section 5(c)(1) of the Northwest Power Act. Inclusion of those costs is
beyond the authority of the Act. Commenters also suggested that
inclusion of transmission costs creates an incentive for utilities to
construct unnecessary transmission facilities. (DSI, R. 19A).

Several investor-owned utilities argued that all transmission costs
should be included on the basis that both transmission and generation
costs are resource costs, that BPA's half of the exchange includes both
transmission and generation, and that a utility's ASC must include both
transmission and generation costs in deference to "wholesale rate
parity" (R. 626).

The investor-owned utility commenters argued that exclusion would
distort the comparison of "coal-by-wire" (which could be excluded) and
coal-by-train (which would be included as a generation cost). They also
claimed that including transmission costs would not distort rational
economic choices by providing financial incentives to construct
unnecessary transmission lines. There would be no such incentive, state
the commenters, because all transmission costs are not recovered through
the residential exchange and because traditional ratemaking procedures
would still provide a check on the prudence of transmission expenditures
(*e.g.*, Puget, R. 625-627).

Between these two extremes there have been proposals to include only a
portion of transmission costs. The DSIs suggested an option which would
allow existing transmission costs for lines which connected a resource
with the load center. This would require definition of existing lines
which would meet that criterion. That criterion would also apply to new
transmission lines as well. (R. 2633-2634; 6597-6598). The DSIs argue
that only those lines that integrate resources should be included. They
offered four proposals for defining allowable transmission (R.
6598-6599).

Various other transmission "cap" proposals were offered, ranging from
1.8 mills which would exclude costs associated with fringe area
transmission facilities, dedicated feeders, and low voltage transmission
not related to any generating resource (WWPUD, R. 561-563), to a 1.5
mill cap area as discussed by the DSIs. (R. 175).

Following receipt of written comments and at the conclusion of
negotiations, BPA staff offered a revised transmission cost proposal on
May 15, 1984, to allow in the residential exchange subsidy all
transmission plant in service as of July 1, 1984, as defined by the FERC
uniform system of accounts. For transmission plant placed in service
after July 1, 1984, staff proposed to allow transmission plant limited
to the lesser of the costs of transmission facilities required to
transmit power from the utility's generating resources to the utility's
load area or the costs of facilities necessary to interconnect with the
closest feasible point on BPA's transmission system, plus wheeling costs
to the utility's load area. A participating utility would remain free to
construct facilities that were more costly than those facilities
necessary to interconnect to the'BPA system; however, the additional
amount would not be subsidized by BPA through the residential exchange
program (R. 2947).

**B. Discussion of Positions**

Commenters have suggested variations from excluding all transmission
costs to including all transmission costs as determined by exchanging
utilities or rate regulators, with several alternatives that cover the
spectrum between the two extremes. Proposals which define a cap could
distort the comparison between "coal-by-wire" or coal by some other
transmission mode. By limiting the transmission component at a specific
level, the cost of transmitting power over a line from a mine-mouth
plant to a load center might be excluded in contrast to a load center
coal plant which would include the cost of transporting the coal to the
plant. A cap provision of this kind may exclude a resource cost (Puget,
R. 627; R. 2515).

Including only existing transmission that integrates resources to load
centers presents a definitional problem. The transcript of the
consultation process is replete with discussion of the proper definition
of generation integration (R. 2507-2518; R. 2592-2610, R. 2630-2649,
R.2796-2803). Definitions of generation integration can range from only
lines that connect the first step-up transmission point to lines which
connect to load areas at relatively low voltages. It appears to be more
difficult to define generation integration in relation to existing lines
where the original purpose for a line is different from its current use
and where that use may change again in the future. It is also difficult
to define a load center or area when many service areas are spread over
a large territory. Nearly every party had a different proposal for
defining the appropriate transmission lines to include in the
calculation of ASC, aside from total exclusion or inclusion.

Including all future transmission facilities, as defined by the FERC
Uniform System of Accounts, would likely provide an incentive for
utilities to construct unnecessary transmission facilities, a portion of
the cost of which could then be subsidized through the residential
exchange. These new facilities might be built exclusively to serve
out-of-region markets, clearly not a resource cost associated with the
residential exchange. The ASC methodology should include the principle
that only future transmission that integrates resources to regional load
should be included. This is much easier to determine before a
transmission line is completed than after it is completed and in use.

**C. Decision**

From a legal standpoint, BPA believes that there is no requirement that
transmission costs be included in resource costs for calculation of the
residential exchange subsidy. BPA is directed by section 5(c)(7) to
develop a methodology for calculating "the average system cost of that
\[participating\] utility's resources..." *See* section 5(c)(1).
Resource is synonymous^\*\*^ with generating facilities and conservation
measures, not with transmission facilities.

Resource is narrowly defined by section 3(19) of the Northwest Power Act
as:

> \(A\) electric power, including the actual or planned electric power
> capability of generating facilities, or
>
> \(B\) actual or planned load reduction resulting from direct
> application of a renewable energy resource by a consumer, or from a
> conservation measure.

Elsewhere in the statute, the terms "resource" and "resources" are used
synonymously^\*\*^ with generating facility and conservation
measures.[^9] Where Congress intended to define the cost of resources to
include more than generation, it did so expressly. Section 3(4)(8) of
the Northwest Power Act defines "cost-effective" resource by reference
to a number of ancillary costs including" ... if applicable, the cost of
distribution and transmission to the consumer..."

BPA concludes that there is no requirement in the Northwest Power Act
that BPA subsidize transmission investments and expenses under the
residential exchange program. However, it does not follow that the 1981
methodology included improper costs. The Act does not contain a specific
prohibition of including transmission costs in ASC, although BPA would
tend narrowly to construe statutes that add to its revenue requirement.
There is nothing in the statute that would lock the Administrator into a
single methodology. When revising the ASC methodology the Administrator
is provided considerable discretion by section 5(c)(7). The inclusion of
transmission costs is permitted by the Act but not required. The
question for the BPA Administrator to decide then becomes one of policy.

Although the case is by no means compelling, BPA is persuaded to include
in ASC transmission costs which reflect integration of generating
resources.

The exchange of views in the consultation proceeding on the issue of
what amount of transmission is necessary to integrate a resource with a
load area produced no consensus. For existing transmission facilities,
voltages can range from a cut-off point between distribution below 69 kV
to as high as 230 kV. A consensus on voltage level was not reached. The
original use of existing transmission facilities often differs from its
current use; what was once distribution may be transmission and vice
versa. Moreover, defining a point where a transmission line enters into
a load area and then becomes either load area transmission or
distribution can be difficult. As a result of the lack of consensus and
the difficulty in defining existing transmission which is used for
integrating resources, BPA has chosen to include in the calculation of
the ASC subsidy all existing transmission, as defined by the FBRC
Uniform System of Accounts, in service as of July 1, 1984, the effective
date of the revised ASC methodology adopted in this decision.

New transmission facilities pose a less difficult problem in defining
those lines which are constructed to integrate a resource with a load
area. These lines can be reviewed in the context of justification for
construction. Duplicate or redundant facilities will not be subsidized.
BPA has chosen to limit the inclusion of future transmission facilities,
based on the following criteria:

> For transmission plant commencing service after July 1, 1984,
> transmission plant costs which can be exchanged are limited to
> transmission facilities that are directly required to integrate^\*\*^
> resources to the-transmission system grid. Specifically, transmission
> costs which can be exchanged are limited to the lesser of the costs of
> transmission facilities required to transmit power from the generating
> resource to the exchanging utility's system or the sum of the costs of
> the transmission facilities required to integrate the generating
> resource to the BPA system and the wheeling costs necessary to wheel
> the power over the BPA system to the exchanging utility's system. If
> the utility chooses to construct facilities that are more costly than
> the facilities required to interconnect to the BPA system, the total
> costs of that facility to be exchanged shall be no greater than the
> facility costs that would have been incurred to interconnect with the
> BPA system.

BPA has no intention of interfering with utilities' decisions on what
transmission to construct as is suggested by some commenters. However,
BPA does not believe it is appropriate to require other ratepayers in
the Northwest to subsidize transmission decisions which are clearly
beyond the bounds of integrating a resource. If a utility chooses to
build new lines for other purposes such as bulk power sales, they may
make an economic decision which is to their benefit. However, those
costs would be excluded from ASC calculations. In the case of lines
built for bulk power sales, the corresponding wheeling revenues from
those sales using the new bulk power lines would be excluded in
calculating a revenue credit against ASC if the participating utility
can make the appropriate demonstration. (PP&L, R. 6688).

**III. SUBSIDIZATION OF CONSTRUCTION WORK IN PROGRESS**

**A. Summary Of Proposals**

One of the costs a utility incurs while constructing new plant is that
of financing capital investment, which may be referred to as carrying
charges. There are two alternative methods for treating carrying charges
incurred during the construction period. One method capitalizes the
carrying charges as an Allowance for Funds Used During Construction
(AFUDC). Under this method the carrying charges are computed
periodically (usually monthly) and are added to the direct cost of the
construction (FERC Account 107). The total cost of the completed
construction will include not just direct costs of land, labor, and
materials; it will also include the carrying charges recorded during
construction. These charges will be fully recovered from the ratepayers
during the life of the plant as depreciation expense. AFUDC is recorded
as income by the utility as the carrying charges are accrued during the
construction period. Actual cash payments from ratepayers to cover the
carrying charges begin when the plant is completed.

The second method for recovering construction carrying charges is
through inclusion of Construction Work in Progress (CWIP) in rate base.
Under this method CWIP is treated like plant in service. The utility
recovers carrying charges currently from ratepayers, rather than adding
the charges to the cost of construction. The carrying charges are
determined by the allowable return (debt and equity) that is applied to
utility investment which is used and useful. The return on CWIP is
recorded as income on a current basis (just as AFUDC) and actual cash
payments are made by the ratepayers currently (unlike AFUDC).

In BPA's proposal of February 3, 1984, CWIP was excluded from the
calculation of ASC due to the difficulty of retroactively adjusting ASC
if CWIP were to have been subsidized for a construction project that was
later terminated (R. 17). The residential exchange subsidy cannot
include the costs of any facility which is terminated prior to initial
commercial operation. 16 U.S.C. §839(c)(7)(c). BPA's February 3 proposal
was not intended to prejudge the choice between the CWIP and AFUDC
methods by any state regulatory body.

Pacific Power & Light Co. suggests that CWIP should be allowed in rate
base because retroactive adjustment has not been a problem under the
1981 methodology. However, PP&L recommends that if CWIP is excluded, the
effective tax rate should be adjusted to exclude related interest
expense. (R. 492-493). Since income taxes are to be excluded from ASC,
this tax adjustment will not be necessary.

In contrast, the DSIs state that CWIP should be excluded from
calculation of ASC (R. 62A-72A). They suggest that the difficulty of
recovering exchange subsidy payments when construction projects are
terminated has been demonstrated by experience under the current
methodology. The DSIs suggest the problem also arises if the
construction project is completed but then is used to serve
extraregional loads or new large single loads within the Northwest.
*See* section 5(c)(7)(A) and (B) of the Northwest Power Act. The DSIs
also claim that inclusion of CWIP in calculation of ASC forces BPA and
its customers to lend exchanging utilities their construction financing
costs. The DSIs also note that no Northwest regulatory jurisdiction
permits inclusion of 'CWIP in rate base as a general practice.

Washington Water Power Co. (R. 625), Montana Power Co. (R. 649), and
Portland General Electric Co. (R. 709) suggest that exclusion of CWIP is
inconsistent with the concept of wholesale rate parity. PGE and the
Oregon utility commissioner (R. 708, 174A) note that FERC allows CWIP
for purposes of wholesale ratemaking and that BPA includes CWIP (for
Washington Public Power Supply System plants) in its priority firm rate.

Commenter Leroy Hemingway suggests that elimination of CWIP from ASC
removes a regulatory tool that may provide needed flexibility in
recovering resource costs (R. 605).

Western Washington PUDs suggest that BPA should exclude CWIP for
generation plant but not for transmission plant (R. 564-565).

**B. Discussion Of Positions**

All major jurisdictions in which participating utilities are regulated
(Oregon, Washington, Idaho, and Montana) currently do not allow CWIP in
rate base for purposes of determining retail rates. Thus, under the
jurisdictional costing approach, which BPA has decided to retain, CWIP
has become an academic issue for investor-owned utilities that
participate in the residential exchange.

Publicly owned utilities that set their rates on a cash basis do not use
rate base to determine part of their revenue requirements. They only use
rate base to spread the revenue requirement among their different
customer classes. (*See* Johnson, PNGC, R. 2285.)

All participants in the negotiation sessions agreed that generating CWIP
would be excluded from rate base. *See* Ailshie, BPA, R. 2235; Tanner
(DSI), R. 1707.)

**C. Decision**

Since CWIP is not allowed by regional regulatory authorities, it would
not be appropriate under the jurisdictional approach to include CWIP in
the calculation of ASC, thereby requiring BPA's customers to subsidize
participating utility construction projects.

Moreover, BPA must comply with the proscription of section 5(c)(7)(C),
16 U.S.C. §839(c)(7)(C), which states that ASC shall not include "any
costs of any generating facility which is terminated prior to initial
commercial operation." This provision requires BPA to recover amounts
included in ASC for CWIP on construction projects which are subsequently
terminated. *See* Administrator's 1981 decision at 8. However, it is
quite difficult to reverse the effects of allowing a CWIP return in ASC.
From this perspective, the better policy is to include generating
resources in the calculation of ASC only when they go into commercial
operation. No CWIP will be included in the rate base calculation of ASC
under the methodology adopted in this Record of Decision.

With regard to transmission CWIP, BPA has separately decided in this
decision only to include in ASC transmission that is necessary not
redundant. Such a determination will not be made until the line is
completed. It would be inappropriate to include a transmission facility
in ASC before it went into commercial operation for the same reasons
that generation CWIP is excluded. This result is both equitable and easy
to administer.

**IV. TREATMENT OF EQUITY RETURN**

**A. Summary Of Positions**

The jurisdictional costing approach has caused serious concern that
equity returns allowed by regulatory agencies have indirectly
compensated participating utilities for the costs of generating
facilities terminated prior to initial commercial operation. Although
not necessarily inconsistent with relevant state laws, such allowances
violate section S(c)(7)(C) of the Northwest Power Act if included in
ASC. In its proposal of February 3, 1984, BPA therefore proposed a
generic method for determining the equity return component of ASC for
investor-owned utilities.[^10] Compare, Generic Determination of Rate
Return on Common Equity for Electric Utilities, FERC Docket No.
RM80-36-000, 47 F.R. 38,332 (1982).

In the first quarter of each year, BPA proposed to determine and publish
a national-average equity return allowed by retail rate regulators for
electric utilities during the preceding calendar year. Equity return
data would be derived from published statistical sources on publicly
traded electric utility securities. This national-average number would
be used as the equity return allowance for each participating
investor-owned utility throughout the relevant exchange period.

BPA thought that this national-average number might be excessive for two
reasons. First, it is reasonable to expect that regulators throughout
the nation increase equity returns to compensate for terminated plant
costs\--either implicitly or explicitly. *See*, *e.g.*, *Consumers
Council v. Public Utilities Commission*, 447 N.E.2d 749 (1983). As noted
earlier, such costs cannot be included in ASC. Second, provisions of the
Northwest Power Act should reduce the equity return requirements of
Pacific Northwest utilities vis-a-vis the national average. The
residential exchange, the opportunity to purchase firm power for load
growth under section 5(b)(l), the conservation funding available from
BPA under section 6, and other provisions of the Northwest Power Act
reduce the financial risks for regional utilities in relation to
utilities not affected by the Northwest Power Act. BPA proposed to
compensate for these two circumstances by reducing the national-average
equity return one percentage point (100 basis points) for use in the ASC
methodology.

In a BPA staff proposal of May 15, 1984, it was proposed that the return
component of the residential exchange subsidy be calculated in the
following manner:

> \(a\) for private utilities, multiply rate base by the embedded cost
> of long-term debt;
>
> \(b\) for publicly owned utilities, use the lesser of the average
> embedded cost of debt or 75 percent of the 90 day Treasury bill rate
> for the proceeding calendar year times rate base (*see* May 15
> proposal, R. 2966); and
>
> \(c\) for cooperatives, use the greater of the average embedded cost
> of debt times rate base or the rate of return necessary to meet "TIER"
> (times interest earned ratio) requirements.

Investor-owned utility commenters generally asserted that common equity
is a resource cost. (Puget, R. 6576; CPN, R. 6554-6555; IPC, R. 6662;
PGE, R. 6709; WWP, R. 6665; UP&L, R. 6576-6577). Removal of equity costs
would not be consistent with the concept of wholesale rate parity.
(Puget, R. 2347-2348; PP&L, R. 6678-6679; IPC, R. 6662).

IOU commenters state that the BPA staff's proposal of using the weighted
cost of long-term debt as the-rate of return component of the
residential exchange subsidy would be insufficient to allow recovery of
actual generation and transmission costs through ASC. A capital
structure composed entirely of debt securities would carry a higher cost
than a capital structure with a mix of equity and debt. Debt securities
are less risky since the return on equity serves as a cushion by
absorbing fluctuations in earnings. (PP&L, R. 6679). Commenting public
utility commissions sham this viewpoint. (IPUC, R. 2144; OPUC, R.
6581-6583; WUTC, R. 6561).

In addition, the IOUs point out that the cost of debt includes coverage
without which they would not be able to issue debt. (PP&L, R. 6679).
BPA's staff proposal does recognize that coverage, at least for the
cooperatives, is a resource cost. *See* Footnote d. The staff's proposal
allows only one times debt coverage for the IOUs which is below most
utility's debt interest coverage. (PP&L, R. 6678-6682).

IOU commenters also criticize BPA's concern that allowed equity could
provide compensation for generating resources terminated prior to
completion and the risks of such termination. Pacific Power & Light
claims, without documentation, that most regulatory jurisdictions allow
full amortization of terminated plant costs apart from equity return.
(PP&L, R. 6680-6681). If no terminated plant costs are included dn
equity return, then adjustments are unnecessary and unwarranted. *Id.*
The Washington Utilities and Transmission Commission points out that
terminated plant costs in ROE can be identified and removed, at least in
some jurisdictions. An alternative measure for the costs of resources
associated with equity capital should not be necessary. (WUTC, R. 6561).

The various publicly owned utility commenters had mixed opinions about a
rate of return subsidy component. Snohomish County PUD supported the
current ASC methodology on rate of return as applied to public utilities
similar to Snohomish. (Hutchison, WWPUC, R. 1834-1837). Springfield
Utility Board urged that a national average equity return be applied.
(Loveland, SUB, R. 2296). The Public Power Council supports using the
embedded cost of debt. The PPC supports the embedded cost of debt as a
proxy for the rate of return because returns allowed by the
jurisdictional regulators contain terminated plant costs. (R.
6670-6671). Mr. Collins, an interested private citizen, recommended that
no return component be allowed in ASC. (Collins, R. 1816-1817).

The Western Washington PUD Association believed that the return
determined by rate regulators provides the most accurate measure of the
cost associated with equity. They suggest, however, that BPA should
adjust return allowed in ASC whenever it contains a terminated plant
cost. (R. 759).

The PUDs of Clallam, Clark, Grays Harbor, Lewis and Mason County
advocate use of the actual embedded cost of debt for the debt component
and substituting the cost of "high grade" utility bonds for the equity
component. (Saleba, R. 851). Current debt costs can be used in place of
equity return because it is theoretically appealing, simple to
administer, equitable, and consistent for all of BPA's customer groups.
(*Id.*; Saleba, R. 2542-2543). In addition, using the weighted cost of
debt would remove both an equity return component related to terminated
plant costs and the risk of such termination. (WWPUD, May 24, 1984, p.
3).

The DSIs argued an entire spectrum of possibilities. As their primary
position, they asserted that equity return is not a valid measure of the
cost of resources and should be excluded. (R. 73A). The DSIs recognize
that there are capital costs associated with resources. However, equity
costs do not reflect capital costs, but only profits\--the requirements
of the investor, which are not a resource cost. (Tanner, DSI, R.
1772-74). However, the DSIs suggested as an alternative that BPA use the
equity returns allowed by regulators, subject to a defined cap. (Taylor,
DSI, R. 1819-1831, 2276).

As a DSI alternative to be used if BPA determined that the cost of
resources includes an equity component, Dr. Taylor proposed using an
exchanging utility's embedded cost of debt as a better measure of
resource costs within the meaning of section 5(c). (Taylor, DSI, R.
1831). The DSIs assert that coverage requirements are not a major item
for consideration in ratemaking for investor-owned utilities. In
addition, the DSIs note that actual debt costs do not include any
coverage ratio. (Taylor, DSI, R. 1825-26).

**B. Discussion of Positions And Decision**

Nearly all commenters agree that equity and coverage requirements reduce
the risk of debt securities by providing a cushion that absorbs
fluctuations in revenues. No one contends that this does not reflect
prudent utility practice which benefits both ratepayers and bondholders.
Lacking equity support, generation and transmission investments would
most likely be financed at higher rates. (*See*, *e.g.* OPUC, R.
6581-82). BPA does not dispute this.

However, BPA cannot agree that equity returns allowed by regulators do
not include, at least tacitly, terminated plant costs and the risks of
such terminations. These may well be compensable for ratemaking
purposes; however, section 5(c)(7)(C) of the Northwest Power Act
prohibits their inclusion in ASC. The IOUs incorrectly assume that the
cost of equity capital in excess of the cost of debt, *i.e.* the risks
of the business enterprise, are resource costs within the limits of
section 5(c)(7)(C). "If you use the embedded cost of debt, you are
implicitly taking out \[of ASC) that incremental amount related to
equity financing\--that risk of construction that really should not be
in the cost..." (Taylor, DSI, R. 1818).

Unless the methodology adopted in this decision accounts for the
terminated plant problem, BPA will be required to make difficult^\*\*^,
controversial adjustments in each investor-owned utility ASC filing.
*See* BPA's Average System Cost Report for Portland General Electric
Co., Jurisdiction: Oregon (May 13, 1983); *See* *also* Average System
Cost Report for Pacific Power & Light Co., Jurisdiction: Oregon
(November 2, 1983).

ASC should include neither equity nor coverage requirements because
these are costs related to default risk. BPA effectively eliminates
default risk by guaranteeing the return on investment for residential
and small farm loads.

Some may argue that this position is not reflective of ratemaking.
However, the residential exchange program is not governed by ratemaking
principles. In developing an ASC methodology the BPA Administrator has
considerable discretion in deciding whether to permit inclusion of an
equity return allowance and, if so, how that component is to be
determined. It might well be that, given enough time, BPA could devise a
finer-tuned measure of the cost of capital that was free of terminated
plant costs. But it would still be controversial and subject to
criticism by those who wanted the residential exchange subsidy to be
higher, or lower.

References to "wholesale rate parity" do not force a contrary
conclusion. This ambiguous phrase is not even found in the Northwest
Power Act. If the methodology adopted in this decision provides rate
relief to the residential customers of exchanging utilities, which it
does in the amount of about \$170 million per year, then the objectives
of section 5(c) will be reasonably met. One of these objectives is the
exclusion of terminated plant costs from the residential exchange
subsidy. Another vital objective of, the Act is that BPA not become the
"deep pocket" to which exchanging utilities can shift excessive or
improper costs. *Supra* at 9. The Administrator's decision, which
reasonably balances these conflicting objectives, should be conclusive.
Under that decision, the residential ratepayers of exchanging utilities
will continue to enjoy the lowest electric rates in the nation.

There seems to be little record support for treating cooperatives,
publicly owned utilities, and investor-owned utilities differently on
this question. Therefore, the appropriate measure of the overall rate of
return for calculation of ASC will be the embedded cost of long-term
debt for the exchanging utility. However, if depreciation expense is not
included in retail ratemaking for the exchanging utility, then return
will be equal to the lesser of: (1) interest expense plus depreciation
expense, or (2) debt service plus revenue-financed capital expenditures.
In no event will the sum of Contract System Cost and Distribution/Other
costs be greater than the revenue requirement used to set rates.

**V. TREATMENT OF INCOME TAXES IN THE RESIDENTIAL EXCHANGE**

**A. Summary Of Positions**

BPA proposed to use the exchanging utility's effective income tax rate
in determining ASC. Significant distinctions exist between tax
regulations and the ratemaking policies adopted by regulators. Commonly,
tax expenses included in rates exceed the amounts actually paid by the
utility to the Internal Revenue Service and to state taxing authorities.
Depreciation deductions, which may be claimed at an accelerated rate for
tax purposes, are "normalized" over the service lives of assets. *See*
*Public Systems v. FERC*, 709 F.2d 73 (D. C. Cir. 1983). Interest
expense deductions are also normalized for ratemaking purposes.
Investment tax credits, which reduce tax liability permanently, may also
be amortized for ratemaking purposes. These ratemaking policies are
designed by regulators to increase utility cash flow. However, there is
no such policy expressed in section 5(c) of the Northwest Power Act.
BPA's February 3, 1984, proposal was not intended to affect decisions of
rate regulators to increase the cash flow of utilities for whatever
policy reasons they adopt.

Western Washington PUDs commented that income and revenue-related taxes
are not resource costs and should not be included in the residential
exchange. Such taxes are incurred because of the nature of the taxpayer
as an investor-owned corporation (WWPUD, R. 570). The residential
exchange was not intended to eliminate differences in tax incurrence
between public and private utilities, only to provide rate relief to the
residential customers of the latter.

The DSIs agreed that income taxes are not costs of resources within the
meaning of section 5(c) of the Northwest Power Act. They claim that
there was no consensus on inclusion of income taxes in the 1981
methodology; instead, the issue was sublimated by emphasis on
jurisdictional costing issues (R. 1505-06). Inclusion of income taxes,
the DSIs state, gives investor-owned utilities more than "wholesale rate
parity" with BPA's preference customers and destroys the competitive
"yardstick" that preference was intended to create. (DSI, R. 4A).

The DSIs also note that the inclusion of state and local taxes in ASC
provides an incentive for these taxing jurisdictions to use BPA as a
"deep pocket" to fund local interests on a region-wide basis (R. 1428,
1429, 1438, 2252). Voters should not be able to vote for a tax and then
shift the tax to BPA through the residential exchange (R. 1439).

The Public Power Council has recommended that taxes be excluded from ASC
(R. 1499-1500).

Investor-owned utility commenters stated that income taxes are resource
costs, generally because such taxes are included in a utility's cost of
service for ratemaking purposes (*e.g.*, Puget, R. 2348).

The Idaho PUC commented that income taxes should be included in ASC. The
PUC argued that taxes must be considered resource costs, because if a
utility had no money to pay its taxes it would have no money to build
resources (R. 2145). However, if income taxes were excluded, deferred
income taxes should not be factored into the ASC methodology either. The
Washington Utilities and Transportation Commission urged the inclusion
of income taxes (R. 2286).

**B. Analysis Of Positions And Decision**

**1. Statutory Analysis**

The legislative history of section 5(c) of the Northwest Power Act makes
it reasonably clear that, on the basis of the discretion granted him
under section 5(c)(7), the Administrator may decide not to subsidize
income taxes under the residential exchange program. The Senate Report
accompanying S. 885, the Senate version of the bill that became the
Northwest Power Act, states that section 5(c)(7) " ... contains a list
of costs to be excluded in the determination of 'average system costs';
[additional exclusions may be incorporated in the
methodology]{.underline} for determining average system cost under this
section." S. Rep. 272, 96th Cong., 1st Sess. 27 (1979) (emphasis added).

The legislative development of the ASC provisions also supports' the
approach that the Administrator has the discretion to exclude income
taxes. As originally drafted, the residential exchange provisions fully
defined the concept of average system cost. In S. 2080, introduced by
Senator Jackson to the 95th Congress, and in H.R. 9020 introduced by
Representative Meeds, "system cost" was defined as the:

> full cost to a private utility of acquiring, owning and operating the
> power facilities used or to be used to supply power purchased under
> §6(b) and shall be the sum of the following: (A) fixed costs, (B)
> operating expenses, including fuel, depreciation, taxes other than
> federal income taxes, federal and state income taxes, purchased and
> interchanged power costs, and wheeling costs, and (C) any other
> expenses related to the purchase of power, the construction,
> ownership, operation and maintenance of generating plants to the
> extent not included in (A) and (B) above. \[S. 2080, 95th Cong., 1st
> Sess., §10(a)(2) (September 9, 1977); *See*, H.R. 9020, 95th Cong.,
> 1st Sess. §10(a)(2) (September 9, 1977).\]

S. 3418 and H.R. 13931, also introduced during the 95th Congress,
dropped this "defined" approach, which never reappeared in any bill
subsequently introduced. Instead, Congress simply directed the
Administrator specifically to exclude those costs enumerated in section
5(c)(7)(A), (B) and (C). The Administrator has discretion to either
exclude or include any other costs. S. 885 as amended by the House \--
and the Northwest Power Act as enacted \-- provided the Administrator
with discretion to both determine ASC and develop the ASCM (in
consultation with the Council). H.R. Rep. 976-II, 96th Cong., 2d Sess.
11 (1980); 16 U.S.C. §839c(c)(7).

Thus, nothing in the Act or its legislative history requires' the
inclusion or exclusion of income taxes in computing the average system
cost of a utility's resources. Resource costs are not defined in the
Act. The exclusions required in section 5(c)(7) are not exclusive. Since
the Act does not define resource costs, we have to look elsewhere to
determine whether income taxes should be treated as a cost of a
resource.

**2. Legal And Policy Analysis**

Although income taxes have long been held to be costs of service for
ratemaking purposes, A.J.G. Priest, *Principles of Public Utility
Regulation* 51-52 (1969); *cf.* *Galveston Elec. Co. v. City of
Galveston*, 258 U.S. 388, 399 (1922); *Georgia Ry. Power Co. v. Railroad
Comm'n.*, 262 U.S. 625, 633 (1923), they are not necessarily associated
with the cost of specific resources, nor are they required to be
included as a cost for purposes of the residential exchange, which is
*sui generis*. Again, BPA stresses that section 5(c) does not require
the determination of any sort of wholesale power rate.

The purpose of the residential exchange in the Act is, in the words of
Senator Hatfield, to provide "power to private utilities for their
residential loads at exactly the same rate as power sold to preference
bodies." 126 Cong. Rec. S.14694 (daily ed. Nov. 19, 1960). This is
accomplished when BPA "sells" power to exchanging utilities at the same
rate applicable to preference customers. However, "sale" was not
expected to achieve parity in the retail rates between preference
customers and investor-owned utilities. H.R. Rep. No. 976, 96th Cong.,
2d Sess. 60 (1980). Thus, the Act did not necessarily contemplate
subsidizing all costs that result in rate disparity between public and
private utilities. Rather, it assumes the differences inherent in the
different forms of business organization will remain.

Earning a profit and the resultant income tax liability is one of the
primary differences between the publicly owned and investor-owned
utilities. This basic difference should not be affected by the
residential exchange. Income taxes are a function of the nature of an
enterprise as an investor-owned utility. The tax laws make
investor-owned utilities revenue collectors for the government. Income
taxes are not resource costs. Publicly-owned utilities own the same
types of power resources, yet incur no tax expense.

Subsidization of income taxes serves to confer on investor-owned
utilities the tax advantages of publicly owned utilities. This extra
benefit goes far beyond the purpose of the residential exchange intended
by Congress. The exchange should not be a vehicle for redistributing tax
burdens from exchanging utilities to BPA's other customers (including
publicly owned preference customers) or to the Federal Treasury (to the
extent BPA rates fail to recover the full cost of the residential
exchange subsidy).[^11]

If federal and state income taxes are included in ASC, income taxes
imposed on private utilities and not on public utilities would be spread
to all BPA ratepayers regardless of their tax status.[^12] State income
taxes imposed in one jurisdiction and not in another, or imposed at
varying rates, would be redistributed to all BPA ratepayers in the
region. If normalized taxes were allowed in ASC, income taxes might be
permanently shifted to BPA's customers from participating utilities.
This is because participating utilities have 'a unilateral right to
"deem" out of the exchange when actual taxes exceed normalized taxes.
(*See* R. 1408.)

Under the 1981 methodology, BPA has dealt with a revenue related state
tax seemingly tailor-made for regionalization through the residential
exchange. Idaho Power Co. attempted to include in ASC the so-called
Idaho "KWH tax." Section 63-2701 of the Idaho Code. Exceptions and
exemptions in the Idaho KWH tax remove the requirement of payment from
many, if not all, of the affected electric utility's commercial and
manufacturing customers. That is, the tax almost exclusively applies to
the retail customers whose rates are subsidized under the residential
exchange. BPA's treatment of this tax is now pending FERC review in
Docket No. ER83-687-000.

Legal precedent on "resource" costs support the conclusion that income
and revenue-related taxes should be excluded from ASC. In 1976, the
Federal Power Commission (FPC) was required by the Alaska Natural Gas
Transportation Act, 15 U.S.C. §719, et seq., to perform a type of
cost/benefit analysis on various pipeline proposals. In its
consideration of the "Net National Economic Benefits" of the various
proposals for an Alaskan gas pipeline, the FPC held that income taxes
were not costs of resources:

> United States [income taxes are excluded on the grounds they are
> transfer payments rather than true resource costs]{.underline}...
> Taxes other than income (*e.g.*, property taxes) are included on the
> grounds that they are a proxy for the costs of governmental services
> (*e.g.*, roads, health systems and schools for construction workers
> and employees) required as a result of a system's construction. \[58
> F.P.C. 810, 927 (1977), footnote deleted, emphasis supplied.\]

The Commission built upon the findings of Administrative Law Judge Litt
who found that "\[t\]reating U.S. income taxes as transfer payments
rather than costs is consistent with existing economic philosophy, as
evidenced in Robert Nathan's scholarly presentation on the subject." 58
F.P.C. at 1394. The FPC's distinction between income taxes and property
taxes is the same distinction recognized by BPA in the ASC methodology
adopted in this decision.

**3. Decision**

Relevant legal and policy analysis, plus the weight of public comments,
suggest that income taxes should not be included in the calculation of
ASC. BPA's decision to exclude income taxes from calculation of ASC does
not mean that any investor-owned utility will not recover such expenses
in rates for sales of electric power. BPA has simply determined that
income taxes are not resource costs within the meaning of section 5(c)
of the Northwest Power Act and, therefore, not includable in the
residential exchange subsidy.

**VI. DETERMINATION OF GENERATING RESOURCES INCLUDABLE IN THE
COMPUTATION OF AVERAGE SYSTEM COST**

**A. Summary of Positions**

In the ASC methodology proposal of February 3, 1984, costs of generating
resources were to be included in the ASC calculation only if those costs
were included in a utility's rate base for retail ratemaking purposes by
at least one regulatory authority in the Pacific Northwest. The intent
of this proposal was to exclude costs of generating resources used for
off-system sales, *i.e.*, resources not used to serve retail
(residential and small farm) loads. (BPA, R18; Meyer (BPA), R.
1861-1862, 1864). BPA proposed to credit revenue from off-system sales
contract system costs.

The DSIs agreed. (DSIs, R. 26A). However, they suggest that BPA clarify
whether the costs of resources serving retail loads may be exchanged if
this entails development of cost of service/cost allocation
methodologies. (DSIs, 26A-27A; Tanner, R. 1862, 1864-1865; Tanner, R.
809). The DSIs stress that all of an exchanging utility's resources
(exclusive of those serving extraregional, or new large single loads) be
included in ASC and that all of a utility's sales, including wholesale
firm and nonfirm sales, should be credited against ASC, either by
crediting kilowatthour sales against contract system load, or by
crediting sales revenue against contract system cost. (DSIs, R. 27A;
Tanner, R. 1875; DSIs, R. 835-836). Similar concerns were expressed by
the Springfield Utility Board. (Banry, SUB, R. 162A).

The Western Washington PUDs (WWPUD) also proposed that costs and
revenues associated with generation plant not included in a utility's
retail rate base by at least one retail rate regulator should be
excluded from the ASC calculation (R. 542-566).

The Pacific Northwest Generating Company (PNGC) commented that BPA's
initial proposal on generating resources should be clarified, and
questioned whether the intent of the proposal is to allow a generating
resource that finds its way into rates in one form or another is to be
exchanged. (R. 538-539).

Several investor-owned utilities commented that the February 3 proposal
does not explain how BPA would determine what generating resources would
be included in ASC and could cause major uncertainty for exchanging
utilities. (PGE, R. 702, 709; PP&L, R. 482-493; IPC, R. 633-638, 639).
These commenters claim that BPA's February 3 proposal is inconsistent
with the objective of using actual data as represented by the FERC Form
1 which includes secondary sales revenue. (WWP, R. 497, 504; MPC, R.
644, 647). The investor-owned utilities also express concern that BPA is
willing to include secondary sales revenues which reduces ASC, but is
not willing to include the corresponding generation costs (*e.g.*, PGE,
R.702, 709).

The Oregon Public Utility Commissioner amplified on these comments by
suggesting that BPA clarify the ground rules for determining what
constitutes a resource dedicated to secondary load. (R. 164A, 172A).
OPUC points out that BPA has surplus firm capacity exceeding the
capacity of WPPSS No. 2, implying that WPPSS No. 2 is available for
secondary sales and might therefore not be included in the priority firm
rate. *Id.*

The Public Generating Pool contends that excluding costs of generating
units used exclusively for the production of secondary energy is
short-sighted since resources are not built exclusively for the
production of nonfirm energy (R. 514, 516).

**B. Discussion of Positions And Decision**

BPA's proposal to exclude the costs of generating resources used for
off-system sales was a necessary corollary to the uniform costing (FERC
Form 1) approach to calculating ASC. Now that BPA has decided to retain
the jurisdictional costing approach instead, this issue becomes moot.
Virtually all parties submitting comments for the record believed that
state regulatory commissions can be relied upon to determine what
constitutes proper generating resources includable in ASC. Therefore,
special criteria for identifying how generating resource costs should be
treated in the ASC calculation are no longer required.

Retail rate orders will continue to be the primary source of data on
generating resources. However, where necessary, BPA will independently
determine costs (including costs of generating resources) for inclusion
in ASC under the jurisdictional costing approach. The costs of any
generating resource improperly included in a utility's ASC filing will
be excluded from the ASC calculation.

**VII. TREATMENT OF AFFILIATED FUEL COSTS IN CALCULATING ASC**

**A. Summary Of Positions**

Under the uniform costing approach proposed by BPA, fuel costs included
in the ASC determination would normally have been derived from FERC
Form 1. However, special criteria were proposed for instances where the
participating utility acquires fuel from a corporate affiliate (R.
19-20). BPA defined "corporate affiliate" as a parent or subsidiary
corporation, a fuel trust that to any degree is owned or controlled by a
participating utility, or a corporation that has a parent corporation in
common with a participating utility. Affiliate transactions are not
characterized by arm's-length bargaining. The natural incentive of both
parties to such transactions is to maximize the seller's profit. BPA was
concerned that the residential exchange could become a means for passing
excessive profits on to affiliates of participating utilities.

In expressing concern about affiliate fuel transactions, BPA followed
the lead of FERC (and its predecessor the Federal Power Commission)
which has long held that such costs warrant special scrutiny. *Montana
Power Co.*, 4 FPC 213 (1945); and *Pacific Power & Light Co.*, 3 FPC 329
(1942). The FPC was not bound by the pricing provisions of affiliate
contracts; an independent determination of costs was authorized. *Safe
Harbor Water Power Corp.*, 1 FPC 230, 237-40 (1940).

In *Federal Register* notice of February 3, 1984, BPA proposed to
calculate ASC of a participating utility with a fuel affiliate based on
the lowest unit fuel cost allowed by that utility's regulators or, if
lower, the unit cost contained in its FERC Form 1 or equivalent document
(R. 19-20). This variant of the jurisdictional costing approach would
ensure that any inflated fuel prices charged by affiliates were not
included in ASC.

Pacific Power & Light commented on this proposal by noting that the cost
data used by different regulators is from different test years.
Therefore, comparisons between regulators are invalid. (R. 482-494).

Washington Water Power stated that the parent utility may be only one of
several entities buying fuel from the affiliate. Sufficient safeguards
exist in the agreements with the other utilities. (R. 497, 504-505).

Commenter Hemingway stated that BPA's method achieved a low result, but
not necessarily an accurate one. The decisions of regulators who give
the most attention to affiliated fuel costs could be disregarded under
the BPA proposal. (R. 600, 607).

**B. Discussion of Positions And Decision**

BPA was initially concerned that the fuel costs shown in FERC Form 1
might be inflated for purchases from affiliates. Comparing the FERC Form
1 fuel costs with the fuel costs approved by regulators was selected as
a reasonable method of checking the Form 1 costs. Since BPA has decided
to retain the costs approved by the regulatory commissions as the source
for costs includable in ASC, this issue has become moot. However, BPA
still retains the right to examine the affiliated fuel costs approved by
regulatory agencies, and determine if they are appropriate for
calculating ASC.

**VIII. CONSERVATION COSTS INCLUDABLE IN THE CALCULATION OF ASC**

**A. Summary Of Positions**

[BPA Review]{.underline}. BPA proposed to include conservation costs,
subject to two limitations. First, such costs had to be incurred as part
of a program that is consistent in terms of cost and timing, with the
conservation plan developed by the Pacific Northwest Electric Power and
Conservation Planning Council. Second, conservation costs incurred
pursuant to model standards included in the Council Plan, as required by
section 4(f)(1) of the Northwest Power Act, were not includable in ASC.

Pacific Power & Light Co. and Puget Sound Power & Light Co. objected to
this BPA approval authority. They state BPA could use the approval
authority to force the utilities to sign BPA's long-term conservation
contracts, which may not be cost-based. (PP&L, R. 462, 493; Puget, R.
620, 628).

Other investor-owned utilities commented that their conservation
programs were developed in cooperation with, and approved by, state
regulators. Under the BPA proposal, BPA could exclude these locally
designed programs, even though they are' cost-effective. (IPC, R. 633,
639; WWP, R. 497-505).

Puget Sound Power & Light objected to excluding from ASC the costs of
meeting model standards. (R. 620, 628). Excluding these costs
discourages the utility from implementing the Regional Council's plan.
One commenter stated that this would provide a disincentive to utilities
that take a leadership role in establishing model standards. (Utah Power
& Light, R. 612, 617).

The Washington Utilities and Transportation Commission commented that
disallowing costs incurred to promote conservation hinders the utility's
ability to achieve the level of conservation envisioned by the Regional
Council. (R. 698, 700).

The Western Washington PUDS stated that BPA's proposal could be
interpreted to mean only BPA conservation programs will be approved.
(Mundorf, WWPUD, R. 1895-1896). The PUDs argue that the Regional
Council's plan is designed to meet the energy needs of the Northwest as
a whole, and is not designed to be utility specific. A utility with
relatively high load growth may require more conservation than the
Regional plan calls for, because conservation is the cheapest resource
available to meet that load growth. Yet BPA could disallow the
conservation costs above what the Regional Council's plan calls for,
even though the utility is seeking to minimize costs. (Mundorf, WPPUD,
R. 1911-1912).

[Conservation-Related A&G Expenses]{.underline}. BPA's initial proposal
did not specifically address the question of whether conservation
administrative and general (A&G) expenses be allowed in determining ASC.
The DSIs argue, however, that A&G expenses are not resource costs, and
should not be used to calculate ASC. Only costs of physical improvements
which produce a measurable reduction in load should be allowed in ASC.
(R. IA, 28A-29A; Wilcox, DSI, R. 1924). Costs incurred to promote
changes in consumer behavior should be excluded, since the consumer
makes the change, not the utility. (Wilcox, DSI, R. 1901). Some parties
have questioned whether advertisements that promote conservation but
contain the utility's name are promoting goodwill for the utility as
much as promoting conservation.

Utah Power & Light argues that the A&G costs must be incurred to achieve
conservation. Similar costs are included in the PF rate, and they should
therefore be allowed in the ASC. (UP&L, R. 6578).

The WWPUDs claimed that costs of conservation audits should be included
in ASC. The audit causes the customer to install the physical
improvements. (Hutchison, WWPUD, R. 2674-2675). However, BPA pays for
the audit where the customer participates in BPA-sponsored conservation
programs. (Hutchison, WWPUD, R. 2679). The utility only pays for audits
in which the consumer purchases the conservation measures themselves or
performs no conservation. Unfortunately BPA cannot differentiate between
audits which induce no conservation and those which lead to the consumer
paying for the conservation measures themselves. (Meyer, BPA, R. 2737).

BPA's proposal would allow the BPA conservation contract charge in
determining ASC. (Meyer, BPA, R. 1893-94.) The Public Power Council
argued that the contract charge should not be exchangeable. The Council
states that the contract charge reflects an 1983 rate case cost
allocation that assumes the utility is not exchanging those costs. (PPC,
R. 528).

[Billing Credits]{.underline}. The Western Washington PUDs also state
that all billing credits paid by BPA to regional utilities should be
used as an offset to reduce an exchanging utility's ASC. (Hutchison,
WWPUD, R. 1934). The WWPUDs state that most utilities will receive
billing credits for rate design measures. (Mundorf, WWPUD R. 1934).
Utilities can implement these rate designs at low cost, and receive
large billing credits from BPA that may greatly exceed the costs of the
program. (Wilcox, DSI, R. 1938). Even if the entire billing credit
revenue is used as an offset, the utility's ratepayers still get the
benefits of the billing credit. Failure to offset gives the utility a
windfall. (Wilcox, DSI, R. 1939).

Pacific Power & Light Co. favors limiting the billing credit revenues
credited against Contract System Cost to the cost of the measure. PP&L
claims that reducing ASC by any amount of billing credits greater than
the cost of the measure transfers the billing credit revenues to
customers served by Exchange resources. (PP&L, R. 6696.) It then
presents an example to show that non-Exchange and Exchange utilities are
treated differently when the revenue credit exceeds the cost of the
program. (PP&L, R. 6703).

**B. Discussion Of Positions And Decision**

Regulatory commissions review investor-owned utility conservation
programs and disallow those costs that are not prudently incurred.
Similarly, the governing bodies of the publicly owned utilities set
levels o€ conservation expenditures (Ailshie, BPA, R. 1919). However,
rate regulators use guidelines that differ from those used to determine
what costs should be subsidized under the residential exchange (Ailshie,
BPA, R. 1921). Also, in some instances, regulators may approve a total
expense number for a whole range of accounts, leaving it to the utility
to determine how to spend the money (McPhail, DSI, R. 1920). BPA still
has the statutory obligation to ensure that impermissible costs are not
allowed in ASC (Mundorf, WWPUD, R. 1922).

The Administrator will determine what conservation costs are allowable
in ASC. Of necessity, these determinations must be case specific, based
on the information provided by the exchanging utility in its ASC filing.
As a general proposition, however, if a utility accelerates or postpones
implementing one of the Regional Council's programs, the cost of the
program may be higher than if the utility followed the Council's plan.
Under the methodology adopted in this decision, the utility would pay
the higher costs, not BPA's ratepayers. (Meyer, BPA, R. 1910; Ailshie,
BPA, R. 2495-96).

Model conservation standards are mandated by Section 4(f)(1) of the
Regional Act. Section 4(f)(2) of the Northwest Power Act gives, the
Regional Council and the Administrator the authority to impose a
surcharge on customers for those portions of their loads which have not
achieved energy savings comparable to those which would be obtained
under the standards. Therefore, the utilities must implement the model
standards or pay the surcharge. Disallowing model standards costs from
ASC does not discourage utilities from implementing the Council's plan.
Permitting inclusion of the surcharge in ASC would destroy the very
purpose of that surcharge.

The utility may also promote a particular housing development with
all-electric heating that has met the standards. Thus, the utility can
use the model standards to promote load growth. (Meyer, BPA, R. 1899).
Promoting electricity consumption is not a conservation cost and
therefore, not a resource cost.

In implementing the standards, the utility is not actively purchasing
resources, but merely ensuring that the model standards are being met.
Therefore, model standards costs are not resource costs. (Meyer, BPA, R.
1897-1896).

Conservation A&C expenses will be limited to only those expenses
relating to conservation measures for which power is saved by physical
improvements or devices. Advertising, promotion, and audit expenses are
not resource costs and therefore are not includable in the ASC.

The purpose of the conservation-contract charge is to ensure an
equitable allocation of BPA conservation costs between generating and
non-generating utilities. BPA's conservation allocation method in the
1983 rate case assumed that the contract charge was an exchangeable
cost. E-BPA-A-02, 142. Therefore, allowing the contract charge in ASC
does not distort the allocation used in the 1983 rate case. (Mundorf,
WWPUD, R. 1894). BPA will allow the conservation contract charge in ASC.
This does not distort the allocation used in the 1983 rate case.

The offset against ASC will include all revenues arising from billing
credits. The utility still receives the billing credit and its
ratepayers receive the benefits of the credit. It is also consistent
with how BPA treats the cost of other resource acquisitions.[^13]

**IX. FUNCTIONALIZATION BETWEEN SUBSIDIZED AND NONSUBSIDIZED ACCOUNTS**

**A. Summary of Positions**

The 1981 methodology incorporates a three-part functionalization
approach: (1) the Uniform System of Accounts, (2) reliance on analytical
studies prepared by the exchanging utility that demonstrate the
functional nature of an item, and (3) use of footnotes that specify
functionalization treatment. BPA proposed to eliminate the third
approach ("footnote 24" in the 1981 methodology) in its proposal of
February 3, 1984. The functionalization produced by application of
footnote 24 has been very imprecise. BPA would rely exclusively on the
remaining two functionalization methods. (*See* Meyer, BPA, R. 1940-41.)

The Western Washington PUDs support the elimination of Footnote 24 (R.
546, 572; Mundorf, WWPUD, R. 2255; R. 739, 759). According to the PUDs,
all exchangeable costs should be functionalized by direct assignment,
with administrative and general expenses and similar cost items
functionalized on the basis of the utility's labor ratios (R. 546, 572;
Hutchison, WWPUD, R. 1943).

The DSIs support elimination of Footnote 24 in their comments (R. 6A;
43A; 133A). However, the DSIs assert that BPA's reliance on analytical
studies and/or direct functionalization may permit the exchange of
non-resource costs and create unverifiable studies skewed toward
subsidized cost categories (R. 6A; 43A-46A., 135A-138A). Instead, the
DSIs recommend reliance on direct assignment of costs, with use of
existing Footnote 13 (labor ratios) for costs that cannot be directly
functionalized (R. 6A; 43A-46A; 138A-140A; Schoenbeck, DSI, R.
1944-1946).

The DSIs further propose that a number of different ratio allocators be
adopted to lessen arguments over how accounts would be functionalized
given the diverse interpretations that exist under the present
methodology. (Schoenbeck, DSI, R. 1945-46).

The Pacific Northwest Generation Company objects to the elimination of
Footnote 24 (R. 540, 721, 1942). Forcing exchanging utilities to justify
costs through direct functionalization is an unnecessary burden
requiring a great deal of time (R. 540, 2485). Instead of direct
functionalization, the PNGC proposes that BPA retain the 1981
methodology with the exception of Footnote 3, and not permit the direct
functionalization of any costs governed by these footnotes (R. 540).

Generally, the proposed elimination of Footnote 24 for allocating costs
was opposed by investor-owned utility commenters (PGE, R. 712; PP&L, R.
495; WWP, R. 507; Puget, R. 630; MPC, R". 649). The IOUs assert that
Footnote 24 was developed in 1981 as a reasonable method for allocating
general costs and that there is no reason to change (*e.g.*, MPC, R.
649). The IOUs further contend that replacing Footnote 24 with direct
functionalization would force a utility to establish burdensome internal
budgeting and accounting procedures to functionalize costs more
directly, or forego their inclusion in ASC (PGE, R. 713; PP&L, R. 495;
WWP, R. 507; Puget, R. 630).

Additionally, some IOUs contend in their comments on the BPA proposal
that BPA has provided no criteria under the direct functionalization
method, giving BPA discretion to reject filed costs in their entirety.
(UP&L, R. 617; Puget, R. 626). They maintain that this would allow BPA
to be arbitrary in reviewing a utility's direct analysis. (UP&L, R.
625).

The Public Generating Pool suggests that the current functionalization
approach may be reasonable if Footnote 24 is either eliminated or
tightened up (R. 515).

The Public Power Council suggests that BPA consider measures to restrict
abuse of the functionalization process. To prevent abuses, the PPC
suggests that BPA require that an exchanging utility to certify that no
studies have been performed that would show a lower ASC for an item
functionalized under Footnote 24 (R. 371). The PPC also supports BPA's
proposal to eliminate Footnote 24, and the use of direct
functionalization wherever possible (R. 6671).

The Public Utility Commissioner of Oregon notes that Footnote 24 was
developed as a reasonable method of allocating costs of a general
corporate nature, and an approach using individually determined
techniques will lead to a morass of unnecessary studies and paperwork
which is contrary to BPA's goal of minimizing the administrative burden
of the ASC review process. (R. 173A).

The Salmon River Electric Cooperative discusses the use of labor ratios
as a substitute for Footnote 24, especially for the functionalization of
some utility expense items which cannot be directly functionalized (R.
663). However, SREC suggests that BPA develop standard formulae to aid
in functionalizing certain costs (R. 664).

**B. Discussion of Positions**

BPA proposed to eliminate Footnote 24 since it was an imprecise method
of treating exchangeable production and transmission costs. BPA agrees
with many of the commenters^\*\*^ that the application of footnote 24
has led to the inclusion of non-resource related costs. As a result, BPA
proposed the use of direct analysis according to the FERC Uniform System
of Accounts as the only option available for functionalizing costs under
the initial ASC methodology proposal.

However, PNCC assertions that eliminating Footnote 24 and requiring
direct analysis could create excessive burdens has merit, at least in
some instances. BPA also acknowledges the claim by the IOUs noted above,
and WWPUD, that forcing the use of direct analysis could eliminate
certain resource costs that are too difficult to functionalize by a
detailed study (WWPUD, R. 572).

The parties' reply comments reveal conflicting positions on
functionalization. For example, WWPUD contends that the proposed use of
labor ratios to functionalize certain costs such as miscellaneous
production costs is improper because miscellaneous production costs are
not labor-related. The DSI proposal would require that BPA disregard the
fact that the relevant FERC accounts directly functionalize these costs
(WWPUD, R. 761).

The DSIs disagree with the IOU assertion that Footnote 24 is a
reasonable approach since Footnote 24 has permitted abuse (R. \*32). On
the other hand, the DSIs agree with the IOU claim that direct cost
assignment through functionalization studies would be an expensive and
inefficient process, and BPA could consequently find administration of
the exchange more complex and controversial than under the present
approach (R. 833).

**C. Decision**

Although BPA will rely on total costs approved by state regulatory
commissions, these total costs must still be separated into the
production, transmission and distribution/other functions required for
the calculation of ASC. Only properly determined costs should be
categorized into the production and transmission functions as allowed by
the ASC methodology. Therefore, BPA will use the two cost
functionalization methods specified in the BPA proposal, with some minor
modifications.

These two methods (discussed below) entail the choice between direct
analysis or specific functionalization ratios applied to the various
FERC accounts (the so-called "cookbook method"), and functionalization
required by FERC accounts. Adoption of the direct analysis and cookbook
methods has the major support of the parties participating in the
consultation proceeding. These methods should serve to mitigate
significant cost assignment abuses inherent in the existing ASC
Methodology, such as changing functionalization methods from filing to
filing and the inclusion of improper costs in ASC. BPA retains the
authority to review and accept only those functionalized costs it deems
appropriate for exchange transactions, as it did under the previous ASC
methodology.

An exchanging utility will not be permitted to switch back and forth
between the functionalization methods without prior written approval
from BPA. The final functionalization methods are described in detail
below.

> **FUNCTIONALIZATION METHODS:**
>
> A. By direct analysis which assigns costs to either the production,
> transmission, or distribution function of the utility. Such analysis
> is subject to BPA review and approval. This option allows a utility to
> assign costs to, production, transmission and distribution/other when
> it has sufficient data available demonstrating that such cost
> assignment is appropriate. Therefore, the utility is permitted
> flexibility in its ASC functionalization design while BPA retains
> discretion to review and approve how these costs are assigned. The
> utility must submit with its ASC filing any and all workpapers,
> documents, or other materials demonstrating that the functionalization
> under its direct analysis assigns costs based upon the actual and/or
> intended functional use of those items. Failure to submit such
> documentation will result in-the entire account being functionalized
> to Distribution/Other.[^14]
>
> B. According to the following specific functionalization methods by
> FERC account as shown below. The FERC Uniform System of Accounts is
> still used for a large number of the exchange utilities' rate base
> costs and expenses. This option represents a significant shift away
> from the single direct-analysis method presented in BPA's initial
> proposal, and should provide a reasonable alternative to
> functionalizing certain cost items under the direct analysis method
> which may be too burdensome for some utilities.

**ACCOUNT** **FUNCTIONALIZATION METHOD**

l\. RATE BASE ACCOUNTS:

  ------------------- ---------------------------------------------------
  310-373\            Functionalize directly according to the Federal
  (Plant in Service)  Energy Regulatory Commission System of Accounts.

  389\                Functionalize on the ratios of Production,
  (Land and Land      Transmission and Distribution Gross Plant excluding
  Rights)             General Plant.

  390\                Functionalize on the ratios of Production,
  (Structures and     Transmission and Distribution Gross Plant excluding
  Improvements)       General Plant.

  391\                Labor ratios.
  (Office Furniture   
  and Equipment)      

  392\                Functionalize on the ratio of Transmission and
  (Transportation     Distribution Gross Plant excluding General Plant.
  Equipment)          

  393\                Functionalize on the ratio of Production,
  (Stores Equipment)  Transmission and Distribution Gross Plant excluding
                      General Plant.

  394\                Functionalize on the ratio of Production,
  (Tools, Shop and    Transmission and Distribution Gross Plant excluding
  Garage Equipment)   General Plant.

  395\                Functionalize on the ratio of Production,
  (Laboratory         Transmission and Distribution Gross Plant excluding
  Equipment)          General Plant.

  396\                Functionalize on the ratio of Transmission and
  (Power Operated     Distribution Gross Plant excluding General Plant.
  Equipment)          

  397\                Functionalize on the ratio of Production,
  (Communication      Transmission and Distribution Gross Plant excluding
  Equipment)          General Plant.

  398\                Functionalize^\*\*^ to Distribution/Other.
  (Miscellaneous      
  Equipment)          

  399\                Functionalize on the ratio of Production,
  (Other Tangible     Transmission and Distribution Gross Plant excluding
  Property)           General Plant.

  301-303\            Functionalize on the ratio of Production,
  (Intangible Plant)  Transmission and Distribution Gross Plant excluding
                      General Plant.

  114\                Labor Ratios.
  (Acquisition        
  Adjustment)         

  105\                Functionalize on the ratio of Production,
  (Plant Held for     Transmission and Distribution Gross Plant including
  Future Use)         General Plant.

  120.2-120.4 less    Functionalize to Production.
  120.5 (Nuclear      
  Fuel)               

  186\                Labor Ratios.
  (Miscellaneous      
  Debits)             

  252\                Functionalize to Distribution/Other
  (Customer Advances) 

  257\                Functionalize on the ratio of Production,
  (Unamortized Gain   Transmission and Distribution Gross Plant including
  Reacquired Debt)    on General Plant.

  151-152\            Functionalize to Production.
  (Fuel Stock)        

  153-157, 163\       Functionalize on the ratio of Transmission and
  (Materials and      Distribution Gross Plant including General Plant.
  Supplies)           

  106\                Functionalize on the ratio of Production,
  (Completed          Transmission and Distribution Gross Plant excluding
  Construction not    General Plant.
  Classified)         

  124\                Functionalize to Distribution/Other.
  (Other Investment)  

  184\                Labor Ratios
  (Clearing Accounts) 

  Other Rate Base     Functionalize to Distribution/Other.
  Accounts            
  ------------------- ---------------------------------------------------

**2.** EXPENSE ACCOUNTS:

  ----------------------- ---------------------------------------------------
  501-577\                Functionalize to Production.
  (Fuel, Purchased Power  
  and Power               
  Production^\*\*^        
  Expenses)               

  560-573\                Functionalize to Transmission.
  (Transmission Expenses) 

  580-598\                Functionalize to Distribution/Other.
  (Distribution Expenses) 

  901-905\                Functionalize to Distribution/Other.
  (Customer Accounts      
  Expenses)               

  907\                    Functionalize to Distribution/Other.
  (Customer Service       
  Information             
  Expenses-Supervision)   

  908-910\                Functionalize to Distribution/Other.
  (Other Customer Service 
  Information Expenses)   

  911-916\                Functionalize to Distribution/Other.
  (Sales Expenses)        

  920\                    Labor Ratios.
  (Administrative &       
  General Salaries)       

  921\                    Labor Ratios.
  (Office Supplies &      
  Expenses)               

  922\                    Labor Ratios.
  (Administrative         
  Expenses                
  Transferred-Cr.)        

  923\                    Labor Ratios.
  (Outside Services       
  Employed)               

  924\                    Functionalize on the ratio of Production,
  (Property Insurance)    Transmission, and Distribution Gross Plant
                          including General Plant.

  925\                    Labor Ratios.
  (Injuries & Damages)    

  926\                    Labor Ratios.
  (Employee Pensions &    
  Benefits)               

  927\                    Functionalize to Distribution%Other.
  (Franchise              
  Requirements)           

  928\                    Functionalize to Distribution/Other
  (Regulatory Comm. Fees  
  & Expenses)             

  929\                    Labor Ratios.
  (Duplicate Charges-Cr.) 

  930.1\                  Functionalize to Distribution/Other.
  (General Advertising)   

  930.2\                  Functionalize to Distribution/Other.
  (Miscellaneous General  
  Expenses)               

  931\                    Functionalize to Distribution/Other.
  (Rents)                 
  ----------------------- ---------------------------------------------------

3\. REVENUE ACCOUNTS:

  ------------------- ---------------------------------------------------
  447\                Functionalize to Production.
  (Sales For Resale)  

  450-455\            Functionalize to Production.
  (Other Operating    
  Revenues)           

  456\                Functionalize to Transmission.
  (Wheeling Revenues) 
  ------------------- ---------------------------------------------------

C. THE FOLLOWING ACCOUNTS SHALL BE FUNCTIONALIZED AS FOLLOWS:

  ------------------- ---------------------------------------------------
  107, 120.1\         Functionalize to Distribution/Other.
  (CWIP)              

  108\                The same functionalization used for accounts
  (PIS Depreciation   310-373, Plant in Service (PIS).
  Reserve)            

  108\                Functionalize according to the General Plant ratio.
  (General Plant      
  Depreciation        
  Reserve)            

  111\                The same functionalization used for accounts
  (Accumulated        301-303, Intangible Plant.
  Amortization)       

  256\                The same functionalization used for account 105,
  (Deferred Gain from Electric Plant Held for Future Use.
  Disposition of      
  Utility Plant)      

  403-407\            The same functionalization used for Accounts
  (PIS Depreciation   310-373, Plant in Service.
  Expense)            

  408.1\              With the exception of property taxes and labor
  (Other Taxes)       related taxes, all taxes will be functionalized to
                      Distribution/Other. Property taxes will be
                      functionalized using the gross plant ratio
                      including general plant. Labor related taxes will
                      be functionalized using labor ratios.

  409.1, 410.1,       Functionalize to Distribution/Other.
  411.1, 411.4\       
  (Income Taxes)      

  932\                Functionalize according to the ratio developed from
  (Maintenance of     the functionalized totals of accounts 390, 391, 397
  General Plant)      and 398.

  411.6, 411.7\       The same functionalization used for Account 105,
  (Gain from          Plant Held for Future Use.
  Disposition of      
  Utility Plant)      
  ------------------- ---------------------------------------------------

**CHAPTER FIVE**

**BPA REVIEW PROCEDURES**

**A. Summary Of Proposals**

BPA proposed to simplify its review procedures. Deficient filings would
be rejected and the new ASC would not be applicable until a proper
filing was received by BPA. To facilitate proper filings, BPA offered
the opportunity for prefiling conferences with exchanging
utilities^\*\*^ where differences could be resolved prior to filing.

During the negotiation sessions, the parties arrived at a general
consensus that BPA should play a more active role in ascertaining
whether ASC filings contain legitimate resource costs eligible for the
exchange. Although jurisdictional cost data will still be used, it
simply provides the starting point for BPA's review process.

The review procedures that were included in BPA's staff proposal on May
15, 1984, reflect concerns raised during the consultation sessions and
the experience gained by BPA staff during two years of exchange program
administration. The major changes to, the current procedures were
necessary to implement the more active nature of BPA's review as well as
to bring somewhat more formality to the review process.

While not participating in the negotiation sessions held on April 20,
23-27, 30 and May 1-4, 1984,' investor-owned utility commenters have
opposed a more active role by BPA during the review process. (PP&L, R.
6684-6685; PGE, R. 6709; UP&L, R. 6575; IPC, R. 6660-6661). The public
utility commissions for the state of Washington, Idaho and Oregon have
taken positions similar to the private utilities. Both the private
utilities and the state commissions note that BPA is not precluded from
participating in the state retail rate proceedings.

On May 25, 1984, BPA received a number of comments regarding its
proposed rule for the review process. BPA's rule for its review process
incorporates a number of the suggestions raised by various parties.

**B. Decision**

Several commenters assert that BPA's review procedures are not
changeable parts of the ASC methodology. They claim instead that these
procedures are fixed by BPA's Residential Sales and Purchase Agreement
with exchanging utilities, Contract No. DE-MS79-83BP9. *See* UP&L, R.
6575). This is incorrect.

The ASC methodology is comprised of a number of sections, including both
BPA procedures and FERC procedures. FERC's interim regulations included
the BPA procedures. *See* 18 C.F.R. sec135.13a (1983 ed.). In its final
rule, however, FERC excluded the BPA procedures, noting that the
procedures are a BPA rule, and that the parties should raise their
concerns over BPA procedures with BPA.

The 1981 ASC methodology, including both BPA and FERC procedures, was
merely incorporated in the Residential Sale and Purchase Agreement for
ease of reference. The methodology, which was adopted by the
Administrator at the end of a statutory process, antedates the contract.
Section VI of the 1981 methodology provides for changes in the
methodology, including the BPA procedural components thereof. BPA's
procedures are a BPA rule which is subject to change when the
Administrator finds it necessary to do so.

BPA has determined that the responsibility placed on it by the Northwest
Power Act mandates a more active role. BPA acknowledges that a more
active role in the review process may not decrease the amount of
controversy^\*\*^ surrounding BPA's review of ASC filings. (*See* Puget,
R. 6570-6571; PP&L, R. 6685-6686). In addition, BPA recognizes that the
revised procedures may require more time to administer than the current
review procedures. *See* Puget, R. 6571; PP&L, R. 6683-6685). The
concerns raised by the investor-owned utility commenters are the
necessary result of BPA's expanded role in reviewing the costs included
in the average system cost filings.

A description of the revisions to BPA's review procedures follows.

[Subsection III.D.1]{.underline}, which defines parties, has been
revised to require that persons accorded party status demonstrate an
interest in the outcome of the BPA review. In the review process,
persons accorded party status have substantial rights including the
right to request data from the utility. *See* subsection III.D.2. The
ability to obtain confidential or proprietary data should be limited to
persons with an economic and financial interest in the process. (*See*
PP&L, R. 6694). Generally, customers of BPA will have the right to
intervene; however, retail customers of BPA wholesale customers may not
be able to demonstrate an unrepresented interest so long as their
utility has intervened. *See*, *e.g.*, Durham, R. PGE. All other
provisions of BPA's Review Procedures that are affected have been
revised accordingly.

[Section I.J]{.underline}, which defines "Test Period", has been revised
to use a test period consistent with the one used by the retail rate
regulator in setting rates upon which the ASC filing is based. There is
a proviso, however. The test period will not be less than twelve months.
Using less than a twelve month test period for determining the costs
used to compute average system cost would not adequately reflect the
variation in the loads and costs that occur. This would not reflect the
true cost of resources for the filing utility.

[Section I.L]{.underline}, which defines when an Appendix l is "filed",
has been modified to allow the utility to hand deliver the Appendix I to
BPA's Division of Financial Requirements in Portland. The limitation on
mailings was provided as a convenience to the utilities submitting an
ASC filing. The modification, however, limits the time for hand delivery
to normal business hours, 8 AM to 5 PM. BPA recognizes that some of the
utilities may prefer to hand deliver the Appendix 1. This modification
was requested by PP&L. (R. 6692). May 25, 1984) p. 19. BPA, however,
retains the certified mailing requirement. It is the responsibility of
the utility to ensure that BPA receives the utility's Appendix 1.
Section I.L has been further modified to reflect this responsibility by
requiring that BPA receive the Appendix 1 before it is considered filed.
The return receipt will be evidence that the filing has been made.

[Section IV]{.underline}, which states the Administrator's procedures
for revising the ASC methodology, has been modified to clarify the
original intent of section VI of the 1981 methodology. In addition,
initiation^\*\*^ of the consultation proceeding is made discretionary,
rather than mandatory. This modification ensures that BPA is not
required to initiate^\*\*^ a process that it believes unnecessary.

[Length of Review]{.underline}. BPA's original proposal included a
variable review period that ranged from 130 days to 200 days depending
on the circumstances. (*See* Exhibit 2 to Transcripts, R. 1160). As a
result of public discussions with the parties and for administrative
convenience, BPA Staff proposed a fixed determination date. BPA
recognizes that the longer review period could present a greater
financial risk to the utility. (*See* IPC, R. 6661- 6662; PP&L, R.
6685-6686). However, BPA's experience has shown that for complex issues
an extended period of time may be required.

For example, *BPA's Average System Cost Report for Portland General
Electric Company* (May 13, 1983), which resulted in the exclusion of
terminated plant costs from ASC, required approximately 200 days to
complete. In addition, BPA's decision to take a more active role in the
review process necessitates allowing parties an opportunity to address
issues that may not have been addressed in the retail rate process.

Under the 1981 methodology the comment period closes 100 days after the
beginning of the Exchange Period. BPA then had 20 days to issue its
final determination. Experience has shown that comments, especially from
the DSIs, were submitted on the last day of the comment period. As a
result, there have been many requests from utilities to be given an
opportunity to respond to the comments. The new review procedures
address this problem by requiring an early identification of the issues
and give all parties an opportunity to comment and to reply to comments
of other parties.

BPA believes that the review procedure is a reasonable balancing of the
financial risk of the utilities and the need to provide sufficient time
to carry out BPA's responsibilities^\*\*^ to review the average system
cost filings of the utilities. BPA notes that some of the IOUs are
concerned that the review period may run as long as 310 days. (*See*,
*e.g.* PP&L, R. 6694). This is a misinterpretation. The extra 100 days
which would result in a 300 day review period is applicable to only the
initial filing under the new methodology. All other filings would be
subject to the 210 day deadline.

BPA may challenge the load figures used by exchanging utilities in their
ASC filings. *See* Section III.D.4. (*Contra*, *see* WWPUD, May 25,
1984; DSI, R. 6594-6654). BPA is aware that the costs in the
jurisdictional proceedings are based on an assumed load and that the
load may be related to many variables. (*See* PP&L, R. 6693-6694). BPA
also acknowledges the complexity of any adjustment to loads and its
effect of all related costs. Notwithstanding, BPA has a responsibility
to examine the loads used since any change in the loads will have a
direct effect on the average system cost.

In addition to the modifications specifically addressed above, there are
additional minor modifications to tighten the procedures. These include
(1) extending the holiday provision of Section III.D to all deadlines
(WWPUD, May 25, 1984); (2) changing the deadline for requesting oral
argument and clarifying who can present oral argument (WWPUD, May 25,
1984, p. 26-27); (3) requiring service on all parties of all comments
and cross comments (WWPUD, May 25, 1984, p. 25-26), (4) defining Initial
Exchange Period (WWPUD, May 25, 1984); and (5) limiting Appendix 1
filings for jurisdictions subject to the exchange only (PP&L R. 6692).

Each exchanging utility is required to file under the new methodology
within 20 days after implementation by FERC. Any utility failing to do
so will have its ASC deemed equal to zero until compliance occurs. *See*
methodology "Filing Procedures," section II.(B)(1)(a).

**CHAPTER SIX**

**IMPLEMENTATION OF THE REFORMED METHODOLOGY**

**A. Summary Of Positions**

Several commenters have suggested that the new ASC methodology be
phased-in over a reasonably short period of time. "Phase-in" would
minimize the retail rate effects of the change in methodology for the
residential customers of exchanging utilities. In its proposal of May
15, 1984, BPA staff proposed that the new methodology be phased-in over
the course of one year.

Under the staff phase-in proposal, the new methodology would be
implemented by FERC on July 1, 1984, the date on which participating
utilities qualify to exchange 90 percent of their residential loads
under Section 5(c) of the Northwest Power Act. However, for the ensuing
12-month period, the actual ASC subsidy for each participating
utility-could be determined as the average of the ASC in effect on July
1, 1984, and the ASC calculated under the new methodology.

On July 1, 1985, the new methodology would become the exclusive means of
determining the ASC of each participating utility. July 1, 1985, is the
date on which participating utilities qualify to exchange 100 percent of
their residential loads.

Phase-in only affects the utilities currently "exchanging" with BPA. The
six "deeming" investor-owned utilities will not be affected by phase-in,
or by the new methodology for that matter.

Only the DSIs oppose this implementation proposal. After stating a
number of objections, the DSIs propose a six-month phase-in instead. (R.
6592).

**B. Decision**

The ability to phase-in an ASC methodology is inherent in the
discretionary authority granted the BPA Administrator by section5(c) of
the Northwest Power Act. The purpose of the residential exchange subsidy
is to provide rate relief to the residential customers of exchanging
utilities. It would be anomalous^\*\*^ if the Administrator were not
able to consider the effects of a change in methodology on these retail
ratepayers. BPA will implement the new methodology according to the
staff phase-in proposal, if FERC approves it.

Both the DSIs and various publicly owned utilities analyze the phase-in
proposal from the perspective of the so-called DSI "floor rate." The
Northwest Power Act provides in section 7(c)(2), 16 U.S.C. §839e(c)(2),
that "the Administrator's rates \[to the DSIs\] during such period
\[after July 1, 1985\] shall in no event be less than the rates in
effect for the contract year ending on June 30, 1985." The DSI rates in
effect during the relevant contract year vary according to the level of
the residential exchange subsidy. The DSIs seek a low floor rate; the
publicly owned utilities want it higher. Resolution of the floor rate
question must await BPA's 1985 general rate proceeding; the issue will
not be decided now.

**CHAPTER SEVEN**

**FINDINGS AND CONCLUSION**

Following the consultation proceeding required by section 5(c)(7) of the
Northwest Power Act, l6 U.S.C. §839c(c)(7), and in consideration of the
foregoing discussion, the Administrator has determined to adopt the
methodology set forth in this Record of Decision as the new
administrative rule governing the calculation of the average system cost
of resources for utilities participating in the residential exchange
program. The methodology will now be submitted to the Federal Energy
Regulatory Commission for review and approval in accordance with section
5(c)(7).

Issued in Portland, Oregon, June 4, 1984.

Peter T. Johnson

Administrator

INDEX TO

OFFICIAL RECORD

1984 AVERAGE SYSTEM COST

METHODOLOGY PROPOSAL

(BPA File No. ASC-83)

BONNEVILLE POWER ADMINISTRATION

U.S. DEPARTMENT OF ENERGY

JUNE 1984

INDEX TO THE OFFICIAL RECORD

1984 AVERAGE SYSTEM COST CONSULTATION

[Page \#]{.underline}

Certification of Record 0001

FEDERAL REGISTER "Notice of Reconsultation of the Average System Cost
0002

Methodology; Request for Comments and Recommendations." (48 FR 45829,
10/7/83)

10/7/83 transmittal to the public with reply card to receive future
mailings.

FEDERAL REGISTER notice "Proposed Methodology for Determining the 0006

Average System Cost of Resources for Electric Utilities Participating in
the Residential

Exchange Established by Section 5(c) of the Pacific Northwest Electric
Power Planning

and Conservation Act. (49 FR 4230, 2/3/84)

2/2/84 transmittal to the public with 2/84 Issue Alert explaining
Average System Cost.

Correspondence on ASC reconsultation:

l\. 12/27/82 Letter to R.B. Lisbakken (PP&L) from Peter T. Johnson 0040

(BPA) regarding PP&L's ASC filing.

2\. 4/13/83 letter to Peter T. Johnson (BPA) from Brett Wilcox (DSIs)
0082

supporting ASC re-examination.

3\. 4/14/83 letter to Peter T. Johnson (BPA) from Chip Greening (PPC)
0083

regarding ASC problems.

4\. 5/13/83 letter to Peter T. Johnson (BPA) from Chip Greening (PPC)
0084

supporting ASC amendment.

5\. 5/18/83 memo to C.M. Butler (FERC) from Peter T. Johnson (BPA) 0086

regarding final adoption of 1981 ASC methodology and intent to

initiate new consultation process.

6\. 8/16/83 letter to Peter T. Johnson (BPA) from Brett Wilcox 0088

(DSIs) regarding Coopers A Lybrand ASC reviews.

7\. List of parties requesting copies of comments including 12 0102

letters received by BPA, 2/84 - 4/84.

8\. 3/29/84 Letter to Robert Short (PGE) and David Bolender (PP&L) 0116

from Peter T. Johnson (BPA) regarding clarification of the record.

4/4/84 response letter to John Cameron, Jr. (BPA) from Marcus Wood 0117

(Counsel).

4/6/84 response letter to Marcus wood (Counsel) from 0118

John Cameron, Jr. (BPA).

4/10/84 response to 3/29 letter from Alvin Alexanderson (PGE) to 0119

John Cameron, Jr. (BPA).

9\. 4/19/84 letter to peter T. Johnson (BPA) from W.G. Hulbert. Jr. 0121

(Snohomish PUD) clarifying statement made at press conference.

10\. 4/26/84 Motion to Supplement Public Record and to Permit 0123

Responses to Supplement Materials, Memorandum Supporting

Pacific's motion to Supplement Record from Marcus Wood (Counsel).

Comments:

Comments received on BPA's notice of ASC reconsultation; comment period:

10/7/83 through 11/7/83.

ASC-1 4/5/83 Snohomish County PUD, William G. Hulbert, Jr. 0129

ASC-2 10/17/83 William B. Culham 0135

ASC-3 10/28/83 Lawrence S. Bradley 0137

ASC-4 10/30/83 Philip Uhrig 0140

ASC-5 11/2/83 Lane Electric Coop, Norman Oakley 0142

ASC-6 11/4/83 WA Util. & Transportation Comm., Robert Bratton 0143

ASC-7 11/7/83 Pacific Northwest State Commissions, Paul Graham. 0145

ASC-8 11/7/83 Portland General Electric, James Baxendale 0150

ASC-9 11/8/83 Puget Sound Power & Light, Priscilla Derick 0152

ASC-10 11/8/83 Kaiser Aluminum, John Niemand II 0157

ASC-11 11/7/83 Direct Service Industries, Michael Dotten/Grant Tanner
0160

ASC-12 11/8/83 Pacific Northwest Generating Co., Leayesh Johnson 0339

ASC-13 11/7/83 Western WA PUDs, Terence Mundorf 0342

ASC-14 11/7183 Public Power Council, Line Wolverton 0336

ASC-14A 11/17/83 Public Power Council comment correction 0375

ASC-15 11/4/83 Public Generating Pool, Joseph Recchi 0376

ASC-17 11/7/83 Fred Walter 0378

ASC-18 11/183 Investor-Owned Utilities, Alvin Alexanderson 0380

11/29/83 BPA response 0382

ASC-19 11/29/83 Southern California Edison, C.W. DuBois, Jr. 0384

ASC-20 11/27/83 Direct Service Industries, Alex McPhail 0385

ASC-21 1/11/84 Direct Service Industries, Grant Tanner 0388

ASC-22 1/10/84 Direct Service Industries, Grant Tanner 0393

ASC-24 10/31/83 Direct Service Industries, Brett Wilcox 0401

ASC-25 10/28/83 Direct Service Industries, Brett Wilcox 0404

ASC-26 12/15/83 Direct Service Industries, Brett Wilcox 0406

ASC-27 12:15/83 Direct Service Industries, Alex McPhail 0412

ASC-28 2/10/84 Kaiser Aluminum, H.M. Nelson 0442

Comments received on BPA's proposed ASC methodology as published in the
FED. REG.; comment period: 2/3/84 through 3/19/84.

ASC-83- 1 2/29/84 Ravalli County Electric Coop, Gary Mason 0443

2 3/2/84 Assn. Western Pulp & Paper Workers, Ferris Bryson 0444

3 3/1/84 Central Lincoln PUD, D.F. Jackson 0447

4 2/29/84 Wahkiakum County PUD, Charles Weber 0449

5 2/27/84 POWER, Walter Belka 0450

6 2/27/84 Fred Huett 0451

7 2/27/84 Triangle Lake Schools, Donald Hopkins 0459

8 2/10/84 WA State Farm Bureau, Dan Ahrenholtz 0460

9 no date Jim Spindler 0462

ASC-83- 10 3/8/84 Direct Service Industries, Brett Wilcox 0463

11 3/7/84 Direct Service Industries, Brett Wilcox 0465

12 no date Mark Hoggans 0471

13 3/2/84 Eugene Denney 0472

14 3/7/84 Harney Electric Coop, Jack Heaston 0473

15 3/9/84 Lower Valley Power & Lgt., Winston Allred 0475

16 3/9/84 Direct Service Industries, Grant Tanner 0477

17 & 18 Austin Collins 0479

19 3/9/84 United Steelworkers, Alan Link 0481

20 3/19/84 Pacific Power & Light 0482

21 3/16/84 WA Water Power Co., Los Bryan 0497

22 3/3/84 Columbia River Fishermen's Protective Union, 0509

W. Wm. Puustinen

23 3/19/84 Weyerhaeuser Co., Norbert Nethven 0512

24 3/19/84 Public Generating Pool, Keith Parks 0514

25 3/19/84 Public Power Council, Judith Bearzi 0517

60 3/21/84 Public Power Council correction to ASC-83-25 0537

26 3/19/84 Pacific NW Generating Co., Leayesh Johnson 0538

27 3/19/84 Western WA PUD's, Terence Mundorf 0542

30 3/16/84 Northwest Power Planning Council, Ketih Colbo 0598

31 3/19/84 Leroy Hemmingway 0600

32 3/16/84 Southern CA Edison, Mark Frazee 609

33 3/16/84 Utah Power & Light, Douglas Little 612

34 3/16/84 Puget Sound Power & Light, Priscilla Derick 620

35 3/13.'84 Idaho Power, Barton Kline 633

36 3/16/84 Western Montana Generating & Transmission, Steven Herndon 642

37 3/15/84 Montana Power, R. Blair Strong 644

38 3/15/84 Public Ownership League of Cowlitz County, Sid Nelson 650

39 3/15/84 Consumers Power, Inc., David Blake 652

40 3/13/84 Montana Public Service Comm., Thomas Schneider 654

42 3/13184 Salmon River Electric Coop., Jeff Rostberg 659

43 3/12/84 CP National, C.S. Rasmussen 672

44 3/16/84 Cowlitz County PUD, Robert McKinney 673

45 3/15/84 statement by Fall River Coop., Calvin Wickham 675

46 3115/84 ID County Light & Power, Earl Weeks 676

47 3/12/84 City of Tacoma, Paul Nolan 677

48 3/13/84 George Helkey 679

49 3/12/84 Fair Electric Rates Now, Jim Lazar 681

50 3/16/84 ID Public Utilities Comm., Conley Ward, Jr. 695

51 3/16/84 WA Utilities & Transportation Comm., Larry Rogers 698

52 3/19/84 Portland General Electric, James Baxendale 0702

53 3/15/84 City of Portland, Mike Lindberg 0714

55 3/19/84 Direct Service Industries, Grant Tanner (4 documents) 01A

68 3/23/84. Direct Service Industries supplement to 146A

ASC-83-55, Grant Tanner

56 3/19/84 Springfield Utility Board, Gale Banry 161A

57 3/12/84 Aluminum Trades Council, James Brumitt 163A

58 3/19/84 OR Public Utility Comm., Paul Graham 164A

59 3/12/84 City of Soda Springs, Roy Rainey 176A

61 3/15/84 Vera Water & Power, William Jobb 178A

ASC-83- 62 3/14/84 Idaho Grower Shippers Assn., David Smith 179A

63 3/8/84 Ray Baker 180A

64 3/13/84 Hower Taylor 182A

65 3/13/84 L. Kent Taylor 183A

66 3/12/84 Howard Taylor & Sons, Inc., L. Kent Taylor 184A

67 3/2/84 Dwight Miller 185A

Reply comments received on proposed ASC methodology as published in the
FED. REG.; comment period: 3/15/84 through 4/23/84.

ASC-83R-1 4/9/84 Pacific NW Generating Co., Leayesh Johnson 721

R-2 4/13/84 Pacific Power & Lgt., Marcus Wood 723

R-3 4/12/84 Southern CA Rdison, Mark Frazee 734

R-4 4/12/84 Western WA PUD's, Terence Mundorf 739

R-5 4/13/84 Direct Service Industries, Michael Dotten 765

R-6 4/13/84 Puget Sound Power & Lgt., Priscilla Derick 789

R-7 4/13/84 Public Power Council, Judith Bearzi 803

R-8 4/13/84 Direct Service Industries, Grant Tanner 805

R-9 4/x3/84 Portland General Electric, Donald Furman 838

R-10 4/13/84 Clallam, Clark, Grays Harbor, Lewis & Mason 850

PUD Counties, Gary Saleba

Testimony submitted to BPA for 4/20/84 consultation session with BPA
Administrator.

Community Action Agency of Portland 854

Emergency Helping Agencies Committee, Sally McCracken 857

Salvation Army, Cascade Division; Venona Raines 860

Snow-Cap, Doug Rogers 863

United Steelworkers of America, Local 330; Robert F. Saunders 867

United Steelworkers of America. Local 8141; H.D. Lacy 869

International Chemical Workers Union, Richard Edgington 871

IOU Joint Statement 873

Meetings:

Optional handouts from 4 regional clarifying sessions:

1\) FED. REG. notice of proposed ASC methodology with corrections 874

2\) 2/84 BPA Issue Alert on ASC 902

3\) ASC model "Hertz Electric Co." 906

Clarifying meeting transcript on technical issues of proposed Average
915

System Cost methodology, 2/24/84, Spokane.

Clarifying meeting transcript on technical issues of proposed Average
944

System Cost methodology, 2/27/84, Portland.

Clarifying meeting transcript on technical issues of proposed Average
975

System Cost methodology, 2/28/64, Seattle.

Clarifying meeting transcript on technical issues of proposed Average
1063

System Cost methodology, 3/1/84, Idaho Falls.

Consultation session exhibits and attachments:

Exhibits 1151

1 - Revised ASC functionalization procedures, draft 1. 1154

2 - Review procedure, BPA draft 1. 1160

3 - Rate of return methodology, BPA. 1169

4 - Review procedures for revised ASC methodology, 1170

draft 2, 4/30/84;

introduction to revised ASC methodology, draft 1;

functionalization procedures; draft 1;

schedules. draft 1.

5 - Review procedures, draft 3; 1201

introduction to revised ASC methodology, draft l;

functionalization procedures, draft 2;

schedules, draft 1

6 - True-up for account 447 reviews, draft 1 1244

7 - Residential rate comparisons (table), 5/2/84. 1245

8 - ASC qualifying transmission, 5/1-2/84. 1246

9 - Footnotes to revised ASC methodology, 5/3/84. 1248

9a - ASC transmission plant, 5/3/84. 1255

9b - Clarification of footnote 7. 1256

9e - Conservation (definition). 1257

10 - Functionalization procedures, 5/3/84. 1258

11 - Review procedure, draft 2, 5/2/84. 1265

12 - Excerpts of financial data, PP&L, PGE 1277

13 - Conservation (definition), footnote i. 1280

14 - Footnote d. 1281

15 - Limited transmission exchange costs. 1282

16 - ASC transmission plant 1286

18 - Proposed footnote d. 1290

19 - Review procedure, draft 3, 5/7/84. 1294

Attachments

1 - Transmission as defined in footnote 7. 1308

2 - 4/26/84 letter to Peter T. Johnson (BPA) from Conley Ward 1309

(Idaho PUC) regarding ASC revision.

3 - 5/3/84 memo to Steven Ailshie (BPA) from George Gwinnutt 1313

(BPA) transmitting comment of John W. Howarth (Tillamook PUD).

Consultation Session, 4/20/84, Portland, Volumes I & II; 1317

Handouts: Principles for the ASC Methodology Reconsultation 1454

FED. REG. notice of proposed policy. 1455

Consultation session transcript, 4/23/84, Portland, Volume III. 1493

Consultation session transcript, 4/24/84, Portland, Volume IV. 1711

Consultation session transcript, 4/25/84, Portland, Volume V. 1887

Consultation session transcript, 4/26/84, Portland, Volume VI. 1974

Consultation session transcript, 4/27/84, Portland, Volume VII. 2058

Consultation session transcript, 4/30/84, Portland, Volume VIII. 2222

Consultation session transcript, 5/1/84, Portland, Volume IX. 2365

Consultation session transcript, 5/2/84, Portland, Volume X. 2526

Consultation session. transcript, 5/3/84, Portland, Volume XI. 2616

Consultation session transcript, 5/4/84, Portland, Volume XII. 2692

Documentation of meetings involving ASC consultation:

1\. Memo by Charles Mayor (BPA) regarding 1/9/84 meeting with 2811

Grant Tanner and Gordon Taylor (DSIs) about cost of capital;

1/10/84 memo by Grant Turner (DSIs) about Cost of Capital 2812

for Revised ASCM

2\. 2/7/84 memo by Steven Cook (BPA) regarding 2/7 meeting on 2820

proposed ASC methodology with DSIs and DSI consultant

Drazen-Brubaker; list of questions and answers.

2/9/84 letter to Steven Cook (BPA) from Alex McPhail (DSIs)

with list of questions asked at 2/7 meeting.

3\. 2/10/84 memo by Steven Cook regarding telephone conversation 2826

with Leayesh Johnson (PNGC); list of questions and answers.

4\. 2/10/84 memo by Steven Cook regarding telephone conversation with
2826a

Bob Gentry (Clark County PUD); list of questions and answers.

5\. 2/22/84 transcript of presentation on BPA's proposed change to ASC
2866

methodology during Northwest Power Planning Council meeting

in Missoula, Montana.

3/2/84 letter to Keith Colbo (Northwest Power Planning Council) 2866

from Stephen Ailshie (BPA) regarding ASC consultation process.

3/14/84 memo by Stephen Ailshie (BPA) regarding discussion with 2867

Chuck Collins (Northwest Power Planning Council) about ASC

consultation process.

6\. 3/6/84 memo by Peter T. Johnson (BPA) regarding meeting between 2868

IOUs and EPA regarding objectives of proposed ASC modification.

3/9/84 draft of minutes sent to meeting attendees. 2871

3/26/84 letter to Robert Ratcliffe (BPA) from John Ellis (Puget 2875

Sound Power & Light) regarding 3/9 draft.

7\. 3/15/84 memo by Charles Mayor (BPA) regarding 3/6 meeting with 2876

Northwest Power Planning Council about rate relief and ASC

reconsultation process.

8\. 3/15/84 memo by Charles Mayor (EPA) regarding 3/8 meeting with 2879

PGE on PGE press statement that proposed ASC methodology would

raise rates by 38 percent.

9\. 3/23/84 memo by Peter T. Johnson (BPA) regarding 3/22 meeting 2883

with DSIs which covered, in part, ASC methodology.

10\. 3/30/84 remarks of Peter T. Johnson (BPA) before City Club of 2684

Portland, "After the Firestorm" covering, in part, the residential
exchange.

11\. 4/6/84 invitation to Northwest utility commissions from Steven 2893

Ailshie (BPA) to discuss possible ASC methodologies; response to

requests from WA and ID commissions.

4/11/84 response letter to Stephen Ailshie (BPA) from John Smyth 2895

(Wyoming PSC) regarding invitation to attend 4/19/84 utility

commissioners' meeting an ASC.

4/17/84 response letter to Stephen Ailshie (BPA) from Gene Maudlin 2896

(Oregon PUC.) regarding invitation to attend 4/19/84 utility

commissioners' meeting on ASC.

4/18/84 letter to Gene Maudlin (Oregon PUC) from Stephen Ailshie (BPA).
2897

12\. 4/13/84 memo by Steven Coot (BPA) regarding 1/11 meeting with 2898

DSI consultant Drazen-Brubaker about IOU return, public utility

exchange cost' IOU transmission cost, and resource approach vs.

present methodology; workpapers.

13\. 4/18/84 memo by Nancy Randall (BPA) of calls to state regulatory
2921

bodies regarding meeting on ASC methodology.

14\. 5/17/84 memo by Steven Cook (BPA) regarding 5/9 meeting with 2922

Larry Frank (DSI consultant) about rate impacts.

Informational Mailings by BPA:

2/16/84 general information letter enclosing 2/84 Issue Alert. 2930

2/17/84 notice of clarifying meetings on technical issues. 2935

3/2/84 extension of comment periods; notice of meeting opportunities.
2936

4/11/84 notice of consultation sessions. 2937

4/20/84 BPA press release announcing ASC consultation sessions. 2938

4/27/84 letter explaining ASC process to date with 2/84 Issue Alert.
2940

5/15/84 letter enclosing (BPA) staff's proposed Average System Cost 2945

Methodology developed in public consultation sessions.

5/17/84 letter enclosing Index to the ASC Official Record, 2974

requesting additions by 5/25/84.

5/17/84 letter enclosing Information Release, Issue Alert and 2982

request for comments by 5/25/84.

Addendums to the Record:

Other comments received after 4/23/84. 2986

List of Commenters 6548

PGE letter enclosing petitions. 6545

BPA's certificate in lieu of petitions. 6546

Comments received on 5/15/84 BPA Staff ASC proposal;

comment period 5/18/84 through 5/25/84.

Consumers Power, Inc. 6548

Martin Marietta Aluminum 6550

Idaho Cooperative Utilities Association 6552

CP National Corporation, 6554

ARCO Aluminum 6557

WUTC 6560

Puget Sound Power and Light Co. 6564

Utah Power and Light Co. 6572

Public Utility Commission of Oregon 6580

DSIs 6585

Everett Area Chamber of Commerce 6655

Southern California Edison Co. 6656

Idaho Power Co. 6659

Washington Hater Power Co. 6664

Pacific NW Generating Co. 6668

Public Power Council 6670

Pacific Power and Light Co. 6673

Portland General Electric Co. 6708

Fair Electric Bates Now 6754

Power Planning Council 6760

Cowlitz County PUD 6762

Idaho Public Utilities Commission 6797

Correspondence:

5/10/84 Brief memo from Charles Mayor to Stephen Ailshie regarding 6763

documenting a Determination of No Significant Impact Regarding

Proposed ASCM.

5/15/84 response letter to George Hansen from JoAnn Scott 6771

regarding ASCM.

5/21/84 response letter to George Hansen from Peter Johnson 6773

regarding constituents concern over ASCM. 6773

5/17/84 response letter to Floyd Aylor from Peter Johnson 6775

regarding Dundee City Council Resolution of 4/11/84.

Dundee Resolution. 6776

5/17/84 response letter to Andrew Ulver from Peter Johnson 6777

regarding letter sent to Donald Hodel about ASCM.

Letter to Hodel. 6779

5/17/84 response letter to Prad Shah by Peter Johnson 6780

regarding letter sent to Donald Hodel.

Letter to Hodel.

5/2/84 memo on Revision of ASCM from Dan Meek to Peter Johnson. 6782

5/25/84 letter from Dan Meek emphasizing portion of the memo. 6790

5/25/84 letter to Raymond O'Connor from Peter Johnson 6792

requesting expeditious FERC review.

5/31/84 response letter to Marcus Wood from John Cameron 6795

regarding PP&L's request to supplement the record.

5/23/84 letter to Peter Johnson from Conley Ward submitting comments.
6797

Residential Purchase and Sales Agreement 6800

Additional correspondence:

Letter from Phil Talmadge to Congressional Delegation 6922

Letter from Joel Pritchard to Peter Johnson commenting on ASC
methodology. 6923

Letter from Alcoa Committee of 1700 to Congressmen attaching petitions
6924

BPA certificate in lieu of petitions 6925

Petition of Alcoa Committee of 1700 6926

Letters from interested individuals to members of Congress 6928-6953

ABBREVIATIONS OF COMMENTING PARTIES

[PARTY]{.underline} [ABBREVIATION]{.underline}

Bonneville Power Administration BPA

CP National Corp. CPN

Direct Service Industrial Customers DSI

Idaho Cooperative Utilities Assoc. ICUA

Idaho Power Co. IPC

Idaho Public Utility Commissioner IPUC

Investor owned utilities IOU

Montana Power Co. MPC

Oregon Public Utility Commissioner OPUC

Pacific Northwest Generating Co. PNGC

Pacific Power & Light Co. PP&L

Portland General Electric Co. PGE

Public Generating Pool PGP

Public Power Council PPC

Puget Sound Power & Light Co. Puget

Salmon River Electric Cooperative SREC

Springfield Utility Board SUB

Utah Power s Light Co. UP&L

Western Washington PUDs WWPUD

DEPARTMENT OF ENERGY

BONNEVILLE POWER ADMINISTRATION

Methodology for

Determining the Average System

Cost of Resources for Electric

Utilities Participating in the Residential

Exchange Established by

Section 5(c) of the Pacific Northwest

Electric Power Planning and Conservation Act

June 1984

CONTENTS:

Procedures

Schedules

Footnotes

**REVIEW PROCEDURE**

**BONNEVILLE POWER ADMINISTRATION**

The following rule sets forth the procedures by which an Average System
Cost (ASC) filing is to be submitted to Bonneville Power Administration
(BPA) and by which the BPA review process will be conducted. BPA's
review is to determine the ASC for the purpose of the residential
exchange between BPA and participating utilities pursuant to section
5(c) of the Pacific Northwest Electric Power Planning and Conservation
Act, 16 U.S.C. §839, *et. seq.* (Northwest Power Act).

**I. DEFINITIONS:**

For purposes of BPA's review procedures for Appendix 1, the following
definitions apply:

A. "Average system cost" or "ASC" means for each Jurisdiction and each
exchange period the quotient obtained by dividing Contract System Costs
by Contract System Load.

B. "Commission" means the Federal Energy Regulatory Commission.

C. "Contract System Costs" means the Utility's Costs for production and
transmission resources, including power purchases and conservation
measures, which Costs are includable in, jurisdictionally allocated by,
and subject to the provisions of Appendix 1. Contract System Costs do
not include Costs excluded from ASC by section 5(c)(7) of the Northwest
Power Act.

D. "Contract System Load" means the firm energy load used by the State
Commission for the purpose of establishing retail rates, adjusted
pursuant to the Average System Cost Methodology rule.

E. "Costs" means the aggregate dollar amount or any portion of the
amount allowed or relied upon by the State Commission to determine the
test period revenue requirement for the Utility in a Jurisdiction.

F. "Exchange Period" means the period of time during which a Utility's
jurisdictional retail rate schedules are in effect, commencing with the
effective date of these schedules and ending with the effective date of
new retail rate schedules in the Jurisdiction; provided that no Exchange
Period shall commence prior to or extend beyond the term of the
Utility's Residential Purchase and Sale Agreement. For the purposes of
any initial Appendix 1 filing' the Exchange Period shall commence on the
date such Appendix 1 is filed and end with the effective date of the
next retail rate change.

G. "Jurisdiction" means the service territory of the exchanging Utility
within which a State Commission has authority to approve the retail
rates.

H. "New Large Single Load" means that load defined in section 3(13) of
the Northwest Power Act, and as determined by BPA as specified in power
sales contracts with its customers.

I. "Regional Power Sales Customer" means any entity that contracts
directly with BPA for the purchase of power for delivery in the region
as defined by section 3(14) of the Northwest Power Act.

J. "Test Period" means the time period (not less than 12 months) used by
the State Commission to determine Costs for retail ratemaking.

K. "State Commission" means a state regulatory body, preference utility
governing body' or other entity authorized to establish retail electric
rates in a Jurisdiction.

L. "File" or "Filed" means that the Appendix 1 has been:

\(1\) hand delivered to the Division of Financial Requirements;
Bonneville Power Administration; Portland, Oregon; or

\(2\) mailed to BPA by certified mail, return receipt requested, to the
following address:

Bonneville Power Administration

Division of Financial Requirements Routing: DN

P.O. Box 3621

Portland, Oregon 97208

and has been received by BPA. An Appendix 1 shall be considered to be
filed as of the date of the postmark on the certified mailing.

M. "Review Period" means that period of time during which a Utility's
Appendix 1 is under review by Bonneville. The review period begins when
an Appendix 1 is Filed and ends two hundred and ten (210) days after the
Utility Filed its Appendix 1.

**II. FILING PROCEDURES:**

The procedures set forth in this section state the filing requirements
for all Utilities which File an Appendix 1. The procedures are as
follows:

A. Appendix 1 is a form that identifies Contract System Costs and
Contract System Load and permits the calculation of ASC.

B. For each Exchange Period and for each regional Jurisdiction in which
a Utility provides service' the Utility shall complete and File three
copies¬of Appendix 1 as follows:

1\. (a) Within twenty (20) working days after the date the Commission
grants interim approval, or final approval in the event no interim
approval is granted to any revised ASC Methodology, the Utility shall
File an Appendix 1, which includes a loss study' reflecting its Costs
for the test period for the rate schedule(s) then in effect for each
Jurisdiction. Subject to the provisions of section III, the ASC
determined from each Appendix 1 shall be the rate applicable to exchange
power from that Jurisdiction during the initial Exchange Period. For
purposes of this subsection, the initial Exchange Period shall commence
on the date the Commission grants interim approval, or final approval in
the event no interim approval is granted to any revised Methodology;
provided that if a Utility Files an initial Appendix 1 after the
twenty-day deadline' BPA may make the new ASC payable only from the date
the initial Appendix 1 was actually Filed. However, BPA shall not delay
as a result of a late filing of an Appendix 1, the effective date of any
change in the ASC if the late filing was the result of unavoidable delay
or excusable neglect, and the Utility proceeded to File its initial
Appendix 1 as soon as practicable. If a Utility fails to File its
initial Appendix 1 within the twenty-day deadline, the ASC of that
Utility for the initial Exchange Period shall be zero (0) until the
Utility files its initial Appendix 1.

\(b\) For those Utilities that are parties to an Exchange Transmission
Credit Agreement (ETCA), within twenty (20) working days after the date
the ETCA is terminated, the Utility shall File an Appendix 1, which
includes a loss study, reflecting its Costs for the Test Period for the
rate schedule then in effect for each Jurisdiction. Subject to the
provisions of section III of this rule, the ASC determined from each
Appendix 1 shall be the rate applicable to exchange power from that
Jurisdiction during the initial Exchange Period. For purposes of this
subsection, the initial Exchange Period shall commence on the date the
ETCH is terminated; provided that if a Utility Files an initial Appendix
I after the twenty-day deadline, BPA may make the new ASC payable only
from the date the initial Appendix 1 was actually Filed. However, EPA
shall not delay as a result of a late filing of an Appendix 1, the
effective date of any change in the ASC if the late filing was the
result of unavoidable delay or excusable neglect, and the Utility
proceeded to File its initial Appendix 1 as soon as practicable.

2\. Thereafter, not later than five (5) working days after filing for a
jurisdictional rate change or otherwise commencing a rate change
proceeding, the Utility shall File a preliminary Appendix 1, setting
forth the Costs proposed by the Utility and shall deliver to BPA all
information initially provided to the State Commission.

3\. Not later than twenty (20) days following the commencement date of a
new Exchange Period, the Utility shall File a revised Appendix l, which
includes a loss study, reflecting its Costs as approved by the State
Commission and a reconciliation of all Costs included on the revised
Appendix l 'to the rate order issued by that Utility's State Commission.
Subject to the provisions of section III of this rule,- the ASC included
in the revised Appendix 1 will be the ASC applicable to exchange power
for that Jurisdiction-during the Exchange Period, provided that if a
Utility Files a revised Appendix 1 after the twenty day deadline, BPA
may make the new ASC payable only from the date the revised Appendix 1
was actually filed. However, BPA shall not delay as a result of a late
filing of an Appendix 1, the effective date of any change in the ASC if
the late filing was the result of unavoidable delay or excusable
neglect, and the Utility proceeded to File its revised Appendix 1 as
soon as practicable.

4\. (a) A Utility filing a preliminary Appendix I shall mail written
notice thereof to each of BPA's Regional Power Sales Customers or their
designee notice of any ASC filing.

\(b\) A Utility filing a revised Appendix I -shall mail written notice
thereof to each of BPA's Regional Power Sales Customers or their
designates notice of any ASC filing. This notice shall make reference to
the right to comment thereon and shall state the date the Utility Filed
its revised Appendix 1.

C. If BPA or any of its regional power sales customers have been denied
the right to participate in a jurisdictional rate review proceeding or
with rights equivalent to any retail customer of the Utility, no change
in ASC based on a change of Costs authorized in that proceeding shall be
effective until BPA has completed its review pursuant to section III of
this rule.

**III. BPA REVIEW PROCESS:**

A. BPA may intervene in each jurisdictional rate proceeding for each
Utility participating in the Residential Purchase and Sale Agreement.

B. Each Appendix 1, except those required by section II(B)(2) of this
rule, shall be reviewed by BPA or its designee to determine whether the
Costs are consistent with generally accepted accounting principles for
electric utilities, whether Contract System Costs contains only allowed
Costs, and whether the revised Appendix 1 complies with the requirements
of this Methodology including applicable definitions and requirements
incorporated from the Commission's Uniform System of Accounts. In
addition, each Appendix 1 shall be reviewed by BPA or its designee to
determine whether the Contract System Load used by the Utility is an
appropriate load for purposes of the Utility's ASC computation.

BPA will make an independent\*\* determination for ASC computation of
(1) the appropriateness of the inclusion of Costs; (2) the
reasonableness of the Costs included in Contract System Cost; and (3)
the appropriateness of Contract System Loads. BPA shall not be obligated
to pay an ASC different than the ASC based on Contract System Costs and
Contract System Load as determined by BPA; provided that if a final
order of the Commission or a reviewing court rejects BPA's ASC
determination, then the ASC payable by BPA shall be the ASC as revised
by BPA on remand.

C. The review period for each Appendix 1 required by section II(B)(I) of
this rule shall commence no later than one hundred (100) days from the
date the Utility Files the Appendix 1 required by section II(B)(1). BPA
shall mail written notice of the date BPA's review period commences to
the Utility, to each of BPA's Regional Power Sales Customers or their
designee notice of any Appendix 1 filing. The Appendix 1 required by
section II(B)(1) o£ this rule shall then be subject to review as set
forth in section III(D). For purposes of the review process, the
Appendix l referred to in section II(B)(1) shall be deemed to be a
"revised Appendix 1" as used in III(D) below and the date the review
period commences shall be deemed be the date the Utility Filed its
revised Appendix 1.

D. The revised Appendix 1 described in section II(B)(3) of this rule
shall be subject to review as follows:

1\. Not later than 80 days following the date a Utility Files a revised
Appendix 1, only Regional Power Sales Customers or their designee may
submit written challenges to Costs included in the Utility's Contract
System Costs. The challenge shall identify the specific Cost and state
the nature of the challenge. Any of BPA's Regional Power Sales Customers
who submit challenges will be accorded automatic party status for
purposes of the review process on that Utility's filing. To be
considered by BPA, challenges must be received by BPA no later than
eighty (80) days following the date a Utility Files its revised
Appendix 1. In addition to those of EPA's Regional Power Sales Customers
who so request will be accorded party status for a specific filing if
said request is received no later than eighty (80) days following the
date a Utility Files its revised Appendix 1. For purposes of the review
process, the Utility is a party to any review of any Appendix l which is
submitted by the Utility.

2\. (a) Not later than ninety (90) days following the date the Utility
Files its revised Appendix 1, BPA shall mail to the Utility and all
parties a notice (1) listing each challenged Cost and the nature of the
challenge; (2) listing all parties for the review process for the
revised Appendix 1; and (3) requesting comments by all parties on
challenged costs.

\(b\) Comments shall be submitted in writing to BPA and to all parties.
Written comments, to be considered, must be [received]{.underline} by
BPA and must be mailed to all parties within thirty (30) days of the
date of the notice.

\(c\) Parties may submit written cross comments in response to the
previously submitted comments. Cross comments must be in writing and
must be [received]{.underline} by BPA and must be mailed to all parties
not later than fifteen (15) days following the date the parties submit
written comments.

3\. Requests for oral argument before the Administrator or his designate
must be submitted in writing to BPA with a statement setting forth
reasons why the party believes the review process will be enhanced
thereby. The written requests for oral arguments must be submitted no
later than one hundred and fifty (150) days following the date the
Utility Files its revised Appendix 1. BPA may, in its sole discretion,
grant the request for oral argument. Requests for oral argument shall be
served on all parties.

4\. (a) Not later than one hundred and thirty-five (135) days following
the date a Utility Files its revised Appendix 1, BPA may, in its sole
discretion, issue a notice to all parties requesting comments on Costs
that have not been challenged previously, on Contract System Loads, and
on other issues that have not been raised previously. Any challenge to
the Contract System Load used by the Utility in computing ASC may be
raised at this time only, and only by BPA. All comments responding to
this notice must be received in writing no later than one hundred and
fifty (150) days following the date the Utility Files its revised
Appendix 1. In addition to providing the written comments to BPA, any
party commenting shall provide all parties with a copy of the comment
not later than one hundred and fifty (150) days following the date the
Utility Files its revised Appendix 1.

\(b\) Parties may submit written cross comments in response to the
comments submitted in response to the notice in section III(D)(4)(a) of
this rule. Cross comments from all parties must be
[received]{.underline} in writing by BPA and must be mailed to all other
parties not later than one hundred and sixty-five (165) days following
the date the Utility Files its revised Appendix 1.

5\. In the event a request for oral argument is granted, any party shall
be permitted to present oral argument. The presentation of the Utility
shall be last. Oral argument shall be presented no later than one
hundred and eighty (180) days from the date a Utility Files its revised
Appendix 1.

6\. The Review Period will and two hundred and ten (210) days from the
date the Utility Files its revised Appendix 1. BPA will-issue its final
determination not later than two hundred ten (210) days from the date
the Utility Files its revised Appendix 1.

If the date of BPA's final determination or any other deadline contained
in these review procedures falls on a Saturday, a Sunday, or a legal
public holiday, then the deadline or BPA's final determination shall
fall on the first day following that is not a Saturday, a Sunday or a
legal public holiday. Legal public holiday means legal public holiday as
defined in 5 U.S.C. 6103(a).

E. (1) BPA may request data from the Utility at any time during the
Review Period. Each Utility shall respond to reasonable data requests
for information relevant to Appendix 1 from BPA, provided that the
furnishing of proprietary or confidential information to any party to
the review proceedings may be made contingent on the granting of proper
safeguards to prevent unauthorized use,or disclosure. The Utility shall
provide all the data requested no later than thirty (30) days from the
date of BPA's data request. If the Utility objects to the data request,
it shall state in writing to BPA the specific basis for its objection no
later than twenty-five (25) days from the date of BPA's data request.
BPA will issue a ruling as to whether the Utility's objection will be
sustained or overruled. If BPA rules that the Utility must comply with
the data request, the Utility has fifteen (15) days from the date of
BPA's ruling to comply. If the Utility does not provide the data
requested, BPA may, in its discretion, remove from Contract System Costs
all Costs that are associated with the data not provided.

\(2\) Data requests from persons or entities other than BPA shall be
limited as follows. Each Utility shall respond to reasonable data
requests for information relevant to Appendix 1 from any party in the
review process for that Utility's Appendix 1, provided that the
furnishing of proprietary or confidential information to any party to
the review proceedings maybe made contingent on the granting of proper
safeguards to prevent unauthorized use or disclosure. A Utility which
provides data to any party in response to a data request by that party
shall also provide the same data to BPA. Data requests must be received
by the Utility no later than forty (40) days from the date the Utility
Filed its revised Appendix 1. The data request must identify the
specific Cost(s) that is associated with the information requested. The
Utility shall provide all the data requested no later than sixty-five
(65) days from the date the Utility Filed its revised Appendix 1. If the
Utility objects to the data request, it shall state with specificity in
writing to BPA the basis for its objection. BPA will issue a ruling as
to whether the Utility's objection will be sustained or overruled. The
Utility must submit its objection no later than sixty (60) days from the
date the Utility Filed its revised Appendix 1. If BPA rules that the
Utility must comply with the data request, the Utility has fifteen (15)
days from the date of BPA's ruling to comply. If the Utility does not
provide the data requested, BPA may, in its discretion, remove from
Contract System Costs all Costs that are associated with the data not
provided.

\(3\) All written comments and written cross comments received by BPA by
the deadlines set forth above will be included as part of the record
supporting the ASC determined by BPA. In addition' all data provided by
the Utility as part of its filing in response to data requests from BPA
or from any party shall be included as part of the record supporting the
ASC determined by BPA. For any jurisdictional rate proceeding in which
BPA has intervened, all data received by BPA by virtue of its intervenor
status shall also be included as part of the record supporting the ASC
determined by BPA.

F. If BPA has not issued a report as of the last date of the review
period, the ASC rate shown on the revised Appendix 1 described in
section II(B) of this rule Filed by the Utility shall be the ASC from
the commencement of the relevant Exchange Period until the date BPA
issues its report. The ASC, as determined by BPA, shall then be the ASC
rate from the date of BPA's determination until the commencement of the
Utility's next Exchange Period.

**IV. CHANGE IN AVERAGE SYSTEM COST METHODOLOGY:**

The Administrator, at his or her discretion, or upon written request
from three-quarters of the Utilities that are parties to contracts
authorized by section 5(c) of the Northwest Power Act, or from
three-quarters of BPA's preference customers, or from three-quarters of
EPA's direct-service industrial customers' may initiate a consultation
process as provided for in section 5(c) of the Northwest Power Act.
After completion of this process, the Administrator may propose a new
ASC Methodology to the Commission. However, the Administrator shall not
initiate any consultation process until one year of experience has been
gained under the then-existing ASC Methodology, *viz*, one year after
the then-existing Methodology has been adopted by BPA and implemented by
the Commission through interim or final approval, whichever occurs
first.

**TIMELINE**

**REVIEW PROCEDURE**

**BONNEVILLE POWER ADMINISTRATION**

[DAY]{.underline} [EVENT]{.underline}

-20 COMMENCEMENT OF NEW EXCHANGE PERIOD

0 UTILITY FILES REVISED APPENDIX 1 UTILITY MAILS NOTICE OF FILING.

40 DEADLINE FOR DATA REQUESTS TO UTILITY FROM PARTIES.

60 DEADLINE FOR UTILITY TO OBJECT TO DATA REQUEST FROM PARTIES.

65 DEADLINE TO RESPOND TO DATA REQUEST FROM PARTIES.

80 DEADLINE TO RAISE ISSUES IN THE UTILITY'S ASC FILING (SUBMIT WRITTEN
CHALLENGES TO COSTS INCLUDED IN THE UTILITY'S APPENDIX 1).

DEADLINE TO REQUEST PARTY STATUS FOR ALL PERSONS OR ENTITIES NOT
SUBMITTING CHALLENGES TO THE COSTS INCLUDED IN THE UTILITY'S APPENDIX 1.

90 BPA MAILS NOTICE OF ISSUES, LIST OF PARTIES, AND REQUEST FOR
COMMENTS.

120 DEADLINE FOR SUBMISSION OF WRITTEN COMMENTS ON FIRST ROUND ISSUES.

135 DEADLINE FOR SUBMITTING WRITTEN CROSS COMMENTS ON FIRST ROUND
ISSUES.

BPA MAILS NOTICE OF SECOND ROUND ISSUES.

150 DEADLINE FOR SUBMISSION OF WRITTEN COMMENTS OF SECOND ROUND ISSUES.

150 DEADLINE FOR REQUESTING ORAL ARGUMENT.

165 DEADLINE FOR SUBMISSION OFWRITTEN CROSS COMMENTS ON SECOND ROUND
ISSUES.

180 DEADLINE FOR PRESENTATION OF ORAL ARGUMENT.

210 REVIEW PERIOD ENDS. BPA ISSUES FINAL DETERMINATION.

**INSTRUCTIONS**

Exhibit C - Appendix 1 is the form on which a Utility participating in a
Residential Purchase and Sale Agreement shall report its Contract System
Costs and other necessary data for the calculation of ASC.

The form consists of four schedules that shall be completed by the
Utility in accord with these instructions and the provisions of the
footnotes following the schedules. Any items not applicable to the
Utility shall be so identified.

The schedules are as follows:

Schedule 1 - Plant Investment/Rate Base/Rate of Return

Schedule 2 - Weighted Average Cost of Long Term Debt

Schedule 3 - Expenses

Schedule 4 - Average System Cost

The filing Utility shall reference and attach workpapers that support
Costs, including details of allocation and functionalization.

All references to the Commission accounts are to the Commission Uniform
System of Accounts as of July 1, 1984. The Costs includable in the
attached schedules are those includable by reason of the definitions in
the Commission accounts. If the Commission accounts are later revised or
renumbered, any changes shall be incorporated into this form by
reference, except to the extent that RP• determines that a particular
change results in a change in the type of Costs allowable for exchange
purposes. If the Utility does not follow the Commission accounts, its
filing must include a reconciliation between its accounts and the items
allowed as Contract System Costs.

BPA may require the Utility to account for purchased power transactions
with affiliated entities as though the affiliated entities were owned in
whole or in part by the Utility, if necessary to properly determine and
or functionalize the Utility's Costs.

A Utility operating in more than one Jurisdiction shall allocate its
total system Costs among Jurisdictions in accord with the same
allocation methods and procedures used by the State Commission to
establish jurisdictional Costs and resulting revenue requirements.
Appendix 1 shall include details of the allocation. This allocation also
accomplishes the exclusion of the Costs of additional resources to meet
loads outside the region, as required by section 5(c)(7) of the
Northwest Power Act.

All schedule entries and supporting data shall be in accord with
generally accepted accounting principles and practices as these
principles and practices apply to the electric utility industry.

Schedule 1 Exhibit C Appendix 1

BONNEVILLE POWER ADMINISTRATION

RESIDENTIAL PURCHASE AND SALE AGREEMENT

Average System Cost Methodology

Test Period:

Plant Investment/Rate Base/Rate of Return (Thousands)

  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------
                                                                                  Functionalization                                     

  Line                [\                           Total To Be                    [\                        [\                          [\
  [No.]{.underline}   Items]{.underline}           [Functionalized]{.underline}   Production]{.underline}   Transmission]{.underline}   Other]{.underline}

                      \(1\)                        \(2\)                          \(3\)                     \(4\)                       \(5\)

                                                                                                                                        

                      PRODUCTION PLANT                                                                                                  

  1                   Steam Production 310-316                                                                                          

  2                   Nuclear Production 320-325                                                                                        

  3                   Hydraulic Production 330-336                                                                                      

  4                   Other Production Plant                                                                                            
                      340-346                                                                                                           

  5                   Total Production Plant                                                                                            

  6                   Transmission Plant 350-359                                                                                        
                      [a]{.underline}/                                                                                                  

  7                   Distribution Plant 360-373                                                                                        
                      [b]{.underline}/                                                                                                  

  8                   Intangible Plant 301-303                                                                                          
                      [j]{.underline}/                                                                                                  

  9                   General Plant 389-399                                                                                             
                      [j]{.underline}/                                                                                                  

  10                  Electric Plant-in-Service                                                                                         

                                                                                                                                        

                      LESS:                                                                                                             

  11                  Depreciation Reserve 108                                                                                          

  12                  Steam Plant                                                                                                       

  13                  Nuclear Plant                                                                                                     

  14                  Hydraulic Plant                                                                                                   

  15                  Other Plant                                                                                                       

  16                  Transmission Plant                                                                                                
                      [a]{.underline}/                                                                                                  

  17                  Distribution Plant                                                                                                
                      [b]{.underline}/                                                                                                  

  18                  General Plant                                                                                                     
                      [j]{.underline}/                                                                                                  

  19                  Amortization Reserve 111                                                                                          
                      [j]{.underline}/                                                                                                  

  20                  Total Depreciation &                                                                                              
                      Amortization                                                                                                      

                                                                                                                                        

  21                  TOTAL NET PLANT                                                                                                   

                                                                                                                                        

  22                  Nuclear Fuel 120.2-120.4                                                                                          
                      Less 120.5                                                                                                        

  23                  Accumulated Deferred\                                                                                             
                      Debits 186 [j]{.underline}/                                                                                       

  24                  Cash Working Capital                                                                                              
                      [h]{.underline}/                                                                                                  

  25                  Materials and Supplies\                                                                                           
                      151-157, 163                                                                                                      
                      [j]{.underline}/                                                                                                  

                                                                                                                                        

                      LESS:                                                                                                             

  26                  Accumulated Deferred                                                                                              
                      Investment                                                                                                        

                      Tax Credits/255                                                                                                   
                      [j]{.underline}/                                                                                                  

  27                  Accumulated Deferred Income                                                                                       
                      Taxes/281-283                                                                                                     
                      [j]{.underline}/                                                                                                  

  28                  Other Accumulated Deferred                                                                                        
                      Credits/253, 256-257                                                                                              
                      [j]{.underline}/                                                                                                  

  29                  Customer Contributions and                                                                                        
                      Aid\                                                                                                              
                      to Construction/252                                                                                               
                      [j]{.underline}/                                                                                                  

  30                  Other 106, 124, Various                                                                                           
                      [i]{.underline}/                                                                                                  
                      [j]{.underline}/                                                                                                  

                                                                                                                                        

  31                  TOTAL RATE BASE                                                                                                   

                                                                                                                                        

  32                  Times Rate of Return                                                                                              
                      \@\_\_\_%, [d]{.underline}/                                                                                       
  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------

Schedule 2 Exhibit C Appendix 1

BONNEVILLE POWER ADMINISTRATION

RESIDENTIAL PURCHASE AND SALE AGREEMENT

Average System Cost Methodology

Test Period:

Weighted Average Cost of Long Term Debt

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

  Line   Items      Date of Date of    Interest   Iace     Premium   Discount   Issue     Net        Interest
  No.               Issue   Maturity   Rate       Amount                        Expense   Proceeds   Expense

                    \(1\)   \(2\)      \(3\)      \(4\)    \(5\)     \(6\)      \(7\)     \(8\)      \(9\)

  1                                                                                                  

  2                                                                                                  

  3                                                                                                  

  4                                                                                                  

  5                                                                                                  

  6                                                                                                  

  7                                                                                                  

  8                                                                                                  

  9                                                                                                  

  10                                                                                                 

  11                                                                                                 

  12                                                                                                 

  13                                                                                                 

  14                                                                                                 

  15                                                                                                 

  16     Weighted                                                                                    
         Average                                                                                     

         Cost of                                                                                     
         Long Term                                                                                   
         Debt                                                                                        
  ------ ---------- ------- ---------- ---------- -------- --------- ---------- --------- ---------- ----------

Schedule 3, Page 1 of 2 Exhibit C Appendix 1

BONNEVILLE POWER ADMINISTRATION

RESIDENTIAL PURCHASE AND SALE AGREEMENT

Average System Cost Methodology

Test Period:

Expenses (Thousands)

  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------
                                                                                  Functionalization                                     

  Line                [\                           Total To Be                    [\                        [\                          [\
  [No.]{.underline}   Items]{.underline}           [Functionalized]{.underline}   Production]{.underline}   Transmission]{.underline}   Other]{.underline}

                      \(1\)                        \(2\)                          \(3\)                     \(4\)                       \(5\)

                                                                                                                                        

                      PRODUCTION                                                                                                        

  1                   Fuel 501, 516, 547                                                                                                

  2                   Purchased Power 555                                                                                               

                      Operations & Maintenance                                                                                          

  3                   Steam 500, 502-514                                                                                                

  4                   Nuclear 517,519-532                                                                                               

  5                   Hydro 535-545                                                                                                     

  6                   Other 546,548-554                                                                                                 

  7                   TOTAL PRODUCTION EXPENSE                                                                                          

                                                                                                                                        

  8                   TRANSMISSION 560-573                                                                                              
                      [a]{.underline}/                                                                                                  

  9                   DISTRIBUTION 560-596                                                                                              
                      [b]{.underline}/                                                                                                  

  10                  CUSTOMER ACCOUNTING\                                                                                              
                      901-905 [j]{.underline}/                                                                                          

  11                  CUSTOMER ASSISTANCE 907-910                                                                                       
                      [j]{.underline}/                                                                                                  

                                                                                                                                        

                      ADMINISTRATIVE &\                                                                                                 
                      GENERAL [j]{.underline}/                                                                                          

                      Account Number                                                                                                    

  12                  920                                                                                                               

  13                  921                                                                                                               

  14                  922                                                                                                               

  15                  923                                                                                                               

  16                  924                                                                                                               

  17                  925                                                                                                               

  18                  926                                                                                                               

  19                  927                                                                                                               

  20                  928                                                                                                               

  21                  929                                                                                                               

  22                  930                                                                                                               

  23                  930.2                                                                                                             

  24                  931                                                                                                               

  25                  932                                                                                                               

  26                  Total A & G                                                                                                       

                                                                                                                                        

  27                  TOTAL OPERATIONS &                                                                                                
                      MAINTENANCE                                                                                                       

                                                                                                                                        

  28                  DEPRECIATION & AMORTIZATION                                                                                       
                      403-407                                                                                                           

  29                  Steam Production Plant                                                                                            

  30                  Nuclear Production Plant                                                                                          

  31                  Hydraulic Production Plant                                                                                        

  32                  Other Production Plant                                                                                            

  33                  Transmission Plant                                                                                                
                      [a]{.underline}/                                                                                                  

  34                  Distribution Plant                                                                                                
                      [b]{.underline}/                                                                                                  

  35                  General Plant                                                                                                     
                      [j]{.underline}/                                                                                                  

  36                  Amortization                                                                                                      
                      [j]{.underline}/                                                                                                  

  37                  TOTAL DEPRECIATION &                                                                                              
                      AMORTIZATION                                                                                                      
  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------

Schedule 3, Page 2 of 2 Exhibit C Appendix 1

BONNEVILLE POWER ADMINISTRATION

RESIDENTIAL PURCHASE AND SALE AGREEMENT

Average System Cost Methodology

Test Period:

Expenses (Thousands)

  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------
                                                                                  Functionalization                                     

  Line                [\                           Total To Be                    [\                        [\                          [\
  [No.]{.underline}   Items]{.underline}           [Functionalized]{.underline}   Production]{.underline}   Transmission]{.underline}   Other]{.underline}

                      \(1\)                        \(2\)                          \(3\)                     \(4\)                       \(5\)

                                                                                                                                        

  38                  Taxes 408, 409.1                                                                                                  
                      [j]{.underline}/                                                                                                  

  39                  Federal Income Tax                                                                                                
                      [j]{.underline}/                                                                                                  

  40                  State Income Tax                                                                                                  

  41                  Other Expenses                                                                                                    
                      [j]{.underline}/                                                                                                  

                                                                                                                                        

                      Less:                                                                                                             

  42                  Sales for Resale Rev. 447                                                                                         

  43                  Other Operating Revenues\                                                                                         
                      450-456 [j]{.underline}/                                                                                          

  44                  Billing Credits                                                                                                   
                      [c]{.underline}/                                                                                                  

  45                  TOTAL OPERATING EXPENSES                                                                                          

                                                                                                                                        

  46                  Return from Schedule 1                                                                                            

  47                  Other Adjustments                                                                                                 

                                                                                                                                        

  48                  TOTAL COST                                                                                                        
  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------

Schedule 3A Exhibit C Appendix 1

BONNEVILLE POWER ADMINISTRATION

RESIDENTIAL PURCHASE AND SALE AGREEMENT

Average System Cost Methodology

Test Period:

Taxes Other Than Income Taxes (Thousands)

  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------
                                                                                  Functionalization                                     

  Line                [\                           Total To Be                    [\                        [\                          [\
  [No.]{.underline}   Items]{.underline}           [Functionalized]{.underline}   Production]{.underline}   Transmission]{.underline}   Other]{.underline}

                      \(1\)                        \(2\)                          \(3\)                     \(4\)                       \(5\)

                                                                                                                                        

                      PRODUCTION                                                                                                        

  1                   FEDERAL - Insurance                                                                                               
                      Contributions                                                                                                     

  2                   \- Unemployment                                                                                                   

                      STATE                                                                                                             

  3                   California - Property                                                                                             

  4                   \- Unemployment                                                                                                   

  5                   Oregon - Property                                                                                                 

  6                   \- Tri-Met                                                                                                        

  7                   \- Lane County                                                                                                    

  8                   \- Unemployment                                                                                                   

  9                   \- Regulatory Commission                                                                                          

  10                  Washington - Property                                                                                             

  11                  \- Unemployment                                                                                                   

  12                  \- Generating Tax                                                                                                 

  13                  \- Pollution Control Credit                                                                                       

  13a                 \- Revenue & Business                                                                                             

  14                  Idaho - Property                                                                                                  

  15                  Montana - Property                                                                                                

  16                  \- Unemployment                                                                                                   

  17                  Wyoming - Property                                                                                                

  18                  \- Unemployment                                                                                                   

  19                  Utah - Property                                                                                                   

                                                                                                                                        

  20                  LOCAL - Occupation and                                                                                            
                      Franchise                                                                                                         

  21                  IN-LIEU TAXES                                                                                                     
                      [e]{.underline}/                                                                                                  

  22                  OTHER                                                                                                             

                                                                                                                                        

  23                  TOTAL                                                                                                             
  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------

Note: 1. Supporting workpapers are to be attached.

2\. Footnotes referenced on Schedule 3 will be relied upon in
determining ASC.

Schedule 3B Exhibit C Appendix 1

BONNEVILLE POWER ADMINISTRATION

RESIDENTIAL PURCHASE AND SALE AGREEMENT

Average System Cost Methodology

Test Period:

Other Included Items (Thousands)

  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------
                                                                                  Functionalization                                     

  Line                [\                           Total To Be                    [\                        [\                          [\
  [No.]{.underline}   Items]{.underline}           [Functionalized]{.underline}   Production]{.underline}   Transmission]{.underline}   Other]{.underline}

                      \(1\)                        \(2\)                          \(3\)                     \(4\)                       \(5\)

                                                                                                                                        

                      Operating Revenues:                                                                                               

  1                   Sales for Resale 447                                                                                              

  2                   1\.                                                                                                               

  3                   2\.                                                                                                               

  4                   Total                                                                                                             

                                                                                                                                        

                      Other Operating Revenues                                                                                          
                      450-456 [j]{.underline}/                                                                                          

  5                   Acct. 450                                                                                                         

  6                   Acct. 451                                                                                                         

  7                   Acct. 452                                                                                                         

  8                   Acct. 453                                                                                                         

  9                   Acct. 454                                                                                                         

  10                  Acct. 455                                                                                                         

  11                  Acct. 456                                                                                                         

  12                  Total Other Revenues                                                                                              
  ------------------- ---------------------------- ------------------------------ ------------------------- --------------------------- --------------------

Note: 1. Supporting workpapers are to be attached.

2\. footnotes referenced on Schedule 3 will be relied upon in
determining ASC.

Schedule 38 Exhibit C Appendix 1

BONNEVILLE POWER ADMINISTRATION

RESIDENTIAL PURCHASE AND SALE AGREEMENT

Average System Cost Methodology

Test Period:

Average System Cost

  ------------------- ------------------------------------------------ ----------------------
  Line                [\                                               [\
  [No.]{.underline}   Items]{.underline}                               Amounts]{.underline}

                      \(1\)                                            \(2\)

                                                                       

  1                   Contract System Costs                            

  2                   Production Cost (from Schedule 3)                

  3                   Transmission Cost (From Schedule 3)              

  4                   Less Excluded Load costs [f]{.underline}/        

  5                   Total Contract System Costs                      

                                                                       

  6                   Contract System Load                             

  7                   Total Load (MWh)                                 

  8                   Less:                                            

  9                   Nonfirm Adjustment (MWh)                         

  10                  Other Adjustments (MWh)                          

  11                  Net Load (MWh)                                   

  12                  Plus:                                            

  13                  Distribution Losses (MWh) [g]{.underline}/       

  14                  Total Net Load (MWh)                             

                                                                       

  15                  Less:                                            

  16                  Excluded Load (MWh) [f]{.underline}/             

  17                  Excluded Load Dist. Losses (MWh)                 

  18                  Total Contract System Load (MWh)                 

                                                                       

  19                  Average System Cost (Mills/kWh) (Line 5 / Line   
                      18)                                              
  ------------------- ------------------------------------------------ ----------------------

**AVERAGE SYSTEM COST METHODOLOGY**

**FOOTNOTES**

[a]{.underline}/ Transmission plant and the associated cost to be used
in the calculation of the average system cost (ASC) are limited to:

\(1\) For transmission plant in service as of July 1, 1984, transmission
plant will be as defined by the Federal Energy Regulatory Commission
Uniform System of Accounts and will include radial transmission lines.

\(2\) For transmission plant commencing service after July 1, 1984,
transmission plant costs which can be exchanged are limited to
transmission that is directly required to integrate resources to the
transmission system grid. Specifically, transmission costs which can be
exchanged are limited to the lesser of the costs of transmission
facilities required to transmit power from the generating resource to
the exchanging utility's system or the sum of the costs of the
transmission facilities required to integrate the generating resource to
the BPA system and the wheeling costs necessary to wheel the power to
the exchanging utility's system. If the utility chooses to construct
facilities which are more costly than the facilities required to
interconnect to the BPA system, the total costs to be exchanged shall be
no greater than the facility costs that would have been incurred to
interconnect with the BPA system."

[b]{.underline}/ Distribution plant means all land, structures,
conversion equipment, lines, line transformers, and other facilities
employed between the primary source of supply (*i.e.*, generating
station, point of receipt in the case of purchased power) and of
delivery to customers, which are not includable in transmission system,
as defined in footnote a(1), whether or not such land' structures, and
facilities are operated as part o€ a transmission system or as part of a
distribution system. Stations that change electricity from transmission
to distribution voltage shall be classified as distribution stations.

Where poles or towers support both transmission and distribution
conductors, the poles, towers, anchors, guys' and rights-of-way shall be
classified as transmission facilities. The conductors shall be
classified as transmission or distribution facilities according to the
purpose for which they are used. Land (other than rights-of-way) and
structures used jointly for transmission and distribution purposes shall
be classified as transmission or distribution according to their major
use.

[c]{.underline}/ Contract System Costs shall reflect the costs and the
revenues arising from conservation and/or retail rate schedules
implemented to induce conservation, and for which the utility receives
billing credits. These billing credit revenues shall be functionalized
on the same basis as the cost of the related conservation measures.

[d]{.underline}/ The overall rate of return to be applied to a utility's
Exchange Period rate base as shown in Appendix 1 shall be equal to its
weighted average cost of long term debt. The utility's overall rate of
return times rate base will equal the utility's return provided that if
depreciation is not used for jurisdictional ratesetting, then return
will be equal to the lesser^\*\*^ of: (1) interest expense plus
depreciation, or (2) debt service and revenue financed capital
expenditures. In no event will the sum of Contract System Cost and
Distribution/Other costs be greater than the revenue requirement used to
set rates

[e]{.underline}/ A tax-exempt utility may include in-lieu taxes up to an
amount that is comparable, for each unit of government paid in-lieu
taxes, with taxes that would have been paid by a nontax exempt utility
to that unit of government. In no event shall the utility's regional
total in column 2 be greater than the actual amount paid or the amount
used to determine the total revenue requirement for the test period.
In-lieu taxes shall be functionalized according to a direct analysis
included with the Appendix 1 or to Distribution/Other.

[f]{.underline}/ The cost of additional resources sufficient to serve
any New Large Single Load that was not contracted for, or committed to,
prior to September 1, 1979, is to be determined as follows:

\(1\) To the extent that any New Single Loads are served by dedicated
resources' at the cost of those resources' including applicable
transmission;

\(2\) In the amount that New Large Single Loads are not served by
dedicated resources, at BPA's New Resources rates as established from
time to time pursuant to section 7(f) of the Regional Act, and as
applicable to the utility, and applicable BPA transmission charges if
transmission costs are excluded in the determination of BPA's New
Resource rate, to the extent such costs are recovered by the utility's
retail rates in the applicable jurisdiction; and

\(3\) To the extent that New Large Single Loads are not served by
dedicated resources plus the utility's purchases at the New Resource
rate, the costs of such excess load shall be determined by multiplying
the kilowatthours not served under subsections (1) and (2) above,by the
cost (annual fixed plus variable cost, including an appropriate portion
of general plant, administrative and general expense and other items not
directly assignable) per kilowatthour of all baseload resources and long
term power purchases (five years or more in duration), as allowed in the
regulatory jurisdiction to establish retail rates during the Exchange
Period, exclusive of the following resources and purchases: (a)
purchases at the New Resources rate pursuant to section 7(f) of the Act;
(b) purchases at the Federal Base System rate, pursuant to section 5 (c)
of the Act; (c) resources sold to BPA, pursuant to section 6(c)(1) of
the Act; (d) dedicated resources specified in footnote k(1) of this
methodology; (e) resources and purchases committed to the utility's load
as of September 1, 1979, under a power requirements contract or that
would have been so committed had the utility entered into such a
contract; and (f) experimental or demonstration units or purchases
therefrom. Transmission needed to carry power from such generation
resources or power purchases shall be priced at the average cost of
transmission during the Exchange Period.

\(4\) Any kilowatthours of New Large Single Loads not met under
subsection (1), (2), or (3) above will be assumed to be supplied from
the most recently completed or acquired baseload resource(s) or long
term power purchase(s), exclusive of dedicated resources and
experimental or demonstration resources or purchases therefrom, that are
committed to the utility's load as of September 1, 1979, under a power
requirements contract. The cost of these generation resources and
long-term power purchases and the transmission cost associated with
these resources or purchases will be calculated as specified in
subsection (3) above.

\(5\) If the New Large Single Load is served on any energy or capacity
interruptive basis, the utility shall prepare a calculation subject to
review by BPA of the fixed (if any) and variable costs of providing such
service, except that the amount excluded from ASC for the New Large
Single Load shall not be less that the transmission and generation cost
included in the retail rate charged the New Large Single Load.

[g]{.underline}/ The losses shall be the distribution energy losses
occurring between the transmission portion of the utility's system and
the meters measuring firm energy load. Losses shall be established
according to a study (engineering, statistical and other) that is
submitted to BPA by the exchanging utility :subject to review by BPA.
This study shall be in sufficient detail so as to accurately identify
average distribution losses associated with the utility's total load,
excluded loads, and the residential load. Distribution losses shall
include losses associated with distribution substations, primary
distribution facilities, distribution transformers, secondary
distribution facilities and service drops.

[h]{.underline}/ Cash Working Capital greater than 1/8th Operations and
Maintenance expenses less fuel and purchased power expenses is
functionalized to Distribution/Other. The remainder of Cash Working
Capital shall be functionalized on the basis of Operations and
Maintenance expenses less fuel and purchased power.

[i]{.underline}/ Conservation costs are costs of measures or resources
for which power is (or is planned to be) saved by means of physical
improvements, alterations, devices, or other installations which are
measurable in units. A contract charge paid pursuant to BPA's long term
conservation contract will be an allowable conservation cost in Average
System Cost. Only conservation costs funded by the utility will be
functionalized to Production in the Utility's Average System Cost.
Conservation costs incurred to promote changes in consumer behavior
including costs attributable to audits, brochures, advertising,
pamphlets, leaflets, and similar items, or required by a government
entity through building code provisions or programmatic conservation
costs in lieu of building code provisions' will be functionalized to
Distribution/Other. Conservation surcharges imposed pursuant to section
4(f)(2) of the Northwest Power Act' or other similar surcharges or
penalties imposed on a Utility for failure to meet required conservation
efforts will also be functionalized to Distribution/Other. Conservation
and associated costs must be generally consistent with the Regional
Council's resource plan as determined by the Administrator.

[j]{.underline}/ FUNCTIONALIZATION:

Except for those accounts that are required to be functionalized under
subsection III(C) below, functionalization of each account included in
the Utility's ASC shall be by either, but not both, of the following two
methods:

\(1\) direct analysis, or (2) according to the specific
functionalization ratios applied to the various Uniform System of
Accounts. These two methods are described below in subsections III(A)
and III(B), respectively.

**I. RULES:**

\(A\) If a Utility has previously functionalized an account by direct
analysis as set forth in subsection III(A) below, the utility is not
allowed to use the specific functionalization ratio method without prior
approval from BPA.

\(B\) The Utility must submit with its ASC filing any and all
workpapers, documents, or other materials that demonstrate that the
functionalization under its direct analysis assigns costs based upon the
actual and/or intended functional use of those items. Failure to submit
such documentation will result in the entire account being
functionalized to Distribution/Other.

\(C\) For Accounts 389, 390, 391 and 392 and Accounts 920, 921, 922,
930.2 and 932, the utility may functionalize these accounts using one,
but not any combination, of the following functionalization methods,
whichever assigns the highest cost to the Production and Transmission
function:

1\. Subsection III(A) described below;

2\. Subsection III(B) described below; or

3\. For publicly-owned and cooperative utilities that have neither
generation facilities nor affiliated generation organizations over which
the utility exercises over half of the voting rights, 10 percent of
gross plant investment may be assigned directly to Production and 10
percent of labor costs assigned to Production. The remainder of Accounts
389, 390, 391, and 392 will be functionalized using Transmission and
Distribution Gross Plant Ratios excluding General Plant.

The remainder of Accounts 920, 921, 922, 930.2 and 932 will be
functionalized using the Labor Ratio for Transmission and Distribution,
and the balance assigned to Distribution/Other.

**II. DEFINITIONS:**

For purposes of subsections III(A) and III(B) [Labor Ratios]{.underline}
is defined as the ratios which assign costs on a pro rata basis using
salary and wage data for production, transmission, and
distribution/other functions included in the Test Period costs on which
Appendix 1 is based. If however, this information is unavailable,
comparable data shall be used for the most recent calendar year as
reported on the Federal Energy Regulatory Commission Form 1 (at page
355), or similar document for those utilities not required to file
Federal Energy Regulatory Commission Form 1.

**III. FUNCTIONALIZATION METHODS:**

\(A\) Be direct analysis which assigns costs to either the production,
transmission, or distribution function of the utility. Such analysis is
subject to BPA review and approval.

\(B\) According to the following specific functionalization methods:

**ACCOUNT FUNCTIONALIZATION METHOD**

l\. RATE BASE ACCOUNTS:

  ------------------- ---------------------------------------------------
  310-373\            Functionalize directly according to the Federal
  (Plant in Service)  Energy Regulatory Commission System of Accounts.

  389\                Functionalize on the ratios of Production,
  (Land and Land      Transmission and Distribution Gross Plant excluding
  Rights)             General Plant.

  390\                Functionalize on the ratios of Production,
  (Structures and     Transmission and Distribution Gross Plant excluding
  Improvements)       General Plant.

  391\                Labor ratios.
  (Office Furniture   
  and Equipment)      

  392\                Functionalize on the ratio of Transmission and
  (Transportation     Distribution Gross Plant excluding General Plant.
  Equipment)          

  393\                Functionalize on the ratio of Production,
  (Stores Equipment)  Transmission and Distribution Gross Plant excluding
                      General Plant.

  394\                Functionalize on the ratio of Production,
  (Tools, Shop and    Transmission and Distribution Gross Plant excluding
  Garage Equipment)   General Plant.

  395\                Functionalize on the ratio of Production,
  (Laboratory         Transmission and Distribution Gross Plant excluding
  Equipment)          General Plant.

  396\                Functionalize on the ratio of Transmission and
  (Power Operated     Distribution Gross Plant excluding General Plant.
  Equipment)          

  397\                Functionalize on the ratio of Production,
  (Communication      Transmission and Distribution Gross Plant excluding
  Equipment)          General Plant.

  398\                Functionalize^\*\*^ to Distribution/Other.
  (Miscellaneous      
  Equipment)          

  399\                Functionalize on the ratio of Production,
  (Other Tangible     Transmission and Distribution Gross Plant excluding
  Property)           General Plant.

  301-303\            Functionalize on the ratio of Production,
  (Intangible Plant)  Transmission and Distribution Gross Plant excluding
                      General Plant.

  114\                Labor Ratios.
  (Acquisition        
  Adjustment)         

  105\                Functionalize on the ratio of Production,
  (Plant Held for     Transmission and Distribution Gross Plant including
  Future Use)         General Plant.

  120.2-120.4 less    Functionalize to Production.
  120.5 (Nuclear      
  Fuel)               

  186\                Labor Ratios.
  (Miscellaneous      
  Debits)             

  252\                Functionalize to Distribution/Other
  (Customer Advances) 

  253\                Functionalize to Distribution/Other
  (Other Deferred     
  Credits)            

  255\                Functionalize to Distribution/Other
  (Accumulated        
  Deferred Investment 
  Tax Credits)        

  257\                Functionalize on the ratio of Production,
  (Unamortized Gain   Transmission and Distribution Gross Plant including
  Reacquired Debt)    on General Plant.

  281-283\            Functionalize to Distribution/Other
  (Accumulated        
  Deferred Income     
  Taxes)              

  151-152\            Functionalize to Production.
  (Fuel Stock)        

  153-157, 163\       Functionalize on the ratio of Transmission and
  (Materials and      Distribution Gross Plant including General Plant.
  Supplies)           

  106\                Functionalize on the ratio of Production,
  (Completed          Transmission and Distribution Gross Plant excluding
  Construction not    General Plant.
  Classified)         

  124\                Functionalize to Distribution/Other.
  (Other Investment)  

  184\                Labor Ratios
  (Clearing Accounts) 

  Other Rate Base     Functionalize to Distribution/Other.
  Accounts            
  ------------------- ---------------------------------------------------

2\. EXPENSE ACCOUNTS:

  ----------------------- ---------------------------------------------------
  501-577\                Functionalize to Production.
  (Fuel, Purchased Power  
  and Power Production    
  Expenses)               

  560-573\                Functionalize to Transmission.
  (Transmission Expenses) 

  580-598\                Functionalize to Distribution/Other.
  (Distribution Expenses) 

  901-905\                Functionalize to Distribution/Other.
  (Customer Accounts      
  Expenses)               

  907\                    Functionalize to Distribution/Other.
  (Customer Service       
  Information             
  Expenses-Supervision)   

  908-910\                Functionalize to Distribution/Other.
  (Other Customer Service 
  Information Expenses)   

  911-916\                Functionalize to Distribution/Other.
  (Sales Expenses)        

  920\                    Labor Ratios.
  (Administrative &       
  General Salaries)       

  921\                    Labor Ratios.
  (Office Supplies &      
  Expenses)               

  922\                    Labor Ratios.
  (Administrative         
  Expenses                
  Transferred-Cr.)        

  923\                    Labor Ratios.
  (Outside Services       
  Employed)               

  924\                    Functionalize on the ratio of Production,
  (Property Insurance)    Transmission, and Distribution Gross Plant
                          including General Plant.

  925\                    Labor Ratios.
  (Injuries & Damages)    

  926\                    Labor Ratios.
  (Employee Pensions &    
  Benefits)               

  927\                    Functionalize to Distribution%Other.
  (Franchise              
  Requirements)           

  928\                    Functionalize to Distribution/Other
  (Regulatory Comm. Fees  
  & Expenses)             

  929\                    Labor Ratios.
  (Duplicate Charges-Cr.) 

  930.1\                  Functionalize to Distribution/Other.
  (General Advertising)   

  930.2\                  Functionalize to Distribution/Other.
  (Miscellaneous General  
  Expenses)               

  931\                    Functionalize to Distribution/Other.
  (Rents)                 
  ----------------------- ---------------------------------------------------

3\. REVENUE ACCOUNTS:

  ------------------- ---------------------------------------------------
  447\                Functionalize to Production.
  (Sales For Resale)  

  450-455\            Functionalize to Production.
  (Other Operating    
  Revenues)           

  456\                Functionalize to Transmission.
  (Wheeling Revenues) 
  ------------------- ---------------------------------------------------

\(C\) THE FOLLOWING ACCOUNTS SHALL BE FUNCTIONALIZED AS FOLLOWS:

  ------------------- ---------------------------------------------------
  107, 120.1\         Functionalize to Distribution/Other.
  (CWIP)              

  108\                The same functionalization used for accounts
  (PIS Depreciation   310-373, Plant in Service (PIS).
  Reserve)            

  108\                Functionalize according to the General Plant ratio.
  (General Plant      
  Depreciation        
  Reserve)            

  111\                The same functionalization used for accounts
  (Accumulated        301-303, Intangible Plant.
  Amortization)       

  256\                The same functionalization used for account 105,
  (Deferred Gain from Electric Plant Held for Future Use.
  Disposition of      
  Utility Plant)      

  403-407\            The same functionalization used for Accounts
  (PIS Depreciation   310-373, Plant in Service.
  Expense)            

  408.1\              With the exception of property taxes and labor
  (Other Taxes)       related taxes, all taxes will be functionalized to
                      Distribution/Other. Property taxes will be
                      functionalized using the gross plant ratio
                      including general plant. Labor related taxes will
                      be functionalized using labor ratios.

  409.1, 410.1,       Functionalize to Distribution/Other.
  411.1, 411.4\       
  (Income Taxes)      

  932\                Functionalize according to the ratio developed from
  (Maintenance of     the functionalized totals of accounts 390, 391, 397
  General Plant)      and 398.

  411.6, 411.7\       The same functionalization used for Account 105,
  (Gain from          Plant Held for Future Use.
  Disposition of      
  Utility Plant)      
  ------------------- ---------------------------------------------------

[^1]: The exchange was set equal to 50 percent of a participating
    utility's qualifying residential and small farm load as of July 1,
    1980, and has been increasing in equal increments toward 100 percent
    of such load. *See*, section 5(c)(2).

[^2]: Section 5(c)(5) allows BPA to acquire an "equivalent amount of
    electric power from other sources to replace power sold to \[a
    participating\] utility," if the cost of such replacement
    acquisition is less than the applicable ASC. Once again, however,
    the key phrase is "equivalent amount." In any event, such
    alternative purchases, other than BPA resources, have been construed
    to require seven years advance notice. *See*, section 4(a),
    Residential Purchase and Sale Agreement, Contract No. DE-MS79-83BP9.
    BPA designates this contract as part of the record of this
    consultation proceeding. (R. 6800).

[^3]: The outcome of this consultation proceeding will not change the
    way in which BPA establishes rates under section 7 of the Northwest
    Power Act. The resource concept'was devised by Congress to allocate
    the benefits and costs of the Federal Base System among competing
    classes of BPA customers. BPA has faithfully implemented Congress'
    ratemaking directives. However, the resource concept should not
    obfuscate the nature of the residential exchange as a subsidy from
    BPA to the participating utilities.

[^4]: However, Congress has recognized that this wholesale rate parity
    could last only until July 1, 1985, due to the rate protection
    accorded BPA's preference customers as of that date. *See* section
    7(b)(2) and 7(b)(3), 16 U.S.C. §839e(b)(2) and (b)(3).

[^5]: However, BPA does keep an account of such unpaid amounts, which
    are offset against subsequent BPA payments to the utility. *See*
    section 10, Residential Purchase and Sale Agreement, BPA Contract
    No. DE-MS79-81BP9.

[^6]: Furthermore, section 5(c)(4), 16 U.S.C. §839c(c)(4), recognizes
    that BPA's priority firm rate, insofar as it applies to the
    residential exchange, may carry one or more "supplemental rate
    charges" after July 1, 1985, due to implementation of section
    7(b)(3) of the Northwest Power Act, 16 U.S.C. §839e(b)(3). Were this
    to occur and cause the applicable priority firm rate to exceed a
    participating utility's ASC, that utility 'could terminate its
    participation in the residential exchange. *See* section 9 of the
    Residential Purchase and Sale Agreement, *id.*

[^7]: BPA does not take issue with the way in which any rate regulator
    follows the dictates of its governing statute or ordinance. We are
    not necessarily suggesting that retail residential rates have been
    set above the zone of reasonableness before application of the BPA
    exchange subsidy. BPA's problems with the jurisdictional costing
    approach focus on the dissimilarities between the Northwest Power
    Act and state regulatory laws and policies.

[^8]: *Public Utility Commissioner of Oregon v. BPA* (D. Or., Civil No.
    84-270-PA), dismissed March 21, 1984, appeal pending, 9th Cir. No.
    84-3722; *Public Utility Commissioner of Oregon v. BPA* (9th Cir.
    No. 84-7185); *Pacific Power & Light Company v. BPA* (D. Or., Civil
    No. 84-261-PA).

[^9]: *E.g.*, the definitions of "Federal base system resources" in
    §3(10), "major resource" in §3(12) and "renewable resource" in
    §3(16), 16 U.S.C. §§839x(10), (12) and (16), respectively; and §6
    (conservation and resource acquisition), 16 U.S.C. §839d. Resources
    characteristically "serve \[a BPA customer's\] firm load," 16 U.S.C.
    §839c(b)(1)(A) and (B), or "meet, on a planning basis, the load
    requirement . . .," 16 U.S.C. §B39c(c)(4)(C)(i).

[^10]: Under the February 3 proposal, no change would have been made in
    the way that capital costs were determined for publicly-owned and
    cooperative utilities.

[^11]: The Comptroller General, in ruling on a bid protest in which a
    private utility was underbid by a rural cooperative for a government
    contract to provide electric service, held that the government was
    not required to take into account income taxes the private utility
    would have paid if it had been awarded the contract. 43 Comp. Gen.
    60, 62 (1963). He noted that "no provision is made in any statute or
    regulation for eliminating the competitive advantages that
    cooperatives \...are given by statute, nor are there any provisions
    for eliminating a tax advantage one offeror may have over another."
    *Id.* at 63. Although this decision relates to a contract award, the
    principle of the decision applies here. The purpose of the exchange
    under the Northwest Power Act is not to alter the tax advantages of
    publicly owned utilities, or to confer such benefits on private
    utilities.

[^12]: Courts have traditionally held that discrimination results when
    all of a utility's customers assume the burden of special taxes
    exacted by a particular taxing entity within the utility's service
    area. *See*, Priest, supra, at 54, 307-308; *Village of Maywood v.
    Illinois Commerce Comm'n*, 23 Ill, 2d 447, 452, 178 N.E. 2d 345,
    348, 42 Pub. Util. Rep., 298, 301 (1961). FERC ordered a power
    company to eliminate from its cost of service a tax "add-back" not
    properly attributable to its wholesale customers. *Re New England
    Power Co.*, 2 FERC 161,106, 61,258 (1978).

[^13]: Pacific Power & Light's analysis is flawed for several reasons.
    First, it assumes that the utilities serve only residential and
    small farm loads. It is this assumption which forces the utility to
    repay its entire billing credit. Actually, the utility only returns
    the percent of the credit that makes up its residential and small
    farm load. Second, it assumes that all utilities receive the same
    per-unit billing credits. Those utilities receiving lower per-unit
    billing credits pay part of the billing credits of the other
    utilities. Therefore, the.exchanging utility will never return its
    entire billing credit to BPA.

[^14]: To ameliorate the concerns raised by the PNGC, BPA will continue
    allowing certain plant account costs (389, 390, 391 and 392) and
    administrative and general expense account costs (920 and 921, 922,
    930.2 and 932) to be functionalized by the following three options,
    whichever assigns the highest cost to the production and
    transmission functions: (1) direct analysis, (2) the specific
    functionalization ratios discussed next, or (3) for publicly-owned
    and cooperative utilities that have neither generation facilities
    nor affiliated generation organizations over which the utility
    exercises over half of the voting rights, 10 percent of gross plant
    investment may be assigned directly to Production and 10 percent of
    labor costs assigned to Production. The remainder of accounts 389,
    390, 391, and 392 will be functionalized using Transmission and
    Distribution Gross Plant Ratios excluding General Plant-The
    remainder of Accounts 920, 921, 922, 930.2 and 932 will be
    functionalized using the Labor Ratio for Transmission and
    Distribution, and the balance assigned to Distribution/Other.