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SECTION 7(b)(2)

IMPLEMENTATION METHODOLOGY

ADMINISTRATOR'S

RECORD OF

DECISION

BONNEVILLE POWER ADMINISTRATION

U.S. DEPARTMENT OF ENERGY

b-2-84-F-02

August 1984

**SECTION 7(b)(2)**

**ADMINISTRATOR'S RECORD OF DECISION**

**[TABLE OF CONTENTS]{.underline}**

\[page numbers refer to original document\]

[Section]{.underline} [Page]{.underline}

I. Introduction 1

A. Procedural Posture 1

B. Legal Requirements 3

1\. Northwest Power Act 3

2\. BPA's Legal Interpretation 4

II\. Reserve Benefits 7

III\. Financing Benefits 12

IV\. Natural Consequences 19

V. Selection of: Computer Model to Perform the Rate Test 30

VI\. Rate Test Trigger 32

Appendix A: Party Abbreviations 34

Appendix B: List of Parties' Witnesses and Representatives Appearing in
the\
Section 7(b)(2) Implementation Methodology Hearing 35

Appendix C: Section 7(b)(2) Implementation Methodology 37

**I. INTRODUCTION**

**A. Procedural Posture**

On February 29, 1984, BPA issued its "Section 7(b)(2) Proposed Rate Test
Methodology." A notice of the "Proposed Section 7(b)(2) Implementation
Methodology, Public Hearings, and Opportunities for Public Review and
Comment" was published in 49 Fed. Reg. 11235 (March 25, 1984). That
notice initiated a formal hearings process under section 7(i) of the
Northwest Power Act (16 U.S.C. 839e(i)).

An evidentiary hearing on the proposed methodology was conducted by
Judge Seymour Wenner, Hearing Officer. Party status was granted to a
total of 45 entities including publicly owned and investor owned utility
customers, direct service industrial customers (DSIs), and Federal[^1]
and state agencies. Judge Wenner commenced the proceeding with a
prehearing conference at which rules of practice and procedural
schedules were discussed. He issued special rules of practice on April
10, 1984, which were revised on April 25, 1984.

BPA's proposed methodology was sponsored formally in the written
testimony and exhibits of two witnesses.[^2] BPA responded to more than
190 data requests concerning all aspects of its proposal. Three days of
clarifying sessions (transcribed oral discovery) were conducted between
April 13 and April 20, 1984.

On April 30, 1984, BPA filed a technical brief and the parties filed
extensive testimony and exhibits. This was followed by two more
clarifying sessions on May 9 and May 14 and by further written
discovery. On May 9 the parties filed prehearing briefs; on May 18, BPA
filed a prehearing statement of issues.

BPA and the parties simultaneously filed rebuttal testimony on May 17,
1984; additional written discovery ensued. All parties so desiring
simultaneously filed surrebuttal testimony on May 25, 1984.

Cross examination occurred on May 31 and June 1, 1984. During the
hearing Judge Wenner granted all motions to strike written testimony
that was based on legal conclusions or that which went beyond the scope
of the proceeding.

On June 15, 1984, the parties filed their post-hearing briefs.
Consideration of the briefs and the remainder of the official^\*\*^
record of the proceeding resulted in a Tentative Decision released on
June 28, 1984. The Administrator has concluded that in order to give BPA
customers a measure of certainty as to the section 7(b)(2) methodology,
a Record of Decision should be entered. This methodology will not be
changed during the course of the 1985 wholesale power proceeding unless
an error or anomaly requiring correction is discovered.[^3]

Therefore, on July 1, 1984, Judge Wenner issued a supplementary order
providing for the filing of reply briefs by the parties. These briefs
were submitted on July 17, 1984; the DSIs were granted an extension of
time in which to file, and their brief was submitted on August 1, 1984.

This Record of Decision is divided into five sections, which correlate
with the broad subject areas being considered: reserve benefits,
financing benefits, natural consequences, selection of a computer model,
and rate test trigger. Within the individual sections, the issues and
evidence are addressed as follows: (1) a summary of each BPA proposal
and the position each party has taken on the record concerning the
issue; (2) an evaluation of those positions; and (3) the Administrator's
decision on the issue. Three informational appendices are included:
Appendix A lists the parties to the section 7(b)(2) proceeding and the
preferred abbreviations of their names; Appendix B lists the witnesses
and representatives of the parties to the section 7(b)(2) proceeding;
Appendix C summarizes the methodology to be used to implement the
directives of section 7(b)(2).

One other matter must be examined to complete the discussion of the
procedures utilized in this case.

On January 23, 1984, BPA published a notice of its proposed legal
interpretation of section 7(b)(2) (49 Fed. Reg. 2811). Comments and
reply comments were received from interested parties. Subsequently, on
May 31, 1984, BPA released its legal interpretation (published on June
8, 1984, in 49 Fed. Reg. 23998). The interpretation resolves the basic
legal issues required to implement section 7(b)(2). *See* Section
I.B.2., *infra*, for a more detailed discussion of this interpretation.
It interprets the statute by incorporating principles of statutory
construction, reviewing legislative history and considering the comments
made by interested parties. BPA's proposed methodology, which is the
subject of this proceeding, incorporates the legal interpretation[^4]
into its policy and computer program proposals.

**B. Legal Requirements**

**1. Northwest Power Act**

Section 7(b)(2) of the Northwest Power Act (16 U.S.C. 839e(b)(2))
requires that after July 1, 1985, the rates charged by BPA for firm
power sold to public body, cooperative and federal agency customers
("7(b)(2) customers") may not exceed, in total, as determined by the BPA
Administrator, such customers' power costs for their general
requirements, under five specified assumptions. In other words, the
Administrator, before establishing rates to be charged the 7(b)(2)
customers for wholesale firm power sold them after July 1, 1985, must
compare two numbers: the average amount BPA would charge them over a
five year period pursuant to the general ratemaking guidelines found
elsewhere in the Northwest Power Act ("the Program case amount")[^5] and
the average cost of power to them over the same five year period
pursuant to those guidelines and, in addition, pursuant to the five
assumptions listed in section 7(b)(2) ("the 7(b)(2) case amount"). If,
upon comparison of the two numbers, the 7(b)(2) case amount is smaller
than the net program case amount, then the 7(b)(2) customers will be
charged the sum representing the total program case amount less the
difference between the net program case amount and the 7(b)(2) case
amount.[^6] The purpose of section 7(b)(2), then, is to afford BPA's
preference customers rate protection in the event that other provisions
of the Northwest Power Act (in particular, the power exchange program
with the investor owned utilities) would otherwise increase the price of
power sold them.

**2. BPA's Legal Interpretation**

The legal interpretation published by BPA resolves those basic legal
issues involved in the implementation of section 7(b)(2). It was
developed through a notice-and-comment procedure that was conducted
separately from this hearing. The tentative legal interpretation
(published on January 23, 1984, in 49 Fed. Reg. 2811) solicited public
comment during the period January 23 through February 29, 1984. Much of
the comment and participation which accompanied the development of the
June 8 interpretation were provided by the parties to this hearing.
Several of the parties remain opposed to the interpretation and
presented arguments against portions of it in their briefs.[^7] Matters
resolved therein will not be considered in this Record of Decision.
*See* *Central Lincoln II*, slip op. at 34-37, which supports the
proposition that BPA need not re-submit its legal interpretation for
another round of public comment.

Three of the parties continue to express concern that certain section
7(g) costs are counted twice in the rate test. *See* APAC Brief, Ex.
B-PA-01, 27-29; PGP Brief, Ex. B-PG-01, 9-18; PPC Brief, Ex. B-PP-01,
30-31; APAC Reply Brief, Ex. R-PA-01, 10; PGP Reply Brief, Ex. R-PG-01,
2-5; and PPC Reply Brief, Ex. R-PP-01, 16. Due to the emphasis placed on
this issue, a more detailed exposition is given below.

> The relevant portion of section 7(b)(2) provides as follows:
> "...\[T\]he projected amounts to be charged for firm power ... (to
> 7(b)(2)\] customers, exclusive of amounts charged such customers under
> \[section 7(g)\] for the costs of conservation, resource and
> conservation credits, experimental resources and uncontrollable
> events, may not exceed in total-an amount equal to the power costs
> if..." \[certain assumptions are made\]. 16 U.S.C. § 839e(b)(2).

"The projected amounts to be charged" means the program case. "Exclusive
of amounts charged ... under section 7(g)" means that the enumerated
section 7(g) costs are to be subtracted from the program case. There is
no parallel command in the statute to subtract from the 7(b)(2) case the
costs corresponding to those allocated under section 7(g) in the program
case. The result, in a numerical display, would be as follows:

> 20 mills ("the projected amount to be charged"; also called the
> program case amount)
>
> \- [3 mills]{.underline} (certain 7(g) charges)
>
> 17 mills (the amount to be compared with the 7(b)(2) case amount; also
> called the net program case amount)

This amount, 17 mills, is to be compared to the 7(b)(2) case amount. For
illustrative purposes, assume that the 7(b)(2) case amount is 15 mills,
which may include costs that correspond to those allocated under section
7(g) in the program case. The program case amount is therefore 2 mills
greater than the 7(b)(2) case amount (17 mills - 15 mills = 2 mills).
The test has thus triggered. Next, since the amounts to be charged to
the 7(b)(2) customers, less the enumerated 7(g) costs, may not exceed
the 7(b)(2) case amount, it follows that the 7(b)(2) customers may be
charged up to the 7(b)(2) case amount plus the enumerated 7(g) costs.
Otherwise, there would be no reason for the section 7(g) costs being
mentioned in the statute. Hence, the statute allows and provides for the
double counting of certain section 7(g) costs.

Double counting of all or some of the section 7(g) costs (conservation;
resource and conservation credits ("billing credits"); experimental
resources; and uncontrollable events) may be theoretically possible, as
explained above. However, it does not occur in all instances. The costs
of both experimental resources and uncontrollable events are included in
total in both the program case amount (20 mills, in the example given
above) and in the 15 mill 7(b)(2) case amount. But the costs of billing
credits and conservation, although appearing in the 20 mill figure, are
not necessarily included in the 15 mills. This is because billing
credits and programmatic conservation are added to the resources used to
serve the 7(b)(2) customers only to the extent that they are needed
after the FBS is exhausted and only in the event that they are the
least-cost resources to be added. If the FBS is sufficient to serve the
7(b)(2) load, or other available additional resources have lower costs,
then billing credits and programmatic conservation will not be added to
the 7(b)(2) case.

BPA's legal interpretation of June 8, 1984, 49 Fed. Reg. 23998, deals
with eight issues relevant to implementation of section 7(b)(2). Only
those issues that can be resolved on the basis of statutory language or
legislative history are treated in the legal interpretation. Briefly,
the eight issues are as follows:

> \- The five-year rate test period will consist of the test year for
> the relevant rate case plus the ensuing four years.
>
> \- Only the assumptions specified in section 7(b)(2) and any
> unavoidable consequences or secondary effects of those assumptions
> will be considered to determine 7(b)(2) customers' power costs in the
> 7(b)(2) case.
>
> \- The costs of conservation, resource and conservation credits,
> experimental resources, and uncontrollable events ("7(g) costs") will
> be included in the program case when the projections of loads and
> rates are made. The final program case power costs will then be
> reduced by the applicable 7(g) costs for comparison with the 7(b)(2)
> case power costs.
>
> \- The DSI loads which are located within or adjacent to the service
> areas of 7(b)(2) customers will be assumed, in the 7(b)(2) case, to be
> served by those customers beginning July 1, 1985, unexpired DSI
> contracts with BPA notwithstanding.
>
> \- The entire amount of DSI load included in the general requirements
> of the 7(b)(2) customers will be assumed to be served as firm load in
> the 7(b)(2) case.
>
> \- Information contained in Appendix B to the Senate Report, S. Rep.
> No. 272, 96th Congress, First Session (1979), will be used to identify
> DSI loads within or adjacent to geographic service boundaries of
> public bodies and cooperatives. This information will be adjusted as
> necessary to reflect changes in the status of BPA service to the DSI
> customers as assumed in the relevant rate case.
>
> \- To determine Federal base system (FBS) resources not obligated to
> "other" entities under existing contracts in the 7(b)(2) case, the DSI
> load which is not within or adjacent to the service areas of
> preference customers will be assumed to be served by investor owned
> utilities only as the DSI power sales contracts with BPA expire.
>
> \- Three types of resources will be assumed to be available to serve
> 7(b)(2) customers' loads when the FBS resources are exhausted in the
> 7(b)(2) case: (1) the resources actually acquired by BPA from the 7(b)
> (2) customers in the relevant rate case; (2) the resources owned or
> purchased by the 7(b)(2) customers that are not dedicated to their own
> regional loads; and (3) generic resources of whatever size is required
> to serve the preference customers' remaining load, at the average cost
> of all new resources acquired by BPA from non-7(b)(2) customers during
> the relevant five-year period. The resources will be "stacked" in
> order of cost and assumed to be used as needed to meet loads, least
> cost first.

**II**

**RESERVE BENEFITS**

Section 7(b)(2)(E) presents one of the assumptions that BPA is to make
when calculating the power costs of the 7(b)(2) customers in the 7(b)(2)
case: "the quantifiable monetary savings, during such 5-year period, to
public body, cooperative and Federal agency customers resulting from ...
reserve benefits as a result of the Administrator's actions under this
Act were not achieved." That is, the 7(b)(2) customers' power costs will
be higher by some amount in the 7(b)(2) case because they must replace
the system reserves that are provided in the program case by BPA's
restriction rights on the DSI loads. The reserve benefits issue concerns
how to quantify that amount.

**Issue #1**

How should reserve benefits be quantified?

**Summary of Positions**

BPA proposed to quantify reserve benefits in the 7(b)(2) case by using
the same analysis as is used in the relevant rate case to determine the
value of the reserves provided by BPA's restriction rights on DSI loads.
The full value attributed to those rights by that analysis, rather than
the credit allowed the DSIs for those rights, would be the basis for
quantifying the loss of reserve benefits in the 7(b)(2) case relative to
the program case. Melton and Armstrong, BPA, Ex. E-BPA-01, 16; Melton
and Armstrong, BPA, Ex. E-BPA-03R, 11.

PPC proposed that instead of the full value of the rights, the credit
allowed the DSIs in the relevant rate case (which credit is a portion of
the calculated full value) should be used to quantify reserve benefits
in the 7(b)(2) case. Wolverton, PPC, Ex. E-PP-01, 19-20; Lucas, O'Meara
and Wolverton, PPC, Ex. E-PP-04R, 24; Reply Brief, PPC, Ex. R-PP-01, 16.

APAC and PGP joined PPC in urging that the reserves credit, rather than
the full value of the rights, be used. APAC Brief, Ex. B-PA-01, 35; PGP
Brief, Ex. B-PG-01, 22; PGP Reply Brief, Ex. R-PG-01, 5-7.

The DSIs agreed in principle with BPA's proposal. They were concerned
that the computer model proposed for use in the rate test did not
reflect BPA's actual valuation method and thus did not take into account
the full value BPA attributes to the rights. They also proposed that a
financing benefits analysis be performed in the determination of reserve
benefits in the 7(b)(2) case. Peseau, DSI, Ex. E-DS-01, 9-10 and 18; DSI
Brief, Ex. B-DS-01, 4-5; DSI Reply Brief, Ex. R-DS-01, 2-3. APAC and PGP
opposed this last suggestion. APAC Brief, Ex. B-PA-01, 36; PGP Brief,
Ex. B-PG-01, 18-24; PGP Reply Brief, Ex. R-PG-01, 7-8.

**Evaluation of Positions**

PPC argued that the credit more nearly reflects the reserve benefit than
does the value attributed to the restriction rights by the rate case
analysis, and that the credit has remained more stable over time than
has the value. Wolverton, PPC, Ex. E-PP-01, 19; PPC Reply Brief, Ex.
R-PP-01, 16. PPC and APAC claimed that the full value affects only the
rate test and not the actual rates themselves. Lucas, O'Meara and
Wolverton, PPC, Ex. E-PP-04R, 23; APAC Brief, Ex. B-PA-01, 35. The
example posited by PPC is that the full value of the restriction rights
could be increased from case to case, while the credit would remain the
same. In fact, the values assigned by past rate cases were \$521 million
(1981 rate case); \$95 million (1982 rate case); and \$88 million (1983
rate case). The respective credits were \$76 million; \$48 million; and
\$45 million. PPC argued that by using the value rather than the credit,
the 7(b)(2) customers' costs would increase, thus decreasing the chance
that the rate test would trigger. Lucas, O'Meara and Wolverton, PPC, Ex.
E-PP-04R, 23. Nevertheless, as BPA and the DSIs pointed out, the
calculation of the credit given the DSIs is based on a share-the-savings
methodology. Thus the credit does not represent the cost of the reserves
that the 7(b)(2) customers would need to acquire in the 7(b)(2) case.
Melton and Armstrong, BPA, Ex. E-BPA-03R, 12; Peseau, DSI, Ex. E-DS-02R,
8-9. PPC's characterization of the value of reserves calculation as
"hypothetical" (Lucas, Wolverton and O'Meara, PPC, Ex. E-PP-04R, 24)
appears to refer to the fact that the dollar amount itself is not used
to calculate any actual rates. But that value is objectively determined
and is open to review by all parties in the relevant rate case. Peseau,
DSI, Ex. E-DS-02R, 8; Melton and Armstrong, BPA, Ex. E-BPA-03R, 12.
Moreover, PPC's assertion that the credit has remained more "stable"
than the value over time is not accurate. BPA used different methods to
determine the value between 1981 and 1983: in the 1981 rate case, the
calculation was based on a marginal costing method, while in both the
1982 and 1983 rate cases the value was calculated by using the
opportunity cost of providing equivalent reserves through such devices
as combustion turbines and load tripping devices. O'Meara, PPC, TR 1176.
It is clear that both the credit and the value of reserves remained
"stable" as between the 1982 and 1983 rate cases. Lucas, O'Meara and
Wolverton, PPC, E-PP-04R, 24.

PGP believes that BPA has misread section 7(b)(2)(E). PGP Reply Brief,
Ex. R-PG-01, 5-6. PGP interprets the language, "the monetary savings ...
from ... reserve benefits ... [under this Act]{.underline} were not
achieved," to mean that only the monetary equivalent of the restriction
rights (whether the full value or the credit), and not the monetary
value of reserves provided to replace the restriction rights, is to be
considered. Under the Northwest Power Act, the Administrator has the
authority to provide reserves for the BPA system. *See* Section 5(d)(1)
and (3). BPA's restriction rights on DSI loads currently provide these
reserves. *See* BPA 1983 Wholesale Power Rate Design Study, Ex.
WP-83-FS-BPA-07 at A-9. However, in the event that these restriction
rights are inadequate to provide the required level of reserves, BPA can
acquire additional reserve resources. To examine what monetary savings
from reserve benefits under the Northwest Power Act were
[not]{.underline} achieved, the monetary savings that [were]{.underline}
achieved must be examined. This requires a point of reference. In this
case, that point of reference is what the costs would have been had BPA
not been able to take actions authorized by the Northwest Power Act.
These include the acquisition of restriction rights and additional
reserve resources. This is not in conflict with BPA's legal
interpretation because it is one of the five assumptions specifically
required by section 7(b)(2).

The DSIs' criticism of the manner in which the computer model reflects
the value of reserves analysis used in the rate case was addressed in
BPA's rebuttal testimony: the proxy calculation currently in the model
has been replaced to represent more accurately BPA's actual valuation
method. Melton and Armstrong, BPA, Ex. E-BPA-03R, 12.

The DSIs also proposed that BPA include financing benefits in the
calculation of the reserve benefits for the 7(b)(2) case; Peseau, DSI,
Ex. E-DS-01, 9-10; DSI Brief, Ex. B-DS-01, 4-5; DSI Reply Brief, Ex.
R-DS-01, 2-3. This proposal is reasonable. BPA's analysis of the full
value of the restriction rights in its rate cases represents, in part,
the amount it would cost BPA to provide 7(b)(2) customers with
alternative reserve resources, if the restriction rights were
unavailable. PGP Brief, Ex. B-PG-01, 20-21; Melton and Armstrong, BPA,
Ex. E-BPA-03R, 14. That analysis takes into account interest rates
available to BPA at the time of the assumed resource construction.
However, the reserves in the 7(b)(2) case would have to be provided by
resources owned by the regional utilities, since provision of reserves
by BPA is an action precluded in the 7(b)(2) case by section 7(b)(2)(E).
Melton and Armstrong, BPA, Ex. E-BPA-01, 14-15. However, these utilities
would not have the option of BPA financing currently accounted for in
BPA's analysis. This proposal, then, tracks in the 7(b)(2) case the same
methodology (albeit using a different interest rate) used in the
relevant rate case. Thus the proposal is not, as was argued by PGP and
APAC, contrary to the Northwest Power Act or to BPA's legal
interpretation by taking into account assumptions (or their natural
consequences) not listed in section 7(b)(2). This proposal has been
implemented by providing the necessary information on the resources used
in the analysis of the restriction rights to the financial analyst.
Armstrong, BPA, TR 787-789.

PGP argues that the financing benefits analysis required by section
7(b)(2)(E)(i) applies solely to the load/resource balance defined in
section 7(b)(2)(D). Thus no analysis of financing benefits should be
performed on the reserve benefits that must be quantified under section
7(b)(2)(E)(ii). PGP Reply Brief, Ex. R-PG-01, 6-7. The reserve benefits,
though, resulting from BPA's "actions under this Act" (section
7(b)(2)(E)(ii)) include BPA's actions related to the provision of
reserves. Therefore, section 7(b)(2)(E)(ii) requires the assumption that
the 7(b)(2) customers construct their own reserve resources using their
own sources of financing to determine the monetary savings from reserve
benefits that were not achieved.

**Decision**

BPA will quantify reserve benefits in the 7(b) (2) case by using the
same analysis as is used in the relevant rate case. The full value (not
the credit) attributed to the restriction rights by that analysis will
be the quantity of the reserve benefits in the 7(b)(2) case. A financing
benefits analysis of the reserve margins required in the 7(b)(2) case
will be reflected in the reserve benefits determination this analysis
will be performed by the outside financial analyst. *See* Section III,
Issue #2, *infra*.

**Issue #2**

What adjustments, if any, should be made to the rate case's analysis of
the value of the restriction rights for the quantification of reserve
benefits for the 7(b)(2) case?

**Summary of Positions**

BPA proposed that the analysis performed in the relevant rate case which
quantifies the value of the restriction rights be adjusted to reflect
the fact that "within or adjacent" DSI loads in the 7(b)(2) case will be
less than 100 percent of DSI loads served by BPA in the program case.
Melton and Armstrong, BPA, Ex. E-BPA-01, 16. Another proposed adjustment
accounts for the difference in reserve requirements that may occur
between the program case and the 7(b)(2) case due to different
load/resource balances in the two cases.

PGP, APAC and PPC opposed in general BPA's recognition of natural
consequences, one of which is demand elasticities, so presumably they
opposed BPA's proposed adjustment to reserve requirements due to
different load/resource balances. PGP Brief, Ex. B-PG-01, 5, 23; APAC
Brief, Ex. B-PA-01, 19-20; PPC Brief, Ex. B-PP-01, 14-19. PGP asserted
that BPA's proposed adjustment to reserve requirements was offered,
without justification, as a fourth natural consequence. PGP Reply Brief,
Ex. R-PG-01, 8-10.

The DSIs proposed that the reserve benefits calculation for the 7(b)(2)
case should include a monetary quantification of the reserves provided
by the first quartile of DSI load. Peseau, DSI, Ex. E-DS-01, 9; Ex.
E-DS-03SR, DSI Brief, Ex. B-DS-01, 3-4.

**Evaluation of Positions**

PGP, APAC and PPC's posture on BPA's recognition of natural consequences
in general is discussed in Section IV, Issue #1, *infra*. For the
reasons noted in Issue #1, at 9, *supra*, BPA's proposed adjustment to
reserve requirements is not considered a natural consequence. *See* PGP
Reply Brief, Ex. R-PG-01, 9-10.

The DSI position is that the restriction rights lost when the first
quartile of DSI load is assumed to transfer to 7(b)(2) customers as firm
load must be quantified in the 7(b)(2) case whether or not it is so
quantified in the program case or the relevant rate case. Peseau, DSI,
Ex. E-DS-01, 9; Ex. E-DS-03SR, 2; DSI Brief, Ex. B-DS-01, 4. BPA has not
explicitly quantified in its past rate cases the value of the
restriction rights provided by the first quartile of the DSI load.
Melton and Armstrong, BPA, Ex. E-BPA-03R, 13; Peseau, DSI, Ex. E-DS-01,
9. However, during cross examination, the BPA witness declared that for
the 7(b)(2) case, a determination would have to be made at the time of
the relevant rate proceeding as to whether the first quartile's
restriction rights provide reserves. If so, then the value of those
restriction rights (reserves) would be explicitly quantified even if no
such quantification is made in the program case or in the rate case.
Armstrong, BPA, TR 786-787.

No party opposed BPA's proposal that an adjustment be made to the rate
case's quantification of reserves due to the fact that only the "within
or adjacent" DSI customers are assumed to be served by 7(b)(2) customers
in 7(b)(2) case.

**Decision**

The quantification of reserves as calculated in the relevant rate case
will be adjusted in the 7(b)(2) case for the actual amount of "within or
adjacent" DSI loads assumed to be served by 7(b)(2) customers.

An evaluation of the recognition of differing load/resource balances can
be found in Section IV, Issue #1, *infra*. Based on the decision on that
issue, and on the decision to perform a financing benefits analysis on
the reserve benefits (see Issue #1, at 9, *supra*), an adjustment will
be made for the potentially different level of reserves required for the
7(b)(2) case.

A determination will be made in the relevant rate proceeding as to
whether the restriction rights on the first quartile of the DSI load
provide reserves. If it is determined that they do, and the value of
those restriction rights has not been calculated as part of the relevant
rate case valuation of reserves analysis, then the value will be
explicitly quantified in a manner consistent with the valuation method
performed in the relevant rate case for the other three quartiles. This
analysis of the first quartile's restriction rights will be made in the
7(b)(2) case even if it is not made-in the relevant rate case.

**III**

**FINANCING BENEFITS**

Section 7(b)(2)(E) requires the following assumption about the financing
costs the 7(b)(2) customers face in the 7(b)(2) case: "the quantifiable
monetary savings, during such 5-year period, to public body, cooperative
and Federal agency customers resulting from ... reduced public body and
cooperative financing costs as applied to ... \[additional\] resources,
other than Federal base system resources, ... were not achieved."[^8] In
other words, the 7(b)(2) customers' power costs may be higher by some
amount in the 7(b)(2) case because the customers themselves would have
to finance the acquisition of additional resources needed to meet their
firm loads after BPA's FBS resources are exhausted. In the program case,
BPA acquires the additional resources needed, making possible reduced
financing costs. The financing benefits issue concerns how to quantify
the difference between BPA's financing cost and the 7(b)(2) customers'
cost.

**Issue #1**

Should all additional resources needed to serve the general requirements
of the 7(b)(2) customers be assumed to be owned by those customers?

**Summary of Positions**

BPA proposed that all additional resources required (other than FBS
resources) be assumed to be owned by the 7(b)(2) customers. As to the
type 3 resource, that is, those resources acquired from non-7(b)(2)
customers, BPA proposed that they be assumed to have been constructed by
a proxy association of all 7(b)(2) customers, each having an ownership
share in proportion to firm load. The financing benefits analysis would
then be performed using the proxy association's cost of construction.
Melton and Armstrong, BPA, Ex. E-BPA-01, 11-12.

PPC agreed that with respect to type 1 and 2 resources, the actual owner
(a 7(b)(2) customer) should be assumed to have constructed the resource
in the 7(b)(2) case and the analysis would be performed as to that
7(b)(2) customer. Wolverton, PPC, Ex. E-PP-01, 28-29.

PPC and APAC opposed BPA's proposal for an analysis on a proxy ownership
of the type 3 resource. They urged that the analysis be performed on the
entity that actually constructed the resource, whether that entity is an
investor owned utility or a DSI. Wolverton, PPC, Ex. E-PP-01, 29-31;
APAC Brief, Ex. B-PA-01, 33. Also, in the case of conservation, PPC
proposed that conservation funded by BPA in the program case should be
assumed to be performed, for purposes of the financing benefits
analyses, by the utility serving the geographical area where BPA's
conservation investment was made. Wolverton, PPC, Ex. E-PP-01, 31.

**Evaluation of Positions**

The PPC and APAC proposal to analyze financing costs for the non-7(b)(2)
customer actually constructing the type 3 resource means that the
quantification would relate to the costs of the non-7(b)(2) customer
rather than to those of the 7(b)(2) customer. Section 7(b)(2)(E)(1)
refers to financing benefits for "public body and cooperative" entities.
It is thus unclear how any amount of financing benefits quantified for a
non-7(b)(2) customer would translate to an amount affecting the 7(b)(2)
customers in the 7(b)(2) case. Melton and Armstrong, BPA, Ex. E-BPA-03R,
15-16. PPC's opposition to the concept of a proxy association was that
7(b)(2) customers (particularly the cooperatives, since they can obtain
financing through the REA) would organize construction efforts to
minimize costs. No studies or other evidence were offered to support
this assertion. Wolverton, PPC, Ex. E-PP-01, 29-30.

PPC's proposal to estimate financing benefits of conservation
investments, based on an analysis of the utility serving the area where
the BPA investment was made, is unacceptable for similar reasons. BPA
may make investments in conservation for areas that are served by
non-7(b)(2) customers. Again, the financing benefits for these customers
may have no relation to financing benefits that would be forgone by
7(b)(2) customers.

**Decision**

The assumption of resource ownership by the 7(b)(2) customers of type 1
and type 2 resources is reasonable and was supported by the parties. The
assumption that type 3 and conservation resources are owned or sponsored
by the 7(b)(2) customers avoids speculation and additional complicating
assumptions about financing arrangements in the 7(b)(2) case. It
recognizes that financing benefits should logically be quantified for
only the 7(b)(2) customers in order properly to determine their power
costs in the 7(b)(2) case.

**Issue #2**

Should an outside financial expert perform the financing benefit?

**Summary of Positions**

BPA proposed to employ an outside consultant to perform the analysis or
financing benefits because BPA's in-house expertise is insufficient to
perform such an analysis. Melton and Armstrong, BPA, Ex. E-BPA-01, 11.

PGP, PPC, APAC and the DSIs supported the use of an outside consultant.
Wolverton, PPC, Ex. E-PP-01, 26; Peseau, DSI, Ex. E-DS-01, 27; E-DS-3SR,
9; Spettel, PGP, Ex. E-PG-01, 6; APAC Brief, Ex. B-PA-01, 31.

**Evaluation of Positions**

The parties to this proceeding agreed that an outside consultant should
be retained to analyze financing benefits. The analysis requires
expertise beyond that of BPA staff. Melton and Armstrong, BPA, Ex.
E-BPA-01, 13-14.

**Decision**

An outside consultant has been employed to analyze financing benefits
for the section 7(b)(2) rate test.

**Issue #3**

Are BPA's assumptions relating to the analysis of financing benefits
appropriate?

**Summary of Positions**

BPA proposed to provide the outside consultant with several assumptions
relating to the type, cost and ownership of the resources to be
analyzed. Melton and Armstrong, BPA, Ex. E-BPA-01, 11-13.

Neither PPC nor APAC criticized BPA's proposal of the substance of the
information to be provided to the consultant. Wolverton, PPC, Ex.
E-PP-01, 25; APAC Brief, Ex. B-PA-01, 33.

The DSIs supported BPA's proposal, provided that all relevant
information on resource additions is sent to the consultant, including
information related to reserve resources, with no constraints on the
type of analysis to be performed. Peseau, DSI, Ex. E-DS-03SR, 9.

**Evaluation of Positions**

The parties to this proceeding agreed on the type of information to be
provided to the outside financial expert by BPA. Such information
includes resource type, cost and sponsor. Pursuant to the evaluation and
decision regarding reserve resources (at 9, *supra*), the information
should include that relating to reserve resources.

**Decision**

BPA will provide the information as to type, cost and ownership of
additional resources, including reserve resources, to the consultant.

**Issue #4**

Is Wertheim & Co., Inc., the appropriate outside financial expert to the
financing benefits analysis for the rate test as part of BPA's 1985
initial rate proposal?

**Summary of Positions**

BPA selected Wertheim & Co., Inc., BPA's financial adviser, to perform a
financing benefits analysis for the 1985 initial proposal rate test on
the basis of Wertheim s expertise in financial matters related to
Northwest utilities. Melton and Armstrong, BPA, Ex. E-BPA-01, 13-14.

PPC opposed BPA's selection of Wertheim on the grounds that Wertheim has
an ongoing contractual relationship with BPA and thus may produce a
biased analysis. Wolverton, PPC, Ex. E-PP-01, 25-26; PPC Brief, Ex.
B-PP-01, 26-27.

PGP and APAC supported the PPC position. Spettel, PGP, TR 1144-1145;
APAC Brief, Ex. B-PA-01, 31-32.

The DSIS supported BPA's position. Peseau, DSI, Ex. E-DS-01, 27; Ex.
E-DS-03SR, 9.

**Evaluation of Positions**

BPA selected Wertheim & Co., Inc., to perform the financing benefits
analysis for the 1985 rate test because of Wertheim's proven working
knowledge of the region's economy and regional utilities acquired by
acting as BPA's financial adviser for the last three years. Melton and
Armstrong, BPA, Ex. E-BPA-01, 13-14. PPC, PGP and APAC believe that the
ongoing contractual relationship might inhibit independent analysis, and
could result in only that analysis acceptable to BPA. No examples or
specific instances of bias were offered for this assertion. O'Meara,
PPC, TR 1168; Spettel, PGP, TR 1144-1145. PPC also expressed doubts
about the expertise of any bond house to perform the financing benefits
analysis. PPC presented no reasons as to why a bond house might lack
that expertise. Wolverton, PPC, Ex. E-PP-01, 26. Moreover, any financial
expert retained by BPA or by any of the parties would be under contract
and would be subject to the same claims of bias. The financing benefit
analysis, whether sponsored by BPA or by an intervenor in the rate case,
will be subject to cross examination and other procedures required by
section 7(1) of the Northwest Power Act. In any event, expertise, not
independence, is the crux of this issue. Were it not for the fact that
BPA staff lacks the necessary expertise, the analysis would be performed
in-house. Melton and Armstrong, BPA, Ex. E-BPA-01, 11.

**Decision**

PPC, PGP and APAC's opposition to the selection of Wertheim & Co., Inc.,
to perform the financing benefits analysis is not supported by the
evidence. The choice of Wertheim to perform any necessary financing
benefits analysis for the 1985 initial proposal is reasonable.

**Issue #5**

Was BPA's selection process for the outside financial expert proper?

**Summary of Positions**

BPA selected Wertheim & Co., Inc., again because of Wertheim's working
knowledge of the region's economy and regional utilities. BPA did not
consult with outside parties in making the selection. Melton and
Armstrong, BPA, Ex. E-BPA-01, 11.

PPC believes that BPA should have consulted with PPC and other parties
before choosing a financial consultant. Wolverton, PPC, Ex. E-PP-01,
25-27; PPC Reply Brief, Ex. R-PP-01, 17. PPC offered a detailed
selection procedure: PPC would select one representative, and BPA and
all non-7(b)(2) customers would select one representative. The two would
select a third representative; these three would then choose a financial
expert to perform the analysis. The selection committee would be formed
eight months before BPA's initial proposal for a rate adjustment is
filed; the expert selected seven months before the initial proposal; the
expert's findings made available three months later; customer meetings
and a comment period would ensue one month after that; and the final
analysis would be submitted to BPA two months before publication of the
initial proposal for inclusion into its direct case. Wolverton, PPC, Ex.
E-PP-01, 27-28; PPC Brief, Ex. B-PP-01, 25, 27-28.

APAC supported PPC's proposal. APAC Brief, Ex. B-PA-01, 32.

PGP agreed that the selection of a financial expert should be made
through joint consultation with the parties. PGP Pre-Hearing Brief, Ex.
P-PG-01, 14.

**Evaluation of Positions**

The decision to retain Wertheim to perform the analysis of financing
benefits for the 1985 rate test was made as part of the Administrator's
authority to set rates and his discretion to employ methodologies for
that purpose. This authority and discretion are counterbalanced by the
Administrator's responsibility to solicit input via a public involvement
process each time he proposes to set rates. Melton and Armstrong, BPA,
Ex. E-BPA-03R, 14. In addition, BPA consulted with interested parties,
including PPC, APAC and PGP, in a series of discussion meetings held
specifically to discuss the section 7(b)(2) implementation methodology.
Melton and Armstrong, BPA, Ex. E-BPA-01, 13. The PPC proposal would
introduce an unnecessary and unworkable procedure into the already
complex and time-consuming ratesetting process. Melton and Armstrong,
BPA, Ex. E-BPA-03R, 15. First, there is no statutory requirement that
any component of a rate filing be subject to public comment before
publication of a notice of BPA's initial proposal. *See* 16 U.S.C.
839e(1) (section 7(1)). Second, the schedule is impractical considering
the timing of determinations of data for BPA's rate filings: data would
not be available as needed to implement the schedule. Melton and
Armstrong, BPA, Ex. E-BPA-03R, 15.

A major thrust of the PPC and APAC arguments regarding the selection of
Wertheim was that BPA, in essence, simply named a consultant to perform
an analysis and that this act does not constitute a methodology.
Wolverton, PPC, Ex. E-PP-01, 24; Lucas, Wolverton and O'Meara, PPC, Ex.
E-PP-04R, 9; PPC Brief, Ex. B-PP-01 25; APAC Brief, Ex. B-PA-01, 32. BPA
proposed more than the name of Wertheim, however. As was pointed out in
Section II, issue #3, *supra*, BPA suggested several assumptions to be
provided to the financial expert. These assumptions are found in BPA's
direct testimony (Melton and Armstrong, Ex. E-BPA-01, 11-13) and
include, among others, what additional resources are assumed to be
required; whether proxy, sponsorship of resources is assumed; and the
type and cost of additional resources. The PPC methodology proposal
itself, on the other hand, appears simply to name an expert (or at
least, to name who will appoint representatives to name an expert).
APAC's critique of BPA's proposal (APAC Brief, Ex. B-PA-01, 32-33)
highlights BPA testimony that is allegedly inconsistent with regard to
the method of determining financing benefits. Upon close examination,
however, it can be seen that the statements are not contradictory.
Witness Melton testified that BPA proposes to use Wertheim for the short
term, *i.e.*, for the 1985 rate case, but that BPA would not be
compelled to use Wertheim in future rate cases (TR 974). Witness
Armstrong said that one part of BPA's methodology was to name Wertheim
(TR 878), later clarifying his statement by explaining that the
methodology BPA proposed included the "general concept" of using an
outside financial consultant, "and only for the '85 rate case are we
proposing that Wertheim be used." Armstrong, BPA, TR 1083.

**Decision**

BPA's selection process for the outside consultant for the financing
benefits analysis was proper. The Administrator's authority to set power
rates, and his responsibility to encourage public involvement, support
BPA's position.

**Issue #6**

Should the analysis of financing benefits be performed in the same
manner for each rate test?

**Summary of Positions**

BPA proposed that the analysis of financing benefits be performed in a
manner chosen by the financial expert for each rate test. Each analysis
would take into account the economic conditions existing at the time the
analysis is made. Melton and Armstrong, BPA, Ex. E-BPA-01, 14;
Armstrong, BPA, TR 880.

The DSIs supported BPA's position. Peseau, DSI, Ex. E-DS-01, 27-28.

PPC seemed implicitly to support BPA's position by suggesting that the
method used to quantify financing benefits could change for each rate
test because different contractors could be performing the analysis each
time. O'Meara, PPC, TR 1178-1179.

**Evaluation of Positions**

The parties agreed that the analysis of financing benefits should be
performed anew for each rate test to reflect, among other things,
current economic conditions at the time of the relevant rate case.

**Decision**

The analysis of financing benefits will be performed on a case-by-case
basis for each rate test. The analysis itself will be performed in a
manner deemed appropriate by the financial expert conducting the
analysis.

**IV**

**NATURAL CONSEQUENCES**

Natural consequences, also referred to as secondary effects, result from
the relationship of the 7(b)(2) case to the program case: the two cases
will be modeled using the same underlying premises and ratemaking
procedures. Implementing the five assumptions listed in section 7(b)(2)
in the 7(b)(2) case may produce results different from those in the
program case when using the same underlying premises and ratemaking
procedures used in the program case. These differing results are the
natural consequences of the 7(b)(2) assumptions. *See* BPA Legal
Interpretation, 49 Fed. Reg. 23998, 2400-2401 (1984), which contains a
full discussion of the legal basis for the recognition of such secondary
effects.

**Issue #1**

Are the natural consequences identified by BPA the direct and
unavoidable results of the five section 7(b)(2) statutory assumptions?

**Summary of Positions**

BPA identified, three natural consequences of the five statutory
assumptions listed in section 7(b)(2): demand elasticities, amount of
surplus firm-power available, and size of nonfirm energy markets. These
three consequences result from the section 7(b)(2) assumptions because
the underlying premises of economic principles and system physical
constraints will be held constant between the program case and the
7(b)(2) case. Melton, BPA, Ex. E-BPA-01, 10-11.

PPC opposed BPA's recognition of any natural consequences. In
particular, PPC argued that BPA-proposed to consider only those natural
consequences that are harmful to the preference customers. Wolverton,
PPC, Ex. E-PP-01, 7; PPC Brief, Ex. B-PP-01, 14-16; PPC Reply Brief, Ex.
R-PP-01, 15.

PGP and APAC supported the PPC positions. Spettel, PGP, Ex. E-PG-01, 4;
PGP Brief, Ex. B-PG-01, 5-6; APAC Brief, Ex. B-PA-01, 19-26; APAC Reply
Brief, Ex. R-PA-01, 9-10.

ICP implicitly supported BPA's proposal. Wilson, McCullough, Hannigan
and Powers, ICP, Ex. E-IC-01, 3-4; ICP Brief, Ex. B-IC-01, 1-3.

**Evaluation of Positions**

BPA's proposal to recognize natural consequences is consistent with its
legal interpretation. The three natural consequences identified by BPA
from maintaining the same underlying premises and processes in the
7(b)(2) case as in the program case. When the five assumptions from
section 7(b)(2) are implemented within that framework, unavoidable
natural consequences may result. Reflecting those unavoidable natural
consequences will avert technical inconsistencies. Melton, BPA, Ex.
E-BPA-01, 10-11; ICP Brief, Ex. B-IC-01, 2. For example, if the 7(b)(2)
case amount and the program case amount differ significantly, the
economic principle of demand elasticity may need to be reflected in a
new load forecast for the 7(b)(2) case. Melton, BPA, Ex. E-BPA-01, 11.
Disregarding any significant differences and their effect on loads
implies that the price elasticity of demand for electricity for the
7(b)(2) customers is zero. This implication is not one of the five
assumptions listed in section 7(b)(2). Melton, BPA, Ex. E-BPA-01, 12.
Similarly, since the load/resource balances in the program case and the
7(b)(2) case will differ due to the transfer of DSI loads, the amount of
surplus firm power available and the assumed size of the market for
nonfirm energy will differ between cases. A failure to recognize those
differences would change the underlying premises upon which BPA bases
its load/resource balance. Melton, BPA, Ex. E-BPA-01, 11. Such a change
is not one of the assumptions in section 7(b)(2). Melton, BPA, Ex.
E-BPA-01, 12.

PPC and PGP alleged that BPA has proposed to reflect only the natural
consequences that would harm the 7(b)(2) customers. Wolverton, PPC, Ex.
E-PP-01, 7; Spettel, PGP, Ex. E-PG-01, 4. PPC, APAC and PGP described
certain situations that could benefit the 7(b)(2) customers:[^9]

> \- In the 7(b)(2) case, residential customers of investor owned
> utilities would incur higher rates, and thus use less electricity.
> More cheap power would then be available for the 7(b)(2) customers.
>
> \- The price, not merely the amount, of surplus firm power could
> change. The capacity of the Pacific Southwest intertie could constrain
> surplus sales to California. BPA could sell surplus firm on the
> nonfirm market. This reduces the amount of surplus firm power and in
> turn possibly increases the realized price of surplus firm power. This
> may make it likelier for the rate test to trigger.
>
> \- Power lost because of the fish flush is a change in the physical
> characteristic of the FBS and should be restored to 7(b)(2) customers.
>
> \- There would be a decrease in BPA's operation and maintenance costs
> due to the absence, in the 7(b)(2) case, of certain costs incurred
> because of the Northwest Power Act (conservation, fish and wildlife,
> billing credits, and the like).
>
> \- The 7(b)(2) customers, in the 7(b)(2) case, could negotiate with
> the DSIs to serve the industries with interruptible power.
>
> \- Changes in the price of power affect not only loads (the basis for
> BPA's proposal to account for demand elasticities) but also load
> pattern shapes over a given period of time. The change in these shapes
> could affect the level of average energy available.

Lucas, O'Meara and Wolverton, PPC, Ex. E-PP-04R, 17-18; Spettel, PGP,
Ex. E-PG-01, 4-5; Miller, APAC, TR 1042-1044.

Most of the examples axe not the direct result of implementing the
7(b)(2) assumptions and leaving all other underlying premises and
ratemaking principles the same. Many require assumptions not specified
in section 7(b)(2). Furthermore, the examples suggest a "what if"
approach (that is, an approach to the 7(b)(2) case that attempts to
hypothesize, in extreme detail, the conditions that would have existed
had the Northwest Power Act never passed). PPC, PGP and APAC criticized
this approach as arbitrary and speculative. Wolverton, PPC, Ex. E-PP-01,
7; PPC Brief, Ex. B-PP-01, 15; PGP Brief, Ex. B-PG-01, 5; APAC Brief,
Ex. B-PA-01, 20.

> \- Assuming that 7(b)(2) customers could obtain cheap power from
> investor owned utilities in the 7(b)(2) case would conflict with BPA's
> legal interpretation. 7(b)(2) customers are assumed to be served with
> FBS and defined additional resources only.
>
> \- BPA does not argue with the proposition that the price of surplus
> firm power could differ between the cases. The levels of surplus firm
> and nonfirm sales and markets, discussed in Issue #4, at 24-25,
> *infra*, could vary between the cases. The price of surplus firm
> depends on the resources and their amounts that comprise the surplus
> firm available, and the amount that is assumed marketed, so the price
> may also vary between the cases. Melton, BPA, TR 826. It should be
> noted that BPA is-not hereby identifying a fourth secondary effect. An
> adjustment to the price of surplus firm power occurs because of the
> differing levels of surplus firm power available, discussed in Issue
> #4, at 24-25, *infra*.
>
> \- Excluding the fish flush would require the assumption that the fish
> and wildlife provisions of the Northwest Power Act are not binding.
> This is not specified in section 7(b)(2), and the fish flush will be
> included in the program case. Therefore, it would not be appropriate
> to exclude it in the 7(b)(2) case.
>
> \- Decreasing BPA's operation and maintenance costs would require the
> assumption that programs such as fish and wildlife did not take place
> in the 7(b)(2) case, which is not specified in section 7(b)(2). To the
> extent that conservation and billing credits are not included in
> additional resource costs in the 7(b)(2) case, their costs would not
> be included. Melton and Armstrong, BPA, Ex. E-BPA-01, 32.
>
> \- Speculation on interruptible service to DSIs by the 7(b)(2)
> customers in the 7(b)(2) case conflicts with BPA's legal
> interpretation which requires 100 percent firm service to within or
> adjacent DSI loads.
>
> \- With respect to the changes in load pattern shapes, BPA witness
> Melton testified (TR 1043) that it would be "possible" for the changes
> to affect the level of average energy available. This is not
> sufficient evidence to recognize that suggestion as a secondary effect
> in the 7(b)(2) case.

APAC also argued that BPA's proposal to recognize the three secondary
effects (elasticity, amount of surplus firm power and size of nonfirm
energy markets) is the result not of BPA system physical constraints or
economic principles, but of BPA staff inability to model other secondary
effects. APAC Brief, Ex. B-PA-01, 25. Certainly BPA witnesses are
concerned about the burden imposed by complex computer modeling
processes. Melton, BPA, TR 1046. The administrative burden placed on an
agency is a valid consideration as to whether a task should be
undertaken. See *University of Cincinnati v. Heckler*, No. 83-307, slip
op., at 5 (6th Cir., May 14, 1

**Decision**

The PPC/PGP/APAC criticism of the three natural consequences identified
BPA was not supported by their evidence. Their examples of other natural
consequences are either in conflict with BPA's legal interpretation or
are not natural consequences of the 7(b)(2) assumptions. The three
natural consequences that were identified by BPA are valid results of
the assumptions in section 7(b)(2). BPA already takes into account the
potential change in price of surplus firm power as between the program
case and the 7(b)(2) case.

**Issue #2**

Should a new load forecast for the 7(b)(2) case be generated if the
sales in the two cases differ significantly?

**Summary of Positions**

BPA proposed that the load forecast prepared for the relevant rate case
(extended for the rate test period) be input to the computer model to
calculate the program case rates. The loads used to calculate the
7(b)(2) case rates will be the same as those used for the program case,
except that programmatic conservation savings will be removed and DSI
loads not served by BPA will be assumed to be served 100 percent firm.
If the 7(b)(2) case rates differ significantly from the program case
rates, making a new forecast necessary, the same demand models used to
forecast the rate case and program case loads may be used to generate a
new 7(b)(2) case load forecast. Melton and Armstrong, BPA, Ex. E-BPA-01,
8.

PPC and PGP proposed that the loads should not differ between the
program case and the 7(b)(2) case. Wolverton, PPC, Ex. E-PP-01, 14-15;
Spettel, PGP, Ex. E-PG-01, 4; PGP Brief, Ex. B-PG-01, 14-15; PPC Brief,
Ex. B-PP-01, 16-19. APAC implicitly supported the PPC/PGP position. APAC
Brief, Ex. B-PA-01, 23.

ICP proposed that it would be necessary to perform a load forecast for
the 7(b)(2) case, using the rates calculated for the 7(b)(2) case and
forecasting models that incorporate long term elasticities. Iteration
would be necessary between the rate test computer model and BPA's load
forecasting model to reach equilibrium between price and demand. Wilson,
McCullough, Hannigan and Powers, ICP, Ex. E-IC-01, 25; ICP Brief, Ex.
B-IC-01, 6-7.

**Evaluation of Positions**

BPA believes that the elasticity of demand for electricity is an
underlying premise of the ratesetting process that needs to be reflected
as a natural consequence of the five assumptions listed in section
7(b)(2), Reflecting demand elasticities may make a new load forecast
necessary if the rates calculated for the program case and 7(b)(2) case
differ significantly. Melton, BPA, Ex. E-BPA-01, 11.

The PPC/PGP/APAC position is inconsistent with BPA's legal
interpretation. Melton and Armstrong, BPA, Ex. E-BPA-3R, 8. In addition,
PPC proposed that elasticity effects be reflected in the program case
but not in the 7(b)(2) case. The PPC witness was unable to give either a
technical reason for this inconsistency or any scenario that would
produce rates which would yield such results. Wolverton, PPC, TR
1202-1206.

ICP proposed that the effects of rates on loads should be reflected
beginning with the date of the passage of the Northwest Power Act. It
suggested that load forecasting models with long term elasticities be
used to forecast loads for the 7(b)(2) case. Wilson, McCullough,
Hannigan and Powers, ICP, Ex. E-IC-01, 24-25. Such a process is
inconsistent with BPA's proposal to keep the underlying processes
(*e.g.*, load forecasts) the same for the 7(b)(2) case as for the
program case. Melton, BPA, Ex. E-BPA-01, 9. The ICP proposal requires
that a different load forecasting model be used for the 7(b)(2) case
than would be used for the program case. Hannigan, ICP, TR 718. *See*
Issue #3, *infra*.

**Decision**

BPA's proposal to perform a new load forecast for the 7(b)(2) case if
the monetary amounts in the program case and 7(b)(2) case differ
significantly is reasonable. It is consistent with BPA's legal
interpretation. It also considers the practical aspects of performing a
new load forecast in an already complex ratesetting process.

**Issue #3**

Should the same demand models used to forecast loads for the relevant
rate case be used to develop loads for the 7(b)(2) case?

**Summary of Positions**

BPA proposed that the same demand models used for the relevant rate case
be used to forecast loads for the 7(b)(2) case. Melton and Armstrong,
BPA, Ex. E-BPA-01, 8.

ICP proposed that the models used for the 7(b)(2) case should
incorporate elasticity effects occurring both before and after the five
year rate test period. This implies that the demand models to be used
for the section 7(b)(2) rate test should be different than those used
for the relevant rate case. Wilson, McCullough, Hannigan and Powers,
ICP, Ex. E-IC-01, 25-27; Hannigan, ICP, TR 718.

**Evaluation of Positions**

The BPA proposal to use the same demand models to forecast loads for the
section 7(b)(2) rate test as are used for the relevant rate case is
consistent with BPA's legal interpretation. The program case is a
simulation of the relevant rate case test year plus the ensuing four
years. Melton and Armstrong, BPA, Ex. E-BPA-01, 9. As such, it logically
should use as many inputs as possible from the relevant rate case. The
load forecast prepared for the relevant rate case can easily be extended
to serve the input requirements of the section 7(b)(2) rate test. Melton
and Armstrong, BPA, Ex. E-BPA-01, 8.

The ICP proposal is inconsistent with BPA's legal interpretation.
Attempting to reflect cumulative elasticity effects since the passage of
the Northwest Power Act would be an overly speculative, complex process.
Melton and Armstrong, BPA, Ex. E-BPA-03R, 18.

**Decision**

BPA will use the demand models used to forecast loads in the relevant
rate case to determine loads for the section 7(b)(2) rate test. This
practice is consistent with BPA's legal interpretation.

**Issue #4**

Should adjustments to surplus firm and nonfirm sales and markets be made
between the program case and the 7(b)(2) case?

**Summary of Positions**

BPA proposed that the level of surplus firm power available will differ
between the two cases due to the different load/resource balances. The
nonfirm energy markets will also differ between the two cases. These two
adjustments are natural consequences of the five 7(b)(2) assumptions.
Melton and Armstrong, BPA, Ex. E-BPA-01, 17; Armstrong, BPA, TR 796.

PPC appeared implicitly to support BPA's position on the level of
surplus firm available. Its proposed PPC/7(b)(2) computer model
(discussed in Section V, *infra*) includes a provision for adjusting the
level of surplus firm based on loads and resources in the 7(b)(2) case.
Wolverton, PPC, Ex. E-PP-01, 81-82. APAC, by supporting the use of the
PPC/7(b)(2) computer model, appeared to support PPC's position. APAC
Brief, B-PA-01, 16.

PGP urged that neither the level of surplus firm power available nor the
level of the nonfirm market should differ between the two cases.
Spettel, PGP, Ex. E-PG-01, 6-7; Spettel, PGP, TR 1145. However, PGP also
supported the use of the PPC/7(b)(2) computer model. Spettel, PGP, Ex.
E-PG-01, 7-13. This is inconsistent with PGP's position on the
determination of available surplus firm in the 7(b)(2) case.

**Evaluation of Positions**

BPA's proposal reflects provisions of its legal interpretation. Changes
between the program case and the 7(b)(2) case in the amount of surplus
power and the size of nonfirm energy markets are natural consequences of
the five assumptions listed in section 7(b)(2). Loads in the 7(b)(2)
case will differ from the program case loads because of the assumption
of 100 percent firm service to the "within or adjacent" DSIs, because of
the potential new load forecast to reflect price elasticity, and because
of the differences in resources used in the 7(b)(2) and program cases.
Such load differences could require an adjustment in the amount of
surplus power available between the program case and the 7(b)(2) case.
Similarly, the smaller DSI first quartile nonfirm load, and the
potentially different amount of displaceable^\*\*^ new resource
generation, support possible adjustments to nonfirm energy markets in
the 7(b)(2) case. Melton and Armstrong, BPA, Ex. E-BPA-01, 17. PPC and
APAC appeared to support BPA's position on the determination of the
level of surplus firm available.

PGP's position cannot be ascertained.

**Decision**

To be consistent with BPA's legal interpretation, adjustments to surplus
firm power availability and nonfirm energy markets in the program case
will be made for the 7(b)(2) case. Such adjustments are natural
consequences of the section 7(b)(2) assumptions.

**Issue #8**

What assumption should be made in the 7(b)(2) case as to the amount of
surplus firm power sales?

**Summary of Positions**

BPA proposed that the level of surplus firm power sold in the two cases
would be the same, except as adjusted for the amount of surplus firm
power available (which will be different in the two cases due to natural
consequences) and for the absence of sales in the 7(b)(2) case of
surplus firm power to the DSI first quartile. Melton and Armstrong, BPA,
Ex. E-BPA-01, 17-18; TR 822-823.

The DSIs argued that the amount of surplus firm power sales in the
7(b)(2) case should be different from the amount in the program case
because of the elasticity effects of different prices for the surplus
firm power in the two cases. DSI Brief, Ex. B-DS-01, 12-14; DSI Reply
Brief, Ex. R-DS-01, 4-5.

**Evaluation of Positions**

BPA's assumption that the levels of surplus firm sales in the 7(b)(2)
and program cases will not differ except for the two adjustments
described in Issue #4 at 24-25, *supra*, is consistent with BPA's
general approach in its legal interpretation of section 7(b)(2). The
DSIs are concerned that BPA's assumption of equal levels of surplus firm
sales in the two cases is in error in that the levels of forecasted
sales of other types of power may be adjusted for price elasticity
effects. DSI Brief, Ex. B-DS-01, 13; DSI Reply Brief, Ex. R-DS-01, 5. To
the extent that the relevant rate case, and thus the program case,
reflects price in the determination of surplus firm power sales, that
same process is used in the 7(b)(2) case. At this time; the program case
targets a particular amount of marketable surplus firm power, which
amount is assumed to exist in the 7(b)(2) case. To assume otherwise
would require speculation. Melton, BPA, TR 826-827; 831-832.

**Decision**

BPA will assume the same level of surplus sales in the program case and
in the 7(b)(2) case, except as adjusted for availability and DSI first
quartile sales.

**Issue #6**

How should additional resources be assumed to meet load in the 7(b)(2)
case: in exact increments to meet the load, or in discrete "lumps" that
could result in a surplus of firm power?

**Summary of Positions**

BPA proposed that the type 1 and 2 additional resources be added in
discrete "lumps", but that the type 3 resource be assumed to be added in
the exact amount needed to meet the load in the 7(b)(2) case. Armstrong,
BPA, TR 808. This proposal is consistent with BPA's legal
interpretation. Armstrong, BPA, TR 805. Melton and Armstrong, BPA, Ex.
E-BPA-03R, 11.

PGP, APAC and PPC proposed that all additional resources should "be
acquired in the quantity necessary to obtain a balance between power
loads and resources." Thus, no surplus should ever exist in the 7(b)(2)
case. Spettel, PGP, Ex. E-PG-01, 5; APAC Brief, Ex. B-PA-01, 29-30;
Wolverton, PPC, Ex. E-PP-01, 16-17; Lucas, O'Meara and Wolverton, PPC,
Ex. E-PP-04R, 25-26; PPC Brief, Ex. B-PP-01, 19-21; PPC Reply Brief, Ex.
R-PP-01, 17.

The DSIs proposed that a short term surplus may exist in the 7(b)(2)
case as a result of adding any of the three types of additional
resources to meet load. Peseau, DSI, Ex. E-DS-01, 19-20- DSI Brief, Ex.
B-DS-01, 7-8; Peseau, DSI, Ex. E-DS-02R, 3-6; DSI Reply Brief, Ex.
R-DS-01, 6.

ICP supported the DSI position. Wilson, McCullough, Hannigan and Powers,
ICP, Ex. E-IC-02R, 1-2; ICP Brief, Ex. B-IC-01, 7-8; ICP Reply Brief,
Ex. R-IC-01, 3-4.

**Evaluation of Positions**

PGP/PPC/APAC supported their proposal of no surplus due to additional
resources in the 7(b)(2) case with the existence of "regional
arrangements" that can have the effect of adding resources in increments
as necessary to meet load. Lucas, O'Meara and Wolverton, PPC, Ex.
E-PP-04R, 25-26. Such arrangements would also reduce or eliminate the
surplus in the program case. Wolverton, PPC, TR 1210. The DSIs and ICP
pointed out that, in reality, contingency planning results in resources
often coming on line ahead of the exact time needed, and in lumpy
increments that result in a surplus of capacity. Peseau, DSI, Ex.
E-DS-01, 19. The PPC proposal is unrealistic in its assumption of
perfect resource timing, and is inconsistent with the program case. "The
economic principle of cost minimization" that PGP uses to support its
proposal (Spettel, PGP, Ex. E-PG-01, 5) is more theoretical than
practical. Utilities may indeed attempt to minimize the cost of their
resource additions, but the reality remains that surpluses are created
by adding resources in "lumps". Peseau, DSI, Ex. E-DS-02R, 5; Wilson,
McCullough, Hannigan and Powers, ICP, Ex. E-IC-02R, 1.

PPC also argued that section 7(b)(2) does not refer specifically to
costs of surplus power and therefore that no surplus should be reflected
in the 7(b)(2) case. PPC Brief, Ex. B-PP-01, 21; PPC Reply Brief, Ex.
R-PP-01, 17. PPC's argument is inconsistent with BPA's legal
interpretation. Moreover, it would introduce bias to the rate test by
understating 7(b)(2) case power costs. DSI Brief, Ex. B-DS-01, 7.

The DSI/ICP proposal, that all three resource types be added in "lumps",
is overly speculative, because the type 3 resource is made up of generic
resources with generic (average) costs. Adding resources from this third
category in exact increments is the practical solution. Armstrong, BPA,
TR 804. Moreover, BPA's legal interpretation requires that the generic
resources be added in the "size required (for the\] remaining loads..."
49 Fed. Reg. at 24005. While nongeneric resources often come on line in
lumpy increments, no adequate showing has been made by ICP or the DSIs
as to why generic resources would (or to what extent they would). *See*
DSI Reply Brief, Ex. R-DS-01, 7-8; ICP Reply Brief, Ex. R-IC-01, 4. A
generic resource is nowhere defined as a discrete, single existing
resource; section 7(b)(2)(D)(ii) requires merely that additional
resources be obtained at the "average cost of all other new resources
acquired by BPA." The ICP reference (ICP Reply Brief, Ex. R-IC-01, 4) to
the analysis of financing benefits for the type 3 resource is not
persuasive. The "average cost of all other new resources" requires an
averaging of the cost, not of the physical characteristics, of other new
resources. The assumption of "average" physical characteristics for the
type 3 resources, in order to achieve lumpiness, would be arbitrary and
speculative.

**Decision**

BPA will treat the first and second types of additional resources in the
7(b)(2) case as "lumps"; this reflects the actual increments by which
BPA acquires them. BPA will assume that generic resources are acquired
in exact increments as needed to meet load, thus reflecting the genetic
nature of that category of additional resources, as described in the BPA
legal interpretation.

**Issue #7**

What resources should be assumed to comprise any potential surplus in
the 7(b)(2) case?

**Summary of Positions**

BPA proposed to maintain the same underlying premises and processes
between the two cases. Under BPA's current ratemaking methodologies, two
resource pools would be used in the 7(b)(2) case to be consistent with
the program case. That is, 7(b)(2) customers' general requirements would
be assumed to be served with FBS resources until those resources are
exhausted, then with additional resources. Surplus firm power would be
assumed to be comprised of resources in the reverse order. Armstrong,
BPA, TR 815-816.

BPA also proposed that the costs of unsold surplus FBS power be
allocated to all customers of the FBS. The costs of unsold surplus
additional resources should be allocated to the 7(b)(2) customers.
Armstrong, BPA, TR 872.

ICP appeared to agree with BPA's initial proposal for the treatment of
resource costs in the 7(b)(2) case. ICP expressed concern that any FBS
surplus firm power should be allocated only the costs of the FBS, and
that surplus additional resources owned by the 7(b)(2) customers should
be allocated the full cost of those resources. Wilson, McCullough,
Hannigan and Powers, ICP, Ex. E-IC-01, 4-7. The ICP Brief reiterated the
concept that additional resources in the 7(b)(2) case should be treated
by the SPM as if owned by the 7(b)(2) customers, not by BPA. ICP Brief,
Ex. B-IC-01, 3-5. The ICP Reply Brief claimed that the SPM treats
additional resources as BPA resources, thus allocating the overhead
costs related to those additional resources to FBS customers. It also
claims that "unsold surplus resources are then sold outside the region,
rather than allocated to the 7(b)(2) customers..." ICP Reply Brief, Ex.
R-IC-01, 4-5.

The DSI position is that the costs of all resources in the 7(b)(2) case
should be melded. The 7(b)(2) customers and the purchasers of surplus
firm power in the 7(b)(2) case would thus be allocated the same costs.
Peseau, DSI, Ex. E-DS-01, 24-27; Peseau, DSI, Ex. E-DS-03SR, 5; DSI
Brief, Ex. B-DS-01, 11; DSI Reply Brief, Ex. R-DS-01, 3-4.

PPC supported BPA's proposal for resource stacking. Wolverton, PPC, Ex.
E-PP-01, 15-16; Lucas, O'Meara and Wolverton, PPC, Ex. E-PP-04R, 15; PPC
Brief, Ex. B-PP-01, 28-30.

**Evaluation of Positions**

BPA projects three "rates" in the 7(b)(2) case. The rate for power sold
under pre-Northwest Power Act contracts is based on FBS costs, including
a portion of the costs of any potential unsold surplus FBS resources,
and additional non-7(b)(2) related cost and revenue adjustments. The
second rate (the 7(b)(2) rate) applies to the general requirements of
the 7(b)(2) customers. It is based on the costs of the remaining FBS and
any potential new resources, including costs of unsold surplus FBS or
additional resources. The third rate is for surplus firm power sales,
based on the costs of surplus resources and the non-7(b)(2) related cost
and revenue adjustment allocations. Melton and Armstrong, BPA, Ex.
E-BPA-01, 30-31. However, BPA agrees with the ICP position that because
additional resources should be assumed to be owned and operated by
7(b)(2) customers, FBS costs and other BPA related costs and revenue
adjustments should be allocated only to loads served with the FBS.

BPA's treatment of resource costs in the 7(b)(2) case is consistent with
its legal interpretation. As stated therein, "...additional resources
are assumed to be acquired to meet the 7(b)(2) customers' loads [when
FBS resources are exhausted]{.underline}" (emphasis added). Also, as
argued by PPC, the SPM's treatment of additional resources is consistent
with the assumption that the 7(b)(2) customers would own and operate
those resources: the ICP implication that surplus additional resources
could not be sold is "economically implausible." Lucas, O'Meara and
Wolverton, PPC, Ex. E-PP-04R, 10-11. To assume that no surplus firm
power from additional resources could be sold also would be inconsistent
with BPA's assumption of the same level of surplus firm power sales in
the 7(b)(2) case as in the program case (adjusted only for natural
consequences), as discussed in Issue #5, at 25, *supra*. The asymmetry
between the program case and the 7(b)(2) case proposed by ICP and the
DSIs is inconsistent with BPA s general approach of keeping the
underlying ratemaking premises and processes the same for the two cases.
Armstrong, BPA, TR 816.

**Decision**

ICP and the DSIs did not support with sufficient evidence their proposal
that the "one pool" concept would properly account for the costs of
additional resources in the 7(b)(2) case. BPA's treatment of resources
stacking is consistent with BPA's legal interpretation and ensures
symmetry between the program case and the 7(b)(2) case.

**V**

**SELECTION OF COMPUTER MODEL TO PERFORM THE RATE TEST**

**Issue**

What is the appropriate computer model to perform the section 7(b)(2)
rate test?

**Summary of Positions**

BPA proposed to use its Supply Pricing Model (SPM) to calculate the two
sets of rates to be used in the rate test. Melton and Armstrong, BPA,
Ex. E-BPA-01, 20-21.

PPC offered two models for consideration, but recommended that its
PPC/7(b)(2) model be used for the rate test. The PPC/7(b)(2) model would
utilize extensive inputs from the relevant rate case to calculate the
two sets of rates to be compared; the model then would perform the rate
test. Wolverton, PPC, Ex. E-PP-01, 74-75; PPC Reply Brief, Ex. R-PP-01,
15-16. PPC also proposed, as a second best alternative, a modified
version of BPA's SPM which separates, as much as possible, the
determinations made for the program case from those made for the 7(b)(2)
case and modularizes the SPM. Wolverton, PPC, Ex. E-PP-01, 95-96.

APAC supported use of the PPC/7(b)(2) model. APAC Brief, Ex. B-PA-01,
16-19.

PPC, ICP and the DSIs, in a meeting held May 15, 1984, agreed to use the
SPM, as modified by PPC, as a base from which to develop a workable rate
test model. Lucas, O'Meara and Wolverton, PPC, Ex. E-PP-04R, 2.

PPC, ICP and the DSIs, in a meeting held May 15, 1984, agreed to use the
SPM, as modified by PPC, as a base from which to develop a workable rate
test model. Lucas, O'Meara and Wolverton, PPC, Ex. E-PP-04R, 2.

PGP supported the use of either of PPC's proposed models. Spettel, PGP,
Ex. E-PG-01, 7-13.

ICP stated generally that the 7(b)(2) methodology should accurately
model BPA's ratesetting practices. Wilson, McCullough, Hannigan and
Powers, ICP, Ex. E-IC-01, 4.

The DSIs did not address the selection of a computer model to conduct
the section 7(b)(2) rate test, but made specific proposals relating to
the SPM's technique. Peseau, DSI, Ex. E-DS-01, 4. They urged that the
PPC/7(b)(2) model not be adopted for use in the section 7(b)(2) rate
test. Peseau, DSI, Ex. E-DS-02R, 10-11. The DSIs generally supported the
technical restructuring of the SPM. Peseau, DSI, Ex. E-DS-02R, 12. They
specifically stated that the ICP proposed model of nonfirm markets be
adopted. DSI Reply Brief, Ex. R-DS-01, 12.

**Evaluation of Positions**

Any computer model is simply a tool to perform rapid mathematical and
logical calculations. BPA Pre-Hearing Brief, Ex. P-BPA-01, 1. The
calculations of concern here implement the theories and decisions to be
applied in the rate test. It is these decisions and theories that are of
paramount importance, although certainly they must be represented
accurately in any computer model.

The SPM was modified by PPC. PPC, ICP and the DSIs all generally
appeared to approve the SPM as modified (Lucas, O'Meara and Wolverton,
PPC, Ex. E-PP-04R, 2-3; McCullough and Peseau, ICP and DSI, Ex.
E-JP-01R, 1-3) although PPC continued to urge the use of its PPC/7(b)(2)
model. BPA was able to duplicate the results of the its original SPM
with the modified SPM, and agreed to adopt the modified SPM as the basis
for further modeling efforts to perform the rate test. Armstrong, BPA,
TR 756. In addition, BPA agreed to evaluate five modeling proposals
submitted by the joint ICP/DSI rebuttal testimony for inclusion in the
SPM. Armstrong, BPA, TR 781-782. The PPC/SPM was not complete at the
time it was adopted, but it provided a common basis for further model
development and evaluation by BPA and the parties. Wolverton, PPC,
E-PP-01, 97-98; Peseau, DSI, Ex. E-DS-02R, 11-12; Lucas, O'Meara and
Wolverton, PPC, Ex. E-PP-04R, 4; McCullough and Peseau, ICP and DSI, Ex.
E-JP-01R, 3-4.

The modified SPM does two things: it models the program case (which
tracks the rate case and projects that case over a five year period),
and it models the 7(b)(2) case (which tracks the program case over the
same five year period, with the addition of the five assumptions and
their natural consequences). This comports with BPA's approach as
defined in its legal interpretation (*see* 49 Fed. Reg. at 2400-2401).

The PPC/7(b)(2) model, by contrast, attempts to fix a portion of the
rate test methodology and to separate entirely the program case from the
7(b)(2) case. Wolverton, PPC, Ex. E-PP-01, 75. However, the program case
and the 7(b)(2) case are inextricably linked and cannot be separated on
account of BPA's approach of modeling the cases the same except for the
7(b)(2) assumptions and their natural consequences. Melton and
Armstrong; BPA, Ex. E-BPA-03R, 21-23. The separation of the cases
effected by the PPC/7(b)(2) model results from inputting much of the
data needed by the model to develop the 7(b)(2) projections. The
PPC/7(b)(2) model does not produce projections for the program case.
However, this is an essential feature of any rate test model. Melton,
BPA, TR 854. The other models needed to calculate the inputs for the
PPC/7(b)(2) model (including some model like the SPM for use in modeling
the program case) would themselves be subject to scrutiny and
contention, thus possibly increasing, rather than lessening, the
complexity of the rate test. Peseau, DSI, Ex. E-DS-02R, 10-11. DSI
Brief, Ex. B-DS-01, 18.

**Decision**

BPA used the modified SPM as the basic model to develop the final rate
test model. BPA reemphasizes the fact that the computer model is a tool
for implementing the legal interpretation and the Administrator's
decisions on the substance of the section 7(b)(2) methodology. A
computer model cannot, of course, be used to abridge or circumscribe the
statutory discretion accorded the Administrator to set rates.

**VI**

**RATE TEST TRIGGER**

**Issue**

What assumptions should be made in order to compare the results of the
power cost projections for the two cases and to determine any potential
amount to be reallocated during the relevant rate case (test year
amount)?

**Summary of Positions**

BPA proposed that the rate test compare per kilowatthour amounts, rather
than the total allocated power costs of the 7(b)(2) customers, in the
two cases. Those five yearly amounts for each case would be discounted
back to the test year of the relevant rate case, using BPA's projected
future borrowing rate for each of the five years. The rates for each
case would then be averaged, and the result rounded to the nearest
one-tenth of a mill. The rate test would trigger if the program case
amount was one-tenth of a mill or more greater than the 7(b)(2) case
amount. This differential would then be multiplied by the general
requirements of the 7(b)(2) customers in the test year to determine the
test year amount. Melton and Armstrong, BPA, Ex. E-BPA-01, 34-37.

PPC proposed a rounding rule: amounts less than five-hundredths of a
mill should be rounded down; amounts equal to or greater than
five-hundredths of a mill should be rounded up. O'Meara, PPG, TR 948;
PPC Brief, Ex. B-PP-01, 31-32. BPA supported PPG's rounding rule. Melton
and Armstrong, BPA, E-BPA-03R, 21.

APAC supported PPC's and BPA's Positions. APAC Brief, Ex. B-PA-01,
35-36.

The DSIs argued that a one-tenth of a mill threshold before the rate
test triggers should be established. They claim that rounding the rates
before the comparison is made is not an alternative to a threshold and
effectively reduces the threshold by one-half. Peseau, DSI, Ex.
E-DS-03SR, 6-7; DSI Brief, Ex. B-DS-01, 14-16; DSI Reply Brief, Ex.
R-DS-01, 9-10.

**Evaluation of Positions**

BPA and PPC agreed that the program case amounts and the 7(b)(2) case
amounts should be rounded to one-tenth of a mill before the comparison
is made. Wolverton, PPC, E-PP-01, 33; Melton and Armstrong, BPA,
E-BPA-03R, 21; PPC Brief, Ex. B-PP-01, 31. BPA chose the one-tenth of a
mill level of significance to be consistent with the rounding rules used
in establishing wholesale power and transmission rates. PPC questioned
BPA's reason for using one-tenth of a mill, but did not offer an
alternative. Melton, BPA, TR 948.

The DSIs argued that instead of rounding the amounts, an absolute
threshold of one-tenth of a mill should be established. Peseau, DSI,
E-DS-03SR, 6-7; DSI Brief, Ex. B-DS-01, 15-16; Reply Brief, DSI, Ex.
R-DS-01, 9. They claimed that this threshold would be reasonable because
the amounts are not accurate to hundredths of a mill. Peseau, DSI,
E-DS-02R, 14; DSI Reply Brief, Ex. R-DS-01, 9. This proposal is
inconsistent with BPA's ratesetting process; furthermore, section
7(b)(2) requires that the rate test trigger whenever the program case
amount exceeds the 7(b)(2) case amount. Rounding does not alter this
requirement.

**Decision**

The discounted, averaged per kilowatthour amounts for each case will be
rounded to the nearest tenth of a mill for comparison. If the difference
between the program case amount and the 7(b)(2) case amount is one tenth
of a mill or more, the rate test will trigger. This difference will then
be multiplied by the general requirements of the 7(b)(2) customers in
the test year of the relevant rate case to calculate the test year
amount.

Issued at Portland, Oregon, this 17th day of August 1984.

Peter T. Johnson

Administrator

**APPENDIX A**

**PARTY ABBREVIATIONS**

Association of Public Agency Customers APAC

Bonneville Power Administration BPA

California Public Utilities Commission CPUC

Direct Service Industries[^10] DSIs

Hanna Nickel HN

Intercompany Pool[^11] ICP

Los Angeles (City of) Department of Water and Power LADWP

Montana Power Company MPC

Oregon Public Utilities Commissioner OPUC

Pacific Gas and Electric Company PG&E

Pacific Northwest Generating Company PNGC

Pacific Power and Light Company PP&L

Portland General Electric PGE

Public Generating Pool[^12] PGP

Public Power Council PPC

Puget Sound Power and Light Company PSP&L

San Diego Gas and Electric Company SDGE

Southern California Edison SCE

Tacoma (City of) TU

Washington Water Power Company WWPC

Western Area Power Administration[^13] WAPA

Western Washington Public Utility Districts[^14] WWPUD

**APPENDIX B**

**LIST OF PARTIES' WITNESSES AND REPRESENTATIVES**

**APPEARING IN THE**

**SECTION 7(b)(2) IMPLEMENTATION METHODOLOGY HEARING**

[Individual]{.underline} [Representing]{.underline}

Addison, Tom PSP&L

Armstrong, David J. BPA

Ater, Jonathan DSIs

Austin, R. Michael BPA

Ball, David A. DSIs

Baxendale, J. Richard PPC

Bearzi, Judith A. PPC

Benedetti, A.J. Weyerhaeuser Co.

Benedict, James E. PGP

Bubenik, Mark L. TU

Cameron, John A., Jr. BPA

Carey, Linda WAPA

Cooke, Jenny M. BPA

Crisson, Mark Martin Marietta

Eckhart, Tom PSP&L

Engberg, David PP&L

Fairchild, Peter G. CPUC

Fell, James F. PP&L

Flanagan, Stephen P. ESMG, Inc.

Foster, Bruce SCE

Frazee, Mark A. SCE

Furman, Donald PGE

Fusselman, Jerry PPC

Galloway, George M. PP&L

Garten, Allen M. APAC

Gentry, Robert Clark PUD

Glover, Lori A. DSIs

Graham, Paul A. OPUC

Greening, Robert M., Jr. PPC

Grey, Robert J. HN

Hannigan, Scott R. PGE

Holt, Roger LADWP

Howard, Marty PGE

Howarth, John W. Tillamook PUD

Hutchison, Coe Snohomish PUD

[Individual]{.underline} [Representing]{.underline}

Johnson, Eric R. PGE

Johnson, Leayesh PNGC

Karl, Donald G. PSP&L

Landau, Jack L. DSIs

Lauckhart, Richard PSP&L

Leone, C. Clark BPA

Lessner, Rochelle PPC

Lucas, Deborah J. PPC

McCullough, Robert F. PGE

McKenzie, A. Kirk DSIs

Melton, Shirley R. BPA

Miller, Max M. APAC

Mills, Edward PP&L

Mundorf, Terence L. WWPUD

Murphy, Paul DSIs

O'Meara, Kevin P. PPC

Peseau, Dennis E. DSIs

Powers, John T. PGE

Rehmann, James SCE

Saxton, Ronald L. DSIs

Shanker, Roy J. APAC

Siniscal, Evelyn PGE

Spettel, Scott C. PGP

Walsh, James F. MPC

Williams, Walter City of Seattle

Wilson, Robert C. PP&L

Wolverton, Lincoln PPC

Wordley, Bill PP&L

Young, Robert DSIs

Yu, Fu-Hau BPA

**APPENDIX C**

**SECTION 7(b)(2) IMPLEMENTATION METHODOLOGY**

**I. Introduction**

The Pacific Northwest Electric Power Planning and Conservation Act, 16
U.S.C. § 839 (1980), ("Northwest Power Act") confirms BPA's obligation
to establish and revise BPA's rates for the sale and transmission of
electric power. Section 7(b)(2) of the Northwest Power Act provides that
"after July 1, 1985, the projected amounts to be charged for firm power
for the general requirements of public body, cooperative and Federal
agency customers, exclusive of amounts charged such customers under
subsection (g) for the costs of conservation, resource and conservation
credits, experimental resources and uncontrollable events, may not
exceed in total, as determined by the Administrator, during any year
after July 1, 1985, plus the ensuing four years, an amount equal to the
power costs for general requirements of such customers if the
Administrator" makes a set of assumptions, outlined in the remainder of
section 7(b)(2). These assumptions hypothetically remove the effects of
certain provisions in the Northwest Power Act. In order to implement the
provisions in section 7(b)(2) BPA has formulated a methodology that
specifies how BPA will conduct the section 7(b)(2) rate test.

The implementation of section 7(b)(2) in any given BPA rate proceeding
requires two distinct steps. The first step is to compare a projection
of BPA rates developed under all the provisions of the Northwest Power
Act, but without considering the effects of section 7(b)(2) (the program
case), with a projection of BPA rates developed under the assumptions
outlined in section 7(b)(2) (the 7(b)(2) case). Both projections are of
rates applicable to public body, cooperative, and Federal agency
customers (7(b)(2) customers) and are based on the costs of power
required to serve the general requirements of those customers over a
five-year period.

If the projected rates in the program case are determined to be higher
than those in the 7(b)(2) case, then the second step is required. The
rates for the 7(b)(2) customers being developed in the BPA rate
proceedings must be reduced and the difference allocated to other BPA
rates pursuant to section 7(b)(3) of the Northwest Power Act. This
potential reallocation must be made within the framework of sound
ratemaking principles and of BPA's statutory obligations.

**II. Definitions**

This section contains definitions applicable to section 7(b)(2). Terms
identified in the Northwest Power Act have the same meaning in this
section, unless further defined.

1\. [7(b)(2) Customers]{.underline}. Those firm power customers of BPA
that are listed in section 7(b)(2) of the Northwest Power Act as subject
to the rate test, *viz*, public bodies, cooperatives, and Federal
agencies.

2\. [Within or Adjacent]{.underline}. Relating to direct service
industrial (DSI) customers' loads determined in accordance with section
7(b)(2)(A) to be geographically within or adjacent to the service
territories of 7(b)(2) customers.

3\. [Forecast DSI Loads]{.underline}. Those loads of direct service
industries that are forecast to be served by BPA, during any future
period, pursuant to section 5(d)(1) of the Northwest Power Act.

4\. [Relevant Rate Case]{.underline}. The wholesale power rate
adjustment proceeding being conducted at the time the projections for
section 7(b)(2) are made, and in which any adjustment to rates in
accordance with section 7(b)(2) may be reflected.

5\. [7(b)(2) Case]{.underline}. The entire process of projecting rates
for the relevant five-year period under the provisions of section
7(b)(2) of the Northwest Power Act, including specific data,
assumptions, and results.

6\. [Program Case]{.underline}. The entire process of projecting rates
to be charged in the future under the provisions of the Northwest Power
Act other than section 7(b)(2), including specific data, assumptions and
results.

7\. [Relevant Five-Year Period]{.underline}. The test year of the
relevant rate case, plus the ensuing four years.

8\. [7(b)(2) General Requirements]{.underline}. For the purpose of this
methodology, the public body, cooperative and Federal agency customers'
electric power assumed to be purchased from BPA in the 7(b)(2) case.
General requirements include only power purchased from BPA under section
5(b) of the Northwest Power Act; section 5(c) purchases from BPA are not
included.

9\. [Applicable 7(g) Costs]{.underline}. The costs identified in section
7(g) of the Northwest Power Act that are also listed in section 7(b)(2),
*viz*, costs chargeable to 7(b)(2) customers for conservation, resource
and conservation credits, experimental resources and uncontrollable
events.

**III. Legal Interpretation**

BPA published its Legal Interpretation of Section 7(b)(2) of the Pacific
Northwest Power Planning and Conservation Act in the 49 Fed. Reg. 23998
(1984). The notice presented BPA's interpretation of the statute,
incorporating principles of statutory construction, review of the
legislative history, and consideration of views expressed in a series of
informal meetings with interested persons and in comments received in
response to the publication of an earlier proposed legal interpretation.
The scope of the notice was limited to those issues that relied on the
statutory language or legislative intent for resolution.

Briefly, BPA interprets section 7(b)(2) as follows:

1\. The five-year rate test period will consist of the test year for the
relevant rate case plus the ensuing four years.

2\. Only the assumptions specified in section 7(b)(2) and the natural
consequences or secondary effects of those assumptions will be
considered to determine 7(b)(2) customers' power costs in the 7(b)(2)
case.

3\. The final program case power costs will be reduced by the applicable
section 7(g) costs (conservation, resource and conservation credits,
experimental resources, and uncontrollable events) chargeable to the
7(b)(2) customers for comparison with the section 7(b)(2) case power
costs.

4\. The DSI loads that are located within or adjacent to the service
areas of 7(b)(2) customers will be assumed, in the 7(b)(2) case, to be
served by those customers beginning July 1, 1985, unexpired DSI
contracts with BPA notwithstanding.

5\. The entire amount of DSI load included in the general requirements
of the 7(b)(2) customers will be assumed to be served as 100 percent
firm load in the 7(b)(2) case.

6\. Information contained in Appendix B to the Senate Report, S. Rep.
No. 272, 96th Congress, First Session (1979), will be used to identify
DSI loads within or adjacent to geographic service boundaries of public
bodies and cooperatives. The list will be adjusted to reflect changes in
the status of BPA service to the list of DSI customers as assumed in the
relevant rate case.

7\. To determine Federal base system resources not obligated to "other"
entities under existing contracts in the 7(b)(2) case, the DSI load
which is not within or adjacent to the service areas of preference
customers will be assumed to be served by investor-owned (private)
utilities only as the DSI power sales contracts with BPA expire.

8\. Three types of resources will be assumed to be available to serve
7(b)(2) customers' loads when the Federal base system (FBS) resources
are exhausted in the 7(b)(2) case: (a) the existing or planned resources
actually acquired by BPA from the 7(b)(2) customers in the relevant rate
case; (b) the existing resources owned or purchased by the 7(b)(2)
customers that are not dedicated to their own regional loads; and (c)
generic resources of whatever size required to serve the preference
customers' remaining load, at the average cost of all existing or
planned resources acquired by BPA from non-7(b)(2) customers during the
relevant five-year period. The resources listed in (a) and (b) will be
"stacked" in order of cost and assumed to be used as needed to meet
loads, least cost first. Should additional resources be needed to serve
7(b)(2) customers' loads, they will come from category (c).

**IV. The Program Case**

The program case is the five-year projection of power costs for serving
the general requirements of the 7(b)(2) customers conforming with all
the provisions of the Northwest Power Act, but without considering the
effects of section 7(b)(2). The program case will be developed as a
simulation of the BPA rate proposal results for the test year and a
projection of the rates for the ensuing four years based on the test
year rate proposal methodology and data. All the rate proposal
determinations, decisions and assumptions for the test year regarding
revenue requirements, loads, resources, cost allocation and rate design
will be input or modeled as accurately as possible. Input data for the
ensuing four years will be consistent with or extrapolated from test
year data. Ratemaking methodologies, such as those based on the
"post-85" rate directives in the Northwest Power Act and those used to
allocate costs and revenue adjustments to BPA customer classes, will be
unchanged over the five-year rate test period.

A load forecast is developed for every BPA rate proposal independent of
any requirements for implementing section 7(b)(2). It will include
estimates of BPA programmatic conservation savings for the forecast
period. This forecast will provide the load estimates for the program
case.

Regional resource generation studies are also conducted for BPA's rate
proposals. These studies determine the capability of BPA's and the
region's hydro and thermal resources. The results of these studies as
applied to the test year of the rate proposal will be used in the
program case as the basis for the full five-year period. The test year
results will be held constant except as modified to reflect the start of
commercial operation of generating resources beyond the test year and
for the planned effect or expiration of relevant contracts. Firm and
nonfirm hydroelectric generation will be based on these studies and
assumptions about the level of surplus firm power sales for the program
case will be the same as those made for the rate proposal.

BPA's repayment process will be simulated as closely as possible for the
determination of BPA revenue requirements over the five-year period.
Costs will be projected over the five-year period using budget
estimates, when available. Estimates of future inflation and real cost
escalation and planned additions to the BPA's power system will be used
when budget estimates are unavailable.

Finally, the methodologies for allocating costs and revenue adjustments
among BPA's customer classes used in BPA's rate proposal will be
modeled. These methodologies will be assumed to remain the same for the
five-year period.

The methodologies and data from the rate proposal cannot be described in
detail in this document. They are properly rate case determinations that
are outside the scope of the methodology for implementing section
7(b)(2). The section 7(b)(2) methodology must be flexible enough to
incorporate the methodologies and data from the rate proposal for which
the section 7(b)(2) rate test is being conducted. These methodologies
and data, as part of a BPA rate filing are, in turn, subject to review
and comment pursuant to section 7(1) of the Northwest Power Act. The
section 7(b)(2) methodology can require only that the rate proposal
methodologies and data be modeled or incorporated as accurately as
possible, which would be subject to examination during the section 7(i)
process for the rate proposal.

In summary, the program case will be BPA's best projection of its rates
without considering the effects of section 7(b)(2). The exact
methodology for the rate calculation in the program case cannot be
determined until BPA has prepared its rate proposal. However, the rate
test model will reflect the rate proposal methodology as completely as
possible in producing the program case when the rate test is conducted
for that rate proposal.

**V. The 7(b)(2) Case**

The language of section 7(b)(2) not only directs BPA to conduct a rate
test for the 7(b)(2) customers, but also provides a considerable amount
of direction as to how the rate test is to be conducted. BPA's legal
interpretation of section 7(b)(2) provides the general approach to
developing the 7(b)(2) case. Based on this, the 7(b)(2) case will be
modeled in the same way as the program case, except where section
7(b)(2) provides specific assumptions that modify the program case. The
modeling of these assumptions may lead to different results or natural
consequences from the underlying premises and ratemaking processes that
will be held constant between the two cases. The remainder of this
section outlines how the 7(b)(2) case rate projection for the five-year
test period will be developed.

**1. Load Forecast**

The initial loads that will be used in the 7(b)(2) case will be the same
as those used in the program case, except that they will not include
estimates of programmatic conservation savings. If the 7(b)(2) case rate
projection results differ significantly from the program case results,
the 7(b)(2) case rates may be used to generate a new load forecast using
the same demand models that were used to generate the rate proposal load
forecast. A new 7(b)(2) case rate projection would then be developed
with the new loads. The determination as to whether the rate projections
for the two cases differ significantly enough to warrant generating a
new load forecast, together with a determination as to the
administrative feasibility of performing a new load forecast, will be
made during the relevant rate case.

**2. DSI Loads**

DSI loads will be input to the rate test model on a plant-by-plant
basis. The plants will be flagged to indicate whether they are within or
adjacent to the service area of any 7(b)(2) customer based on the list
contained in Appendix B. If a DSI leaves the region or is no longer
served by BPA, its loads will not be assumed to transfer from BPA
service to utility service. Any DSI served by a utility other than BPA
in the program case will continue to be served by that utility in the
7(b)(2) case. However, if a DSI plant is forecast not to operate due to
economic conditions under the program case, but projected electric rates
are low enough under the 7(b)(2) case to allow a forecasted level of
operation, then the load associated with that level of plant operation
may be included in the 7(b)(2) case load forecast.

All "within or adjacent" DSI loads will be included in the general
requirements of the 7(b)(2) customers from the start of the five-year
period. DSI loads not "within or adjacent" will remain BPA loads until
their pre-Northwest Power Act power sales contracts would have expired,
at which time they are assumed to be served by private utilities. The
forecasted operating levels of the DSIs that are transferred to public
and private utilities are assumed to be served as 100 percent firm
loads. Those DSIs continuing to be served by BPA receive the same
quality of service as in the program case.

**3. Resources**

The residential and small farm power exchange is eliminated in the
7(b)(2) case. The FBS and any additional resources, as defined in
section 7(b)(2), are the only resources available to serve the general
requirements of the 7(b)(2) customers. However, the amount of FBS
resources available to serve the 7(b)(2) customers will be reduced by
any contractual obligations on these resources that were in existence
prior to passage of the Northwest Power Act. These contractual
obligations include the power sales contracts with those DSIs that are
not "within or adjacent," and the Washington Public Power Supply System
Nuclear Plant (WNP) No. 1 Hanford Exchange contract with the private
utilities. As these contracts expire, the amount of the FBS available to
serve the general requirements of the 7(b)(2) customers will increase.
As a result of this priority to FBS power, the projected rates
applicable to the pre-Northwest Power Act contracts could be lower than
the projected rates for the 7(b)(2) customers. Also, 7(b)(2) case
adjustments for reserve benefits that are discussed below would not be
allocated to the loads under those contracts.

If FBS resources, after meeting contractual obligations, are
insufficient to meet the general requirements of the 7(b)(2) customers,
then three types of additional resources can be added to serve those
loads. These additional resources are defined in section 7(b)(2) and
are: (a) actual and planned resource acquisitions by BPA from 7(b)(2)
customers consistent with the program case; (b) existing 7(b)(2)
customer resources not currently dedicated to their regional load; and
(c) generic resources at the average cost of actual and planned resource
acquisitions by BPA from non-7(b)(2) customers consistent with the
program case. These resources will include any conservation programs
undertaken or acquired by BPA. They will be assumed to come on-line to
meet the remaining general requirements of the 7(b)(2) customers after
FBS service in order of least cost first. The first two types of
resources will come on-line in discrete increments, reflecting the
actual size of the resource or the increment actually acquired by BPA.
The third type will be brought on-line in the exact amount required to
meet the 7(b)(2) customers general requirements, reflecting their
generic nature.

**4. Financing Benefits**

Section 7(b)(2)(E)(1) requires that BPA assume that quantifiable
monetary savings to 7(b)(2) customers resulting from reduced public
utility financing costs for the three types of non-FBS resources
described above were not achieved in the 7(b)(2) case. Therefore, any
additional resources required to serve the general requirements of
7(b)(2) customers will not reflect the financing cost reductions
implicit in resource acquisitions in the program case.

In order to quantify these financing cost reductions, BPA will contract
for the services of a financial consultant. If additional resources are,
required in the 7(b)(2) case, a list of these resources will be sent to
the consultant, containing cost and sponsor information for each
resource. For those resources actually acquired by BPA from the 7(b)(2)
customers under the program case, the consultant will estimate the
financing costs for the resource sponsor assuming that BPA had not
acquired the resource output. For those resources actually acquired by
BPA from non-7(b)(2) customers, a proxy public utility sponsorship will
be assumed for the resources. This public sponsorship will be assumed to
be a company formed for resource construction with ownership and
participation by all the region's public utilities in proportion to
their system loads. The consultant will estimate the financing costs of
the resources assuming BPA did not acquire the resource output and the
proxy public sponsorship described above. Finally, when detailed
financing cost and sponsor information is not available for planned
resources, the consultant will follow the same procedures, assuming the
proxy public sponsorship. Any reductions in financing costs determined
from this analysis will be included in the costs of the resource in the
7(b)(2) case.

For the 1985 rate case, BPA has contracted with Wertheim & Co., Inc.,
BPA's financial advisor, to conduct the financing benefits analysis.

**5. Reserve Benefits**

Section 7(b)(2)(E)(ii) requires BPA to assume that "...the quantifiable
monetary savings, during such five-year period, to the public body,
cooperative and Federal Agency customers resulting from reserve benefits
as a result of the Administrator's actions under this Act were not
achieved." Reserve benefits result from BPA's restriction rights on DSI
loads provided for in the DSIs' power sales contracts. The DSIs
currently receive a credit to their rate based on the value of the
reserves provided by these restriction rights. In the 7(b)(2) case,
these restriction rights are lost as the DSIs transfer to public and
private utilities and are assumed to be served as 100 percent firm
loads. Public and private utilities would have to incur the costs of
providing an equivalent amount of reserves from another source.
Therefore, it will be assumed that public utilities will incur a level
of costs based on the value of the reserves provided by the DSI
restriction rights as determined in BPA's rate proposal from those DSIs
that are within or adjacent to public utility service areas. The value
of reserves determination is currently based, in large part, on the cost
of an alternative reserve resource. If this methodology is continued,
the financing benefits for the construction of the reserve resource will
be determined by the financial consultant and included in the reserve
benefits determination. This will reflect the fact that the 7(b)(2)
customers would provide the reserve resource rather than BPA through its
acquisition authority under the Northwest Power Act. Also, if the level
of reserves provided by the DSI restriction rights, and on which the
value of reserves determination is based, is insufficient in the 7(b)(2)
case, based on BPA planning criteria, then additional reserve resources
will be added in the 7(b)(2) case.

**6. Surplus Firm and Nonfirm Sales**

The load and resource situation in the 7(b)(2) case will be considerably
different from that in the program case. The increase in the region's
firm load due to the 100 percent firm service to within or adjacent DSI
loads, a potentially different load forecast for the 7(b)(2) case, and a
potentially different set of resources all imply that a different level
of surplus firm power may be projected for the 7(b)(2) case than for the
program case. The level of surplus firm sales at fully allocated cost in
the 7(b)(2) case will be determined in the same manner as it is in the
program case. However, due to the potentially different forecasts of
available surplus firm power for the two cases, the level of assumed
surplus firm sale will be limited to the size of the projected surplus.
In addition, any sales of surplus firm power projected to be made in the
program case to serve the first quartile of DSI loads that are "within
or adjacent" will not be made in the 7(b)(2) case. Any surplus firm
costs that cannot be recovered from surplus sales at fully allocated
cost will be recovered from regional customers based on the resources
that comprise the surplus. Unrecovered FBS surplus costs will be
allocated to all loads served with FBS. Unrecovered additional resource
surplus costs will be allocated to the 7(b)(2) customers' general
requirements.

Nonfirm energy generation of the region's hydroelectric system will also
be assumed to be the same as in the program case. However, the nonfirm
energy markets will be adjusted in the 7(b)(2) case to reflect the
reduction in the size of the DSI first quartile and the potential change
in the amount of displaceable new resource generation.

**VI. Rate Test Computer Model**

Conducting the section 7(b)(2) rate test requires the use of a computer
model to develop the rate projections for the program case and the
7(b)(2) case. The exact form of the program case methodologies cannot be
determined until the time of the relevant rate case for which the rate
test is being conducted. The 7(b)(2) case is inextricably linked to the
program case as a result of the general approach applied to modeling the
7(b)(2) case. Therefore, the exact structure and form of the computer
model cannot-be specified as part of this methodology. However, a
computer model can be selected that will provide a flexible basis for
implementing the rate test during the relevant rate case. To this end,
BPA's Supply Pricing Model as modified by the PPC will be the base model
for implementing the section 7(b)(2) rate test in the 1985 BPA initial
rate Proposal.

**VII. Comparison of Projection Amounts**

For each of the two cases, program and 7(b)(2), the rate test model will
produce a projection of annual average energy rates for the five-year
rate test period. These two rate projections will be compared to
determine if a reallocation of costs pursuant to section 7(b)(3) is
required. The relevant rate projection for the comparison from the
program case is BPA's Priority Firm Power (PF) rate applicable to the
general requirements of the 7(b)(2) customers. The relevant rate
projection from the 7(b)(2) case is the per kilowatthour power costs of
serving the general requirements of the 7(c)(2) customers.

The PF rate in the program case will be developed in the same manner as
it is in BPA's rate proposal. The 7(b)(2) rate in the 7(b)(2) case will
include the costs of resources required to serve the 7(b)(2) customers,
along with all other costs and revenue adjustments not excluded by the
assumptions in section 7(b)(2). These costs and revenue adjustments
include BPA's administrative and general costs, fixed rate contract
revenue deficiencies, and surplus firm power revenue deficiencies.

Prior to comparison with the 7(b)(2) rates from the 7(b)(2) case, the
projected PF rates from the program case will be reduced by the
applicable section 7(g) costs listed in section 7(b)(2) that were
included in the PF rate projection. All the costs of BPA conservation
programs, billing credits, experimental resources, and uncontrollable
events that were allocated to the PF rate will be subtracted. This
reduced PF rate projection will then be compared to the 7(b)(2) rate
projection to determine, if the 7(b)(2) rate projection is lower, on
average, than the program case projection.

The comparison between the program case and the 7(b)(2) case rate
projections is conducted for a five-year period and should consider the
time value of money. Therefore, the two projections will be discounted
back to the test year of the relevant rate case at BPA's projected
future borrowing rate, and averaged over the five years. The discounted
average will be rounded to the nearest tenth of a mill. If the average
of the five years of discounted 7(b)(2) rates is less than that of the
PF rates, then the determination of an amount of costs to be reallocated
in BPA's rate proposal is required.

**VIII. Determination of Test Year Amount**

If it is determined that the results of the rate test require a
reallocation of costs for BPA's rate proposal, then the amount to be
credited to the 7(b)(2) customers and reallocated to BPA's other
customers must be calculated. This credit reflects the fact that it is a
one-year adjustment that is based on a five-year determination, and also
reflects the comparison method used to determine the need for the
credit. The credit will be based on the five-year average of the
difference between the net discounted rate projections for the two
cases. This average difference will be multiplied by the general
requirements of the 7(b)(2) customers for the rate proposal test year to
determine the reduction in the 7(b)(2) customers' test year costs.

**IX. Conclusion**

The section 7(b)(2) rate test, up to and including the point at which
the test year amount is determined, is conducted outside the mainstream
of BPA's rate development process. While the rate test reflects the
assumptions used in the rate proposal, the rate test has no impact on
BPA rates until the test year amount is included in BPA's rate design.
At this point, any adjustment made to reflect the rate test results in
BPA rates must be done within the overall framework of the rate
development process and of BPA's ratemaking objectives and statutory
requirements. Therefore, the section 7(b)(2) rate test will be conducted
and a test year amount determined as outlined in section 7(b)(2). The
test year amount will then be included as a step in BPA's rate design
process, consistent with other statutory provisions and BPA's ratemaking
objectives.

[^1]: Western Area Power Administration filed a request to withdraw as a
    party but remain as a participant; this request was granted on June
    4, 1984.

[^2]: The written testimony and exhibits of BPA's third witness (John
    Carr) were later adopted and sponsored by one of its other two
    witnesses (Shirley Melton).

[^3]: The methodology adopted herein will be first applied In the 1985
    rate case, and will become final only after BPA's rate proposals are
    confirmed and approved by the Federal Energy Regulatory Commission.
    15 U.S.C. 839e(a)(2); *Central Lincoln Peoples' Util. Dist. v.
    Johnson*, No. 81-7622 *et al.*, slip op. at 11 (9th Cir. Feb 9,
    1984) \[hereafter *Central Lincoln II*\]; *Public Power Council v.
    Johnson*, No. 84-248-PA, slip op. D. Ore. May 15, 1984).

[^4]: BPA's legal interpretation is not subject to this hearing.

[^5]: Section 7(b)(2) also requires that the program case amount be
    reduced by certain 7(g) costs before it ("net program case amount")
    is compared with the second number. *See* BPA Legal Interpretation,
    49 Fed. Reg. 23998, 24002 (June 8, 1984).

[^6]: It appears that one party in this proceeding, the DSIs, may have
    misunderstood the way in which the rate test operates to lower the
    7(b)(2) customers' rates. Two of the DSI briefs indicate that BPA is
    to charge the 7(b)(2) customers the lower of the program case amount
    or the 7(b)(2) case amount. DSI Opening Brief, Ex. P-DS-01, 1; DSI
    Post-Hearing Brief, Ex. B-DS-01; 1, 14.

[^7]: In addition to the post-hearing brief references cited in the
    Tentative Decision at 3, *see* *also* PPC Reply Brief, Ex. R-PP-01,
    11 and 15; and APAC Reply Brief, Ex. R-PA-01, 9-10 (recognition of
    natural consequences). The issue of "double counting" certain
    section 7(g) costs is treated below.

[^8]: The types of additional resources are described in section
    7(b)(2)(D): a type 1, planned or existing resources, owned by
    7(b)(2) customers, acquired by BPA in the five year rate test
    period; type 2, existing resources, owned by 7(b)(2) customers,
    which are not committed to those customers' loads; and type 3,
    planned or existing resources owned by non-7(b)(2) customers,
    acquired by BPA in the five year rate test period. Type 2 resources
    will not require a financing benefits analysis because they are
    already fully constructed and financed.

[^9]: The suggestions that follow were not offered for adoption as
    secondary effects, *see* Spettel, PGP, TR 1145-1146; they were
    offered to show that the natural consequences proposed by BPA are
    "arbitrary". PPC Reply Brief, Ex. R-PP-01, 11-12.

[^10]: Direct Service Industries, Inc., neither petitioned for nor
    received party status. Rather, individual members of the association
    were granted party status, but for convenience, they are
    collectively referred to as the DSIs. The individual parties are:
    Aluminum Company of America; Arco Metals Company; The Carborundum
    Company; Georgia-Pacific Corporation; Martin Marietta Aluminum,
    Inc.; Oregon Metallurgical Corporation; Pacific Carbide and Alloys
    Company; Pennwalt Corporation; and Reynolds Metals Company.

[^11]: The Intercompany Pool neither petitioned for nor received party
    status. For convenience, Portland General Electric Company, Puget
    Sound Power and Light Company, Pacific Power & Light Company,
    Washington Water Power Company and Montana Power Company are
    referred to as the ICP.

[^12]: The Public Generating Pool was granted party status, as were
    certain of its members: Public Utility District No. 1 of Chelan
    County; Central Lincoln People's Utility District; Clatskanie
    People's Utility District; Tillamook People's Utility District;
    Eugene Water and Electric Board; City of Seattle; and City of
    Tacoma.

[^13]: Withdrew as a party on June 4, 1984.

[^14]: The Western Washington Public Utility Districts was granted party
    status, as were certain of its members: Clallam County Public
    Utility District; Clark County Public Utility District; Lewis County
    Public Utility District; Grays Harbor Public Utility District; Mason
    Public Utility District No. 1; Mason Public Utility District No. 3;
    Pacific County Public Utility District No. 3; Pacific County Public
    Utility District; and Snohomish County Public Utility District.