UNITED STATES OF AMERICA

U.S. DEPARTMENT OF ENERGY

BEFORE THE

BONNEVILLE POWER ADMINISTRATION

Proposed Safety-Net Cost Recovery )

Adjustment Clause Adjustment to ) BPA Docket No.: SN-03

2002 Wholesale Power Rates )

DIRECT TESTIMONY

OF THE

JOINT CUSTOMERS

Alcoa, Inc. (AL), Golden Northwest Aluminum, Inc. (GN), Idaho Energy
Authority, Inc. (ID), Industrial Customers of Northwest Utilities (IN),
Northwest Requirements Utilities (NR), Pacific Northwest Generating
Cooperative (PN), and Public Power Council (PP)

WITNESSES:

Raymond D. Bliven

Geoffrey H. Carr

Kevin P. O'Meara

Lincoln Wolverton

Denise Peterson

Senior Counsel

Public Power Council

1500 NE Irving Street, Suite 200

Portland, OR 97232

Phone: (503) 232-2427

Fax: (503) 239-5959

Email: <denisep@ppcpdx.org>

Attorney for the

PUBLIC POWER COUNCIL

April 18, 2003

INDEX

TESTIMONY OF:

RAYMOND D. BLIVEN

GEOFFREY H. CARR

KEVIN P. O'MEARA

LINCOLN WOLVERTON

WITNESSES FOR:

JOINT CUSTOMERS

SUBJECT: [TECHNICAL RESPONSE TO BPA'S SN CRAC PROPOSAL]{.underline}

# Page

Section 1: Introduction and Purpose of
Testimony.........................................1

Section 2: Revenue Requirements and Revenue
Enhancements..........................2

Section 3: BPA's SN CRAC Proposal and BPA's
Incentives...........................21

Section 4: BPA's Secondary Revenue
Forecast...........................................28

## SUBJECT: TECHNICAL RESPONSE TO BPA'S SN CRAC PROPOSAL

## Section 1: Introduction and Purpose of Testimony

Q. Please state your name and qualifications.

A. My name is Raymond D. Bliven. My qualifications are contained in
SN-03-Q-JC-01.

A. My name is Geoffrey H. Carr. My qualifications are contained in
SN-03-Q-JC-02.

A. My name is Kevin P. O'Meara. My qualifications are contained in
SN-03-Q-JC-03.

A. My name is Lincoln Wolverton. My qualifications are contained in
SN-03-Q-IN-02.

*Q. What is the purpose of this section of testimony?*

A. To comment on the technical aspects of BPA's SN CRAC proposal and to
indicate solutions superior to BPA's SN CRAC proposal.

Q. Please summarize your testimony on this issue.

A. This testimony is broken into three parts. The first section asserts
that the Joint Customers have identified a number of areas where BPA
could reduce its costs and enhance its revenues. This would improve
BPA's net revenue situation, which would allow BPA to meet a high
standard of repayment probability without an SN CRAC. The Joint
Customers have done extensive analysis that supports this assertion. We
believe that given current conditions, BPA can use a variety of tools
and sources of funds to avoid implementing an SN CRAC in 2004.

The second section explains why BPA should consider whether to have an
SN CRAC on an annual basis rather than have a multi-year SN CRAC.

The third and final section concludes that the calculations of
forecasted secondary revenue BPA uses in its SN CRAC analysis are based
on a dated version of the AURORA model and an equally dated and
erroneous version of the inputs to AURORA. The combined effect is a
flawed forecast that should not be relied upon to impose a multi-year SN
CRAC.

*Q. How is your testimony organized?*

A. Section 1 is this introduction. Section 2 discusses Revenue
Requirements and Revenue Enhancements. Section 3 focuses on BPA's SN
CRAC Proposal and BPA's Incentives. Finally, Section 4 comments on BPA's
Secondary Revenue Forecast.

**Section 2. Revenue Requirements and Revenue Enhancements**

**2.1 2001 GRSP Provisions related to the SN CRAC**

Q. What do the General Rate Schedule Provisions (GRSPs) say with regard
to cost management in the context of triggering the Safety Net CRAC?

A. The GRSPs say: \"In determining which proposal to include in its
initial proposal in the SN CRAC 7(i) proceeding, BPA will give priority
to prudent cost management and other options that enhance Treasury
Payment Probability while minimizing changes to the FB CRAC.\" 
(WP-02-A-09, Appendix, pages 25 and 26).

Q. *What does this requirement mean to you?*

A. This requirement means that BPA must reduce its costs and use cash
tools to increase the probability of making its U.S. Treasury payments
in a prudent manner so as to minimize the rate increases that may come
as a result of changes to the FB CRAC. The term FB CRAC is used in the
GRSPs because the SN CRAC is a modification of the FB CRAC parameters.
Cash tools include the use of borrowing for long-lived assets, where
appropriate. It is not clear that BPA has done this. Cash tools could
also include the use of ENW refinancing proceeds as described below.

*Q. Has BPA conformed to this requirement?*

A. No, not fully. While BPA has recently reduced the rate at which
spending is increasing, its spending is still far above the levels
assumed and included in BPA's May 2000 and June 2001 base rates. Also,
the spending that BPA has assumed and included in its SN CRAC proposal
for 2003 through 2006 is significantly higher than 2001 actual costs. In
addition, BPA has significant cash tools at its disposal that could be
used to minimize the size of the SN CRAC. Not all of these cash tools
are being used. As a result, we believe that BPA can undertake further
prudent spending reductions and cash management actions to eliminate the
need for an SN CRAC or minimize any SN CRAC rate increase.

**2.2 Development of Costs for May 2000 and June 2001 rates**

*Q. How were costs set for May 2000 and June 2001 base rates?*

A. The Comprehensive Review of the Northwest Energy System Final Report
(1996) contained recommendations that called on BPA to "pursue all
actions possible in the short term to cut costs." These were seen as
essential in making the proposed Subscription-based system for marketing
federal power successful. In 1996, in order to implement this
recommendation, BPA and the Northwest Power Planning Council conducted a
review of the Federal Columbia River Power System (FCRPS) costs. The
Cost Review panel, made up of five executives with experience in
managing large organizations undergoing competitive transitions, focused
on power and transmission costs. The outcome of the review was a
recommended \$137 million in annual cost reductions in each of
FY2002-2006 for the generation function. (BPA-02-FS-BPA-02, page A-24).

In October 1998, BPA released the "Cost Review Implementation Plan" as
part of its Issues '98 process.

On December 21, 1998, BPA issued the Subscription Record of Decision
that contained four principal goals. The second of BPA's principal goals
states:

> "To avoid rate increases through a creative and business-like response
> to markets and additional aggressive cost reductions." (WP-02-A-02,
> Page 2-2).

The Cost Review panel's findings were then used in the revenue
requirement study to establish the May 2000 rates. As such, in May 2000,
BPA issued its Record of Decision on the 2002 Final Power Rate Proposal
in which the issue of program costs was addressed. BPA's decision was:

> "The spending levels included in revenue requirements are consistent
> with commitments made by BPA in the Cost Review and Issues '98 for
> FY2002-2006, including any cost revisions necessary to incorporate the
> results of the Subscription Strategy, the Principles, and changes
> resulting from the revenue requirement and rate development process."
> (WP-02-A-02, Page 5-7).

Rates were reviewed again prior to their effective date to evaluate the
impact of the 2000-2001 power price crisis on BPA's loads and costs.
However, BPA did not raise the issue of program cost assumptions in the
Supplemental Power Rate Proposal (June 2001) proceeding, and the revenue
requirement assumptions for program costs remained unchanged from the
decisions reached in May 2000 in the WP-02 rate proceeding. (WP-02-A-09,
page 1-16).

Throughout these various processes BPA had the opportunity to change the
costs that went into the May 2000 rates, and adjustments were made to
these costs in some cases. In addition, the base rates reflected BPA's
assessment of the risks of over-running these costs levels. As a result,
the customers were willing to rely on these estimates.

**2.3 BPA Cost Increases from 2000 rates**

Q. How does the revenue requirement used in the May 2000 rate case
compare to the costs that BPA is using for the SN CRAC case?

A. The expenses that BPA currently forecasts are about \$669 million per
year higher than those used in the revenue requirement for the May 2000
rate case for FY2004 through FY2006. Total expenses in the SN-03 case
are \$3.04 billion on average per year for each year, FY 2004 through
2006 (SN-03-E-BPA-01, page 3-24). The average revenue requirement for FY
2004 through 2006 in the May 2000 rates was \$2.37 billion per year
(BPA-02-FS-BPA-02, page 51). In total, spending levels in the SN-03 rate
proposal compared to May 2000 rates are \$2.0 billion higher over the FY
2004 to 2006 period. (SN-03-E-BPA-06, page 2, line 21, after errata).

*Q. What are the major drivers of cost increases from BPA's 2000 and
2001 rate case cost projections compared to BPA's current cost
projections?*

A. The major drivers for BPA's cost increases, when the costs in the May
2000 rates are compared to BPA's current forecasted expenses, are
related to augmentation power purchases and investor-owned utility buy
backs, load reduction costs, including the cost of the litigation
premium and increased IOU settlement costs. Taken together, these costs
total about \$952 million per year on average in years 2002 through
2006. (SN-03-E-BPA-02, lines 46 and 50). These costs tend to be fixed in
nature and can only be reduced through the re-negotiation of existing
contracts; as such they are not highly "controllable" by BPA. However,
these costs are already being recovered largely through existing rate
mechanisms such as the LB and FB CRACs.

Q. Does BPA have other costs that are more controllable than
augmentation power purchases, investor-owned utility buy backs, and load
reduction costs?

A. Yes.

Q. What are the more controllable costs, and how do the rate case
estimates of these costs compare to BPA's forecasted costs for the rest
of the rate period?

A. We analyzed BPA's Program Costs as established in the (May 2000) rate
case and compared them to BPA's current 2003 through 2006 cost
forecasts. (See response to SP-BPA: 01, included as SN-03-E-JC-01A)
BPA's Program Costs include the Agency's own Internal Program costs,
corporate overhead costs, Corps and Bureau costs, Energy Northwest costs
and other generating costs (not including renewables). Also included
here are BPA's Fish and Wildlife costs and costs associated with BPA's
conservation program. Not included are BPA's debt service costs,
depreciation expense and other entities' debt service costs. In
addition, augmentation costs, load buy-down costs, and IOU financial
benefits costs are not included in this analysis.

When the BPA Program costs included in May 2000 rates are compared to
BPA's current Program Cost forecasts, even after the reductions that
were made as a result of the Financial Choices process last year, major
cost increases are obvious. For the categories described above,
SN-03-E-JC-01B shows that there is an average 29 percent increase in
costs, or \$183 million per year on average, when 2003 through 2006
program costs of \$624 million in the May 2000 rates are compared to the
now forecasted program costs of \$807 for the same period.

*Q. What are the key drivers of BPA's Program Cost increases?*

A. When BPA's forecasted spending levels are compared to May 2000 rate
case estimates, the key areas of increase for more controllable costs
are Columbia Generating Station (CGS) costs, Corps and Bureau costs,
Power Business Line Operations expense, and Shared Services and
Corporate General and Administrative expense. Of the \$696 million per
year average increase in total expenses from the May 2000 rate case to
current projections for 2003 to 2006, \$171 million average per year is
related to increases in these four areas. These cost increases run from
28 percent (for CGS and Corps and Bureau costs) to 174 percent higher
(for Corporate G&A and Shared Service expense) than the costs used to
develop the May 2000 rates. In total, over four years from 2003 to 2006,
forecasted costs in these four categories are \$685 million higher than
was assumed for these categories when the rates were established in May
2000 and re-affirmed in June 2001. A graph showing the cumulative effect
of these increases over 2003 to 2006 compared to the 2000 rate case is
included as SN-03-E-JC-01C.

Q. Why is it important to compare 2001 actual costs to BPA's forecasted
costs for the rest of the rate period?

A. BPA's actual 2001 cost data can be instructive in showing what costs
were actually being incurred at that time, and what costs can be
expected to be incurred in the near future.

Q. When BPA's forecasted costs are compared to 2001 actual costs, what
are the key drivers for BPA's cost increases?

A. For the more controllable cost areas described above, forecasted
costs for 2003 to 2006 are above 2001 actual costs by about \$127
million per year on average. This represents an average 19 percent
increase in costs from actual 2001 program costs (\$680 million) to
forecasted program costs for 2003 to 2006 (\$807 million). (See
SN-03-E-JC-01B.) Fish and wildlife program costs are significantly above
2001 actuals. As well, Columbia Generating Station costs, other
long-term generating projects, Corps and Bureau costs, Support services,
Corporate G&A expense and Power Business Line operations expense are
other key drivers of BPA's cost increases. A graph showing the effect of
these increases over 2003 to 2006 is included as SN-03-E-JC-01D. These
data were also derived from the BPA response to data request SP-BPA: 01,
which is included as SN-03-E-JC-01A.

*Q. What are the rate implications of these cost increases?*

A. A \$183 million average increase in BPA's 2003-06 more controllable
costs, when compared to the May 2000 base rates, leads to upward
pressure on the SN CRAC of 3.6 mills per kWh on the PF rate. Compared to
the May 2000 base rate of 22 mills, this represents a 16.5% increase, or
more than half of the estimated average SN CRAC presented in BPA's
Initial Proposal of 30% per year for the rest of the rate period.

**2.4 Recommendations for Cost Reductions Consistent with Decisions Made
in Financial Choices**

Q. Please describe the development of the recommendations you are making
in order to eliminate or minimize the size of the SN CRAC.

A. The Joint Customers participated in BPA's Financial Choices process
last year and made a series of recommendations at that time. Some of our
recommendations were incorporated into BPA's final result from that
process, but many were not. In this testimony we are not revisiting the
BPA decisions as described in the Financial Choices closeout letter of
November 22, 2002 (included as SN-03-E-JC-01E). Rather, this proposal
relies on the Financial Choices findings, as well as recently evolving
information from the Agency, particularly regarding secondary energy
revenues, to demonstrate that BPA can avoid or minimize the need for an
SN CRAC at this time by vigorously pursuing opportunities for spending
reductions and financial management tools highlighted in the Financial
Choices process. In other words, decisions need to be made by the
Administrator in addition to those made in Financial Choices, consistent
with the explicit provisions of the GRSPs, cited above.

Our proposal has the following seven elements, a combination of which
can achieve the recommended Joint Customer goal:

1.  BPA's SN CRAC analysis should assume recovery of ENW bearer bonds.

2.  BPA's SN CRAC analysis should assume an increase in spot market net
    revenue assumptions due to higher run-off projections during this
    fiscal year.

3.  BPA should assume all cost cuts identified as a result of Financial
    Choices.

4.  BPA could assume, and its SN CRAC analysis could reflect, deferrals
    and/or reductions of financial payments to the investor-owned
    utilities, pursuant to an overall settlement of matters related to
    litigation.

5.  BPA's SN CRAC analysis, and determination of LB CRAC, could reflect
    removal of the litigation payment premium due the IOUs, assuming the
    settlement of litigation with the IOUs.

6.  BPA could use a portion of the Energy Northwest refinancing proceeds
    as a reserve of last resort to ensure Treasury repayment. An
    alternative approach could be to use all of the refinancing revenues
    that were, and are, to be obtained, in the 2001 through 2003 ENW
    refinancings.

7.  BPA should amortize the amounts borrowed for Conservation
    Augmentation over 20 years, as opposed to the shorter 10-year period
    assumed in the Initial Proposal.

    *Q. Please describe the recovered ENW bearer bond revenues.*

A. In SN-03-E-BPA-01, page 9, lines 9 and 10, BPA staff note "ENW
pursued and won a \$23 million settlement with the Bank of America for
the Bank's role as paying agent on certain BPA-backed bearer bonds. ENW
plans to provide these settlement proceeds to BPA." These revenues are
not yet reflected in BPA's revenue requirement or toolkit runs, but
should be.

*Q. How will increased run-off forecasts affect BPA's revenues?*

A. The Safety Net CRAC Initial Proposal is based on an assumption of 75
MAF (million acre feet) run-off from the Northwest River Forecast Center
(SN-05-E-BPA-05, page 8, line 5 to 7). The latest April 8^th^ forecast
is for 85.3 MAF at The Dalles.
[www.nwrfc.noaa.gov/water_supply/ws_fcst.cgi](http://www.nwrfc.noaa.gov/water_supply/ws_fcst.cgi).
Using a rule of thumb that each MAF will yield \$10 million to BPA
(verified in the clarification session with BPA on 4/2/03), this
translates into \$103 million more in revenues in 2003 if the 85.3 MAF
figure is sustained.

*Q. What is your recommendation regarding these increased revenues?*

A. We recommend that BPA include the latest projection of run-off
available when doing the final calculations in considering the size of
any SN CRAC.

Q. Please describe the cost cuts identified in Financial Choices that
are not yet but should be included in BPA's SN CRAC analysis.

A. In SN-03-E-BPA-04, page 9, lines 25 and 26, BPA staff noted
"\[a\]pproximately \$20 million of cost reductions were inadvertently
omitted but will be reflected in the final proposal." These cost
reductions are not yet in BPA's toolkit runs, but will be in the Final
Proposal.

We believe that this inadvertently omitted cost reduction is the result
of BPA's commitment to reduce average 2003 to 2006 internal operating
expenses, G&A expense and shared services to the 2001 level of \$136
million. (See response to SP-BPA: 01, lines 31 and 35, included as
SN-03-E-JC-01A.) This commitment was stated in the November 22, 2002
Financial Choices close out letter (SN-03-E-JC-01E), on page 5, as
follows: "These and other savings will keep BPA's annual power-related
internal costs to around 2001 levels through 2006."

*Q. Should this commitment include consideration of revenue offsets?*

A. No mention is made in this document of revenue offsets. Therefore, we
recommend that BPA plan to achieve 2001 spending levels in 2003 through
2006 before (that is without) consideration of revenue offsets.

Q. How do 2001 spending levels compare to 2003 through 2006 levels, and
how should spending be reduced to get to the 2001 commitment level?

A. The most recent PBL summary of spending indicates that the
combination of internal operating, G&A and shared services costs for
2003 through 2006 is \$147 million per year, on average.
(SN-03-E-BPA-02, lines 30 and 35 for 2003 to 2006). Over four years the
difference between these amounts (\$147 million minus \$136 million) is
a total of \$44 million. This suggests that a reduction of \$24 million
in addition to the \$20 million in "reductions inadvertently omitted" is
necessary to achieve the 2001 commitment. Therefore, a further reduction
of \$6 million per year, in addition to the \$5 million per year BPA
identified, should be made to BPA's revenue requirement in FY 2003 to
2006.

Q. Please describe your understanding of further savings identified as a
result of Financial Choices.

A. In the November 22^nd^ Financial Choices closeout letter, BPA
Administrator Steven Wright identified two sources of savings. The first
\$350 million is related to savings in projected cost increases over the
rate period that BPA is relatively sure of being able to obtain. These
are expense savings, deferrals and other actions. Examples include
reductions to BPA's internal operations costs, conservation
augmentation, Corps and Bureau cost and CGS costs. These savings, with
the exception of the full amount of Internal Operations, G&A and support
services savings described above, are included as cost reductions in
BPA's SN CRAC Initial Proposal. However, these savings are not
sufficient to prevent the SN CRAC from triggering at an average rate of
30 percent over the next three years under BPA's proposal.
SN-03-E-JC-01F, lines 2 and 3, shows the application of these savings to
BPA's \$1.2 billion FY 2002 to 2006 net revenue gap.

The second source of savings of \$580 million is from actions that BPA
is currently pursuing. These are costs imposed on BPA by other entities
and thus require the action and/or renegotiation of contracts and
agreements by these other entities. Examples of these savings include
ENW and Corps and Bureau costs, power purchase contract re-negotiation,
debt service reductions and reductions to Fish and wildlife costs, among
others. Of this total, \$80 million in Fish and Wildlife Program cost
savings are classified by BPA as "achieved or close." These "Additional
Actions" are shown on SN-03-E-JC-01F, lines 5 through 10.

Q. What is your recommendation regarding the incorporation of further
savings identified as a result of Financial Choices?

A. We recommend that BPA proceed with these further cost reductions
identified in its Financial Choices process. We also commit to working
with BPA to achieve these cost reductions. Along with this commitment we
propose that BPA incorporate these savings into its revenue requirement
for this proceeding.

Q. How should these savings be incorporated into BPA's revenue
requirement for FY 2003 through 2006?

A. Of the \$500 million in savings not already achieved, \$300 million
is related to costs other than the Settlement of Litigation over IOU
Residential Benefits (SN-03-E-JC-01F, line 10 minus line 5). Recognizing
that these cost savings will take time to ramp in, we recommend, in Case
1 described below (see also SN-03-E-JC-01J), that \$40 million of these
cost savings be included in BPA's revenue requirement for FY 2003, \$80
million in FY 2004 and \$90 million in each of FY 2005 and 2006. Case 2,
also described below, ramps in savings as well, but achieves \$40
million less in savings over the four-year period than Case 1.

*Q. Please describe your recommendations concerning IOU financial
benefits.*

A. In response to BPA's financial difficulties, the investor-owned
utilities have already agreed to defer out of this rate period \$55
million in financial benefits that they could receive in FY 2003. They
have also previously expressed an interest in offering to BPA to defer
benefits in 2004, 2005 and 2006 at the same level: \$55 million per
year. The initial Joint Customer proposal to BPA incorporated the \$55
million for the FY 04 -- 06 period as part of a package to demonstrate
that an SN CRAC was not needed in 2004.

Currently the issues surrounding IOU deferrals or reductions of benefits
during the remainder of the rate period are under negotiation between
IOUs and public power, with the active participation of BPA staff. For
purposes of this testimony, with the exception of Case 3 below, it is
assumed that \$55 million per year of IOU current benefits is removed
from the FY 04 -- 06 period, pursuant to an overall settlement of
litigation. We recommend that BPA incorporate the final results of
current negotiations regarding the restructuring of IOU residential
benefits into the SN CRAC process. This assumes successful completion of
such negotiations and approval by all parties prior to the date by which
the Administrator must make a final decision regarding the level of the
SN CRAC, if implemented.

*Q. Please describe your recommendations concerning the "litigation
premium."*

A. Settlement discussions between public power and the investor-owned
utilities regarding the litigation over residential benefits are also
ongoing. The IOUs have previously agreed to defer collection of the
initial \$50 million in "litigation premium" payments out of 2003. As a
result, absent a settlement of litigation, \$67 million per year is
assumed to be collected by BPA in FY 2004, 2005 and 2006 to cover the
four year cost of the litigation premium in the remaining three years of
the current rate period. This "litigation premium" is collected through
the LB CRAC. We recommend that the Agency make a final determination
regarding the size of the LB CRAC that incorporates the results of the
litigation negotiations. Cases 1 and 2 below remove the litigation
premium, while Case 3 assumes that the litigation premium stays in
place.

Q. Please describe your recommendations concerning the "last resort" use
of ENW refinancing proceeds.

A. In 2003 BPA will have \$315 million in income available as a result
of the 2001, 2002 and 2003 ENW debt restructuring program. BPA intends
to use this income to accelerate amortization of existing BPA U.S.
Treasury debt. However, through an agreement with ENW, these funds can
be used by BPA for other purposes in cases of "extreme financial
pressure." (See SN-03-E-JC-01G.) BPA has developed no criteria for
determining "extreme financial pressure." (See response to CA-BPA-10.)
We assert, however, that BPA is under extreme financial pressure given
the extent of recent rate increases and its proposal for further rate
increases.

As a result of the existing extreme financial pressure, we propose that
a portion of these proceeds be held as a reserve of last resort to make
scheduled amortization payments, should the actions described above, or
other actions, not be sufficient to assure Treasury payment. This
restricted usage would only be for the current rate period and funds
would be repaid in full by the end of the rate period. We recognize that
such use of the ENW refinancing program would probably require the
concurrence of the ENW board in order to not imperil future ENW
refinancings. In Cases 1 and 2 below, ENW refinancing proceeds are held
in reserve at \$100 million and \$150 million and, if used to meet
scheduled repayment requirements, repaid in 2006 to show the impact on
Treasury payment probability, for each year.

*Q. Please describe the proposal in Case 3 below that would have BPA use
all of the refinancing revenues that were and, are to be obtained, in
the 2001 through 2003 ENW refinancings*.

A. In Case 3 below, BPA would retain all of the proceeds of ENW debt
restructuring for 2002 through 2006 that occurred or will occur as a
result of the 2001 though 2003 refinancing programs. This would yield
\$581 million in 2003, \$55 million in 2004, \$40 million in 2005 and
\$60 million in 2006. The use of these refinancing proceeds would not be
recovered and paid to the US Treasury for advanced amortization at the
end of the rate period as is assumed in Cases 1 and 2. These funds would
be repaid in future rate periods. This case results in a higher TPP for
2006, but also in higher repayment obligations in the future than if the
funds were used to make advanced amortization payments. Also, interest
expense would increase in 2004 through 2006 by about \$35 million per
year because \$736 million of BPA's debt would not be advance amortized.
(SN-03-E-JC-01H provides the year-by-year availability of ENW debt
restructuring funds).

*Q. Please describe your proposal regarding Conservation Augmentation
financing.*

A. BPA should amortize the amounts borrowed for Conservation
Augmentation over 20 years, as opposed to the shorter 10-year period
assumed in the Initial Proposal.

*Q. Why should BPA do this?*

A. Conservation is an asset that will provide BPA and the region
benefits over the long term. Normally, BPA conservation bonds are 20
years in length, reflecting the life of the asset. Financing an asset
over its useful life spreads the cost recovery for the asset over those
who benefit from the asset. In addition, by financing these ConAug
capital investments over 20 years, BPA will save an average of \$8.4
million from 2003 though 2006. SN-03-E-JC-01I, BPA's response to
NR-BPA:001, provides the data for this analysis.

**2.5 Summary of Findings**

*Q. Please summarize the cost cut/revenue enhancement scenarios that you
have developed*.

A. SN-03-E-JC-01J provides a summary of our findings. Three cases are
displayed on SN-03-E-JC-01J. Case 1 assumes limited use for a repayment
reserve of \$100 million of the \$315 million in ENW refinancing
proceeds in 2003 with Treasury repayment of the \$100 million in 2006.
Full realization of the \$300 million in further Financial Choices cost
reductions is assumed in this case. In addition, the revenues from ENW
bearer bonds, revenues from higher stream flows, BPA internal cost cuts,
and IOU benefit savings and removal of the litigation penalty are
assumed in the case. Case 2 is the same as Case 1, except that use of
ENW proceeds is limited to \$150 million and further cost cuts are
assumed to achieve \$40 million less savings than in Case 1. Case 2 also
assumes that the litigation premium continues to be paid to the IOUs
through the rate period.

As described above, Case 3 uses all of the proceeds of ENW debt
restructuring for 2002 through 2006 that occurred or will occur as a
result of the 2001 though 2003 refinancing programs. This case also
assumes the availability of funds from the ENW bearer bonds, higher
streamflows in 2003 than in BPA's Initial Proposal, \$44 million in
spending reductions for internal operations and corporate overheads and
the ConAug amortization savings. No further cost cuts are assumed under
this approach or any further reductions to IOU benefits or removal of
the litigation premium.

*Q. Please summarize your findings.*

A. As shown on SN-03-E-JC-01J, all three scenarios meet high standards
of repayment probability in each year of the rate period (greater than
56% in each year and greater than 56% over the four year period) and
provide ending reserves well above \$100 million in each year of the
rate period. We believe that given current conditions, BPA can use a
variety of tools and sources of funds, as shown here, to avoid
implementing an SN CRAC in 2004, and can consider FY 05 and FY 06 on a
case-by-case basis once better information is available.

Q. What Toolkit Net Revenue to Cash Adjustments were assumed in the
toolkit runs that you used to produce these results?

A. In response to data request, NR-BPA:02, we were provided with a
revised Toolkit Net Revenue to Cash Adjustments assuming the 2003 ENW
refinancing. This forecast was used in our Toolkit runs, and it is
provided as SN-03-E-JC-01K.

Q. In Cases 1 and 2 below, what is the effect of availability of ENW
proceeds as a reserve of last resort?

A. In Cases 1 and 2, the availability of the ENW revenues as a reserve
increases the overall TPP by 3 percent in Case 1, and 5 percent in Case
2.

*Q. Are you recommending any of the approaches outlined in Cases 1
through 3?*

A. No. Since different groups of customers have different perspectives
on the actions that BPA needs to take to eliminate or minimize the size
of the SN CRAC, we provide only the technical work for those policy
panels to make their own recommendations. That is, we provide a menu and
estimate the impacts of options and sources of funds for BPA without a
policy recommendation as to which should be used.

Q. BPA in its testimony says that it "is going to pursue additional
savings, but will not reflect them in the SN CRAC proposal until there
is a high degree of certainty that they will be achieved."
(SN-03-E-BPA-04, page 10, lines 2 and 3). Why do you disagree with this
approach?

A. The SN CRAC, as BPA has proposed it, is a 3-year adjustment clause
that will trigger to collect funds to cover BPA's increased costs,
whatever they may be. There is no limit on rate increases in the future
because BPA has retained the right to "re-trigger" the SN-CRAC in 2004
and 2005, leading to even higher rate increases in FY05 and FY06 than
the cap in the SN-03 initial proposal. We believe that such an
adjustment clause cannot and will not maintain cost control either at
the agency, or at those entities that depend on BPA for funding.
Additional pressure is necessary to ensure that cost reductions are
maximized and that all prudent means to manage cash flows are
implemented. Implementing an SN-CRAC that permits BPA to relax its cost
reduction efforts is not an acceptable outcome for the Northwest.

**2.6 Mechanisms to Ensure that Further Cost Increases Do Not Trigger
the CRACs.**

Q. Given BPA's three adjustment clauses, are there ways for BPA to
better insure that cost over-runs do not lead to further triggering of
the SN or FB CRACs?

A. Perhaps. In the testimony of Keep, *et. al*., the witnesses state
that, "BPA is open to a way that BPA could be precluded from recovering
excess BPA internal operating costs in the SN CRAC rate design, if these
costs exceed the further reduced limits for 2003 -- 2006"
(SN-05-E-BPA-04, page 17, lines 20 -- 22). Further, in an errata
(SN-03-E-BPA-10 (E1) BPA adds, "BPA could agree that, for purposes of
calculating ANR for the SN CRAC, cost levels for specified categories of
costs would be at levels detailed in the SN CRAC Final Study, not the
actual net cost levels. This would keep any increases in those net costs
from causing an increase in the SN CRAC rates calculated under a
variable design."

*Q. Is a cap needed to prevent future BPA cost increases from triggering
BPA's CRACs?*

A. Yes, we are very concerned that having automatic adjustment clauses
that recover all expense increases will lead to a situation where there
would be insufficient motivation for BPA to hold down costs. Cost
increases would simply be passed through BPA's various CRACs. For
example, while BPA has committed to maintaining internal operating, G&A
and shared services costs at 2001 levels through 2003 to 2006, an
automatic adjustment clause could easily trigger to allow recovery of
costs over 2001 levels. A cap on the ability of BPA to collect spending
over-runs will provide a constant signal to the agency that costs must
be kept under control. A cap should also be implemented for other BPA
and non-BPA controllable costs.

However, BPA's proposal would require a number of details that would
have worked out. For example, changes would be required to the FB CRAC
GRSPs and the Slice true-up calculation that are not part of this
proceeding.

## Section 3: BPA's SN CRAC Proposal and BPA's Incentives

*Q. What is the purpose of this section of testimony?*

A. To explain why BPA should consider whether to have an SN CRAC on an
annual basis, rather than a multi-year SN CRAC, and to explain why BPA
should reserve a portion of Energy Northwest refinancing money as a
financial reserve.

*Q. Does BPA propose a one-year SN CRAC, or a multi-year SN CRAC?*

A. BPA proposes an adjustable or variable SN CRAC through the end of the
rate period. BPA proposes a SN CRAC that could go as high as a 41%
surcharge to base rates, and that is expected to average a 30% surcharge
over base rates. (SN-03-E-BPA-01, page 1-8; SN-03-E-BPA-10, page 6)

Q. Does a multi-year variable CRAC, of the form BPA proposes, markedly
increase the financial burden on the region over a possible CRAC that
was reevaluated every year?

A. Yes.

*Q. What evidence do you have of that?*

A. BPA proposes triggering the SN CRAC using the concept of ANR
(accumulated net revenues). BPA staff states that it did not determine
what level of actual BPA financial reserves corresponded to the SN CRAC
trigger points it proposes, but did suggest how such a calculation could
be performed (See response to PP-BPA-11, attached here as Exhibit
SN-03-E-JC-01L). However, one can calculate the level of overall BPA
reserves associated with these SN CRAC triggers by looking at BPA's
toolkit runs.

*Q. What level of BPA financial reserves trigger the SN CRAC under BPA's
proposal?*

A. BPA's financial reserves can be as high as \$328 million in FY2004,
\$462 million in FY2005, and \$585 million in FY2006, and still trigger
the SN CRAC. In the last two years of the rate case, BPA proposes
triggering the SN CRAC, even if it has more than \$450 million dollars
in reserves. (The calculation of this amount is attached as Exhibit SN
CRAC-03-E-JC-01M).

Q. Has BPA foreclosed having additional SN CRACs in the remainder of the
rate period, if a 41% increase turns out to be insufficient, in BPA's
view?

A. No. BPA retains the option of having further SN CRACs if it feels
that a 41% increase is not sufficient.

Q. Does this mean that the initial proposal in this case understates the
probability of repaying Treasury?

A. Yes. BPA's calculation of Treasury payment probability does not
reflect that BPA proposes retaining the option to charge additional SN
CRACs. Since BPA has that option, BPA can increase rates later to cope
with adverse financial conditions, a possibility that is not reflected
in BPA's TPP calculations.

*Q. What is the bottom line of BPA's proposal from the customer
standpoint?*

A. BPA's proposal is a difficult proposition from a customer standpoint
-- a multi-year SN CRAC with a fixed cap would at least limit the
maximum financial exposure from an SN CRAC. Under BPA's proposal, its
customers are faced with the long-term financial exposure to a
multi-year SN CRAC, yet are also faced with the possible year-to-year
escalation of the SN CRAC in excess of the proposed amount.

Q. Does the automatic adjustment clause mechanism mean that the size of
the SN CRAC can be expected to decline if BPA's financial condition
improves?

A. No. We have learned from the first two years of the current rate
period that allowing BPA rate flexibility via automatic adjustment
clauses reduces BPA's incentives to control costs. Further automatic
adjustment clauses only increases risks that have helped contribute to
BPA's financial problem in the first place.

*Q. Why have automatic adjustment clauses turned out poorly?*

A. The difficulty with automatic adjustment clauses is that if BPA and
entities that receive money from BPA know that if BPA can increase
rates, the incentive of these agencies to control their costs is sharply
reduced. Although BPA has received statements from other entities
collecting money from BPA that these entities will endeavor to control
their costs, the knowledge that a rate increase backstop exists likely
undermines cost-control efforts.

*Q. Has BPA responded differently in the past to financial problems?*

A. Yes. During the mid-1990's, BPA found that its rates were above
market. BPA began losing load, as customers began pursuing cheaper
alternatives.

*Q. What did BPA do then?*

A. BPA pursued an aggressive series of cost-cutting activities. First,
BPA cut its annual operating expense levels for FYs 1996-2000 by
approximately \$500 million per year from the levels in the FY 1995
Congressional Budget. When this proved to be insufficient, BPA cut its
spending for FY 1997-2001 by an additional \$100 million per year. BPA
cut capital expenses significantly, including significant cuts in BPA's
transmission construction program. BPA also pursued cash management
activities, including reducing the amount of revenue financing for BPA
transmission investments, and accessed \$72 million in 1997 in excess
funds in the Supply System WNP-1 Construction Fund to cover a portion of
net billing requirements that BPA would otherwise pay from current
revenues.

BPA additionally negotiated an agreement that stabilized fish and
wildlife costs over a five-year period, successfully negotiated the
4(h)(10)(C) agreement to limit BPA fish and wildlife expenditures to the
share of Federal dams used for power, and established the Fish Cost
Contingency Fund to reflect prior BPA fish & wildlife payments
attributable to the non-power purchases of the dams. (See
WP-96-FS-BPA-02, Appendix A, pages 1-5).

*Q. Why did BPA do this?*

A. BPA had little alternative. BPA lacked take or pay contracts, was
constrained by market conditions, and had a rate structure that could
only be significantly altered once every few years. BPA had to cut costs
sharply, and keep them under control to remain a viable agency.

Q. Can you give another example of how BPA's recent cost-cutting differs
from BPA's cost-cutting behavior in the 90's?

A. In the mid-90's, as BPA began to suffer competitiveness problems, BPA
began reducing headcount rapidly. BPA reduced headcount by 159 positions
in FY1994, another 283 in FY1995, 153 in FY1996, 231 in FY1997, 151 in
FY1998, and 40 in FY1999, for a net reduction of 1017 positions
FY1994-FY1999.

In contrast, BPA added 149 positions in FY2001, when BPA has stated that
PBL lost \$418 million. In FY2002, when BPA has stated that PBL lost
\$390 million, BPA added 230 positions. In FY2003, when BPA has stated
that PBL forecasts losing \$191 million, BPA will add 139 positions. BPA
had 2742 employees in FY2000, but increased its headcount by 518
positions in FY2001-2003, an increase of 19% in total headcount. BPA
states that PBL lost \$1.002 billion during FY2001-2003. (BPA FY 2004
Congressional Budget, page 156)

Q. How many positions does BPA forecast reducing next year in FY2004,
when BPA proposes imposing the SN CRAC?

A. Eight (*ibid*.). This estimate was provided to Congress two weeks
prior to the Administrator's triggering of the SN CRAC rate proceeding.

*Q. Aren't most of the positions BPA has added in TBL and Corporate, not
in PBL?*

A. BPA representatives have repeatedly asserted that most of the
positions added are in TBL and Corporate, and thus they do not reflect a
direct charge on PBL. Of course, the SN CRAC is triggering because BPA
is claiming that the agency as a whole lacks sufficient funds to
reliably repay Treasury, so the headcount additions are relevant from
the standpoint of BPA's overall costs.

In the mid-90's, when BPA did not have the option of raising rates
because it faced mass customer defections, BPA fundamentally
restructured how it did business to reduce its costs. Now, when BPA has
the ability to surcharge, and has take-or-pay contracts that largely
insulate itself from the economic consequences of its rate increases,
the attention to costs apparent in the mid-90's has diminished. In the
view of many of BPA's customers, cost-cutting is now viewed by BPA as
desirable, but not as a paramount priority, since BPA can always rely on
SN CRAC rate increases as a backstop. BPA's reduction in headcount in
the mid-90's sent a dramatic message regarding BPA's priorities, both to
entities outside BPA and to internal audiences within BPA. BPA's recent
increase in headcount, at a time of massive agency financial losses,
sends a negative message.

The existence of automatic adjustment clauses has markedly changed BPA's
incentives to control costs, both to the detriment of BPA's customers,
and to BPA's own long-term detriment. BPA should not be compounding this
problem through an additional application of automatic adjustment
clauses.

Q. Are you asserting that BPA could solve its financial problems simply
through reducing headcount?

A. No. (Although using a rule of thumb that each employee costs
\$100,000 in salary, benefits, office space, and associated costs
indicates that the 1,000 employee reduction during the 90's did reduce
BPA's costs by roughly \$100 million a year.)

Q. Does imposition of an SN CRAC, particularly one with an automatic
adjustment clause, threaten the long-term viability of BPA?

A. Yes. Once BPA creates the expectation that increased rates are going
to be the norm for years, then groups with a financial interest in
receiving money from BPA, as well as other organizations, will likely
start arguing that there is no need for BPA to reduce its rates to its
customers below current levels, when BPA could simply increase the flow
of benefits to outside organizations as an alternative. BPA is at risk
of creating the perception that it will not provide long-term benefits
to its customers, given its pattern of successive rate increases.

Q. BPA has suggested that it might consider a "contingent" SN CRAC
increase, where the size of the SN CRAC would be reduced by specified
amounts if BPA is successful in achieving certain cost-cutting goals.
Would adopting this approach be better than BPA's use of an automatic
adjustment clause with the SN CRAC?

A. A contingent approach might be somewhat better than BPA's proposal,
because it might be somewhat more constrained than an open-ended
automatic adjustment clause. However, it does not remove the fundamental
problem with automatic adjustment clauses, which is that if BPA and
entities that receive money from BPA know that BPA can simply increase
rates if BPA fails to control costs, the incentive for BPA and entities
who receive money from BPA to control their costs is sharply reduced.

*Q. What did BPA have to say about the role of bond ratings on
BPA-backed bonds in evaluating the SN CRAC?*

A. BPA states that the credit rating on BPA-backed bonds is one of the
three important financial indicators that BPA reviews (SN-03-E-BPA-04,
page 3 lines 15-17). BPA further notes that BPA-backed bonds have been
downgraded by Fitch recently, and placed on "negative outlook" by
Standard and Poor's, and cites a Standard and Poor's report that "use of
any debt restructuring savings to offset current operating expenses" may
lead to a further downgrade (SN-03-E-BPA-04, page 7 line 15- page 8 line
2).

*Q. Has BPA made an estimate of the financial impact of such
downgrades?*

A. Yes. In the April 2003, BPA Journal, BPA Senior Financial Analyst
Anita Mertsching was quoted as saying that the recent bond downgrades
had reduced the savings on \$682 million of Energy Northwest debt
refinancing by \$637,000. (BPA's overall saving on the bond sale was
\$37 million.) Mertsching went on to say that if a further downgrade was
experienced, the cost of the downgrades on future bond sales might be as
much as half a percent. This would imply that the benefit from the
roughly \$600 million of Energy Northwest refinancing to be done later
this year might be reduced by as much as \$3 million.

*Q. Are there other factors that BPA must consider?*

A. It is reasonable to assume that the creditworthiness of BPA's
customers also impinges on the rating of bonds backed by BPA. BPA makes
no reference in its testimony to any concern that an additional average
30% rate increase might also impact the creditworthiness of BPA's bonds,
by reducing the ability of customers to pay their BPA bills.

*Q. What do you conclude?*

A. The estimated financial losses caused by ratings downgrades would
appear to be an insufficient justification for BPA's potential
billion-dollar rate increase.

**Section 4: Secondary Revenue Forecast**

*Q. What is the purpose of this section of your testimony?*

A. Having reviewed a number of inputs into BPA's revenue modeling, we
will address some concerns with the natural gas forecast, and identify a
number of errors and inadequate specifications of the inputs into the
AURORA model.

*Q. Do you have any concerns with BPA's natural gas forecast?*

A. In examining BPA gas forecast, two concerns arose, both relating to
the use of NYMEX forward prices in predicting future gas prices.

The first concern relates to the length of time that BPA is using the
NYMEX prices in place of its long-term fundamental price forecast. We
have observed in the past that NYMEX is less accurate in predicting
prices further out in time than in the immediate near-term. NYMEX tends
to project the impact of current events on gas prices continuing out far
into the future. We understand that there is as much art as analysis to
forecasting gas prices, but unless there are overriding reasons, the
NYMEX prices should be merged into the fundamentals forecast somewhere
between one and three years out.

The second concern with BPA's use of NYMEX forward prices as a forecast
is the reliance upon one day's set of prices to represent the entire
period. There is a significant degree of volatility in daily forward
prices. In fact, looking back at BPA's forecast, the date that BPA chose
for its forward prices, January 28th, happened to be a low point of the
immediate daily oscillations, as seen in this chart.

![](media/image1.jpeg){width="3.9993055555555554in"
height="2.7215277777777778in"}

The chart is instructive not just to point out what happened after BPA
took its forward price for April 2003, but more to show the daily
changes in the price of this month's gas. The forward price for April
2003 on January 28th was \$4.96. Thereafter, the price jumped to as high
as \$8.12, and then closed out at \$5.12. We understand that it was as
likely that the market may have turned downward after January 28th as
its upward spike. Our point is that choosing any particular day carries
more risk than taking an average of the preceding days.

For example, had BPA retained its choice of January 28th as it pricing
day, but had taken an average over a ten-day period, it would have
resulted in an April price of \$5.08, coincidentally closer to the
closing \$5.12 price. A more dramatic effect can be seen had BPA decided
to get its pricing on February 28th instead. That day's closing price
was \$8.12. Using that single day would have resulted in a dramatic
difference from the closing price of \$5.12. In contrast, employing the
10-day average in place of the single day would have yielded a \$6.68
price.

This is not a perfect method. For example, on March 7th, using a single
day would result in a price of \$6.98, whereas the 10-day average price
was \$7.22. However, given the uncertainty of using a series of forward
prices to predict the final result, the use of a 10-day average should
help mitigate some of the volatility in daily gas pricing.

We recognize that BPA will be updating its gas price forecast for the
final studies for this rate process rather than using the prices from
its initial proposal. We urge BPA to adopt using a shorter time period
for the NYMEX forward prices and to use a 10-day average when computing
the NYMEX prices that are used in that forecast.

*Q. Have you reviewed BPA's inputs and assumptions to the AURORA model?*

A. We have reviewed some of the more important inputs into AURORA.
Specifically, we have analyzed the existing resources file, the loads
file, the hydro files, and portions of the annual and monthly files that
are associated with the foregoing. We also reviewed the transmission
link file.

*Q. What is your overall assessment of BPA's AURORA modeling?*

A. To start, we note that BPA is using a version of AURORA that is
several generations older than is currently available. BPA is using
version 5.6.33. The latest version available at the end of January,
which is approximately the time BPA would have had to update its model
was Version 6.3.5. Version 5.6.33 was released on September 11, 2001.
Version 6.3.5 was released on December 15, 2002. Our sense is that while
there are differences between versions 5.6 and 6.3, they are not
necessarily ones that need to be addressed in this case, especially
given the short timeframe of the SN-CRAC process. Therefore, given the
magnitude of the changes necessary to move from 5.6 to any of the 6.X
versions, we are comfortable enough with the version of the model to
accept BPA's continued use at this time. However, we urge BPA to work
towards using an updated version as soon as it can, certainly before it
does any further SN-CRAC assessments, such as those proposed for August.

However, in addition to using a dated version of the model, BPA is using
an equally dated version of the inputs to AURORA. BPA has updated
certain inputs, especially those related to its risk modeling. For
instance, hydro generation in certain areas, loads in certain areas, and
gas prices are input variables that are current and varied in the
numerous runs of the model. But other inputs are fixed inputs into each
of the different risk runs, therefore affecting each and every one of
the runs. Particularly of concern to us are the vintage of the resources
that are specified in the resources and resource modifier files.

*Q. What did you find when you analyzed the AURORA resource file?*

A. We immediately recognized that BPA is using an old version of the
resource file that contains significant errors. Many of these errors
were communicated to the AURORA vendor shortly after its release. The
vendor, EPIS, corrected these errors in subsequent releases of their
default dataset. However, because BPA has not updated its default
dataset, they have not yet corrected these errors.

*Q. What were the errors in the default dataset that BPA is using?*

A. There are a number of resources that are specified more than once in
the file. These resources are detailed on Table 1 attached to this
testimony. These duplications overstate the existing resource base in
the Western Interconnection by 3,671 megawatts. In addition, there are
several resources that were installed with temporary operation permits
in response to the 2000-2001 West Coast energy crisis. These resources
have now been removed, and therefore, they should be removed from the
AURORA inputs. The total capacity of these resources is 236.7 megawatts,
as shown on Table 2.

*Q. What else did you find in your review of the resource file?*

A. BPA stated in their initial proposal that they included only those
new resources expected to be completed and online before the end of
2003. We found four resources, totaling 1,771 megawatts, that either
will not be completed in this timeframe, or have yet to begin
construction. *See* Table 3. Also, there are several resources that need
to have their on-line dates revised. We have noted those that may affect
the revenue forecast on Table 4.

Further, based on the latest listing of resources published by the WECC
(*Existing Generation and Significant Additions and Changes To System
Facilities 2001 -- 2011; Data as of January 1, 2002; Issued May 2002*),
BPA's input file includes 2,037 megawatts of resources that are
unavailable due to retirements or being on cold standby status. This
total includes 214 megawatts of generation in Alberta that will retire
in June, 2004. *See* Table 5.

Q. After removing the resources associated with these problems, did you
find any problems with specifications of the remaining resources?

A. Yes. A number of resources in BPA's inputs are specified in the wrong
AURORA area. These resources are shown on Table 6. Most of these are
associated with certain areas that are located in one state, but are on
the other side of a transmission constraint that defines an AURORA
pricing area. Also, there are several California resources that are
specified on the wrong side of Path 15, the transmission constraint that
defines Northern and Southern California. In addition, three resources
seem to be simply errors in location.

We also found, as shown on Table 7, a number of resource are specified
with the wrong fuel. We based our fuel choices on those shown in the
2002 WECC resource listing.

Q. If these changes were included in the input file, would this
constitute an up-to-date listing of resources?

A. No. There are a great number of new resources added to the Western
Interconnection since the file that BPA is using was compiled. We have
summarized these new resources by AURORA area on Table 8, and include
general groupings by resource type. A more detailed listing of the
larger of these units in shown on Table 10, totaling 14,787 megawatts.
Most of 1,360 megawatts of "Other" resources on Table 8 are renewables.
Using BPA's stated guideline of including only resources due on-line
before the end of 2003, our list of resources includes 2,300 megawatts
of Gila River units (due on-line between July and October, 2003), the
632.5 megawatt Mesquite project (due on-line July 2003) and the 550
megawatt Bighorn project (due on-line September, 2003), all in Arizona.
The Blythe project in Southern California is also included, due on-line
April 2003. Our list also includes 1,660 megawatts of new combined
cycles in Baja, Mexico.

The Mexican generators present another problem with BPA's inputs. BPA
does not show Baja loads and resources in AURORA. Baja loads and
resources are a part of the WECC area and are directly interconnected
with Southern California. When the dataset BPA is using was developed,
this was not a significant oversight, because Baja loads and
cost-effective resources were essentially in balance. However, over the
past few years, resources have begun to be developed in Mexico
explicitly for export into the California market. In order to accurately
reflect this in AURORA, a new pricing Baja area should be added in
AURORA. Short of that, some recognition of these new resources should be
incorporated. We would suggest a shortcut for BPA to add 800 megawatts
of combined cycle generation in Southern California. This would reflect
the presence of the new generation, the developer-stated premise that
about one-half of the generation would be marketed in California, and
the current transmission capacity limit between Mexico and Southern
California.

*Q. What other resource additions would you include?*

A. Based on the current 2002 WECC resource listing and more recent news,
we would include about 1,560 megawatts of older generation that are not
included in BPA's resource file. The larger units in this total are
shown on Table 9.

We have also identified about 850 megawatts of existing wind generation
that are included in BPA's resource file. These are summarized by area
on Table 11.

Finally, based on the current 2002 WECC resource listing and other
available information, we have assessed that BPA has overstated the
plant capacities of plants included in BPA's resource file by about
1,410 megawatts. The projects with larger differences are shown on Table
12.

*Q. In this discussion, you have excluded discussion of hydro projects.
Why is that?*

A. In AURORA, the generation capability of hydro projects is calculated
in a different manner than other generation types. AURORA multiplies the
project capacity listed in the resource file by the hydro maximum in the
monthly shaping file to determine the peak capability of a hydro
generator. Given this fact, it is unimportant to AURORA whether the
project capacity listed is correct or not, as long as the product of the
multiplication is correct. So one could show the project size as 106
megawatts and a multiplier of 1.00, or one could show the project size
as 100 megawatts with a multiplier of 1.06. Furthermore, it not
important for AURORA to see each individual hydro unit or project as
long as the total for each area is appropriate. For example, BPA's
resource file contains over 400 hydro units in the Oregon/Washington
area, totaling about 30,735 megawatts. In AURORA, this generation could
be shown as one unit with a size of 30,735 megawatts and the results
would be the same.

Therefore it is less important that the capacity of the hydro generation
listed in the resource file agrees with any other particular listing
than does the hydro listings in total reflect the appropriate amount of
hydro generation. Our review of the hydro generation data shows that
BPA's parameters appear to be reasonable.

*Q. Have you reviewed BPA's load forecasts in AURORA?*

A. Yes, to some extent. BPA models PNW and California loads as variables
in their risk modeling. As a result, there are a number of load points
representing each month. We averaged loads over time and across risk
scenarios to get to expected values for these loads. Comparing those
forecasts to current load forecasts from the WECC (*Summary of Estimated
Loads and Resources, Data as of January 1, 2002, Issued May 2002*),
BPA's forecasts appear too low. BPA appears to have too little load in
Canada and the Rockies and too much load in Arizona/New Mexico/Southern
Nevada. While it also appears that BPA's load forecast for the Northwest
Power Pool is too low, we assume that this is due to the industrial
loads assumed to be operating in the WECC forecast have been removed
from the BPA forecast

*Q. What other concerns do you have with BPA's AURORA inputs?*

A. Our examination of the resource modifier file raises questions about
BPA's assumptions for generation additions and retirements. BPA is
allowing AURORA to retire 1,000 megawatts in 2002, 2,000 megawatts in
2003, 3,000 megawatts in 2004 and 4,000 megawatts each in 2005 and 2006.
Allowing retirements of 14,000 megawatts over this period appears to us
to be too much and not in keeping with past history of retirements. We
believe it would be better for BPA to revise its inputs to reduce the
amount of generation retirements to the 500 to 1,000 megawatts per year
range. This would yield a more reasonable amount.

Additionally, we examined the resource additions in the resource
modifier. We notice that BPA has 480 megawatts of generic resources
added in 2002 and 1,440 megawatts in 2003. Allowing AURORA to add
resources in a historical and current year would be better replaced with
current knowledge of actual resource additions, those being the resource
additions we discussed above.

Further, we would urge BPA to replace generic resource additions in the
near-term with specific resources under development. By this, we are not
saying that BPA should assume that a specific generator will come
on-line in 2004 or 2005, but rather that BPA allow AURORA to select the
generation it wants to add from a list of generators under development
in conjunction with the generic resources.

BPA's resource modifier shows 1,920 megawatts of new generation added in
2004. Our research shows that about 4,000 megawatts of new generation is
currently under construction and expected to come on-line in 2004. About
3,000 megawatts of this is comprised of five new combined cycle projects
(Mesquite 2, Valley, Rocky Mountain, Silverhawk and Metcalf). These
projects currently range from 25 percent to 75 percent complete. We
propose that BPA model these projects that are under construction as
potential new resources that AURORA could choose based on the same
criteria it chooses generic new projects -- the cost to complete the
unit. For example, the Mesquite 2 project cost is about \$250 million,
or \$365 per kilowatt. This project has been under construction since
March 2001, and is projected to be completed in January 2004. This means
that the project is about 73 percent complete. Allowing for 30 percent
of its cost being salvaged should construction be terminated, we would
estimate that about 50 percent of the total cost is sunk cost, resulting
in a cost to complete Mesquite 2 of about \$180 per kilowatt. This value
can be converted into the AURORA input form of about \$815 per megawatt
per week, and entered into the alpha variable file as the cost of adding
this particular project. Then AURORA could select this project from a
menu of resource choices based on market economics, as is currently done
with generic projects.

By including projects that are either under construction and proposed,
AURORA's selection of future resources can be improved by reflecting the
cost to finish a resource rather than relying on the full cost of a
generic resource. Using only generic, full cost resources distorts
near-term forecasts, causing them to be higher than they should be.

*Q. Do you have any other issues with AURORA input file?*

A. Yes, with the transmission link file. We noticed several problems
that should be corrected to conform with the ratings in the WECC Path
Rating Catalog.

The first problem is with the link between Northern California and
Southern California. BPA uses a transfer capability of 3,000 megawatts
in each direction. This is the capability for Path 26, between the Los
Angeles and Bakersfield areas. Generally, Path 15 is considered to be
the demarcation between Northern California and Southern California. In
fact, BPA's resource specification shows resources north of Path 26 as
located in Southern California (e.g., Diablo Canyon). According to the
California ISO, the modeling limits on Path 15 are 1,275 from north to
south and 3,900 from south to north.

Another problem is the link between Southern California and Northern
Nevada. BPA uses a transfer capability of 180 megawatts northbound. The
actual tie is a 55 kV line that has a WECC rated as 17 megawatts. The
BPA link specification in the reverse direction is 18 megawatts, which
is close to the WECC rating. The 180 figure appears to be a simple
error.

The next link that we have an issue with is New Mexico to Arizona. BPA
uses a transfer capability of 1,500 megawatts. This link should consist
of two paths, Path 22 and Path 54. Path 22, Southwest of Four Corners,
has a rating of 2,335 megawatts. Path 54, Coronado - Silver King --
Kyrene, has a rating of 1,100. Together, these paths total 3,435
megawatts.

The next link is Arizona/Southern Nevada to Southern California. BPA
uses a transfer capability of 8,195 megawatts. This is far lower than
the rating on Path 46, West of Colorado River, which has a rating of
10,118 megawatts. The West of River path is more appropriate than the
East of River Path. The West of River path includes the transmission
lines between Southern Nevada and California, while the East of River
path includes lines between Arizona and Southern Nevada.

Finally, we have issues with the links between Utah and Northern Nevada
and Utah and Arizona/Southern Nevada. BPA uses a rating of 545 megawatts
from Utah to Northern Nevada and 450 megawatts in the reverse direction.
Both of these values are 300 megawatts greater than the ratings of Path
32, which leads us to believe that the Path 35 rating was
inappropriately added to Path 32. Path 35 is between Red Butte in Utah
and Harry Allen in Southern Nevada, therefore, it should be a part of
the link between Utah and Arizona/Southern Nevada. Next, BPA uses 820
megawatts from Utah to Arizona/Southern Nevada and 850 megawatts in the
reverse direction, which is close to the sum of Path 78 and Path 79
ratings. The WECC rating of Path 78 is 560 into New Mexico and 600
megawatts into Utah. The rating of Path 79 is 265 megawatts into Arizona
and 300 megawatts into Utah. In order to conform all of this to the WECC
path ratings, BPA needs to add a link specification representing Path
78, between Utah and New Mexico, with a transfer capability of 560
megawatts southbound and 600 megawatts northbound. Then the transfer
capability between Utah and Northern Nevada should be set to the Path 32
rating, 245 megawatts westbound and 150 megawatts eastbound. Finally,
the transfer capability between Utah and Arizona/Southern Nevada should
be set at the sum of the ratings of Path 35 and 79, 300+265 or 565
southbound and 300+300 or 600 megawatts northbound.

*Q. Have you evaluated the results of your recommendations on BPA's
revenues?*

A. We have performed a check on results based on a single reference case
we constructed. We have not performed the full range of risk modeling
that BPA uses in its complete proposal.

*Q. How did you construct the reference case and what were the results?*

A. There are a number of variables that BPA accounts for in the inputs
into AURORA. Gas prices, PNW and California loads and PNW and California
hydro generation are all variables in the forecasting process. BPA runs
AURORA a number of times, varying these inputs based on statistical
projections of their variability, and feeds the AURORA results into
developing the 3,000 cases used in the Toolkit risk analysis.

We took the averages from all of the cases for each of the variables to
construct a single reference case. The reference case uses the annual
average gas prices for each year of the study, the annual average loads,
as well as the average annual hydro generation and shaping. Therefore,
this reference case can be thought of as an average case. However, we
recognize that because of skewness in the risk variables and the effects
of high water resulting in lower prices, that the overall resulting
revenue distribution would not necessarily be represented by this
reference case.

Further, we took into account the *ad hoc* adjustment that BPA made to
the AURORA inputs by subtracting 2,500 aMW from PNW loads. Therefore, we
have two reference case results for comparison: with and without the
adjustment. The annual revenues from secondary sales in the adjusted
case was trued-up to result in annual revenues between \$530 million and
\$560 million for FYs 2004-2006, as reported by BPA in their revenue
forecast as "Balancing Trading Floor Sales" in Chapter 5 of their
proposal. The corresponding annual revenues in our reference case
without any load adjustment is about \$660 million, a result of prices
being about \$3 to \$4 higher than with the adjustment.

After correcting the resource and load inputs into AURORA, we showed
revenues ranging between \$730 and \$780 million, resulting from prices
being about \$6 higher. With the 2,500 aMW adjustment, revenues ranged
from \$730 million to \$780 million.

*Q. Do you agree that BPA should continue their* ad hoc *adjustment to
AURORA prices?*

A. No. Making adjustments of this sort undermines the value of tools
like AURORA. It would be much better for BPA to make a concerted effort
to update their input files into AURORA to get better results than to
make *ad hoc* adjustments to control the outcome.

Q. BPA claims that their adjustment is reasonable given the differences
between the way AURORA simulates the market and the way the market
operates. Do you agree?

A. No. While we recognize that the market does not operate in the manner
modeled by AURORA, we do not agree with BPA's premise that they cannot
achieve the "exact hourly marginal clearing price" determined by AURORA.
No seller would expect to achieve the "exact" AURORA prices. AURORA is a
model that simulates the market. The proper question is whether any
seller can achieve the approximate AURORA prices. Next, BPA claims it
operates in a "bilateral market in which every party does not receive
the highest hourly marginal clearing price." While this statement is
true on its face, it does not necessarily follow that parties will
receive less than the highest hourly marginal clearing price that AURORA
calculates.

BPA first justifies the use of the adjustment by saying that the "amount
of surplus hydroelectric generation available for sale may alter the
range of prices achieved in the market for the participants." The 2,500
aMW corresponds to the amount of surplus generation that BPA produces
under average hydro conditions. BPA argues that due to the transparency
in the market of BPA's surplus generation, buyers and sellers will
discount prices from the cost of the marginal generating unit. BPA
further argues that "\[t\]he actual price BPA receives, however, cannot
precisely be estimated by the variable cost of generating the last kWh
sold."

These arguments fail on two counts. First, AURORA takes into account the
amount of surplus hydro generation from BPA in determining its market
prices. In fact, this is one of the chief variables in BPA's risk
analysis. Most of the variation in BPA's revenues over the 3,000 cases
results from variations due to surplus generation, and their effect on
market prices. This is the primary reason BPA runs a number of AURORA
runs. Therefore, the impact of the surplus generation on market prices
is already taken into account in the AURORA prices; the AURORA prices
are lower when there is more surplus generation and higher when there is
less surplus generation, all other inputs being equal. No further
adjustment in AURORA is necessary to reflect the presence of BPA's
surplus generation.

The other part of the argument fails as well. BPA argues that the
revenue it receives cannot be estimated by variable cost of generating
the last kWh sold. BPA implies that a bilateral market cannot sustain
this price level. But this argument fails to recognize that markets
often trade in excess of the variable cost of the marginal generating
unit. This was borne out in the California Power Exchange, a market that
settled based on the cost of the marginal generating unit for each hour.
But it is an important distinction that the cost of the marginal
generating unit in the CalPX was not measured by its variable cost, but
by its bid. Studies were conducted that showed that the bids of the
marginal units averaged from 20 percent to 35 percent above the variable
cost of the marginal unit. This should be an expected result. Even
though economic theory tells us that prices should be constrained to the
variable cost of production in a perfectly competitive market, the
CalPX, as well as the current bilateral market, was not "perfectly"
competitive. It should not be surprising to see bids above variable cost
in a less than perfect market. The AURORA market simulates a competitive
market, allowing the user to chose the amount above variable cost that
each unit will "bid". BPA runs the AURORA model with this bid variable
set to 5 percent, close to a perfectly competitive market and well below
the observed levels that were measured in the CalPX.

We tested AURORA to measure the impact of this bid margin on the price
forecast. The resulting prices were in the range of 4 to 5 dollars above
those measured in our reference case described above. We believe this
shows that the AURORA prices resulting from the assumptions that BPA
uses have already been adjusted from those that would be achieved in a
market where every seller realized the price set by the bid of the
marginal generating unit. Therefore, no further *ad hoc* adjustment,
such as the one used by BPA, is needed.

Q. What conclusions do you draw from your analysis of BPA's use of the
AURORA model?

A. A very large portion of BPA\'s calculated risk of missing a Treasury
payment arises from the variability in revenues from secondary sales.
BPA uses the AURORA model to estimate the market prices it can expect
from such sales at various gas prices, load levels and water conditions.
But since BPA didn\'t believe the prices predicted in its AURORA runs,
it made an *ad hoc* adjustment to reduce the market prices.

However, it appears that much of the problem of relying on the AURORA
results that BPA produces were the results of using an old dataset that
contained errors and had not been updated to reflect current system
conditions. Since many of these errors and lack of data updates are not
a matter of judgment, but matters of empirical observation, the market
prices produced in the AURORA runs done by BPA with stale data have no
rational basis. Making *ad hoc* adjustments to prices resulting from
this stale data cannot be supported, especially when the reasons given
for such adjustments are not supportable.

This lack of a rational basis for the AURORA output is particularly
critical to BPA\'s proposed SN CRAC because a very large portion of the
proposed rate increase is to cover BPA\'s calculated variability in
revenues from surplus power sales in future years. In past rate cases,
BPA estimated that the revenue variability from surplus sales accounted
for as much as 70 percent of its net revenue risk. With market prices
greater than they were during the time when the 70 percent was
estimated, the net revenue risk to BPA due to surplus sales is most
likely well in excess of 70 percent.

Therefore, for BPA to propose substantial rate increases through the
SN-CRAC mechanism conditioned on a flawed forecast of market prices
results in an equally flawed proof of the need for such rate increases.

Finally, the changing fundamentals of the wholesale electric market, and
the need to keep BPA's revenue forecasts aligned with those changes, is
a substantial reason why BPA should re-evaluate the need for any SN-CRAC
annually.

**Table 1**

**Duplicate Generation Included in AURORA**

  ----------------------- ---------- --------------------------- ---------- -----------
  **Project Name**        **ref#**   **Duplicate Project Name**  **ref#**   **MW**

  Aurora Project GTG -    2144       Fort McMurray (#A)          2771       80
  Mildred Lake AB                                                           

  Cancarb Cogen (Medicine 2764       Cancarb thermal expansion   2147       47
  Hat)                               project                                

  Cancarb Cogen (Medicine 2764       Medicine Hat (TransCanada)  2776       46
  Hat)                                                                      

  Carseland               2797       Carseland nitrogen          2148       80
                                     fertilizer plant                       

  Cavalier                2798       Cavalier compressor station 2149       106

  Dow Chemical- Fort      2767       Dow Chemical Project in     2154       120
  Saskatchewan                       Fort Saskatchewan                      

  Drywood                 2768       Drywood Plant               2155       6

  Griffith Energy Project 2811       Griffith Energy power plant 2168       520

  Gold Creek              2774       Gold Creek power plant      2167       6.5

  Island Cogeneration     2816       Island Cogen at Campbell    2170       250
                                     River BC                               

  La Paloma               2174       McKittrick Generation       2818       1,048
                                     Project                                

  Poplar Creek Ph 1       2781       Suncor Cogeneration 1       2185       180

  Poplar Creek Ph 2       2782       Suncor Cogeneration 2       2186       180

  Poplar Hill             2783       Poplar Hill                 2178       43

  Biogas Elec Cogen 1     1205       Biogas 1                    1204       5.5

  Redding Power 1         1381       REDDING                     2566       28

  Hermiston Power Project 2813       Hermiston                   2169       536
  1 & 2                                                                     

  MIRAMAR                 2473       Miramar 1                   1466       47

  SONOMA CALPINE GEYSER   2652       Geothermal 1                1391       62

  Neil Simpson II 2       72         Neil Simpson 2              71         80

  Scotford (B)            2786       Shell Air Liquide           2195       80

  West Phoenix (Phase 1)  2833       West Phoenix (Phase 4)      2848       120

  **Total MW**                                                              **3,671**
  ----------------------- ---------- --------------------------- ---------- -----------

**Table 2**

**Temporary Generation Included in AURORA**

  -------------------------- ---------- ------------------------------ -----------
  **Project Name**           **ref#**   **Status**                     **MW**

  Clark Public Utilities ICs 2799       Leased through June 2002.      50

  Cowlitz Co PUD ICs Ph 1    2801       Planned service through        6
                                        Apr-2002.                      

  Northwest Regional Power   2777       Retired as of Oct 2001.        32.8
  (John Day)                                                           

  Northwest Regional Power   2778       Retired as of Sep-2001.        32.8
  (Rock Island) Ph 1                                                   

  Northwest Regional Power   2779       Retired                        16
  (Roosevelt Landfill) Ph 1                                            

  Okanogan Co PUD Ph 1       2780       Retired 6/30/01.               6.6

  Tacoma Power ICs           2789       Deactivated, may terminate     52.5
                                        lease for rentals, sell        
                                        purchased units.               

  Idaho Power ICs            2815       Terminated as of Oct-2001.     40

  **Total MW**                                                         **236.7**
  -------------------------- ---------- ------------------------------ -----------

**Table 3**

**Unfinished Generation Included in AURORA**

  -------------------------- ---------- ------------------------------ -----------
  **Project Name**           **ref#**   **Status**                     **MW**

  Goldendale Energy Center   2810       Scheduled for 2004 completion  248

  Everett WA power plant     2157       Construction not begun         248

  new units at Potrero and   2176       Potrero project withdrawn,     1,050
  Contra Costa power plants             Contra Costa construction      
                                        suspended                      

  Huntington Beach \# 4      2843       Repowering on hold             225

  **Total MW**                                                         **1,771**
  -------------------------- ---------- ------------------------------ -----------

**Table 4**

**Significant Revisions to Online Dates in AURORA**

  ------------------ ---------- ------------ ----------- --------------------------
  **Project Name**   **ref#**   **BPA date** **Revised   **Notes**
                                             Date**      

  Oldman Dam         2196       6/30/2001    5/15/2003   delay in construction

  West Phoenix       2847       8/31/2002    6/1/2003    delay in construction
  (Phase 2)                                              

  Coyote Springs 2   2846       11/30/2002   7/1/2003    delay due to fire

  Pincher Creek (A)  2821       11/30/2001   7/15/2003   financing delay

  Muskeg River       2820       11/30/2002   8/15/2003   awaiting replacement of
                                                         defective equipment

  Elk Hills          2805       2/28/2003    6/15/2003   latest information on
                                                         estimated date

  Seven Mile         2827       2/29/2004    4/15/2003   construction ahead of
  Addition                                               schedule
  ------------------ ---------- ------------ ----------- --------------------------

**Table 5**

**Offline Generation Included in AURORA**

  ------------------------------------- ---------- ------------------ -------------
  **Project Name**                      **ref#**   **Status**         **MW**

  Arapahoe                              2763       converted to CC    74

  ARCO PETRO PRODUCTS                   2216       self-generating    8

  AUBERRY ENERGY                        2218       cold standby       7.5

  Boston Bar Diesel 1                   102        retired            2

  Cheyenne Diesel 1                     342        retired            2

  Cheyenne Diesel 2                     343        retired            2

  Cheyenne Diesel 3                     344        retired            2

  Cheyenne Diesel 4                     345        retired            2

  Cheyenne Diesel 5                     346        retired            2

  COLDWATER CREEK                       2279       retired            123.6

  COYOTE CANYON GAS RECO                2294       cold standby       20

  DELANO NRG CO INC                     2305       cold standby       53.4

  Ellwood 1                             1638       cold standby       53

  GEM RESOURCES A                       2353       retired            20

  GEM RESOURCES B                       2354       retired            20

  GEORGIA PACIFIC MARTELL               2358       retired            9

  GEOTHERMAL 1                          2359       retired            118

  GEOTHERMAL 2                          2360       retired            120

  Gerber Compr Sta 1                    877        retired            4

  Geysers 10                            878        shut down          53

  Geysers 9                             891        shut down          53

  Harbor 5                              615        retired            86

  HERSHEY CHOCOLATE USA                 2395       cold standby       6

  Humboldt Bay GT2                      902        retired            15

  Humboldt Bay GT3                      903        retired            15

  Hunters Point 2                       904        retired            107

  Hunters Point 3                       905        retired            107

  Irvington GT3                         1801       retired            25

  Kaiser FC 1                           1396       retired            0.2

  Keogh GT2                             119        retired            50

  Libby 1 Champion                      340        retired            7.5

  Libby 2 Champion                      341        retired            5

  Lytton Diesel 1                       123        retired            3.5

  Martin Drake 4                        356        retired            11

  MINN METHANE HIGHGROVE                2468       retired            1\.

  MINN METHANE WOODVILLE LANDFILL       2470       retired            4

  MODESTO ENERGY LP                     2476       cold standby       14

  MONTEREY REG WATER                    2483       retired            1.7

  NORTH ISL STEAM TURBINE               2492       retired            4.1

  NTC CENTRAL                           2497       retired            16

  OGDEN POWER PAC OROVILLE              2510       cold standby       18

  RIO BRAVO FRESNO                      2572       cold standby       24.3

  RIO BRAVO ROCKLIN                     2575       cold standby       24.4

  Skagit Co Waste 1                     1361       retired            2

  SOLAR TURBINES                        2649       cold standby       9.5

  SOLEDAD ENERGY                        2651       cold standby       12

  TORRANCE REFINERY                     2682       self-generating    41.9

  UC DAVIS - PLANT SERV                 2692       cold standby       3.5

  UCLA Cogen 1                          649        self-generating    39

  ULTRAPOWER BLUE LAKE                  2694       cold standby       11.4

  UCLA So CHILLER COGEN                 2693       cold standby       30.4

  UNOCAL RESEARCH                       2700       self-generating    3.6

  Valley 1                              2703       retired            95

  Valley 2                              2704       retired            99

  Wabamun 1                             1780       retired 11/29/2002 67

  Wabamun 2                             1781       to retire          67
                                                   6/30/2004          

  Wabamun 3                             1782       to retire          147
                                                   6/30/2004          

  Weyco Energy CTR 1                    451        cold standby       25

  Whitehorn 1                           2192       retired            61.2

  WILMINGTON COGEN                      2728       self-generating    28

  **Total MW**                                                        **2,036.7**
  ------------------------------------- ---------- ------------------ -------------

**Table 6**

**Revisions to Area Locations for Generators in AURORA**

  ----------------------- ---------- -------- ----------- --------------------------
  **Project Name**        **ref#**   **BPA    **Revised   **Notes**
                                     area**   Area**      

  MONTEREY PWR CO         2481       SCal     NCal        Monterey County (NP15)

  MONTEREY REG WASTE MGMT 2482       SCal     NCal        Monterey County (NP15)
  DIST                                                    

  Moss Landing 1          2840       SCal     NCal        Monterey County (NP15)

  Moss Landing 2          2841       SCal     NCal        Monterey County (NP15)

  OGDEN PACIFIC POWER     2508       SCal     NCal        Monterey County (NP15)
  SALINAS                                                 

  SOLEDAD PRISON          2650       SCal     NCal        Monterey County (NP15)

  SOLEDAD ENERGY          2651       SCal     NCal        Monterey County (NP15)

  SOLEDAD ENERGY          2651.1     SCal     NCal        Monterey County (NP15)

  Huntington Beach \# 3   2842       NCal     SCal        Los Angeles (SP15)

  MAMMOTH PACIFIC #3      2443       NCal     SCal        Mono County (SP15)

  MAMMOTH PACIFIC I       2444       NCal     SCal        Mono County (SP15)

  MAMMOTH PACIFIC II      2445       NCal     SCal        Mono County (SP15)

  PLES - 1                2553       NCal     SCal        Mono County (SP15)

  Wadsworth (Hiram W      2791       OrWa     SCal        Mono County (SP15)
  Wadsworth) pumping                                      
  plant                                                   

  Ben French 2            60         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French 3            61         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French 4            62         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French 5            63         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French GT1          64         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French GT2          65         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French GT3          66         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French GT4          67         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French IC1          68         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Ben French ST1          69         Colo     Wyo         South Dakota north of TX
                                                          constraint

  Redhawk 1               2844       NCal     Ariz        Maricopa County Arizona

  Redhawk 2               2845       NCal     Ariz        Maricopa County Arizona

  General Chemical 1      1029       Wyo      Utah        Utah side of transmission
                                                          constraint

  Naughton 1              1066       Wyo      Utah        Utah side of transmission
                                                          constraint

  Naughton 2              1067       Wyo      Utah        Utah side of transmission
                                                          constraint

  Naughton 3              1068       Wyo      Utah        Utah side of transmission
                                                          constraint

  SF Phosphates 1         1086       Wyo      Utah        Utah side of transmission
                                                          constraint

  Kings Beach 1           1543       NCal     NNev        Nev side of transmission
                                                          constraint

  Kings Beach 2           1544       NCal     NNev        Nev side of transmission
                                                          constraint

  Kings Beach 3           1545       NCal     NNev        Nev side of transmission
                                                          constraint

  Kings Beach 4           1546       NCal     NNev        Nev side of transmission
                                                          constraint

  Kings Beach 5           1547       NCal     NNev        Nev side of transmission
                                                          constraint

  Kings Beach 6           1548       NCal     NNev        Nev side of transmission
                                                          constraint

  Portola 1               1555       NCal     NNev        Nev side of transmission
                                                          constraint

  Portola 2               1556       NCal     NNev        Nev side of transmission
                                                          constraint

  Portola 3               1557       NCal     NNev        Nev side of transmission
                                                          constraint

  SPI 1                   1558       NCal     NNev        Nev side of transmission
                                                          constraint
  ----------------------- ---------- -------- ----------- --------------------------

**Table 7**

**Revisions to Fuel Specification for Generators in AURORA**

  --------------------------------------- ---------- --------- ------------
  **Project Name**                        **ref#**   **BPA     **Revised
                                                     Fuel**    Fuel**

  Apache Station ST2                      14         gas       coal

  Apache Station ST3                      15         gas       coal

  Yucca GT4                               50         gas       FO2

  Heber City NA7                          483        gas       FO2

  Coachella 1                             550        gas       FO2

  Coachella 2                             551        gas       FO2

  Coachella 3                             552        gas       FO2

  Coachella 4                             553        gas       FO2

  El Centro 3                             568        gas       FO6

  El Centro 4                             569        gas       FO6

  Rockwood 1                              573        gas       FO2

  Rockwood 2                              574        gas       FO2

  Lamar Plt IC1                           581        gas       FO2

  Lamar Plt IC2                           582        gas       FO2

  BGI 1                                   707        coal      coke

  Hunters Point GT1                       907        gas       FO2

  Potrero 4                               951        gas       FO2

  Potrero 5                               952        gas       FO2

  Potrero 6                               953        gas       FO2

  Boise Cascade 1                         996        other     gas

  General Chemical 1                      1029       other     coal

  Provo 5                                 1190       gas       FO2

  Provo 6                                 1191       gas       FO2

  Provo 7                                 1192       gas       FO2

  Provo 8                                 1193       gas       FO2

  Valmont 5                               1257       gas       coal

  Pinon Pine 1                            1554       other     FO2

  Steam Plant No 2 1                      1764       other     coal

  Steam Plant No 2 2                      1765       other     coal

  Irvington 4                             1798       gas       coal

  Pueblo IC1                              2048       gas       FO2

  Pueblo IC2                              2049       gas       FO2

  Pueblo IC3                              2050       gas       FO2

  Pueblo IC4                              2051       gas       FO2

  Pueblo IC5                              2052       gas       FO2

  Rocky Ford IC1                          2053       gas       FO2

  Rocky Ford IC2                          2054       gas       FO2

  Rocky Ford IC3                          2055       gas       FO2

  Rocky Ford IC4                          2056       gas       FO2

  Rocky Ford IC5                          2057       gas       FO2

  ARCO CQC KILN                           2211       coal      coke

  EL SEGUNDO REF#2                        2324       coal      gas

  GWF POWER#1                             2382       coal      coke

  GWF POWER#2                             2383       coal      coke

  GWF POWER#3                             2384       coal      coke

  GWF POWER#4                             2385       coal      coke

  GWF POWER#5                             2386       coal      coke

  HANFORD LP                              2387       coal      coke

  LOS ANGELES REF                         2435       gas       other

  MT POSO COGEN                           2484       gas       coal

  NTC-MCRD STEAM TURBINE                  2499       FO2       gas

  PALO ALTO LANDFILL                      2537       other     gas

  PORT OF STOCKTON                        2557       FO2       coal

  RIO BRAVO JASMIN                        2573       coal      coke

  RIVERSIDE CEMENT CO                     2577       coal      coke

  STOCKTON COGEN CO                       2660       gas       coal

  TOSCO SFAR CARBON                       2683       gas       other

  TULARE                                  2688       refuse    gas

  YUBA CITY WWTP                          2746       gas       refuse

  Red Earth Creek Area                    2784       gas       other

  Springfield ICs                         2787       FO2       gas

  Taber area                              2830       gas       other
  --------------------------------------- ---------- --------- ------------

**Table 8**

**Recent On-line Resource Capacity Not Included in AURORA**

**(excluding on-line hydro and wind capacity)**

  ------------------------------ -------------- ------------- ------------- -------------
  **Project Name**               **Missing      **Combined    **Gas         **Other**
                                 Capacity**     Cycle**       Turbine**     

  Oregon/Washington/IdahoNorth   581.5          22            523.2         36.3

  Northern California            1,620.6        134.3         1288          198.3

  Southern California            3,570.6        2,278.9       1046.9        244.8

  British Columbia               778            0             456           322

  Idaho South                    90             0             90            0

  Montana                        0.2            0             0             0.2

  Wyoming                        85             0             85            0

  Colorado                       2,563.6        845           1706.6        12

  New Mexico                     637.2          0             433.2         204

  Arizona/NevadaSouth            4,850.5        3,962.5       888           0

  Utah                           390.7          0             390.7         0

  Nevada North                   104.3          0             0             104.3

  Alberta                        1,001.7        250           515.7         236.1

  **Total**                      **16,273.8**   **7,492.7**   **7,423.3**   **1,357.8**
  ------------------------------ -------------- ------------- ------------- -------------

**Table 9**

**Older Generation Not Included in AURORA**

**(Units Greater than 40 MW)**

  ------------------------------------- ---------- ------------------ -------------
  **Project Name**                      **Area**   **Status**         **MW**

  West Phoenix ST6                      Ariz       restarted          63

  Burrard Thermal ST1                   BC         restarted          152

  Burrard Thermal ST2                   BC         restarted          152

  Burrard Thermal ST3                   BC         restarted          152

  NW Energy CG                          BC                            48

  Burlington GT1                        Colo                          60

  Burlington GT2                        Colo                          60

  Salinas River GTCG                    NCal                          48

  Sargent Canyon GTCG                   NCal                          47.8

  Caithness Dixie Valley Geoth          NNev                          54.1

  Northeast GT                          Wash                          69

  Harbor CCCG                           SCal                          49.8

  Carson CCCG                           SCal                          49.1

  Salton Sea 3 Geoth                    SCal                          46.3

  **Total MW**                                                        **1,051.1**

  **Total of all older units**                                        **1,562.2**
  ------------------------------------- ---------- ------------------ -------------

**Table 10**

**Major New Generation Not Included in AURORA**

**(Units Greater than 40 MW)**

  ---------------------------------- ---------- ---------------- --------------
  **Project Name**                   **Area**   **Online Date**  **MW**

  Bear Creek CCCG                    Alb        Mar-2003         80

  Castle Rock Ridge Wind             Alb        May-2003         100.8

  Fort Macleod GTCG                  Alb        Mar-2003         55

  Foster Creek GTCG                  Alb        Mar-2003         80

  MacKay River GTCG                  Alb        Nov-2003         165

  Mahkeses Cold Lake GT1             Alb        Dec-2002         95

  Mahkeses Cold Lake GT2             Alb        Dec-2002         95

  McBride Lake Wind                  Alb        Mar-2003         75

  Scotford CCCG                      Alb        Dec-2002         170

  Apache Station GT4                 Ariz       Oct-2002         40

  Bighorn CC                         Ariz       Sep-2003         550

  DeMoss Petrie GT2                  Ariz       Jun-2001         75

  Gila River CC1                     Ariz       Jul-2003         575

  Gila River CC2                     Ariz       Jul-2003         575

  Gila River CC3                     Ariz       Sep-2003         575

  Gila River CC4                     Ariz       Sep-2003         575

  Kyrene CC                          Ariz       Oct-2002         250

  Las Vegas II CCCG1                 Ariz       Jan-2003         115

  Las Vegas II CCCG2                 Ariz       Jan-2003         115

  Mesquite CC1                       Ariz       Jul-2003         632.5

  Palo Verde 2 generator upgrade     Ariz       Sep-2003         57

  Saguaro GT3                        Ariz       Jul-2002         80

  Sundance GT1                       Ariz       Jul-2002         90

  Sundance GT2                       Ariz       Jul-2002         90

  Sundance GT3                       Ariz       Jul-2002         90

  Sundance GT4                       Ariz       Jul-2002         90

  Sundance GT5                       Ariz       Jul-2002         90

  Sundance GT6                       Ariz       Sep-2002         90

  La Rosita CC1                      Baja       Apr-2003         375

  La Rosita CC2                      Baja       Apr-2003         375

  La Rosita CC3                      Baja       Apr-2003         310

  Thermoelectrica de Mexicali CC     Baja       Jun-2003         600

  Arrow Lakes Hydro                  BC         Mar-2002         170

  Stave Falls 1-2 rebuild            BC         Dec-2000         40

  Arapahoe CC5                       Colo       Oct-2002         130

  Blue Spruce GT1                    Colo       May-2003         150

  Blue Spruce GT2                    Colo       May-2003         150

  Brighton GT1                       Colo       Apr-2002         77.1

  Brighton GT2                       Colo       Apr-2002         71.1

  Brush IV GT1                       Colo       May-2002         89

  Brush IV GT2                       Colo       May-2002         89

  Fort St Vrain CC3                  Colo       May-2001         235

  Front Range Power CC               Colo       Apr-2003         480

  Limon GT1                          Colo       Feb-2002         70

  Limon GT2                          Colo       Feb-2002         70

  Manchief GT1                       Colo       Jul-2001         156

  Manchief GT2                       Colo       Jul-2001         156

  Plains End IC1-20                  Colo       May-2002         108

  Rawhide GT-A                       Colo       Jul-2002         65

  Rawhide GT-B                       Colo       Aug-2002         65

  Rawhide GT-C                       Colo       Oct-2002         65

  Valmont GT8                        Colo       Jun-2001         40

  Chowchilla II GT                   NCal       May-2001         49

  Creed GT                           NCal       Jan-2003         45

  Feather River GT                   NCal       Dec-2002         45

  Goose Haven GT                     NCal       Jan-2003         45

  Hanford GT1                        NCal       Aug-2001         44

  Hanford GT2                        NCal       Aug-2001         44

  King City GT                       NCal       Jan-2002         48.7

  Lambie GT                          NCal       Jan-2003         45

  Los Banos GT                       NCal       Nov-2001         49.9

  Los Esteros GT1                    NCal       Mar-2003         48.7

  Los Esteros GT2                    NCal       Mar-2003         48.7

  Los Esteros GT3                    NCal       Mar-2003         48.7

  Los Esteros GT4                    NCal       Mar-2003         48.7

  Panoche GT                         NCal       Dec-2001         49.1

  Red Bluff GT                       NCal       Jul-2001         47

  Redding CC                         NCal       Jun-2002         54

  Riverview                          NCal       Apr-2003         45

  Tracy GT1                          NCal       Apr-2003         84.5

  Tracy GT2                          NCal       Apr-2003         84.5

  Vaca-Dixon GT                      NCal       Jun-2002         49

  Valero GTCG1                       NCal       Oct-2002         51

  Wolfskill GT                       NCal       Apr-2003         45

  Woodland CC2                       NCal       May-2003         80

  Yuba City GT                       NCal       Jul-2002         48.7

  Afton GT                           NMex       Dec-2002         135

  Lordsburg GT1                      NMex       Jul-2002         40

  Lordsburg GT2                      NMex       Jul-2002         40

  New Mexico Wind Energy             NMex       Jul-2003         204

  Pyramid GT1                        NMex       Apr-2003         40

  Pyramid GT2                        NMex       Apr-2003         40

  Pyramid GT3                        NMex       Apr-2003         40

  Pyramid GT4                        NMex       Apr-2003         40

  Agua Mansa GT                      SCal       Jul-2003         43

  Blythe CC                          SCal       Apr-2003         520

  Border GT                          SCal       Oct-2001         49.1

  Century GT                         SCal       Sep-2001         43

  Chula Vista GT                     SCal       May-2001         44

  Drews GT                           SCal       Aug-2001         43

  El Cajon GT (CalPeak)              SCal       Jun-2002         49

  Enterprise Escondido GT            SCal       Sep-2001         49

  Escondido GT                       SCal       Aug-2001         44

  Fresno GT                          SCal       Sep-2001         49.5

  Gates GT                           SCal       Dec-2001         45

  Harbor GT11                        SCal       Nov-2001         47

  Harbor GT12                        SCal       Nov-2001         47

  Harbor GT13                        SCal       Nov-2001         47

  Harbor GT14                        SCal       Nov-2001         47

  Henrietta Peaker GT1               SCal       Jul-2002         48

  Henrietta Peaker GT2               SCal       Jul-2002         48

  High Winds Phase 1                 SCal       Jul-2003         70

  High Winds Phase 2                 SCal       Jul-2003         80

  Lake One GT                        SCal       Jul-2002         47

  Salton Sea Geoth                   SCal       Dec-2000         52.3

  THUMS GTCG                         SCal       Dec-2002         47

  Valley GT5                         SCal       Nov-2001         47

  Evander Andrews GT2                SIda       Sep-2002         45

  Evander Andrews GT3                SIda       Sep-2002         45

  Gadsby 4 GT3                       Utah       May-2001         40

  Gadsby 4 GT4                       Utah       May-2001         40

  Gadsby 4 GT5                       Utah       May-2001         40

  West Valley GT1                    Utah       Oct-2001         40

  West Valley GT2                    Utah       Oct-2001         40

  West Valley GT3                    Utah       May-2002         43

  West Valley GT4                    Utah       May-2002         43

  West Valley GT5                    Utah       Jul-2002         43

  BP Cherry Point GT                 Wash       Sep-2001         72.8

  Fredonia GT3                       Wash       Aug-2001         53

  Fredonia GT4                       Wash       Aug-2001         53

  Lange GT                           Wyo        Jun-2002         40

  **Total MW (listed units)**                                    **13,877.4**

  **Total of all units**                                         **14,768.6**
  ---------------------------------- ---------- ---------------- --------------

**Table 11**

**Differences in Wind Generation Capacity in AURORA**

  -------------------------------------- ------------- ------------- -----------
  **Project Name**                       **BPA Cap.**  **Revised     **Diff.**
                                                       Capy.**       

  Oregon/Washington/IdahoNorth           224.5         445.8         221.3

  Northern California                    578.3         777.6         199.3

  Southern California                    1,042.8       1,339.9       297.1

  Wyoming                                68.0          144.6         76.6

  Colorado                               0.0           46.2          46.2

  Alberta                                87.5          95.7          8.2

  **Total**                              **2,001.0**   **2,849.8**   **848.8**
  -------------------------------------- ------------- ------------- -----------

**Table 12**

**Significant Change in Generation Capacity in AURORA**

**(Differences Greater than** ±**25 MW)**

  ------------------------ ---------- -------------- -------------- ------------ --------------------
  **Project Name**         **Ref#**   **BPA Cap.**   **Revised      **Diff.**    **Notes**
                                                     Capy.**                     

  Moss Landing 6           927        739            816            77           upgraded from
                                                                                 original plan

  Moss Landing 7           928        739            815            76           upgraded from
                                                                                 original plan

  Hunter 3                 1038       395            465            70           

  Elk Hills                2805       500            570            70           

  Joffre Cogen Project     2171       416            474            58           

  Los Medanos Energy       2191       500            555            55           

  Boardman 1               1140       533            585            52           rerating Sep. 2000

  APEX Industrial          2792       500            550            50           
  Expansion                                                                      

  Potlatch Corp 1-4        2032       59             101.9          42.9         

  Tenaska 1                1371       245            283.3          38.3         

  Bonanza 1                406        420            452            32           

  Greeley Energy 1         1231       76.3           108.3          32           

  Huntington 2             1040       425            455            30           

  Coronado 1               1426       365            395            30           

  Arlington Valley         2793       550            580            30           

  Intermountain 1          626        830            855            25           turbine upgrade May
                                                                                 2003

  Intermountain 2          627        830            855            25           turbine upgrade May
                                                                                 2002

  COLDGEN SUNLAW COGEN#1   2277       56             28             -28          partial self-gen

  COLDGEN SUNLAW COGEN#2   2278       56             28             -28          partial self-gen

  Chehalis                 2850       548            520            -28          

  Kern River Cogen Co 1    1664       257            227.2          -29.8        partial self-gen

  High Desert              2814       750            720            -30          

  ORMESA IE                2522       38             7              -31          reduced output

  General Chemical 1       1029       32             0.5            -31.5        mostly self-gen

  Geysers 11               879        106            74             -32          reduced output

  SOUTH BELRIDGE COGEN     2653       48             10.2           -37.8        mostly self-gen

  Geysers 16               883        113            73             -40          reduced output

  Watson Cogen 1           1730       340            297.4          -42.6        partial self-gen

  SAN FRANCISCO REF        2589       49.9           4.8            -45.1        mostly self-gen

  Sturgeon Addition        2828       92             46             -46          

  Valleyview (AB)          2832       92             45             -47          

  EXXON USA                2334       49             1.7            -47.3        mostly self-gen

  Geysers 14               882        109            61             -48          reduced output

  Geysers 18               885        113            62             -51          reduced output

  COSO FINANCE PARTNERS 1- 2291       80             29.0           -51          reduced output
  3                                                                              

  LOS ANGELES REF          2435       54             2.5            -51.5        mostly self-gen

  COSO ENERGY DEV 4-6 CAL  2289       84             29.0           -55          reduced output

  Carson Ice CG CC \--     1390       154.9          99             -55.9        partial self-gen
  1/1/2                                                                          

  Texaco Cogen 1           647        60             1.8            -58.2        mostly self-gen

  Sunrise Cogen Power      2849       320            260            -60          
  Project                                                                        

  Geysers 13               881        133            71             -62          reduced output

  Geysers 12               880        106            42             -64          reduced output

  Geysers 20               886        113            49             -64          reduced output

  Geysers 17               884        113            48             -65          reduced output

  Delta Energy Center      2802       880            811            -69          

  EL SEGUNDO REF#2         2324       76.7           2.7            -74          mostly self-gen

  RICHMOND REF COGEN       2570       99             12.6           -86.4        mostly self-gen

  **Total MW**                        **13,244.8**   **12,578.9**   **-666.0**   

  **Total of all BPA                  **110,927**    **109,516**    **-1,410**   
  listed non-wind units**                                                        
  ------------------------ ---------- -------------- -------------- ------------ --------------------

**Table 13**

**Summary Revised Non-Hydro Resource Capacity in AURORA**

  ------------------------------ --------------- ---------------- -------------
  **Project Name**               **BPA           **Revised        **Change**
                                 Capacity**      Capacity**       

  Oregon/Washington/IdahoNorth   10,617.5        10,179.8         -437.7

  Northern California            14,936.3        14,615.8         -320.5

  Southern California            34,501.4        33,399.8         -1,101.6

  British Columbia               1,510.5         1,940            429.5

  Idaho South                    83.3            132.5            49.2

  Montana                        2,360.5         2,350.2          -10.3

  Wyoming                        6,033.1         5,548.1          -485

  Colorado                       7,016.9         9,485.8          2,468.9

  New Mexico                     5,110.0         5,782.5          672.5

  Arizona/NevadaSouth            21,516.8        26,918.2         5,401.4

  Utah                           4,750.7         6,053.2          1,302.5

  Nevada North                   1,806.3         1,944.5          138.2

  Alberta                        10,724.2        10,346.4         -377.8

  **Total**                      **120,644.5**   **128,696.8**    **8,052.3**
  ------------------------------ --------------- ---------------- -------------

**Table 14**

**Summary of Changes to BPA's AURORA Resource Inputs**

  ------------------------------------------------- ---------------------
                                                    **Unit Capacity**

  **Initial BPA Listing**                           **120,644**

  Remove Duplicates                                 -3,671

  Remove Temporary                                  -237

  Remove Unfinished Generation                      -1,771

  Remove Off-line Generation                        -2,037

  Add Recent Generation                             +14,769

  Add Older Generation                              +1,562

  Add Existing Wind Generation                      +849

  Change in Listed Capacities                       -1,410

  **Revised Total**                                 **128,698**
  ------------------------------------------------- ---------------------

**Table 15**

**Comparison of AURORA Load Forecast Inputs**

  ----------------- ------------- ------------- ------------- -------------
  **BPA Forecast**                                            

                    **2003**      **2004**      **2005**      **2006**

  NWPP              25,459        25,897        26,397        26,880

  CALIF             32,806        33,685        34,601        35,535

  CNDA              12,078        12,203        12,510        12,877

  RMPA              5,864         6,052         6,203         6,333

  AZNM              14,796        15,235        15,560        16,026

  WECC              91,002        93,072        95,270        97,652

  **2001 WECC**                                               

                    **2003**      **2004**      **2005**      **2006**

  NWPP              25,533        26,807        27,264        27,728

  CALIF             32,565        34,009        34,872        35,760

  CNDA              13,510        13,785        14,187        14,509

  RMPA              6,699         6,868         7,011         7,161

  AZNM              13,929        14,227        14,661        15,069

  WECC              92,236        95,696        97,995        100,227

  **Delta: WECC --                                            
  BPA**                                                       

                    **2003**      **2004**      **2005**      **2006**

  NWPP              74            909           866           847

  CALIF             \(241\)       324           271           224

  CNDA              1,432         1,582         1,677         1,633

  RMPA              836           816           808           828

  AZNM              \(867\)       (1,007)       \(898\)       \(957\)

  WECC              1,233         2,624         2,725         2,575
  ----------------- ------------- ------------- ------------- -------------

*Q. Does this conclude your testimony?*

A. Yes, it does.