20080603Westerfield Conformed Testimony.pdf

SUBJECT:
Section 1:
Section 2:
Section 3:
Section 4:
Section 5:
INDEX
DIRECT TESTIMONY OF
LOU ANN WESTERFIELD
Witness for the Idaho Public Utilities Commission
THE LOOKBACK ANALYSIS, DEEMER BALANCES, AND THE 1984
AVERAGE SYSTEM COST (AS C) METHODOLOGY
Introduction and Purpose of Testimony ........................................................
Background............................................
.......................................................
The Lookback Analysis is poor public policy because it is retroactive
ratemaking .....................................................................................................
Deemers...............................................................,.........................................
Average System Cost Methodology """""""""""""""""""""""""""........
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DIRECT TESTIMONY OF
LOU ANN WESTERFIELD
Witness for the Idaho Public Utilities Commission
SUBJECT: THE LOOKBACK ANALYSIS, DEEMER BALANCES, AND THE 1984
AVERAGE SYSTEM COST (ASC) METHODOLOGY
Section 1: Introduction and Purpose of Testimony
Please state your name and qualifications?
My name is Lou Ann Westerfield and my qualifications are described in WP-07-Q-
ID-
What is the interest of the Idaho Public Utilities Commission (IPUC) in this
proceeding?
The IPUC regulates the retail rates and services of three ofthe investor-owned utilities
(IOUs) - Idaho Power, Avista, and PacifiCorp - eligible for Residential Exchange
Program (REP) benefits through the Northwest Power Act. Benefits from the REP
are passed directly through to residential and small farm customers using tariffs
and/or processes the IPUC approves.
What is the purpose of your testimony?
The purpose of my testimony is to propose an alternative method to the Lookback
mechanism proposed by BP A for the years 2002 to 2008. My proposal looks forward
from the May 2007 decisions ofthe United States Court of Appeals, for the Ninth
Circuit ("May 2007 Decisions ), avoids retroactive ratemaking, and results in a fair
distribution of REP benefits and new WP-07 preference rates in the region. Thus, I
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am recommending that BP A avoid the pitfalls of retroactive ratemaking by
abandoning both the Lookback Analysis and the inclusion ofthe deemer balances in
the Lookback Analysis and move forward with a clean slate to establish REP benefits
and new WP-07 preference rates. The Idaho PUC's legal analysis is contained in its
Legal Memorandum, WP-07-ID-
Section 2: Background
Did the May 2007 Decisions specify how BP A should address the remanded rates
from the WP-02 rate case?
No. The court remanded the cases to BP A "but provided little guidance to BP A in its
(May 2007 Decisions J regarding the subsequent actions BP A should take in response
to these opinions." BPA Response to APAC's Motion to Strike, WP-07-BPA-
at page 5.
Did the May 2007 Decisions address the WP-07 rate case?
No. However, as BPA explained in WP-07-BPA-52 at page 3, the remand of the
WP-02 rates implicated the WP-07 rates because the latter used the same
methodology to allocate the costs of the REP Settlement Agreements. BPA ceased
payments ofREP benefits to the IOUs effective June 1 2007 in response to the
Court's decisions.
What approach did BP A take in determining proposed rates in this case?
BPA performed a Lookback Analysis that compares the REP benefits the IOUs
received for the 2002-2007 time period under the Residential Exchange Program
Settlement Agreements (RESAs) entered into in 2000 to the REP benefits the IOUs
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would have received using the 1984 Average System Cost Methodology (ASCM)
then in effect. BP A also used the Lookback Analysis to re-determine the Preference
Rate for its Consumer-Owned Utilities (COU) customers for the time period. BP
also included repayment of the deemer balances, derived from Residential Purchase
and Sales Agreements (RPSAs) signed in 1981 , in the Lookback Analysis.
Is the Lookback mechanism the only approach or response to the May 2007
Decisions?
No. In Exhibit 52 BP A recognized that its proposed Lookback mechanism "is only
one of many possible approaches. During the course of this proceeding, BP A is open
to consider other alternatives that parties may advocate." WP-07-BP A-, p. 11 , ll.
18-20.
What else does the Lookback Analysis propose?
The Lookback Analysis proposes to charge interest on the Lookback amounts
calculated for each IOU. (WP-07-BPA-, p. 12 1.7.) Although retroactive
ratemaking is bad public policy, retroactive ratemaking plus interest is even worse
public policy. Additionally, including interest on the Lookback amounts raises the
issue of whether future REP benefits should be applied first to the interest or first to
the principal. Absence elimination of the Lookback mechanism all together, applying
the REP benefits first to the principal is a fairer solution because it reduces future
interest.
Section 3: The Lookback Analysis is poor public policy because it is retroactive
ratemaking
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Does the Lookback Analysis constitute retroactive ratemaking?
Yes. BP A is proposing to recalculate the REP settlement benefits for the IOUs for FY
2002-2008 and in turn, the 2002-2007 preference rates for the COUs. BP A would
then return the past overcharges to the COUs by offsetting further REP payments to
the IOUs.
Is retroactive ratemaking normally used in setting rates?
No. State regulatory commissions and the Federal Energy Regulatory Commission
(FERC) generally set retail and wholesale rates, prospectively, based on the revenues
expenses, and investments of a recent test-year period, adjusted for known and
measurable changes. In May 2000 under Section 7 of the Northwest Power Act, BPA
established the prospective WP-02 rates (subsequently approved by FERC) for the FY
2002-2006 period. In November 2005 , BP A began the process of establishing
prospective rates in the WP-07 proceeding for FY 2007-2009.
The intent of the regulatory ratemaking process is to establish rates that are as
close as possible to the current time period in order to avoid regulatory lag, the time
gap between the incurrence of prudent costs and the recovery of those costs in rates.
Utilities are not static: customer needs, resources used to serve those needs, available
technologies, legal requirements, and financial and economic factors change over
time. Utility business decisions must address the ongoing nature of providing utility
service, and utilities must demonstrate the appropriateness of their operations and
planning processes through the regulatory review process.
How does retroactive ratemaking comport with the regulatory compact?
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Retroactive ratemaking imposes uncertainty and risk on BP A, utilities and
ratepayers/customers because it would allow second-guessing of BP A and utility
decisions and their consequences. The regulatory compact between regulators and the
utilities they regulate (in this case BP A and its customers) seeks to strike a balance
between establishing rates necessary for the utilities to recover the costs of providing
safe, adequate, and reliable service at a fair and reasonable cost to the consuming
public and providing the utilities the opportunity to earn a reasonable return for their
shareholders. In order to strike this balance, the ratemaking process includes the
certainty that, once a ratemaking authority has examined the books, records , costs
and activities of a utility for a time period covered in a rate proceeding and issued an
order, these items will not be re-examined for prudence at some future time.
retroactive ratemaking were the norm, no utility would be certain of recovery of its
costs, particularly, the long-term costs of major capital facilities.
For example, if an electric utility built a generator with an expected life of 40
years, those costs would normally be placed in rates when the generator becomes
operational and the utility files an application to include the generator s capital
operating, and maintenance costs in rates. If retroactive ratemaking were the norm, a
ratemaking authority could decide in year ten of the generator s operation to remove
the generator s costs from rates. Thus, retroactive ratemaking would wreak havoc on
utility decisions and operations, and utilities would be reluctant to invest in new
facilities, even when needed.
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On the customer side, retroactive ratemaking has several adverse effects on
customers. First, it would create rate uncertainty in the form of unanticipated changes
in customers' bills. Past costs excluded from rates today might be included in rates
tomorrow and result in increased rates for customers. Under retroactive ratemaking,
utility rates might yo-yo up and down for years in rate proceedings rehashing past
matters. Adding to this expense and to rates would be the costs of these additional
proceedings.
What are the implications of retroactive ratemaking?
In addition to the ratemaking issues identified, retroactive ratemaking tries to
reconstruct decisions made in the past. Thus, retroactive ratemaking contains not only
the exercise of recalculating the numbers underlying rates, but also the exercise of re-
determining and re-evaluating options available when past business decisions were
made, selecting a different decision from the one actually made, and determining rates
based on that different outcome. Opening the door to retroactive ratemaking creates
the opportunity to overturn both good and bad past decisions and sends the wrong
signal to utilities for future decisions and investments needed to continue serving their
customers.
BPA's proposal in the WP-07 supplemental proceeding is a good example of the
pitfalls of retroactive ratemaking. BP A has proposed to recalculate REP benefits
recalculate ASCs , add interest, address treatment of LRA payments, include dormant
deemers, and adjust future REP benefits well into the future. In addition, there are
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numerous smaller issues that are subject to new decisions (calculating loads, new
loads, resource stacks, etc.) that are included in the Lookback mechanism.
Does BPA's proposed retroactive ratemaking mismatch rates among generations of
ratepayers?
Yes. The worst aspect of retroactive ratemaking is the case when it assigns increased
costs to future ratepayers for actions that benefited past ratepayers. The regulatory
process cannot time the assignment of costs to rates with perfect precision, but
attempts to the greatest extent possible to match costs and benefits to the appropriate
ratepayer generations. The Lookback Analysis BP A proposes would directly transfer
past costs to future ratepayers. In the worst-case scenario , BP A calculates that
approximately 400 000 Idaho Power residential and small farm customers will forego
REP benefits for more than 20 years - past 2028. WP-07-BPA-, p. 207, ll. 25-
27. This demonstrates that even though present and future eligible customers received
no REP benefits, they bear the consequences of retroactive ratemaking.
Were the rates from the WP-02 rate case still in effect when the May 2007 Decisions
were issued?
No. The WP-02 rate period ended on September 30, 2006. "BPA's WP-07 rates were
filed with FERC for confirmation and approval , and interim approval was granted on
September 1 , 2006. Subsequent to interim approval " BP A asked FERC to Stay final
approval and BP A renewed its Stay ofthe final WP-07 rates on March 4, 2008. WP-
07-BPA-, p. 6 11. 16-17. If the proposed Lookback Analysis is used, future IOU
ratepayers will receive decreased benefits due to the difference between REP benefits
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paid during that period and REP benefits determined using the Lookback Analysis
including interest.
Did any party to the WP-02 rate case, the subject of the May 2007 Decisions, ask for a
stay of those rates?
According to BPA's response to Data Requests ID-BPA-, WU-BPA-, and WU-
BPA-3 attached as Exhibit WP-07-ID-ATI , no party requested a stay. Thus, the
WP-02 rates remained in effect during most of the litigation period. This also makes
the Lookback Analysis inappropriate for addressing the May 2007 Decisions. The
decisions do not mandate retroactive ratemaking, much less adding interest, as the
solution.
In performing the Lookback Analysis, what assumptions did BP A make concerning
what the IOUs would have done in the WP-02 rate case absent the RESAs?
Specifically, BP A assumed the IOUs would have signed agreements based on rates
established using the 1984 ASCM, even though REP benefits were not established in
the WP-02 or WP-07 rate cases using the 1984 ASCM.
Is this a reasonable assumption?
No. There is no way to reconstruct in 2008 what the IOUs would have done in 2000
absent the opportunity to sign the RESAs they did in fact sign. There is also no way
to determine in 2008 whether the 1984 ASCM would have been modified or litigated
in the WP-02 or the initial WP-07 BP A rate proceedings if the RESAs had not been
offered to the IOUs. Thus, the Lookback Analysis is based on the false assumption
that REP benefits and ASCs would have been determined in both BP A proceedings
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using the 1984 ASCM when the IOUs might have challenged the use of the 1984
ASCM absent the RESAs.
Is retroactive ratemaking bad public policy?
Yes. For all the reasons discussed, retroactive ratemaking is bad public policy
because it creates rate uncertainty for utilities and ratepayers, transfers cost
responsibility and benefit eligibility unfairly among generations of ratepayers, and
undermines the decision-making process necessary for utilities to serve their
customers on an ongoing basis.
Is there another factor in this proceeding that exacerbates the negative aspects of
retroactive ratemaking as a policy?
Yes. Because the IOUs involved in the REP simply pass through the benefits to their
retail ratepayers, ratepayers bear the entire brunt of the retroactive ratemaking
treatment proposed in the Lookback Analysis through reduced future REP benefits.
Is the impact of reduced future REP benefits significant?
Yes. Although Pacifi Corp and A vista will still be eligible for REP benefits pursuant
to the calculations in the Lookback Analysis, these benefits are reduced to reflect the
difference between benefits received and benefits that would have been received using
the 1984 ASCM. Thus, using the Lookback Analysis harms their current and future
residential and small farm ratepayers through reduced benefits.
What is the impact on Idaho Power?
Taking into consideration only the proposed Lookback Analysis, Idaho Power has a
Lookback balance (not including deemers) of approximately $95.6 million per BPA
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Table 15.4 in BPA Exhibit 44 at page 201. Idaho Power will receive no REP benefits
for approximately ten years. Idaho Power is the only IOU in this situation.
What will be the result for Idaho Power s residential and small farm ratepayers?
During that ten-year period, the approximately 400 000 residential and 17 000 small
farm customers of Idaho Power will not receive any REP benefits while the customers
of the other five IOUs will receive some benefits, although reduced by the Lookback
Analysis.
Is this an acceptable solution for the region?
No. The Northwest Power Act contemplated the distribution ofREP benefits
throughout the Northwest region - not the skipping over of a substantial number of
ratepayers or the skipping over of the majority of IOU customers in the state of Idaho.
The Lookback Analysis proposes a punitive solution to Idaho ratepayers of all three
IOUs, but particularly punitive to Idaho Power s ratepayers.
What alternative solution are you proposing?
In order to avoid retroactive ratemaking and its associated negative results discussed
above, I propose that the level ofREP benefits be established on a forward-looking
basis to take effect in fiscal year 2009 at the conclusion of this proceeding. Further
the REP benefits established for fiscal year 2009 should be determined using the new
2008 ASCM concurrently proposed in a separate rulemaking. The withheld 2007
REP payments together with any true-up of the 2008 interim REP payments will be
available to BP A. For the WP-02 rate period, what is done is done.
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The better solution at this point is to wipe the slate clean and move forward
without imposing any penalties on the REP benefits in the past. Establishing new
REP benefits levels for the IOUs ' ratepayers using an updated and transparent method
for determining ASCs is a fairer solution for the region than trying to rehash and
recast decisions made over eight years ago under very different circumstances.
Section 4: Deemers
What role do the deemer balances play in the Lookback Analysis?
The deemer balances stem from the 1981 Residential Purchase and Sales Agreement
(RPSAs) entered into by three IOUs - Idaho Power, Avista, and Northwestern
Energy. At the time their ASCs, using the 1981 methodology, were purportedly
below the PF exchange rate. In establishing the REP, the Northwest Power Act did
not contemplate the possibility that ASCs for the IOUs would be lower than the
exchange rate, but, rather, assumed that the IOUs' ASCs would all be above the
exchange rate. As a result, the three IOUs entered into 20-year RPSAs in 1981 that
included provisions to carry the difference between their lower ASCs and the
exchange rate as deemed balances and to not pay REP benefits to the three IOUs until
the deemers had been satisfied.
Did the May 2007 Decisions address the deemers?
No. BP A proposes that the deemer balances be included in the Lookback mechanism.
Recast REP benefits are applied first to the deemer balances for the three IOUs, then
to the Lookback balances for the rate period 2002 - 2007. The inclusion of the
deemers constitutes an extreme case of retroactive ratemaking as the deemers arose
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twenty-seven years ago and in the case of Idaho Power will adversely affect
ratepayers for more than 20 years in the future under BPA's proposaL I will address
the deemers that pertain to Idaho Power and A vista.
What is the result for A vista and Idaho Power of including the deemer balances in the
Lookback Analysis in this proceeding?
When the deemer balances are combined with the Lookback amounts, the result is the
reduction of REP benefits for A vista in FY 2007 and the complete elimination of REP
benefits for Idaho Power for at least the next twenty years. Although A vista is able to
resume flowing its REP benefits to eligible ratepayers in FY 2007 even after
consideration of the deemer balances and the Lookback, reducing future benefits for
the deemers is not appropriate. In Idaho Power s case, the result of adding the deemer
balance to the Lookback amount in this case will deprive its ratepayers - 400 000
residential and 17 000 small farm - of REP benefits over an unacceptable amount of
time, while the other IOUs in the region pass the REP benefits through to their
eligible customers.
The Northwest Power Act did not frame the REP program as applicable to IOU
customers in the Northwest except in the state of Idaho. Using the deemers to deprive
Idaho s ratepayers of future REP benefits is bad public policy.
Did the REP Settlement Agreements entered into in 2000 resolve the disputed issue of
the deemer balances?
No.
Is including the deemers in this proceeding appropriate?
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No. Not only did the May 2007 Decisions and the 2000 REP Settlement Agreements
entered into in the context of the WP-02 rate case not address the deemers, the
deemers are a separate contract matter between the affected IOUs and BP A. The
Ninth Circuit did not have the deemer contracts before it, and, thus, including them in
the resolution of this proceeding is inappropriate. The May 2007 Decisions did not
order BP A to fix all past problems, just those associated with the WP-02 rates and the
Settlement Agreements.
Is the resolution of the deemer issue cut and dried?
No. In fact, BP A recognizes that the affected IOUs dispute the deemer balances.
WP-07-BPA-, p. 208. In addition, there is nothing in Section 5 ofthe Northwest
Power Act that authorizes BP A to create deemer accounts or that authorizes BP A to
exchange when an IOU's ASC is less than the PF Exchange rate.
How are the deemer balances reflected in BPA's case?
The deemers are recorded for each affected IOU by state.
Does this present a problem with regard to Idaho Power s deemer?
Yes. Idaho Power s deemer indicates a separate balance for Idaho, Oregon, and
Nevada. In 2001 , Idaho Power sold its Nevada operations to Raft River Rural Electric
Cooperative to comply with Nevada s electric restructuring law. The IPUC order
approving the sale is attached as Exhibit WP-07-ID-AT2. Thus , there is no way
to assess the Idaho Power - Nevada deemer balance to Nevada customers. The
opportunity to do so has long passed.
Are the deemers generally accepted financial obligations of the affected IOUs?
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, not from an accounting standpoint. According to BPA's response to Data
Request PU-BPA-, the deemers have never been recorded in BPA's books and
accounts. See WP-07-ID-AT3. A review of the Annual Reports and Form 10-
filings made by A vista and Idaho Power since 2001 indicates that neither utility
recorded the deemer obligation on their books either.
Is this the normal accounting treatment for an obligation established by contract?
No. BPA and the IOUs use generally accepted accounting principles for recording
financial transactions in their books. BPA's and the IOUs' financial statements are
audited annually by nationally recognized accounting firms that attest to the fact that
BP A and the IOUs use generally accepting accounting principles implemented
through current accounting and financial standards.
The normal treatment for recording this type of obligation would be the creation
of a regulatory asset, or other appropriate deferral, in BP A's books and a
corresponding regulatory liability, or other appropriate deferral, on the affected IOUs
books to reflect the deemer obligation. Regulatory assets and liabilities, or other
similar deferral, are normally amortized over the life of the obligation. However, this
never happened.
Why were the deemer balances not recorded in the books of BP A and the affected
IOUs?
The answer lies in the Workpapers BP A provided in this proceeding. In the Record of
Decision for the 1983 rate case, BP A decided that, if the deemed IOUs ' loads and
resources were included in the Cost of Service Analysis, then the accounting
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obligation did not have to be recorded. The passage below explains this accounting
interpretation.
For ratemaking purposes BP A treats the exchange as a resource transaction.
The exclusion of loads and resources of utilities projected to be in a 'deemed
equal' status from BPA's CO SA load/resource balance would be equivalent to
treating the deemed exchange as an 'accounting ' transaction , and the
nondeemed exchange as a 'resource ' transaction.
1983 Rate Proposal Record of Decision (Ch. 5 Cost of Service Analysis) p. 169 (Issue
#1).
Obviously, BP A chose the alternative described above to achieve other
objectives in determining rates and REP benefits within the region over the time
period since 1981.
From an accounting standpoint, are the deemers a legitimate obligation?
No. Allowing the recovery in rates of off-the-books transactions is inconsistent with
generally accepted ratemaking principles. Ratemaking is based on the ability to
assess the legitimate costs of a utility by examining its books and records. If a
financial transaction is not recorded on a utility s books, then it is not a transaction
recoverable in rates. Frankly, if a state commission determined that a utility were
conducting transactions off the books, the commission would take drastic measures to
stop the activity and insist that it be recorded in the utility s books and be subject to
the same regulatory scrutiny as other utility activities.
What bearing does BPA's decision to flow REP benefits to Avista and Idaho Power
have on the legitimacy of the deemers?
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Because the RPSA contracts state that REP benefits will not be resumed until the
deemer balances are satisfied, a party could argue that the deemers no longer existed
when BP A provided REP benefits to A vista and Idaho Power. Moreover, A vista and
Idaho Power terminated their RPSAs in 1993 , yet the deemer balances continued to
grow. WP-07-BPA-57 at p. 3 , 11. 21-22.
Are there other accounting guidelines that BP A follows?
Yes. BPA follows the u.s. Department of Energy' s (DOE's) accounting order RA
6120.2, entitled "Power Marketing Administration Financial Reporting." FERC
references this accounting order in its order granting interim approval ofthe WP-
rates. Section 6.a. ofRA 6120.2 provides DOE's policy on financial reporting:
It is DOE policy to encourage sound businesslike financial management and
accounting practices in routine accounting and the preparation of power system
financial statements. Power system financial statements will be prepared in
accordance with generally accepted accounting principles as prescribed by the
American Institute of Certified Public Accountants, the Financial Accounting
Standards Board, the General Accounting Office, and the Office of Management
and Budget, as appropriate. To the extent practicable, the PMAs will maintain
their accounts in accordance with the Uniform System of Accounts prescribed
by the Federal Energy Regulatory Commission for public utilities.
This DOE policy statement on financial reporting for the federal power marketing
agencies, including BP A, reaffirms the point that BP A follows DOE accounting order
RA 6120.2, which states as a matter of policy that BPA will follow generally accepted
accounting principles.
What does BP A's 2007 Annual Report say about "Regulatory Assets and Liabilities
On page 58 ofthe Annual Report
, "
Regulatory Assets and Liabilities" are described
as follows:
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BP A defers costs as regulatory assets such that costs will be recovered through
rates during the periods when the costs are scheduled to be repaid. Amortization
is computed using the straight-line method based upon either the estimated
service lives or the periods the costs are included in rates; or based upon specific
amounts included in rates each year. BP A does not earn a rate of return on its
regulatory assets. BP A defers credits as regulatory liabilities in connection with
the rate setting process.
What conclusions can be drawn from DOE accounting order RA 6120.2 and from
BP A's description of Regulatory Assets and Liabilities in its 2007 Annual Report?
Under generally accepted accounting principles, affirmed by RA 6120.2 and
described in BPA's own 2007 Annual Report, there are no exceptions noted or
contemplated for recording legitimate regulatory assets on BP A's books. Neither
generally accepted accounting principles nor RA 6120.2 provide for "off-the-books
transactions. I also reviewed BP A's annual reports for the past ten years and found
the same silent treatment on the matter of the deemers. BP A cannot have the deemers
both ways. As indicated above, BP A chose to keep the deemers out of its official
books. Either the deemers are a contractual obligation creating a regulatory asset that
appears on BP A's books, or the unrecorded deemers do not represent a regulatory
obligation.
In addition to the principal balance of the deemers , has BP A charged interest on the
deemers?
Yes. In reviewing the deemer contracts, BP A acknowledges that A vista paid simple
interest on its deemer balance but Idaho Power (and Northwest) paid compound
interest. This distinction is significant. As BP A explained, A vista s interest "
calculated only on the initial deemer balance (or remaining balance thereof) and not
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on the interest that has accrued." WP-07-BPA-, p. 196 11. 15-17. Idaho Power
agreement specifies that interest compounds, in other words, interest is calculated on
both the initial deemer balance and interest. Id. at ll. 15-26.
Does the accrual of interest have a significant effect on the deemer balances?
Yes. The results are staggering in terms ofthe penalty imposed on both A vista and
Idaho Power for actions taken in the 1980s all in the name of fairly distributing REP
benefits. In the Lookback workpapers accompanying BPA's case in this proceeding,
BPA indicates that Avista s deemer balance is $99 320 467 as of October 2007, the
sum of$69 042 017 for Washington and $30 278 450 for Idaho. The workpapers
indicate that Avista s deemer balance in January 1987 was $27 336 185 for
Washington and $11 988 313 for Idaho, or a total of $39 324 498. The application of
simple interest from 1987 to 2007 has increased A vista s deemer balance 2.5 times.
For Idaho Power, the situation is even worse because BP A used compound, rather
than simple, interest on the deemer balance. The Lookback workpapers indicate that
Idaho Power s deemer balance is $245 362 811 as of October 2007, the sum of
$223 210,742 for Idaho; $19 244 784 for Oregon; and $2 907 285 for Nevada. The
workpapers indicate that Idaho Power s deemer balance in January 1987 was
$52 903 825 for Idaho; $4 561 262 for Oregon; and $689 064 for Nevada, or a total of
$58 154 151. The application of compound interest from 1987 to 2007 has increased
Idaho Power s deemer balance 4.2 times.
Does the interest have a punitive effect?
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Yes. The result of applying interest over such a long period oftime to A vista s and
Idaho Power s deemer balances constitutes the application of a severe penalty to the
REP benefits of both companies' ratepayers. Additionally, there is no justification for
the inequity created by applying simple interest to Avista s deemer balance and
compound interest to Idaho Power s deemer balance. Although BP A believes that
interest should accrue on both the Lookback and the deemers to reflect the time value
of money, the application essentially amounts to a penalty - in the case of the
deemers, an insurmountable penalty for Idaho Power and for A vista a significant
reduction in REP benefits forward.
Are the arguments you made previously concerning the negative aspects of the
Lookback Analysis as a form of retroactive ratemaking also applicable to the
deemers?
Yes, even more so. The deemers sprang from the unanticipated consequence of the
Northwest Power Act not addressing the situation where an IOU's ASC fell below the
PF exchange rate. The deemers were used in the loads and resources of BP A cost-of-
service studies for years and were characterized as resource, not accounting,
transactions. Although the deemers have their roots in RPSAs, the contractual
obligation was never recorded as a regulatory asset or other deferral or amortized on
BP A's books. The RPSA contracts A vista and Idaho Power entered into in 1981
terminated in 1993 without the issue of deemer balances being resolved. Both A vista
and Idaho Power received REP benefits from BP A after entering into the 1981
RESAs , in spite of the prohibition of receiving future REP benefits until the deemer
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balances were repaid. Any resolution of the deemer issue in 2008 will create an
extreme example of inter-generational subsidies of Avista s and Idaho Power
ratepayers. Finally, the deemers are a contractual issue separate and apart from the
rate case in this proceeding and should not be included in any calculation of REP
benefits on a lookback or going-forward basis. The lack of accounting treatment of
the deemer balances in BPA's books over the past 27 years - not to mention the
absence of any authority in Section 5 of the NP A - challenges the legitimacy of the
repayment obligations that BP A has proposed. I recommend that the deemer balances
not be included in the resolution of this rate proceeding.
Does BPA's proposed treatment of Idaho Power s deemer balance undermine any
other BP A goals?
By including the deemer balance and continuing to accrue interest, BP A will not
achieve its goal of maintaining a reasonable level of REP payments balanced against
repaying the Lookback amounts in 20 years or less. Given the inability of BP A and
Idaho Power to address the deemer balances, Idaho Power s ratepayers are severely
disadvantaged. In essence, Idaho Power ratepayers are penalized for BPA's and
Idaho Power s inability to resolve or address the deemer balance account. The IPUC
strongly encourages Idaho Power and BP A to settle their deemer dispute.
Section 5: ASC Methodology
Do you have a recommendation concerning what BP A should do if it insists on
calculating the Lookback amounts and in establishing new preference rates?
CONFORMED COpy
WP-07-ID-ICC
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Witness: Lou Ann Westerfield
Yes. BP A is developing a new ASCM in a concurrent rulemaking proceeding and
intends to apply the results of that rulemaking to the rates in this case. The facts that
the 1984 ASCM has never been fully litigated because ofthe RESAs and that the
electric utility industry has changed substantially since 1984 in terms of resource
development and options, market operations, and load growth in the Northwest - all
point to the need to use an updated ASCM. As proposed in the ASCM rulemaking, it
would be transparent by relying on readily available data from FERC Form No.
reports, would be easy to update on an annual basis, and would be sustainable going
forward. I recommend that BP A include the results of the ASCM rulemaking in
determining final rates in this proceeding.
Does this conclude your testimony?
Yes.
CONFORMED COpy
WP-07-ID-ICC
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Witness: Lou Ann Westerfield