20041029Petition for Reconsideratin.pdf

DAVIDJ. MEYER
Vice President and Chief Counsel for Regulatory
and Governmental Affairs
VISTA CORPORATION
East 1411 Mission Avenue
Spokane, W A 99220
[phone]
Attorney for A vista Corporation
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OCT 29 P;JilO: 2 ;
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN
THE ST ATE OF IDAHO
) CASE NO. A VU-04-
A VU-04-
VISTA CORPORATION'
PETITION FOR
RECONSIDERATION OF
COMMISSION ORDER NO. 29602
A vista Corporation (hereinafter referred to as "A vista" or "the Company ), pursuant to
RP 33 and 331 et seq , and Section 61-626, Idaho Code, respectfully petitions the Commission
for reconsideration of Order No. 29602, dated October 8, 2004, issued in Case No. A VU-04-
01 and A VU-04-1 (the "Order ). Avista requests reconsideration of Order No. 29602 because
certain portions are unreasonable, unlawful, erroneous, and not otherwise in conformity with the
facts of record and/or the applicable law, resulting in a revenue requirement and rates which are
confiscatory. This Petition is based on the following reasons and upon the following grounds:
A VISTA'S PETITION FOR RECONSIDERATION -
THE COMMISSION'S DISALLOWANCE OF ONE-THIRD OF THE COMPANY'
JURISDICTIONAL SHARE OF DEAL A LOSSES.. AS PART OF ITS REVIEW OF
POWER COST ADJUSTMENT (PCA) ISSUES.. FAILS TO RECOGNIZE EVIDENCE
OF RECORD AND WAS OTHERWISE UNREASONABLE
The Commission s Decision With Reference To "Deals A and B" Natural Gas Hedge
Transactions.
Among the PCA issues deferred for resolution in this general rate case , were the costs
associated with so-called "Deal A" and "Deal B" natural gas hedge transactions. Deal A
consisted of two transactions of 10,000 dthlday each, for a 36-month delivery term, that were
entered into for the purpose of hedging, or fixing, the natural gas price for the period November
, 2001 through October 31 , 2004. Lafferty Direct, Tr. at 564. One transaction was entered into
on April 11 , 2001 at a price of $6.7525/dth and the second transaction was entered into on May
, 2001 at a price of $6.50/dth. (
The second set of transactions, referred to as "Deal B " consisted of two hedge
transactions of 10,000 dthlday each, for the 17 month delivery term June 2002 through October
2003. One transaction was entered into on April 10, 2001 and another transaction on May 10
2001, at prices of $6.50/dth and $5.35/dth, respectively. (. at 565.
As explained by Mr. Robert Lafferty, Manager, Wholesale Marketing and Contracts
A vista was "in a short position on an average basis for the periods of the natural gas
transactions.. at 566.1 Accordingly, given its short position and high price volatility, the
Company had serious concerns regarding the exposure to high energy prices for the Company
and its customers. These concerns were magnified by the Company s exposure to the variability
1 The "short position" refers to the reliance on resources to serve retail customers where the cost of energy is based
on short-term wholesale market prices for either electricity or natural gas, i.e., the Company and its customers are
exposed to the volatility of short-term wholesale market prices.
A VISTA'S PETITION FOR RECONSIDERATION - 2
of hydroelectric generation as highlighted by the low level of hydroelectric generation in 2001.
The combination, therefore, of net system variability and high/volatile energy prices posed a
significant economic risk" to the Company, as testified to by Mr. Lafferty. (
Accordingly, the Company elected to hedge a portion of the natural gas purchases that
had been secured in March of 2001? According to Mr. Lafferty, the amount hedged covered a
portion of the monthly deficits associated with the combined variability of loads and
hydroelectric generation conditions. (
In its Order, the Commission disallowed the entirety of Deal B hedge losses, in the
amount of $6,496,669, noting that, in its view, these transactions were "highly irregular" and
speculative" and that the Company was "operating outside its own risk management policy.
(Order at p. 45). Moreover, inasmuch as the Deal B transactions were with the Company
affiliate, A vista Energy, the Commission noted that no "protocol" had been established for
transactions between A vista Energy and A vista s electric operations. (. at p. 44)
In addressing Deal hedge losses, however, the Commission noted that there were
certain differences that justified a basis for different treatment:
Among those differences are the counterparties themselves, neither of whom were
affiliates of A vista Utilities , and Staffs analysis that demonstrates that these
transactions, had an operating protocol been in place, would have been viewed by
Staff to be within the Company s established risk management limits.
(Order at p. 45.) The Commission deemed a "reasonable disallowance" to be one-third of the
total losses, or $4 771 550 (Idaho s share).
As explained by Company Witness Lafferty, through the financial hedge transactions of Deals A and B , the
Company fixed the price on the physical natural gas purchases for Coyote Springs 2, in order to limit exposure to
higher prices and to provide a measure of price stability for customers. (Tr. at p. 610.) It should be remembered that
the physical purchases of natural gas made by the Company were at "monthly index prices " and that Deal A and
Deal B served to fix the price of the physical purchases. (. at p. 611.
A VISTA'S PETITION FOR RECONSIDERATION - 3
In this Petition, although the Company does not agree with the reasoning behind the
Commission s decision to disallow all of Deal B hedge losses and one-third of Deal A hedge
losses, the Company, nevertheless, has elected to pursue reconsideration only of the
Commission s decision with respect to Deal A hedge losses.3 This should serve to eliminate all
issues concerning affiliate transactions, inasmuch as Deal A, unlike Deal B , did not involve
A vista Energy as a counterparty. Accordingly, the need for "operating protocols" governing
conduct between a utility and its affiliate, which formed the basis for disallowance of Deal B
costs, is not at issue. Deal A hedge losses, therefore, can be viewed strictly on their merits
separate and apart from any A vista Energy involvement. As discussed below, there should be no
disallowance of Deal A losses.
The Commission s Own Staff Was Correct In Not Opposing The Recovery Of Deal
A Hedge Losses.
Staff Witness Keith Hessing, in his direct testimony, was quite clear and unambiguous in
his recommendation to disallow only Deal B hedge losses:
Deal "A" hedges were not done with an Avista affiliate, but Deal "B" hedges
were. Also, the Deal "A" gas purchase did not put the Company over the long
limit contained in it's Risk Policy, the Deal "B" purchase which was executed at a
later point in time caused the utility to exceed the long limit. Not only did the
transaction place A vista above the long limit, but A vista s position continued to
stay above the limit.
Hessing Direct Tr. at 1270.) Therefore, not only did Staff Witness Hessing recognize that Deal
A was not done with an affiliate, Deal A also did not put the Company over the long limit
contained within its risk policy. In other words, it was well within the Company s risk parameters
or "protocols.
3 There is, however, a simple miscalculation of the disallowance that affects both Deal A and B that needs to be
corrected, in any event, as discussed below in Section I.C.
A VISTA'S PETITION FOR RECONSIDERATION - 4
Furthermore, Mr. Hessing acknowledged, at Transcript page 1271 , that "Avista needed
the Coyote Springs 2 plant to reduce its dependence on what had become a highly volatile energy
market." According to Mr. Hessing, "Coyote Springs 2 was to be one of the most efficient
combined cycle gas-fired combustion turbines in the region with a 7,000 BTU/kWh heat rate.
. at 1271-72) Mr. Hessing further noted that the "power needed by customers could be
generated at a cost below the market price.) Simply put, Deal A provided the necessary
gas supply, at a fixed cost, to fuel a needed generation plant.
Moreover, Staff Witness Hessing was quite clear in his VIew that Deal A was not
speculative," notwithstanding his views with respect to Deal B. This was evident in his response
to Commissioner Hansen s question:
Mr. Hessing, I know what you ve stated in your testimony; however, I
guess I'm just a little confused by your answers to Mr. Ward's questions
and I would like you to clarify for me again, if you would, whether you
think Deal A was speculative or not, and if it was not, would you explain
again why it is not.
Well, I think Deal A had some common characteristics with Deal B and it
took a price view at the time, but it wasn t speculative, in my mind, I guess
beyond what I have already said because it aligned the Company s loads
and resources for the future and within the limits that were set in the
Company s risk policy; and it was Deal B that went beyond the limits of
the risk policy and the one which is part of the reason that Staff is
challenging the costs of Deal B.
(Emphasis added) (Tr. at pp. 1308-09.
While the absence of "protocols" governing dealings between A vista and its affiliate
Avista Energy, may have had a bearing on the resolution of Deal B hedge transactions, no
affiliate was involved in the Deal A transactions. In terms of "protocols " in a broader sense, there
were, in fact, "risk policy guidelines" in place. As discussed above, both Company and Staff are
in agreement that Deal A did not violate the limits or protocols of the Risk Policy. In fact, as
A VISTA'S PETITION FOR RECONSIDERATION - 5
noted earlier, Mr. Hessing concluded with regard to Deal A that ". . . it aligned the Company
loads and resources for the future and within the limits that were set in the company s risk
policy.
" (
. at 1309.
In his rebuttal testimony, Company Witness Lafferty provided a chart (attached hereto as
Appendix A) demonstrating the Company s load and resource position (at a 90% confidence
interval) after including both Deals A and B. It is clearly evident from this analysis that Deal A
if looked at alone was well within, and consistent with , the Company s resource planning
criteria. (See also Exhibit 7, Schedule 26 , p. 2.
Moreover, there was sound analysis conducted by the Company that supported its
decision to enter into the Deal A hedge transaction; it was not "cobbled together" after the fact.
Mr. Lafferty, in his direct testimony, beginning at Transcript page 578 , describes the Company
analysis with reference to its exposure to "net position variability." As he explains, in March of
2001 , the Company had performed a Prosym hourly model analysis of monthly net positions for
2002-2004. That model was used to produce data representing the change in the Company s net
system requirement position resulting from the combined monthly statistical variability of
hydrogeneration and load using both a 90% and 95% confidence interva1.4 The results of that
study, as set forth in the attached Appendix A (also appearing at Schedule 26 of Exhibit 7), were
described above. This demonstrated that the hedges served to reduce - not entirely eliminate -
the Company s net position exposure based on 90% confidence interval planning. Stated
differently, with generation available from Deal A natural gas, the Company covered a portion,
4 "Confidence Interval" (CI) represents the probability of the hydro-load variability staying within a specific MW
range. A 90% CI represents a 5% chance that the Company would have to purchase some amount of energy above a
specific MW amount for a given month.
A VISTA'S PETITION FOR RECONSIDERATION - 6
but not all, of its exposure to volatile wholesale prices , as testified to by Mr. Lafferty. (Lafferty
Direct, Tr. at 580.
Not only had the Company, as part of its analysis, conducted extensive modeling of its
load/resource balance prior to entering into the hedged transactions, it also undertook
comparative analysis of the cost to generate power at the hedged price of gas compared to
electric power prices available at the time. The results of this analysis showed that the hedged
natural gas fuel resulted in generation costs in the range of approximately $38/MWh to
$48/MWh for CS2, which was substantially lower than the high-price power available in the
market. (Tr. at 581.
Moreover, under its integrated resource planning or protocols on the electric side of its
business , A vista s resource portfolio includes generation from hydroelectric, coal, wood-waste
natural gas, and wind resources. In addition, the portfolio has regularly included purchases of
power on a long-term, medium-term and short-term basis. These long-term, medium-term and
short-term purchases are generally made at fixed prices, as testified to by Mr. Lafferty. (Lafferty
Rebuttal, Tr. at p. 614.) Therefore, fixing the price of index-based physical purchases through the
Deal A hedge transactions, was altogether consistent with the Company s resource planning
objectives or protocols.
Therefore, when one looks to "prudence" of decision-making at the time the decisions
were made, the evidence demonstrates that (a) an analysis of the load/resource balance with Deal
A had been conducted, demonstrating that even with Deal A, the Company was in a resource
deficit position, and (b) that an examination of forward prices, at the time, demonstrated that the
hedged natural gas fuel would result in generation costs of between $38/MWh to $48/MWh -
well below the higher-priced power available in the market, and (c) that Deal A hedge
A VISTA'S PETITION FOR RECONSIDERATION - 7
transactions were consistent with resource planning objectives and risk policy guidelines or
protocols.
In his rebuttal testimony, Company Witness Lafferty, at Transcript page 619, provided a
chart which showed a comparison of the cost to generate power with the Deal A natural gas
versus the forward price of electricity at the time.5 This demonstrated that the Deal A
transactions "were clearly a lower cost resource for Avista.) Therefore, both need for the
hedge transactions and cost of such transactions were, in fact, analyzed before entering into the
transactions.
Staff Witness Hessing, on cross-examination, agreed that he has "seen information
provided by the Company" that justified purchasing gas at $6:
In other words, would you agree that Deals A and B , at the time they were
entered into, reflected the cost of the gas that the Company chose to lock
in prices for; in other words, a cost defined by those forward market
pnces.
I have seen information provided by the Company that showed that
forward electric prices were high enough to iustify purchasing gas at $Qjf
that's the only consideration that is viewed.
(Emphasis added) (Tr. at p. 1305.
Accordingly, analysis and documentation pertaining to both the load/resource deficits
(even with Deal A included) and the forward market prices did exist before the Company entered
into the transactions. The following documentation was provided for the record in this case and
was available for review by Staff and other interested parties:
Forward market prices for both electricity and natural gas are based on actual forward transactions and
actual price bids and price offers by counterparties in the marketplace. These forward market prices are commonly
used in the electric and natural gas industry to establish prices for, among other things, medium-term transactions,
financial hedge transactions, and to mark-to-market electric and natural gas portfolios for accounting purposes, as
explained by Company Witness Lafferty. (Tr. at p. 618.) In this regard, Avista Utilities is a "price-taker" in the
market and "pays prices equivalent to the forward prices offered by the marketplace," as testified to by Mr. Lafferty.
(Id
A VISTA'S PETITION FOR RECONSIDERATION - 8
The GaslElectric Transaction Record is contained in Confidential
Schedule No. 21 of Exhibit No.
The Position Report for the relevant days including the cover memo
describing market transactions and conditions is contained in Confidential
Schedule No. 31 of Exhibit No.
The information in the Long-Term Physical Electric Load & Resource
Tabulation was presented in different forms and data is summarized in
Schedule No. 26 and Schedule No. 17 of Exhibit No.
Forward electric prices compared to the cost to operate the gas-fired
generation that the Company expected to operate are summarized on a
table in Schedule No. 19 of Exhibit No.
Natural Gas price curves are contained in Schedule No. 27 of Exhibit No.
Comparisons of electric market price vs. cost to generate with the most
efficient generation unit are contained in the table in Schedule No. 19 of
Exhibit No.7 and are also recorded on the GaslElectric Transaction
Records.
Third party natural gas forward price data is attached to the GaslElectric
Transaction Records.
In conclusion, with reference to Deal A, Staff appropriately concluded: (1) that
affiliate" concerns were involved; (2) that it was not "speculative ; (3) that it did not place the
Company outside of its risk policy guidelines or protocols (unlike Deal B , according to Staff);
(4) that forward electric prices were high enough to justify hedging the purchase costs of gas at
$6 levels; and (5) that Deal A provided the necessary gas supply, at a fixed cost, for the needed
Coyote Springs 2 generating plant. All of this attests to the "prudence" of Deal hedge
transactions at the time they were entered into.
In its Order at page 46, the Commission determined that there should be a "sharing of risk
between ratepayers and shareholders" with reference to these hedging activities. As discussed by
Mr. Lafferty, however, there have been many other transactions that the Company has entered
A VISTA'S PETITION FOR RECONSIDERATION - 9
into within its risk policy guidelines, which when viewed with hindsight are very favorable for
customers:
. . . A hindsight analysis of Avista s purchase of 200 MW for the period July 2000
through December 2003 shows that it was over $236,000 000 less expensive than
purchasing at index prices. In addition, based on current market conditions the
100 aMW of more recent purchases described above for the period 2004 through
2010 will provide customers with over $46,000 000 of benefits.
Lafferty Rebuttal Tr. at 617.) The benefits of these transactions have inured primarily to
ratepayers, not shareholders.
Accordingly, the Commission s decision to disallow "one-third" of the costs of the Deal
A transaction was arbitrary and was not supported by evidence of record.
Even If The Commission Were To Continue To Disallow A Portion of Deal A Hedge
Losses, It Has Miscalculated The Disallowance.
The preceding discussion demonstrates why the Commission should not disallow any
the Deal A costs. Should it, nevertheless, decide to continue to disallow "one-third" of Deal A
costs, there are four miscalculations related to the determination of Deal A losses that need to be
corrected. One of the issues, involving the wrong number of days in the month, also affects Deal
B. The four issues are:
The Commission-ordered disallowance of $4 771 550 is based on "one-
third" of the Deal A losses. The Company has already absorbed 10% of the total Deal A
losses through the 90%/10% sharing feature of the PCA. The effective disallowance
therefore 40%of the total losses - not the "one-third" disallowance ordered by the
Commission.
The Deal A disallowance is based on total Deal A losses for the period
November 2001 through May 2004. The losses in the period November 2001 through
A VISTA'S PETITION FOR RECONSIDERATION - 10
June 2002, however, had previously been authorized by this Commission for PCA
recovery.
Staff Exhibit No. 141 , relied upon by the Commission, has the wrong
number of days for the months of July 2003 through May 2004. This error overstates the
loss calculations for both Deal A and Deal B.
The Staff Exhibit No. 141 calculation of Deal A gas losses includes an
incorrect calculation of the Deal A gas profitably burned for the months of November
2003 through May 2004. It included only one-half of the Deal A gas profitably burned
and should have included all of it, since Deal B had ended October 31 2003.
Incorporating these four adjustments to the calculation of Deal A gas losses results in a
Deal A disallowance of $2,122,937. This compares to the Deal A disallowance of $4,771,550 in
Order No. 29602. A summary of the adjustments is shown in Table 1 below. A detailed
worksheet of these adjustments is shown as Attachment B. Attachment C, consisting of Staff
Exhibit No. 141 , has been revised to correct for these errors.6 These calculations are derived
from evidence of record.
In addition, as noted above, the number of days in the months is incorrect for the period
July 2003 through October 2003 for the Deal B loss calculation.Making this technical
correction reduces the Deal B loss by $113,620 from $6,496,669 to $6,383,049. This corrected
calculation for Deal B loss is also shown on Attachment C.
The Actual Deal A Disallowance is More Than One-Third of The Total Loss.
In its Order at page 46, the Commission found a reasonable disallowance for Deal A to
be one-third of the total losses. The ordered disallowance of $4 771 550, however, is based on
6 While Staff Exhibit No. 141 is marked as "confidential " given the passage of time, the Company is prepared to
waive this claim for purposes of facilitating this request for reconsideration.
A VISTA'S PETITION FOR RECONSIDERATION -
one-third of the deferred losses for Deal A. The Company has already absorbed 10% of the total
Deal A losses through the 90%/10% sharing feature of the PCA. Therefore, the effective
disallowance, adding the "one-third" of the deferred losses to the 10% already absorbed, is 40%
of the total losses.
In order to make the disallowance equal to one-third of the total losses, the disallowance
must be reduced such that the disallowance, plus the 10% already absorbed by the Company, is
equal to one-third of the total losses.Making this adjustment alone, without the other
adjustments, would serve to reduce the Deal A disallowance to $3,711,206. A summary of this
adjustment is shown on Table 1 below. A detailed worksheet for this adjustment is shown as
Attachment B.This adjustment, moving from a 40% effective disallowance to a 33%
disallowance based on total losses, is carried through each of the subsequent adjustments
discussed below.
The Deal A Loss Period Includes Months Previously Authorized For PCA
Recovery
In its prior Order No. 29377, dated November 18, 2003, regarding the Company s PCA
deferrals for the period July 2002 through June 2003 , the Commission deferred decisions
regarding losses on the sale of Deal A gas ($5,935,949 plus interest of $77,064) pending further
consideration in the Company s next electric general rate case. Deal A losses for the period
November 2001 through June 2002 were not included in that amount and were not set aside for
further consideration. The PCA deferral balance approved for recovery for the twelve (12) month
period ending June 2002, in Order No. 29130, dated October 15 2002, included approval of Deal
A costs for the period of November 2001 through June of 2002.
In Order No. 29602 an amount of $4 771 550 for Deal A losses were disallowed which
incorrectly includes the amount previously approved for Deal A losses for the period November
A VISTA'S PETITION FOR RECONSIDERATION - 12
2001 through June 2002. The Commission recognizes its previous approval of 90% of Deal A
losses for the November 2001 through June 2002 period in Order No. 29602 when it states at
page 46 that
, "
Of that amount $5,636,885 was previously authorized for PCA recovery (July 1 -
June 2002)." Were the Commission to order a disallowance based on losses that were previously
approved for recovery, it would, in effect, be engaged in retroactive ratemaking. Therefore, an
adjustment is necessary in order to reflect only the amount of the Deal A disallowance beginning
in July 2002.
For the period July 2002 through May 2004, one-third of the total Deal A loss amount is
$2,249,791. This adjustment is shown on Table 1, below.
Wron2 Days In The Month Were Included In Both Deals A and B
Staff Exhibit No. 141 , relied upon by the Commission, has the wrong number of days in
the month in the purchase expense calculation and the sales revenue calculation for the months
of September 2003 through May 2004.This affects both the Deal A and Deal B loss
calculations. For the purchase expense calculation shown in Exhibit 141 , every month beginning
in July 2003 has 31 days. Instead, some months should be 30 days and February 2004 should be
29 days. For the sales revenue calculation in Exhibit 141 , every month beginning July 2003 has
30 days; instead, some months should be 31 days and February 2004 should be 29 days. These
adjustments affect July 2003 through May 2004 for Deal A and July 2003 through October 2003
for Deal B. Correcting for this calculation error reduces the Deal A disallowance by $91 035.
This adjustment is shown in Table 1 , below.
Correcting for this calculation error also reduces the Deal B disallowance by $113,620
from $6,496,669 to $6,383,049. This corrected calculation for Deal B loss is also shown on
Attachment C, which is a revised Staff Exhibit No. 141.
A VISTA'S PETITION FOR RECONSIDERATION -
The Deal A Loss Calculation Includes An Incorrect Calculation For Gas
Profitably Burned For The Period November of 2003 Throu2h May of 2004
Only one-half of gas profitably burned was included in Confidential Staff Exhibit No.
141 for the Deal A loss calculation for the period November 2003 through May 2004. The full
amount of gas profitably burned should have been included for Deal A during this period.
Staff Witness Hessing recognized in his direct testimony, at Transcript page 1263, that
some gas has been burned profitably and, as a result, made adjustments to remove that gas from
the Deal A and Deal B loss calculations. Accordingly, Staff Exhibit No. 141 , relied upon by the
Commission, removes the gas that was profitably burned both from Deal B and from Deal A
through October 2003 , splitting the amount assigned to each on a fifty-fifty basis. However
there is an error in the calculation that occurs in the November 2003 through May 2004 period
where only one-half of the gas profitably burned is removed from Deal A. After Deal B ended on
October 31 2003, all of gas profitably burned should have been assigned to Deal A.
One-third of the total loss amount resulting from the adjustment for this calculation error
reduces the Deal A disallowance by $35,819. This adjustment is shown in Table
Summary
While the Company believes that there should be no disallowance associated with Deal
, correcting for certain miscalculations would serve to reduce the Deal A disallowance to
122,937. A summary of the adjustments to the Deal A disallowance is shown below in Table
1. A detailed worksheet of these adjustments is shown as Attachment B.
A VISTA'S PETITION FOR RECONSIDERATION - 14
Table 1
Deal A Loss Adjustments
Adjusted Cumulative
Disallowance Reduction
Based on from
Adjustment One-Third of $4,771 550
Total Commission
Adjustments to Deal A Losses Disallowance Losses Disallowance
Adjustment from 400/0 to one-third 060,345 $3,711 206 060,345
Adjustment to Remove Nov 2001 - Jun 2002 -$1,461,415 249,791 521 759
Adjustment to Correct for Wrong Number of
Days -$91,035 $2,158,756 -$2 612 794
Adjustment to Correct for Amount of Gas
Burned $35,819 122 937 $2,648,613
II.
THE COMMISSION'S DISALLOWANCE OF COSTS ASSOCIATED WITH BOULDER
PARK WAS EXCESSIVE
While the Commission s Order did not take issue with the prudence of Boulder Park as a
resource, it did disallow $7.62 million of costs (on a system-basis) relating to the construction of
the Company s 25 MW Boulder Park natural gas-fired generating plant. The Commission noted
that the original cost estimate in May of 2001 was $21 million, but that the total actual cost, upon
completion, was $31.9 million. (Order at p. 17.) The Commission deemed it reasonable to limit
the authorized rate base to the original project construction estimate of $21 million plus a 15%
contingency, or $24,150 000. This was then compared with the final cost of Boulder Park of
approximately $32 million, resulting in a disallowance of $7.62 million on a system basis
(Idaho s share is $2.6 million).
A VISTA'S PETITION FOR RECONSIDERATION -
A disallowance of $7.62 million out of a $32 million project, represents a disallowance of
approximately 25% of total project costs; or, stated differently, approximately two-thirds of the
cost overruns, after giving effect to the 15% contingency, were disallowed. This level of
disallowance is unduly harsh, when viewed in the context of the record in this case and given its
own Staffs recommendations.
Turning now to the evidentiary record developed at hearing, the only witness (other than
from the Company) to address the Boulder Park issue was Staff Witness Sterling. Mr. Sterling
began by expressing his belief that it was reasonable for A vista to develop the Boulder Park
project. (Sterling Direct, Tr. at 1219.) He noted that market prices at the time were extremely
high and no one knew if or when such high prices might subside. He further observed that
utilities were pursuing a variety of generating options as well as demand management programs.
According to Mr. Sterling, "I thoroughly reviewed the Company s analysis that it completed at
the time a decision was made to pursue the project. At that time, I believe a decision to proceed
was reasonable.(Tr. at 1219.) And, it is true that the Commission, in its Order, does not take
issue with the prudence of the project.
Mr. Sterling, however, goes on to note that, when the project was first proposed, A vista
estimated the construction cost to be $21 million. () That estimate was later revised upward to
$23.65 million on June 17, 2001. (. at 1220.) The Company s explanation for the cost overruns
that subsequently occurred was as follows: "The excess cost for the Boulder Park Project
generally stemmed from the fast track design-build approach that the Company chose in order to
bring small generation on line as quickly as practical in order to mitigate the high prices and
volatility in the electric power market during the energy crisis." (Emphasis added.) (Tr. at 1220.
A vista chose a "fast track-design build approach" in order to bring small generation projects on
A VISTA'S PETITION FOR RECONSIDERATION - 16
line as quickly as practical to mitigate the high prices and volatility in the electric power market
during the energy crisis. Given that approach, a limited amount of the initial engineering was
completed in preparation of the initial estimates of project cost. Therefore, it is reasonable to
expect that the original project cost estimates would inevitably escalate when using this
approach.
Under different circumstances, more of the engineering and design work would have
been completed and incorporated into the initial project cost estimates prior to project start.
However, such an approach would have delayed the planned construction schedule. The
Company believes its decision to use the "fast track design-build approach" was reasonable given
the circumstances of the energy crisis. It is therefore reasonable to expect a broader range in the
project's costs than the 15% range adopted by the Commission, given such fast-track design
approach called for under the circumstances. Accordingly, while the Company continues to
believe that there should have been no disallowance ordered in this case, any disallowance
should not, in any event, exceed that recommended by Staff, as discussed below.
Using preliminary initial construction cost estimates, however, for ultimately judging the
reasonableness of the final cost of a project is not necessarily fair or reasonable, as expressly
acknowledged by Staff Witness Sterling:
I might also add that using the initial construction cost estimate as the basis for
judging the reasonableness of the final construction cost is not necessarily always
fair. The initial estimate could be low or inaccurate.
(Emphasis added) (Sterling Direct, Tr. at 1224.) Indeed, Staff Witness Sterling went on to
acknowledge, at Transcript page 1221 , that "some of the explanations (for the cost overruns) are
reasonable
" :
Avista clearly did not anticipate many of the problems encountered in the
project's construction or many of the requirements imposed on the project by
A VISTA'S PETITION FOR RECONSIDERATION -
other agencies. For example, the Company cites incomplete construction plans
being provided by the engine generator manufacturer, handicapped building
access requirements, road width requirements, paved instead of graveled site
grounds, building soundproofing requirements and construction plan approval
delays as among the many unexpected factors. I agree that many of these delays
and requirements could not have been anticipated.
(Emphasis added) () With that in mind, Staff Witness Sterling recommended that 10% of the
final project costs be disallowed, deeming such a disallowance to be a "fair amount." (. at
1224.) Mr. Sterling noted that a 10% disallowance would correspond with three particular cost
categories that merited attention: first, construction management costs of $2,159,000 were 2.
times the revised project estimate; secondly, A vista s project management, engineering and
project commissioning costs were $1,110 000; and thirdly, an additional $912 714 was incurred
because of the additional time required to complete the project. In total, these three factors
resulted in a cost overrun of $3,221 714, or approximately 10% of the total final project costs.
. at 1223.
In the final analysis , the only evidence of record challenging the Company s construction
costs for Boulder Park came from Staff Witness Sterling. Mr. Sterling, with a degree in Civil
Engineering, offered his expert opinion, based on a detailed analysis of the cost overrun
components, and concluded with a recommendation that 10% of the final project costs be
disallowed. This was based on specific examination of particular components of the cost-
overrun. The Commission, however, went well beyond his recommendation and disallowed
nearly 25% of the final project cost ($7.62 million out of a total cost of $32 million). The
evidence of record, therefore, suggests that the Commission level of disallowance was
excessive. A vista believes that a more appropriate level of disallowance, if any disallowance is to
A VISTA'S PETITION FOR RECONSIDERATION -
be ordered, should reflect the expert analysis of Mr. Sterling, and should result in a total
disallowance not exceeding $3.2 million (or $1.1 million for Idaho s share).
III.
TECHNICAL CORRECTION TO PENSION ADJUSTMENT
The electric revenue requirement should be increased by $46,411 and the natural gas
revenue requirement should be increased by $11 422 to correctly reflect the impact of the
Commission s adjustment to the Company s pension costs. In determining the net operating
impact ("NOI") of the pension cost reduction, the necessary step of allocating the "system
corporate level of pension expense to utility operations prior to applying the Idaho jurisdictional
allocation factors was omitted. Allocation of the system level of pension expense must first be
allocated 92.22% to utility operations. This methodology was utilized by the Company in its
direct filing and is reflected in Mr. Falkner s workpapers. The allocation to utility operations
was also utilized by Mr. English in preparation of the Staff pension cost adjustment. As noted in
Attachment D column (d), the utility allocation of 92.22% was properly utilized in the
determination of the $1 549 386 and $381 311 authorized pension cost levels for electric and
natural gas, respectively, as shown on lines 9 and 17. However, that step was omitted in the NOI
calculations recreated in column (b), as shown on line 14 and 23. Staff has advised the Company
that they concur with this correction.
Finally, to lend further perspective to this issue and, while not an excuse for cost overruns, it is true that Boulder
Park, even at $32 million, was cost-effective vis-a-vis other alternatives. As shown in Exhibit 8, Schedule 35, page
, the original estimated cost of $21 million for Boulder Park resulted in a net present value benefit of $11 million
when compared with other alternatives (which is, coincidentally, the approximate amount of the cost overrun).
A VISTA'S PETITION FOR RECONSIDERATION - 19
IV.
NA TURE AND EXTENT OF EVIDENCE AND ARGUMENT TO BE OFFERED ON
RECONSIDERA TION
In accordance with the Commission s Rule of Procedure 331 , A vista is required to state
the nature and extent of evidence or argument it will present or offer if reconsideration is
granted. A vista believes that the evidentiary record before the Commission and the applicable
law requires that the Commission modify Order No. 29602 for the reasons set forth in this
Petition for Reconsideration. A vista, accordingly, does not believe that any further evidence is
necessary for the Commission to reach that conclusion. Nevertheless, the Company is prepared
to present additional testimony in support of each of the items it has identified as requiring
modifications as set forth in this Petition.
In conclusion the Company respectfully requests that the Commission grant
reconsideration and modify its Order in accordance with the foregoing.
+11
DATED this ~day of October, 2004.
VISTA CORPORATION
~/Jf
avid J. Meye
Vice President and Chief Counsel for
Regulatory and Governmental Affairs
I:\Spodocs\11150\OOOOl\plead\OO264556.DOC:lg
A VISTA'S PETITION FOR RECONSIDERATION - 20
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A VIST A UTILITIES
Analysis of Commission Allowed Pension Cost
Case No. A VU-04-01 and A VU-04-
A TT A CHMENT D
I ~~~ Description
(a)
Original Ordering Corrected Ordering
Calculation Page Calculation Page Difference
(b)(c)(d)(e)(f)
Commission Allowed System Pension Cost $ 10,347 343 pg24 $ 10,347 343 pg24
Company Direct Case System Pension Cost 000,000 000,009
System Adjustment to Pension Cost $ (3 652 657)$ (3,652,657)
Allocation to Utility (1)92.22%
Commission Allowed 542,320 (805,023)
Company Direct Case 12,910,800 089,200)
Utility Adjustment $ (3,368,480)284 177
Allocation to Idaho Electric 16.237%
Commission Allowed 680,098 549,386 pg24 (130 712)
Company Direct Case 273,180 096,327 (176,853)
Idaho Electric Adjustment (593,082)(546,940)142
State Income Tax 01078 393 896 (497)
Federal Income Tax 205,341 189,365 (15 976)
Net Operating Income Effect 381,348 pg24 351 679 (29,669)
Increase to Revenue Requirement 63926 46,411
Allocation to Idaho Gas 996%
Commission Allowed 413,480 381 311 pg55 (32 169)
Company Direct Case 559,440 515,916 (43,524)
Idaho Gas Adjustment (145,960)(134 604)11,356
State Income Tax 01078 573 1,451 (122)
Federal Income Tax 50,536 46,604 (3,932)
Net Operating Income Effect 93,851 pg55 86,549 (7,302)
Increase to Revenue Requirement 63926 11,422 I
(1) Original calculation of the Commission Allowed Pension Cost adjustment did not take into account the step of
allocating the system pension cost to the utility operations prior to applying the Idaho Jurisdictional electric and gas
allocation factors. This overstatment the expense impact of the pension cost adjustment by $46 142 electric and
$11,356 gas which in turn overstated electric NOI by $29,669 and gas NOI by $7,302.