20041124Reconsideration Order No 29638.pdf

Office of the Secretary
Service Date
November 24 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
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 STATE OF IDAHO.
CASE NOS. AVU-O4-
VU -O4-
ORDER NO. 29638
On February 6, 2004, Avista Corporation dba Avista Utilities (Avista; Company)
filed an Application with the Idaho Public Utilities Commission (Commission) for authority to
increase its rates and charges for electric and natural gas service in the State of Idaho.
On October 8 , 2004, the Commission issued final Order No. 29602 authorizing
Avista to increase its Idaho electric base revenue requirement by $24 716 195 or approximately
16.90%. This increase was offset by disallowances in the Power Cost Adjustment (PCA)
coupled with an adjustment in the PCA recovery period and the reduction in the energy
efficiency rider. These offsetting adjustments reduced the authorized electric net revenue
increase to $3 182 000 or 1.9% of current annual revenue. The Commission also authorized
Avista to increase its natural gas revenues by $3 311 000 or approximately 6.38%.
On October 29 2004, Avista filed a Petition for Reconsideration of Order No. 29602.
Idaho Code ~ 61-626. On November 5, 2004, Potlatch Corporation filed an Answer and Cross
Petition for Reconsideration. Also filed on November 5, was Commission Staffs Reply to
A vista s Petition for Reconsideration. The Commission in this Order approves the technical
computation errors identified by the Company and agreed to by Staff and denies the remaining
relief sought in the Company s Petition for Reconsideration and Potlatch's Cross Petition for
Reconsideration.
The respective Petition, Answer and Cross Petition, and Reply can be summarized as
follows:
A vista Petition for Reconsideration
Avista contends that certain portions of the Commission s Order No. 29602 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 that are confiscatory.
ORDER NO. 29638
L Deal A Disallowance
Avista contends that the Commission s disallowance of one-third of the Idaho
jurisdictional share of Power Cost Adjustment (PCA) Coyote Springs 2 (CS2) Deal A losses fails
to recognize evidence of record and was otherwise unreasonable.
In Avista PCA Order No. 29377, Case No. A VU-03-, the Commission deferred a
PCA recovery decision regarding the Company s acquisition and later sale at a loss of natural
gas to fuel the Coyote Springs 2 (CS2) combined cycle combustion turbine. CS2 was initially
scheduled for testing in early 2002 and was expected to be commercially available in July 2002.
As it turns out, at the time the gas was scheduled for delivery CS2 was not operational nor was it
economical to use the gas purchased at the Company s other facilities. Instead Avista simply
purchased its power needs on the electric market and sold the Deal A gas back into the gas
market at a loss because gas prices had declined.
As reflected in the Commission s Order, Deal A consisted of two transactions of
000 dth/day each, for a 36 month delivery term (November 1 2001 through October 30
2004), that were entered into for the purpose of hedging or fixing, the natural gas price of index-
based physical purchases for the period of November 1 , 2001 , through October 31 , 2004. 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 2, 2001 at a price of $6.50/dth. The price for October 2004
gas was locked-in for three and one-half years into the future. The system loss attributable to
Deal A gas through May 31, 2004 was $47 936 000. The Idaho jurisdictional amount disallowed
by the Commission was $4 771 550.
On reconsideration A vista contends, as previously indicated at hearing by its witness
Robert Lafferty, that the combination of net system variability and high/volatile energy prices
posed a "significant economic risk" to the Company. The Company in response elected to hedge
portion of the monthly deficit associated with the combined variability of loads and
hydroelectric generation conditions.
Avista points out that the Commission s own Staff was quite clear and unambiguous
in its recommendation to disallow only Deal B hedge losses. As Staff witness Hessing indicated
Deal A hedges were not done with an A vista affiliate, but Deal B hedges were. Also, the Deal
A gas purchase did not put the Company over the long limit contained in its Risk Policy. . . .
Tr. at 1270. Citing Commission Staff, Avista contends that Deal A was well within the
ORDER NO. 29638
Company s risk parameters or "protocols ; provided the necessary gas supply, at a fixed cost, to
fuel the needed Coyote Springs 2 generation plant; and was not "speculative" 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. Tr. at 1270 1271-1308-09.
A vista includes as an Appendix to its Petition a load resource position summary
based on 90% confidence interval planning that it contends demonstrates that Deal A if looked at
alone, was well within and consistent with the Company s resource planning criteria. Tr. Exh. 7
Sch. 26, p. 2. (A 90% confidence interval represents a 5% chance that the Company would have
to purchase some amount of energy above a specific megawatt amount for a given month.
A vista disputes the Commission s finding that the Company s supporting analysis
appeared to be "cobbled together after the fact, citing Lafferty testimony describing the
Company s analysis. A vista contends that the record reflects that the Company conducted
extensive modeling of its load/resource balance prior to entering into the hedge transactions and
also undertook a comparative analysis of the cost to generate power at the hedged price of gas
compared to electric power prices available at the time.
Avista contends that fixing the price of index-based physical purchases through the
Deal A hedged transactions was also consistent with its electric Integrated Resource Planning
(IRP) objectives.
The Company concludes that when one looks to the "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 hedged transactions were consistent with resource planning objectives and Risk
Policy guidelines or protocols. The record, the Company contends, demonstrates that both the
need for the hedge transactions and the cost of such transactions were, in fact, analyzed before
entering into the transactions. Analysis and documentation pertaining to both the load/resource
deficits and the forward market prices did exist, the Company states, before it entered into the
transactions.
ORDER NO. 29638
Potlatch Cross Petition
Potlatch in its Cross Petition contends as both a matter of law and equity, that the
entirety of the Deal A costs should be disallowed, citing the "just and reasonable" standard of
Idaho Code 9 61-301. The "just and reasonable" rate standard, Potlatch contends, necessarily
assumes reasonable managerial competence and prudence.If a utility spends money
unnecessarily or imprudently, Potlatch contends it should not be allowed to recover such
expenditures. The underlying physical purchases for Deal A had already been made, Potlatch
states. What Deal A, Potlatch contends, did was to lock-in an immediate gamble on the price
direction of the natural gas futures market. The 36-month length of the Deal A hedges and the
financial exposure created, Potlatch contends, was, as reflected in its testimony of Potlatch
witness Dr. Dennis Peseau, unprecedented for A vista, and for the electric industry as a whole.
Potlatch contends that the risk assumed in Deal A was a derivative risk and that the risk was
assumed without any formal cost benefit analysis. The failure of the Company to evaluate it as
an exposure separate and distinct from the physical purchase of gas, Potlatch contends, was not
only imprudent, it was specifically prohibited by Avista s Risk Management Policy. Citing Risk
Management Policy:
Any incremental market exposure created from the use of derivatives
inconsistent with the risk management objectives of this Policy and is not
permitted. The use of derivatives exposes Avista Corp. to risks similar to
risks of physical products, and may have additional liquidity, settlement
legal, and systematic risk attributes. Even the proposed use of derivatives
that would hedge risks should be assessed against these additional risks, and
such use is permitted only to the extent that the expected benefit is
considered to outweigh these risks. Tr. at 956 (Confidential).
Potlatch contends that the Commission s disallowance of one-third of Deal A's cost
is a wholly inadequate remedy. Deal A, it states, was imprudent and "not permitted" under the
Company s Risk Policy and it should be similarly "not permitted" for ratemaking purposes. The
Commission, Potlatch states, can have no basis for finding that any portion of the costs
associated with Deal A can be passed onto ratepayers as a necessary and prudent expenditure.
The Commission, Potlatch contends, simply does not have authority to attempt a middle
approach that attempts to give something to both the utility shareholders and its ratepayers. Deal
A losses, it concludes, must be left with the utility whose incompetence and recklessness caused
their incurrence.
ORDER NO. 29638
Commission Findings
The Commission has reviewed the filings of record in Case Nos. A VU-04-l/A VU-
04-1 including Avista s Petition for Reconsideration, Potlatch's Answer and Cross Petition for
Reconsideration, Commission Staffs Reply, the underlying transcript of proceedings and our
Order No. 29602. We have also reviewed recent customer comments filed with the Commission
opposing further rate increases.
Contrary to Avista s contention, the Commission did recognize evidence of record.
The Commission weighed all the evidence including conflicting evidence and reached its
conclusions.
Despite Avista contention to the contrary, as reflected in the record, the
Commission finds that Deal A did not conform to established protocols. There were no
Commission-approved protocols in place for electric side gas procurement. The transaction both
in length (36 months) and financial exposure was unprecedented for A vista and was
accompanied by little supporting analysis and paper trail, of the sort relied upon by the
Commission s auditing Staff for utility gas Benchmark transactions.The Deal A hedge
transaction was a financial derivative contract.The Company took a price view using
derivatives that despite the Company s contention to the contrary was clearly not permitted
under its internal Risk Management Policy. Nor was the financial transaction, we find, the sort
of physical transaction clearly authorized in the Company s electric Integrated Resource Plan.
The Commission in its Order prefaces its discussion of Deal losses with a
consideration of what it determined to be a threshold issue, the propriety of Avista s transactions
with Avista Energy. Contrary to Avista s contention, the Commission s findings regarding no
operating protocol" being established for transactions between Avista Energy and Avista
electric operations was not a finding of deficiency as to Deal B alone - it was also a finding
regarding Deal A. The need for operating protocols governing conduct between the utility and
its unregulated affiliate exists whether or not A vista Energy was acting as a counter-party.
Although not a counter-party to the Deal A transaction, A vista Energy brokered the deal. Thus
contrary to Avista s contention, Deal A hedge losses cannot be viewed separate and apart from
any A vista Energy involvement.
The Company s Risk Management Policy, we find, was an internal Company policy
intended to provide transactional guidance. It was not an operating protocol filed with or
ORDER NO. 29638
approved by the Commission. The Benchmark Mechanism, on the other hand, is an operating
protocol approved by the Commission; but it exists only on the gas side, not the electric.
The Company s statements regarding the consistency of Deal A hedge transactions
with its risk policy guidelines and resource planning objectives are not sufficient to justify
transactions that were otherwise engaged in without an underlying Commission approved
operating protocol and agency agreement. The Company s actions exposed utility customers to
the risk associated with the Company s non-regulated subsidiary operations. Deal A was highly
irregular and apart from any other transactions made by A vista. The fact that the Company
failed to purchase gas with the same kind of long-term deals for its gas customers that it did for
its electric customers, we find, also demonstrates the Company s inconsistency.
Potlatch contends that the Commission has no choice but to deny recovery of Deal A
amounts. The Commission disagrees. While Avista was certainly engaging in objectionable
transactions in Deal A and B, the transactions themselves were not expressly prohibited by
Commission Order or established protocol. There was no Order; there was no protocol on the
electric side to provide guidance in affiliate transactions. It is a grey area, not black and white.
The Commission has a joint obligation to the utility and its customers. The Commission has
authority under Idaho Code 99 61-501 and 61-301 to assess the reasonableness of the
Company s actions and to determine a reasonable level of cost recovery.
Consequently, we reaffirm our decision to disallow a portion of the losses associated
with Deal A.
Deal A -- Miscalculations
A vista in its Petition also contends that there are four miscalculations related to the
determination of Deal A losses that need to be corrected. The cumulative reduction for the four
Company-identified miscalculations is $2 648 937. Incorporating these four adjustments to the
calculation of 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. Company Contention: Staff Exhibit 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 calculation for Deal A. ... The Company-proposed adjustment is $91 035.
ORDER NO. 29638
Staff Reply
Staff in its Reply concurs with the Company-proposed corrections to the wrong
number of days in the months that were included in Deal A calculations.
Commission Findings
We accept on reconsideration the corrections for number of days in the month
included in Deal A calculations.
B. Company Contention 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. The
Company-proposed adjustment is $35 819.
Staff Reply
Staff in its Reply concurs with the Company-proposed corrections to the calculation
for gas profitably burned for the period November 2003 - May 2004.
Commission Findings
We accept on reconsideration the corrections for Deal A gas profitably burned for the
period November 2003 - May 2004.
C. Company Contention: 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 Company proposed adjustment is $1 060 344.
D. Company Contention: 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 June 2002, however, had previously been authorized by the Commission for PCA
recovery. To order a disallowance based on losses that were previously approved for recovery
would, the Company contends, constitute retroactive ratemaking.
adjustment is $1,461 415.
The Company proposed
Staff Reply - C
The methodology used to calculate Deal A disallowance, Staff contends, is clearly
specified in Order No. 29602 on page 46:
ORDER NO. 29638
Deal A losses through May amounted to $47 936 010 on a system basis;
$15 905 167 on an Idaho jurisdictional basis. With 90/10 sharing the Idaho
PCA amount related to Deal A losses is $14 314 651. Of that amount
636 885 was previously authorized for PCA recovery (July 1 - June 2002).
Based on our consideration of the record and Deal A findings, the
Commission finds it reasonable to exclude or disallow one-third of the Idaho
system Deal A losses, or $4 771 550.
The table below, Staff states, duplicates the Commission specified methodology. The
total amount of Deal A losses, at the system level, is multiplied by the allocation factor for the
Idaho Jurisdiction, to come up with the Idaho Jurisdictional amount of the total Deal A losses.
This amount is then adjusted to reflect the 10% sharing mechanism in the PCA calculation and
the ratepayer portion of the losses. The ratepayer portion is then divided by three to arrive at the
disallowance ordered by the Commission. Using the same methodology with corrections
incorporating the proper number of days and the proper amount of gas profitably burned results
in a Deal A disallowance of $4 608,452.
1. Losses already recovered on Deal A:
2. Losses deferred for recovery on Deal A:
3. Total System losses on Deal A:4. Jurisdictional Factor:
5. Idaho Jurisdictional Portion of Deal A Losses:
6. 10% Shareholder PCA Portion of Deal A Losses:
7. Ratepayer Portion of Deal A Losses:
8. One Third of Ratepayer Portion of Deal A Losses:
9. Disallowance Amount of Deal A Losses:
Commission
Order
$18 876,448
.$29.059.562
$47 936 010
33.18%
$15 905 168
$ 1 590 517
$14 314 651
$ 4 771 550
$ 4 771 550
Commission Order
With Corrections
$18 876 448
$27.421.045
$46 297 493
33.18%
$15 361 508
$ 1 536 151
$13 825 357
$ 4 608,452
$ 4 608 452
With respect to miscalculation items C and D described above, Staff contends that the
Company s calculation of the Deal A disallowance is not consistent with the Commission
Order. Rather than using total Deal A losses of $46 297,493 (as corrected) to calculate the
disallowance as specified by the Commission, the Company, Staff notes, uses only Deal A losses
of $27,421 045 (as corrected) currently deferred for recovery. The Company then improperly
takes one third of the unrecovered Idaho jurisdictional Deal A losses before applying the 10
percent PCA sharing. This is in contrast, Staff contends, to the Commission Order that applies
the 10% sharing first to the Idaho Jurisdictional losses and then takes one third of the remaining
total to establish the disallowed amount.
ORDER NO. 29638
The Company, Staff states, has calculated the Deal A disallowance in the following
manner:
Deal A losses deferred for recovery:
Jurisdictional Factor:
Idaho Jurisdictional Portion of Unrecovered Deal A Losses:
One Third of Idaho Jurisdictional portion of Unrecovered Deal A Losses:
Less 10% of Idaho Jurisdictional portion of Unrecovered Deal A Losses:
Company Disallowance Amount of Deal A Losses
$27,421 045
33.18%
$ 9 098 303
$ 3 032 768
$ 909 830
$ 2 122 937
The Company, Staff contends, perceives inclusion of the $18 876 448 in the Deal A
disallowances calculation to be retroactive ratemaking and therefore, removes the amount to
correct what it characterizes as a calculation error. However, the Commission Order, Staff notes
clearly states ". . . $5 636 885 was previously authorized for PCA recovery (July I-June 2002).
The $5 636 885 is the Idaho jurisdictional ratepayer share of $18 876,448. Total Deal A losses
were simply used in the Order to establish what amount of the additional losses was subject to
recovery through the PCA and what amount was not. Prior amounts recovered in rates are not
being reversed.
Commission Findings
We reject Avista s characterization of the disallowance methodology and stand by
the clear language of the Order that sets out the process used to establish the disallowed amount.
Contrary to Avista s contention, we have not required a refunding of Deal A losses previously
approved for recovery. While our mathematical calculation is based on the total Deal A losses
through May 2004, we find the Deal A disallowance dollar amount to be otherwise reasonable as
a reduction to the unrecovered Deal A loss amount.
In summary, the net effect of the proposed corrections A and B is an increase in Deal
loss recovery through the PCA of $163 098 after applying the Commission ordered
disallowance methodology.
IL Boulder Park
The Commission s disallowance of costs associated with Boulder Park, A vista
contends, was excessive and unduly harsh.
The Commission in Order No. 29602 regarding Boulder Park found a 53%
construction cost overrun to be unreasonable. The original cost estimate in May 2001 was $21
million. The total actual cost upon completion was $31.9 million. The Commission found it
ORDER NO. 29638
reasonable to limit the authorized rate base amount for Boulder Park to the project construction
estimate plus a 15% contingency, or $24 150 000. The Idaho jurisdictional share of the
disallowance is $2.6 million. The Company contends that the disallowance should not exceed
the 10% of final project costs recommended by Staff, $1.1 million (Idaho jurisdictional share).
Potlatch Answer
Regarding Boulder Park, Potlatch supports in its Answer the Commission
disallowance. The simple fact, Potlatch states, is that Boulder Park costs were wildly excessive
when compared to any reasonable cost overrun possibilities. Clearly if Boulder Park had been
purchased from an independent third party contract, Potlatch posits, it would have been
unreasonable for A vista not to cap any potential cost overruns by contract. Similarly, Potlatch
contends, it is not unreasonable for the Commission to impose an overrun limitation on plants
built by A vista.
Commission Findings
The Commission in Order No. 29602 found that Avista should be held to a higher
standard than recommended by Staff. Ratepayers, we found, should not be asked to pay for what
we continue to find to be a Company learning experience.The reasonableness of our
disallowance is not the percentage of total disallowed, but the percentage of cost overrun
allowed.
IlL Pension Expense Adjustment (Electric/Gas)
A vista in its Petition identified a technical correction to the adjustment of the
Company s pension cost. The identified changes are needed to correctly allocate the "system
corporate level of pension expense to utility operations prior to applying the Idaho jurisdictional
allocation factors.The correction results in a $46,411 increase in the electric revenue
requirement and an $11,422 increase in the natural gas revenue requirement. A vista Petition
Attachment D.
Staff Reply
Staff agrees with the technical correction proposed by the Company.
Commission Findings
The Commission accepts the Company-proposed pension expense adjustments.
ORDER NO. 29638
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over this Petition and A vista
Corporation dba A vista Utilities, an electric and natural gas utility, pursuant to the authority and
power granted under Title 61 of the Idaho Code and the Commission s Rules of Procedure
IDAPA 31.01.01.000 et seq.
ORDER
In consideration of the foregoing and as more particularly described above, IT
HEREBY ORDERED and the Commission by this Order on Reconsideration of final Order No.
29602 in Case Nos. A VU-04-1 and A VU-04-1 approves the Deal A technical corrections
for proper number of days and the proper amount of gas profitably burned.
IT IS FURTHER ORDERED and the Commission by this Order approves the
technical corrections to the natural gas and electric pension expense adjustments.
IT IS FURTHER ORDERED and the Commission by this Order denies
reconsideration of the underlying disallowance for PCA Deal A losses and Boulder Park cost
overruns and reaffirms its related findings in Order No. 29638.
THIS IS A FINAL ORDER ON RECONSIDERATION. Any party aggrieved by
this Order or other final or interlocutory Orders previously issued in this Case Nos. A VU - E-04-
and A VU-04-1 may appeal to the Supreme Court of Idaho pursuant to the Public Utilities Law
and the Idaho Appellate Rules. See Idaho Code 9 61-627.
ORDER NO. 29638
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this J. If
1'A.
day of November 2004.
Comm. Smith was Out of the Office this Date
MARSHA H. SMITH, COMMISSIONER
ENNIS S. HANS N, COMMISSIONER
ATTEST:
te:ill D. Jewell
ommission Secretary
bls/O:A VUE0401 A VUG0401 sw8
ORDER NO. 29638