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IPC-E-01-7 CARLOCK, T(Di)1
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
Q.Please state your name and address for the
record.
A.My name is Terri Carlock. My business
address is 472 West Washington Street, Boise, Idaho.
Q.By whom are you employed and in what
capacity?
A.I am employed by the Idaho Public
Utilities Commission as the Accounting Section
Supervisor.
Q.Please outline your educational background
and experience.
A.I graduated from Boise State University in
May 1980, with a B.B.A. Degree in Accounting and in
Finance. I have attended various regulatory,
accounting, rate of return, economics, finance and
ratings programs. I chaired the National Association
of Regulatory Utilities Commissioners (NARUC) Staff
Subcommittee on Economics and Finance for over 3
years. Under this subcommittee, I also chaired the Ad
Hoc Committee on Diversification. Since joining the
Commission Staff in May 1980, I have participated in
audits, performed financial analysis on various
companies and have presented testimony before this
Commission on numerous occasions.
Q.What is the purpose of your testimony in
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IPC-E-01-7 CARLOCK, T(Di)2
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
this proceeding?
A.The purpose of my testimony is to address
the issues identified in Order No. 28722, IPC-E-01-7
and IPC-E-01-11 for Idaho Power Company (Idaho Power,
Company). These issues are trading practices (to
include hedging, transmission and wheeling charges,
Mid-C pricing and the use of weighted average pricing)
and what has been termed the November trading event.
All of these issues pertain to Case No. IPC-E-01-7 and
IPC-E-01-11. The trading practices going forward
pertain to Case No. IPC-E-01-16.
In initiating the present investigation
regarding the $51.235 million of disputed power
purchases, the Commission intended to investigate the
Company’s “trading practices (to include hedging,
transmission and wheeling charges, Mid-C pricing, and
the use of weighted average pricing)”. Order No.
28722 at 17. In the prefiled direct testimony of
several of its witnesses, the Company asserts that
Staff’s challenge to the Company’s trading practices
in the 2000-2001 PCA year is contrary to prior
Commission Orders. The Staff does not agree with some
of the characterization or inferences drawn from these
interpretations of prior Commission Orders.
In particular, the Company maintains that
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IPC-E-01-7 CARLOCK, T(Di)3
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
the hedging and use of the Mid-C Price Index for day-
ahead and real-time purchases were “previously
reviewed and agreed to between Idaho Power and Staff
and formally approved by the Commission in Order No.
28596 in Case No. IPC-E-00-13.” Idaho Power Response
to Comments at p. 8. As discussed later in more
detail, Staff disagrees with Idaho Power’s
characterization that the Price Index Mechanism is not
subject to review.
Staff recommends the assignment to the
non-operating entity and therefore no recovery from
Idaho customers of both the November transaction
amount of $7,976,701 and the excess transfer pricing
for power of $51,234,902 (Idaho jurisdictional
numbers). These adjustments follow normal regulatory
practices intended to protect customers from potential
affiliate abuse. Staff further recommends Idaho Power
establish and implement additional objectives and
safeguards prior to acceptance of the Index pricing
mechanism in future Power Cost Adjustment cases.
POWER COST ADJUSTMENT OVERVIEW AND HISTORY OF TRADING
PRACTICES
Q.Please provide an overview of the Power
Cost Adjustment (PCA) mechanism.
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IPC-E-01-7 CARLOCK, T(Di)4
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
A.The PCA is a regulatory mechanism that
allows for annual recovery or rebate of 90 percent of
power costs differing from those already included in
rates. The PCA rate adjustment has two components.
First, power cost differences are projected each
spring based on known snowpack. Second, differences
between the projection and actual costs are tracked
and trued-up in the following year. Inaccuracies in
the projection can cause large after-the-fact true-up
adjustments. Actual power costs come from the
Company’s books and are verified by Staff audit each
spring. By its nature, the mechanism allows for
deferral of the costs and recovery after the fact.
The majority of the audit verification takes place
with the true up portion after the fact. Once the
audit is complete, the Commission determines the
amount of the deferral to authorize for recovery.
Q.Has the PCA mechanism changed since it was
first implemented in 1993?
A.Although the basic PCA framework remains
essentially the same, the PCA has evolved and changed
over the years. Several of these changes are
discussed in Company witness Greg Said’s prefiled
direct testimony at pages 9 – 16.
When Idaho Power entered the speculative
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IPC-E-01-7 CARLOCK, T(Di)5
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
commodity trading business for non-system purposes in
1996, the accounting and reporting was not sufficient
to adequately separate trades between system and non-
system purposes. In Staff comments dated May 7, 1999,
Case No. IPC-E-99-3 (Staff Exhibit No. 108, p. 3),
Staff specifically addressed its concern with the
Company’s inability to accurately make this
separation. Staff continued to express its concerns
in the IPC-E-01-7 and IPC-E-01-11 Staff comments dated
April 16, 2001.
Each year since 1996 when non-system
trading activities began, Idaho Power made some
changes to the way the separations were made. These
changes were often made during the PCA year. Staff
reviewed the changes after the fact and accepted them
or made recommendations for further changes. Most of
this process occurred between the Staff and Company
during the audit. Other interested parties also
participated at times. Changes were also made by
Idaho Power to the pricing mechanism used to make the
separations. These changes were not prospective but
reviewed as part of the PCA. The prudence of all
transactions was always reviewed after the fact during
the true up phase of the PCA. Staff reviewed the
transactions based on the information available at the
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IPC-E-01-7 CARLOCK, T(Di)6
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
time that the decision was made.
Q.Staff made an adjustment for approximately
$51 million associated with the transfer price from
the non-system operation to the regulated system.
Please explain why.
A.The market price is not reflective of a
reasonable price surrogate between the system and non-
system for the intra-month purchases. The transfer
price between affiliates must be shown to be
reasonable.
To compensate for this change, Staff
proposes to modify the pricing mechanism for the 2000
– 2001 PCA year for intra-month to more accurately
reflect the total cost. The non-system purchases were
less costly overall than the system purchases at
market index. Since these transactions are with a
speculative arm of IDACORP (regardless of whether IES
was a part of Idaho Power or a separate subsidiary
dealing with Idaho Power), Idaho Power must show the
continued reasonableness of the transfer prices. The
lower-of-cost or market for purchases and the higher-
of-cost or market for sales is the standard default
pricing mechanism used for regulated entities when a
proper pricing mechanism between affiliates entities
has not been justified.
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IPC-E-01-7 CARLOCK, T(Di)7
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
Enhanced audit steps are performed to
review affiliate transactions and to protect customers
from possible affiliate manipulation. In connection
with the stipulation made in Case No. IPC-E-00-13 and
reflected in Order No. 28596, it was clear that
continued review of the pricing mechanism would occur.
This assurance was provided to address the concerns
of parties in the case related to the affiliate
contract and contract pricing.
Q.Please compare system and non-system term
transactions.
A.Term transactions were implemented for
non-system purposes but effectively stopped for system
purposes after September 2000. Staff is concerned
that Idaho Power has substantially limited long-term
power contracts (i.e., in excess of one month) for the
system-operating book. Confidential Staff Exhibit No.
109 shows the actual system purchases. This exhibit
shows no term purchases for January and February 2001
as shown in Columns 3 and 4. Long-term purchases
entered prior to the IES contract, account for minor
term purchases for the system in Columns 5 and 6.
Confidential Staff Exhibit No. 110 shows the actual
non-system purchases of approximately 80% for January
and February 2001. Confidential Staff Exhibit Nos.
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IPC-E-01-7 CARLOCK, T(Di)8
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
111 and 112 reflect the sales transactions. All
Exhibit Nos. 109 through 112 show graphs to reflect
the day ahead, real time, term and total transactions
for the 2000 – 2001 PCA year.
The ability to purchase power at a fixed
price is a valuable tool for rate stability. In the
past, the Company has purchased large amounts of power
at relatively inexpensive prices to serve its load.
This is a change in activity and operations that was
not expected. On the contrary, the parties were
assured during the Company’s workshops that the
operations would not change.
Q.Isn’t it reasonable to expect non-system
transactions to differ from system transactions due to
the increased level of risk the non-system may be
willing to bear?
A.Yes, the magnitude of the transactions
would differ. The non-system may execute additional
and potentially more risky deals. However, the
direction and the existence of transactions should be
consistent. Therefore, since the non-system executed
term transactions, the system should have had some
corresponding transactions within its risk bands.
Term transactions reduce the price
variability and usually the cost for that time period.
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IPC-E-01-7 CARLOCK, T(Di)9
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
Since the term transactions were effectively stopped
for the system, the cost to customers was higher. The
power purchases were shifted to intra-month and priced
at the market index.
Q.Please describe the background events
leading to the Company’s current trading practices?
A.Company witness Sharon Hoyd outlines the
development of wholesale power markets following
FERC’s issuance of Order Nos. 888 and 889 in 1996. As
she explains in her prefiled direct testimony at pages
3 – 11, while the development of markets and the use
of various market devices such as futures and options
increased, the accounting industry was also developing
more stringent accounting rules. The purpose of these
new accounting rules was to appropriately separate the
buying and selling of energy for utility operation
from the buying and selling of energy for trading or
speculative purposes. Eventually, the Financial
Accounting Standards Board (FASB) and its Emerging
Issues Task Force (EITF) promulgated Generally
Accepted Accounting Principles (GAAP) for these
transactions. The adoption of accounting standards
resulted in the issuance of Statement of Financial
Accounting Standards (SFAS) 133, SFAS 138, and EITF
98-10.
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IPC-E-01-7 CARLOCK, T(Di)10
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
Q.What do these standards require?
A.I agree with Ms. Hoyd’s explanation that:
EITF 98-10 was written to give
clarification between energy
contracts and energy trading
contracts for accounting purposes.
SFAS 133 and SFAS 138 were written to
ensure that all obligations with
market price exposure are reflected
in the financial statements.
Hoyd Prefiled Direct Testimony at 7, ll. 7-11
(emphasis added).
Q.Did the Company and Staff discuss the
adoption and application of these new accounting
standards to Idaho Power?
A.Yes. In a letter dated March 18, 1999 to
the then administrator of the Staff’s Utility
Division, Company witness Ric Gale stated that the
Company was changing its classification and reporting
of purchase and sales transactions relating to its
power trading operations. Staff Exhibit No. 113 at p.
1. In particular, transactions (including purchases
and sales) pertaining to “the balancing of the
[Company’s] system load and . . . system reliability
are classified as ‘system’ [transactions].” Id.
Conversely, transactions not related to the balancing
of the system load and resources are classified as
“non-system” transactions. Id. Idaho Power requested
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IPC-E-01-7 CARLOCK, T(Di)11
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
that the administrator provide a “letter indicating
the Commission’s acknowledgement of these changes.”
Id.
Q.Did the administrator forward a letter to
the Company?
A.Yes. In a April 7, 1999 letter to Mr.
Gale, Stephanie Miller (the Utilities Division
Administrator) noted that the Commission understands
the Company’s implementation of the system and non-
system accounting. Idaho Power Exhibit No. 9. Her
letter stated that the Commission “does not take
exception to the described accounting changes but
reserves judgment on ratemaking issues related to the
exclusions of these [non-system, marked-to-market]
transactions from the PCA.” Id.
Q.What was the next historical event?
A.As a result of implementing the accounting
changes, the Company in the 1999-2000 PCA case (Case
No. IPC-E-99-3) separated power transactions for the
months of January, February, and March 1999 into
operating and non-operating transactions. Idaho Power
Exhibit No. 7, Order No. 28049 at 2. The Order
further recites that the Staff asserted in its
comments that “it is unable to reach any firm
conclusions about future effects of removing the non-
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IPC-E-01-7 CARLOCK, T(Di)12
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
operating power marketing transactions from the PCA.”
Id. at 3.
In that PCA case, the Industrial Customers
of Idaho Power (ICIP) also expressed concern that
removal of the non-operating sales from the PCA would
remove the revenue accruing to ratepayers from such
sales. Id. “The ICIP is concerned that Idaho Power’s
management has every incentive to maximize the amount
of sales removed from the PCA while minimizing the
amount of expenses removed.” Id.
Likewise, FMC (now Astaris) expressed
similar concerns. In particular, the Order recites
that FMC insisted that “ratepayers are entitled to
assurances that costs are properly allocated to the
Company’s competitive activities and the ratepayers
are compensated for any use of utility resources to
support the speculative trading.” Idaho Power Exhibit
No. 7, Order No. 28049 at 4.
The Commission agreed with FMC and ICIP
that:
Adequate safeguards must be in place
to ensure that the Company’s
ratepayers are protected from the
risks associated with such
[speculative trading] activities. We
believe that it is premature to
conduct a formal hearing relating to
this issue but agree that further
consideration of this issue is
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IPC-E-01-7 CARLOCK, T(Di)13
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
warranted. We direct the Commission
Staff to coordinate with Idaho Power,
FMC, the ICIP and all other
interested persons to determine,
informally, how best to address the
issue. Those parties might consider
conducting a workshop. If necessary,
any or all of them are free to
petition this Commission to initiate
a formal case. Regardless, we expect
that some written work product will
ultimately emanate from the efforts
of the parties containing an analysis
of the issue and a recommendation
regarding what action, if any, is
needed by this Commission.
Idaho Power Exhibit No. 7, Order No. 28049 at 5.
Q.Following the issuance of this Order on
May 14, 1999, did the parties participate in a
workshop?
A.Yes. As verified by Company witness Said
on page 14 of his prefiled direct testimony, a
workshop was held on September 23, 1999.
Q.Did the workshop result in a “written work
product”?
A.Yes. Staff Exhibit No. 114 reflects the
memorandum dated February 14, 2000 the Staff submitted
a two-page memorandum with four attachments
representing written materials filed by Idaho Power,
the Commission Staff, ICIP, and Astaris. Staff’s
written report labeled as Attachment D (Staff Exhibit
No. 114, pgs. 51 - 56), noted that Staff examined the
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IPC-E-01-7 CARLOCK, T(Di)14
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
off-system transactions for only the month of August
1999 “and finds the adjusted Mid-C average daily price
to be an acceptable price to use for these inter-book
transfers. . . . The Staff concluded that the Mid-C
price with the transmission adjustment is a fair and
just pricing mechanism to use for the inter-book
transfer [between operating and non-operating books of
Idaho Power].” Staff Exhibit No. 114, p. 51.
The Staff Report also noted that Idaho
Power customers “are not necessarily benefiting from
the relationship shared with the energy trading
activities.” Id. Prior to the end of revenue sharing
on December 31, 1999, customers shared the risks and
any benefits from the energy trading contracts. Staff
concluded that new discussions between the parties
needed to be held to discuss risk, rewards, and
allocations in basic rates.
Q.Was the Staff memorandum dated February
14, 2001 submitted into the 1999-2000 PCA case record?
A.No, however, in Order No. 28358 issued May
9, 2000, the Commission acknowledged that the Staff
Report was previously filed with the Commission.
However, the mention of the Staff Report addressed
only ICIP’s recommendation that the Commission
initiate a new proceeding “to consider changes to rate
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IPC-E-01-7 CARLOCK, T(Di)15
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
structure for Idaho Power.” Staff Exhibit No. 115,
Order No. 28358 at 5.
Q.Did the 1999-2000 PCA Order No. 28358
(Case No. IPC-E-00-6) address hedging or the use of
the Mid-C Price Index?
A.No. For this reason, the Commission
should not infer from Greg Said’s prefiled direct
testimony at page 15, lines 6 - 16, that the
Commission did so. The Commission “acknowledged the
Staff memorandum addressing the accounting change
concerns raised by opposing parties.” But as he
indicates in the next sentence, the accounting change
alluded to by the Commission Order No. 28358 concerns
the separation of “energy contracts” (i.e., operating
transactions) from “energy trading contracts” (i.e.,
non-operating transactions).
Q.What happened next?
A.IDACORP created the IDACORP Energy
Solutions affiliate (IES) to be responsible for
natural gas commodity trading. IDACORP expanded the
IES duties to include the wholesale power market
purchases and sales for Idaho Power. To formalize the
relationship between the non-regulated affiliate (IES)
and the regulated utility (Idaho Power), the Company
filed an application on September 1, 2000 requesting
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IPC-E-01-7 CARLOCK, T(Di)16
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
approval of a proposed Electric Supply Management
Service Agreement (“the Agreement”) between Idaho
Power and IES. This was assigned Case No. IPC-E-00-
13.
Q.In their prefiled direct testimonies
Company witnesses Said and Gale imply that Commission
Order No. 28596 in Case No. IPC-E-00-13 authorized the
Company to utilize Mid-C Price Index for real-time and
day-ahead transactions. Staff Exhibit No. 116, Order
No. 28596. Do you concur with these assessments?
A.No, I believe the Company’s reliance upon
this Order is premature for several reasons. First,
in the IPC-E-00-13 case, Idaho Power filed an
application requesting approval of the proposed
Agreement between Idaho Power and its unregulated
affiliate, IES. Staff Exhibit No. 117. What the
Staff and Company do agree upon is that Order No.
28596 approved the adoption of the proposed Agreement.
Where the Company and Staff disagree is the effect of
the adoption.
It is Staff’s contention that by its
explicit terms the Agreement and its Statement of
Services (including use of the Mid-C Price Index in ¶
5.1 of the Statement of Services) were not effective.
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IPC-E-01-7 CARLOCK, T(Di)17
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
Staff Exhibit No. 117 at p. 7. However, paragraph 9
of the Agreement provides
9. Commission Approval. This
Agreement and any future amendments
shall not become effective until the
Commissions have issued their
respective final orders approving the
agreement or any future amendments.
If the final orders of any of the
Commissions initially approving this
agreement contain material terms or
conditions that either party finds
unacceptable, within fourteen (14)
days of the issuance of the order,
the adversely affected party will
have the right to cancel this
agreement by giving thirty (30) days
written notice of cancellation to the
other party.
Staff Exhibit No. 117 p. 7 (Agreement ¶ 9 at p. 4)
(emphasis added). The term “Commissions” specifically
include the Idaho Public Utilities Commission, the
Oregon Public Utilities Commission, and the Federal
Energy Regulatory Commission. Staff Exhibit No. 117
at ¶ 6 p. 7. Given the explicit terms of the
Agreement, it is Staff’s position that its operating
terms, including the use of the Mid-C pricing
mechanism, were not effective at the time this
Commission issued its Order No. 28596 approving the
Agreement on December 19, 2000.
Q.When did the Agreement become effective?
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IPC-E-01-7 CARLOCK, T(Di)18
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
A.By its own terms, the Agreement did not
become effective until the Oregon PUC and FERC
approved the Agreement. FERC conditionally approved
the Agreement effective April 28, 2001. See Exhibit
No. 118 (95 FERC ¶ 61,147 (2001)). FERC did not
approve the Agreement as initially submitted.
Instead, FERC required the Agreement to be modified to
reflect that the Mid-C Price Index not be used for
real-time transactions. Staff Exhibit No. 118 at pp.
1-2. On May 14, 2001, Idaho Power and IES filed the
requisite change to its pricing of real-time
transactions. Staff Exhibit No. 119.
Q.When did the Oregon Commission approve the
Agreement?
A.The Oregon PUC did not issue its approval
until July 3, 2001. Staff Exhibit No. 120. Thus,
under the terms of the Agreement, it was not effective
until July 3, 2001 -- well after the end of the 2000-
2001 PCA year.
Q.Has the Company submitted the FERC
required change to the Agreement for this Commission’s
approval?
A.As of July 20, 2001, the Company had not
filed an application requesting that the Idaho
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IPC-E-01-7 CARLOCK, T(Di)19
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
Commission approve the FERC required amendments to the
Agreement.
The Pricing Mechanism and Disputed $51 Million
Q.Did the Company provide any rationale for
why it utilized the pricing mechanism contained in the
Agreement even though the Agreement was not effective?
A.In Company witness Gale’s direct prefiled
testimony in the combined IPC-E-01-7 and IPC-E-01-11
cases, he was asked a question about when the Company
implemented any of the pricing mechanisms included in
the Agreement. He replied:
Yes, the Company adopted the transfer
price for real-time hourly
transactions once the IPUC approved
the Electric Supply Management
Agreement. This change was
implemented not because the Agreement
had become effective, but because
once the Agreement and the transfer
pricing were approved by the IPUC,
the Company viewed the new real-time
transfer price as the appropriate
price.
Prefiled Direct Testimony Gale at p. 6, ll. 10-
16.
Q.Was the Company’s use of the Mid-C Index
effective on a going forward basis as of the date of
the IPC-E-00-13 Order, December 19, 2000?
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IPC-E-01-7 CARLOCK, T(Di)20
IPC-E-01-11 Staff
IPC-E-01-16
07/20/01
A.No. Mr. Gale indicates that the Company
made the change to real-time hourly pricing in
December 2000. However, Company witness Hoyd testified
the Mid-C pricing methodology was used to calculate
its power purchase cost from April 2000 for the PCA
calculation. Hoyd Prefiled Direct Testimony at 21,
ll. 5-9.
Q.Idaho Power states that the market pricing
mechanism it used was approved in Order No. 28596,
Case No. IPC-E-00-13. Why should that be changed for
the 2000-2001 PCA year?
A.As previously stated, the allocations,
separations and pricing mechanisms used in the PCA
over the years has evolved. These changes may have
been for part of a PCA year or for the full PCA year.
Each year the prior year mechanism was reviewed for
reasonableness in the true-up audit.
The Staff audit function and the Company’s
requirement to demonstrate the continued
reasonableness of market pricing was the safeguard
proposed and adopted by parties as part of the
workshops and stipulation in IPC-E-00-13. Even with
this safeguard, the Industrial Customers of Idaho
Power remained uncomfortable with the mechanism and
did not sign the stipulation. It would not have been
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acceptable to Staff and other parties to endorse a 5-
year contract between the parties without the burden
remaining on the Company to show the continued
reasonableness of the Mid-C Index as a surrogate for
price.
The simple fact is that even if the
Agreement had been in effect, the Company did not
comply with the agreed upon documentation, oversight
manager, and audit tracking mechanisms safeguards
necessary to justify the reasonableness of its market-
priced transactions.
Q.Was the retention of documentation of
marketing transactions and decision-making a concern?
A.Yes. The lack of documentation retained
by Idaho Power to support the decisions was a concern
expressed during the audits since 1997, in Staff
comments and during subsequent workshops. This lack
of retained documentation continues to be a concern in
this case.
The documentation concern now pertains to
the pricing mechanism in addition to the
assignment/allocation of transactions between system
and non-system. Approval of the pricing mechanism in
Case No. IPC-E-00-13 was prefaced on the continued
review and ongoing improvements to the process. This
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is no different than the process that had always been
followed between the Staff and Idaho Power for the PCA
review. In the instant cases, IPC-E-01-7 and IPC-E-
01-11, the dollar magnitude is greater. The increase
in this magnitude is partially due simply to the
increase in transactions entered into by Idaho Power
and now its affiliate IDACORP Energy. Any time
transactions occur between affiliates, the necessary
review and documentation required for separations,
allocations or the pricing products are enhanced.
Failure to require enhanced scrutiny of affiliate
transactions could allow increased costs to be charged
customers by manipulation of the affiliate
relationship.
When Staff conducted its true-up audit of
Company transactions made during the 2000-2001 PCA
year, it discovered pricing concerns related to the
ongoing reasonableness of using the Index pricing as a
surrogate. These concerns must be corrected by
allocating the higher transfer prices to the non-
regulated operations. To this end, Staff recommends
non-recovery of the $51,234,902 (Idaho jurisdictional
amount).
Proper safeguards must be implemented to
address and eliminate these issues in the future.
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Once objectives and safeguards are approved and in
place, future true-up audits for prudence will focus
on compliance with these objectives and safeguards.
Q.Are there other reasons why the Commission
should adopt the Staff’s adjustment to power costs
rather than using of the Mid-C Price Index?
A.Yes. Restricted to its context in the
Case No. IPC-E-00-13, the Staff and the Company
suggested that use of published market indices is an
appropriate method for pricing transactions between
regulated and non-regulated affiliates. However, IES
was not licensed by FERC to conduct trading activities
until it received FERC approval on April 27, 2001.
See Staff Exhibit No. 118. The trading was performed
under Idaho Power’s authority. The point here is that
until the Commissions and FERC approved the Agreement
between IES and Idaho Power, all power purchases were
made by Idaho Power not IES. Because Idaho Power was
purchasing energy for itself, ratepayers should not
pay a price for that power that is significantly
higher than its cost, even if the “price” was the
market index.
Idaho Power was asked in audit requests to
supply vouchers, invoices or documentation supporting
compliance with the terms of the contract. The
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Company responded that the contract was not in effect
since it lacked the required approvals. Consequently,
the Company insisted the other provisions had not yet
taken effect. The other provisions -- $2 million
annual credit, Idaho Power Oversight manager,
implementation of audit tracking mechanisms -- were
safeguards to insulate customers from potential
affiliate abuse.
Even though the Company utilized the
pricing mechanisms contained in the Agreement, the
Company did not credit Idaho retail customers with the
stipulated $2 million. Direct Testimony of witness
Gale, Case Nos IPC-E-01-7 and IPC-E-01-11 testimony at
p. 4, ll. 6 - 9.) John R. Gale, Vice-President of
Regulatory Affairs, notified the Commission in a
letter dated June 29, 2001 that the “commitment to
initiate the flowback obligation” of $2 million
annually, would go into effect on July 1, 2001. Staff
Exhibit No. 121. Consequently, the pricing mechanism
should go into effect no sooner than that date.
Q.Is it possible for a pricing mechanism to
be reasonable at one point in time but not at another
time period?
A.Yes. As markets change and the
relationship between affiliated interests change, it
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is possible for a pricing mechanism to be reasonable
at one point in time but not at another. The
magnitude of transactions also impacts the possibility
that the reasonableness may change. When the level of
market participation and the dollar prices are small,
the transactions’ reasonableness is more likely to
fall within an acceptable band. As the transactions
change, the level of activity and the price increase.
This exacerbates the differences between a surrogate
or market price and the actual cost of the affiliate
beyond an acceptable band, making it so the market
price is no longer reasonable.
Q.Please explain the calculation for the
pricing adjustment recommended by Staff.
A.For the months of December 2000, January
2001 and February 2001, Staff has re-priced the day-
ahead power purchased from the Non-Operating System to
the System at the daily weighted average price paid by
the Non-Operating System. That way, the System pays
exactly what the Non-Operating System pays. The Non-
Operating System should not be allowed to profit
substantially from the regulated system. Staff
believes that the weighted average price is fair and
reasonable. It provides incentive to make sure that
all trades are sound and reasonable for both the
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system and non-system transactions with minimal
ability to game or manipulate the price.
Substantially greater margins on similar transactions
for a non-regulated entity compared to a regulated
entity is an indicator of an improper pricing
mechanism. The magnitude of this adjustment is shown
on Staff Confidential Exhibit Nos. 122 - 127. Staff
Confidential Exhibit No. 122 shows the daily record
for December 2000, Staff Confidential Exhibit No. 123
shows the daily record for January 2001, and Staff
Confidential Exhibit No. 124 shows the daily record
for February 2001.
Consistent with the adjustment for the
detailed audit for the three months listed above,
Staff determined that the rest of the day ahead power
for the PCA year should be re-priced using a weighted
average monthly price. While not as precise as a
daily price, Staff believes it is fairly
representative. These months were not audited on a
day by day basis due to time constraints. The months
of August and September 2000 did not have adjustments,
the transfer prices were already at the lower of cost
or market, when compared to the weighted average
monthly price for purchases, and at the higher of cost
or market for sales. This adjustment is shown on
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Staff Confidential Exhibit No. 125 for the months of
April through November 2000.
Staff has made adjustments to the day
ahead transactions for the months of April 2000
through February 2001, with the exception of the
months of August and September, and included them in
the Non-Firm Purchases and Surplus Sales, Lines 19 and
20 of the PCA calculation on Company Exhibits 1 and 3
of Case Nos. IPC-E-01-07 and IPC –E-01-11,
respectively. The net adjustment, before the
jurisdictional and sharing allocations, and without
the effect of interest on the deferral balance for the
day ahead transactions is ($61,467,386.84). The Idaho
jurisdictional number is $51,234,902. This represents
a benefit to the customer. The calculation is
summarized on Staff Exhibit No. 128.
In December 2000, the Company changed the
way the Real Time Transactions were priced. In the
past, the transactions always flowed through the
system at their actual cost. Now, however, the
transactions are priced based on the weighted average
price of all real time transactions that touch the
Idaho Power system on an hourly basis. According to
Staff’s analysis, this has also resulted in
overcharges and underpayments in several cases. Staff
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has re-priced the real time purchase transactions for
the months of December 2000 through February 2001 to
the lower of the Non System’s cost or market price.
Staff has also re-priced the real time sale
transactions for the same months using the higher of
sales price or market. Staff believes that purchases
and sales should be kept separate and that the system
should get the benefit of the best price.
The Staff made adjustments to the inter-
book real time sales and purchases for the months of
December 2000, and January and February 2001. The net
adjustment, before the jurisdictional and sharing
allocations, and without the effect of interest on the
deferral balance, for the real time transactions are
($4,666,381.95). This represents a benefit to the
customer. The calculation is shown on Staff
Confidential Exhibit Nos. 122 - 125 and summarized on
Staff Exhibit No. 128.
NOVEMBER TRANSACTION
Q.Please explain what has been termed the
‘November transaction’.
A.The ‘November transaction’ is the
transaction identified by Staff during the PCA audit
as an adjustment in the true up. The Risk Management
Committee (RMC) Minutes reflected a term transaction
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for the system that was not completed. Staff adjusted
the PCA results as if that transaction were completed
resulting in a recommended removal of the higher
priced replacement power from the recommended
increase. Idaho Power claims the transaction was not
completed because the RMC changed its decision later
during the same meeting. The continued Staff review of
this transaction and the explanation by Idaho Power
does not change the Staff position.
Q.Please explain the operating plan.
A.The operating plan is a primary planning
tool used by Idaho Power to operate the system and is
a primary tool used by the RMC for its decision making
related to the system. The operating plans are the
documents provided to Staff to support the power
purchase transactions, sales transactions and the
decisions made by the RMC. The operating plans show
the forecasts under the expected scenario, a best
scenario and a worst scenario.
Q.What did the operating plans reveal that
are available for the time of the RMC meeting on
November 21, 2000 when the purchase decision was made
for January?
A.The operating plans provided to Staff
showed that under almost every scenario the system
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would be short in January. The RMC minutes and
available supporting documentation do not provide
information to counter the original decision to
purchase power for the system to cover the January
shortage. Any subsequent information on pricing or
other data was not reflected in the RMC minutes or
retained to support the decisions made. Absent this
documentation, the change of decision simply looks
like a bad decision or an error that was contrary to
the prudent decision originally made, and passes the
detrimental cost to customers. These costs should not
be recovered from customers. The decision not to
purchase was made by the RMC and should be absorbed by
the non-system operations.
Staff has adjusted the amount of the
purchased power expenses in January 2001 by the total
system amount of $10,288,386, as shown on Staff
Confidential Exhibit No. 127, that would have been
saved if the RMC had completed the directive. All the
documentation supports a forward purchase of power for
the system. Rationale for a change of vote has not
been provided. It is reasonable for Staff to adjust
the purchase power expense to reflect the purchase as
if it had been made. To do otherwise would pass the
result of improper decision on to customers at their
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expense.
Q.Why does Staff find the Company’s
explanation unpersuasive?
A.The operating reports available for
review, the RMC minutes, and the subsequent events
referenced by Idaho Power do not justify the reversal
of this term transaction. The subsequent events do
not reflect the same product for comparison. A
longer-term product may be packaged to get a better
deal overall even when one portion of the transaction
would result in an imbalance for the system. Idaho
Power could have been short in January but still
packaged a deal that would sell power for the first
quarter in exchange for power in the third quarter.
These transactions are not mutually exclusive.
Q.In his testimony Darrel Anderson, Vice
President – Finance & Treasurer, Idaho Power Company,
explains why the system didn’t need to purchase for
January 2001. Do you accept his explanation as a
protrayal of the complete facts?
A.No. Price trends from Idaho Power
documents also reflect forward prices for January 2001
increasing. While there may be several reasons for any
increase, historical price trends were probably not
the primary consideration. Recent price increases for
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gas and electricity caused decisions by most traders
to be based on other data, such as forward market
prices, total trading position of IDACORP and Idaho
Power. Staff Confidential Exhibit No. 129 summarizes
the operating plan forecasts and the forward market
price data available as documentation for RMC
decisions. The November transactions relates to the
November 21, 2000 RMC meeting. The documentation
retained includes the operating plans for November 16,
2000 and November 28, 2001 but not anything in
between.
Exhibit No. 129 shows the operating plan
documentation to sketch the transaction referred to by
Company witness Anderson for the forward sale of power
in the First Quarter of 2001 in exchange for the
purchase of power in the Third Quarter of 2001. If
market prices were higher in the third quarter than
the first quarter, Mr. Anderson’s claim that they
wouldn’t sell if short might not be completely
accurate because line 24 of Staff Exhibit No. 129
shows they completed the opposite where they were
buying for the third quarter when September was
forecasted to be long. This exhibit shows how forward
market prices and inventory may have been greater
factors for consideration than absolute balance of the
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system forecasted need.
Q.Please explain how these problems can be
avoided in the future.
A.Proper documentation to support prudent
decisions should include information supporting the
decision or change in decisions and the rationale if
the decision made is not directly supported by the
available data. All charts or discussion papers must
be retained as support. The PCA review is conducted
at least annually. This is a reasonable time frame for
the Company to retain such documentation. If the
decision can not be shown to be prudent at the time it
was made, the associated expenses should not be
recovered from the regulated customer but should be
assigned to the non-system operation or recorded below
the line.
REQUIRED OBJECTIVES AND SAFEGUARDS
Q.Please provide an overview of the
objectives you believe Idaho Power must implement
related to trading activities and risk management.
A.Idaho Power is responsible for providing
power at a reasonable cost to its customers. To
assure the costs are reasonable, Idaho Power must
maintain documentation and RMC minutes reflecting the
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data available and considered in making its decisions.
When a product or service is provided to the
regulated utility from an affiliate or non-regulated
operation, the review by the Commission Staff of those
transactions must be enhanced. Therefore Idaho Power
must retain and provide additional documentation above
that required for a third-party transaction.
The objectives I recommend the Idaho Power
focus on include the following categories: 1) term
transaction decision management and documentation, 2)
forecasting documentation, 3) risk management profile
measures, 4) performance standards and 5) transfer of
value evaluations. These objectives, as further
discussed by Staff witness Thomas J. Lord, will
provide parties to Idaho Power cases additional
opportunity to review the decision making process of
Idaho Power and ensure that customers are paying
reasonable prices for power. The affiliate
relationship and the transfer pricing mechanisms are a
major portion of the review conducted by Staff and
parties to assure the transfer prices are and remain
reasonable.
Q.Would you anticipate that the lower-of-
cost or market for purchases and the higher-of-cost or
market for sales continue now that IDACORP Energy is
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in full operation and in separate facilities from
Idaho Power?
A.I believe market pricing for the intra-
month transactions will be the appropriate pricing
mechanism once the control objectives are quantified
and operational. Staff recommends for the current
filings, IPC-E-01-7 and IPC-E-01-11 that the following
pricing mechanisms apply to all day ahead
transactions:
1.Purchases by Idaho Power from the non-
operating book for the system should be priced at the
lower of cost or market. Staff recommends that the
market price continue to be based on the Mid-C price
or another acceptable pricing mechanism approved by
the Commission.
Staff further recommends that the cost be
based on the actual cost of the power, using a daily
weighted average of the price actually paid for the
power by the non-operating book to third parties.
2.Sales from Idaho Power from the operating
book to the non-operating book should be priced at the
higher of cost or market. Staff recommends that the
market price continue to be based on the Mid-C price
or another acceptable pricing mechanism approved by
the Commission.
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Staff further recommends that the cost be
based on the actual price of power sold to third
parties.
These pricing recommendations will provide
the ratepayer with the assurance that they will not
pay rates based on prices that are unfair, unjust and
unreasonable.
The Company, Staff and other interested
parties should work together to develop the objectives
and safeguards. This is critical to ensure the
reasonableness of using an Index as a surrogate for
actual costs going forward in IPC-E-01-16. The
continued cooperative efforts are necessary to achieve
a workable solution. Idaho Power has informally
indicated they favor the proposed process. The
resulting objectives and safeguards should be
presented to the Commission for approval or rejection
in the order issued in Case No. IPC-E-01-16. These
efforts will be made between now and the hearing in
these cases.
Absent appropriate safeguards, Staff will
continue to propose lower-of-cost or market for
purchases and the higher-of-cost or market for sales
as the only transfer pricing mechanism to assure there
in no affiliate manipulation and that customers are
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charged fair, just and reasonable rates.
RISK MANAGEMENT COMMITTEE
Q.Please provide an overview of the Risk
Management Committee?
A.During the 2000 – 2001 PCA year, the Risk
Management Committee (RMC) consisted of IDACORP and
Idaho Power officers. These members are listed on
Exhibit No. 130 as provided in Response to Staff
Production Request No. 1. No member solely
represented the interests of Idaho Power and its
customers.
According to Idaho Power, “The purpose of
the RMC is to maintain general oversight over all
commodity trading and financial risk management
operations.” Response to Staff Production Request No.
3. The decision-making process of the RMC is
explained in Response to Production Request No. 4.
The RMC reviews operating proposals
prepared by Idaho Power Company
personnel. The proposals include
assumptions for supply and demand
requirements based on data available
at that time. Based on the results
of this data, the collective
experience of the committee members,
other pertinent internal and external
data, and an in-depth discussion
between committee members, decisions
are made to determine the need to buy
or sell energy. Numerous factors are
considered in coming to these
decisions including weather, expected
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load requirements, current snowpack,
transmission availability, pricing
and the overall system portfolio
position. When it is determined that
an action is required, a
recommendation is made by a committee
member and put to the entire RMC for
a vote. A majority is required to
confirm a transaction for inclusion
in the operating plan.
Staff expressed concern in its comments
filed on April 16, 2001 in these cases that the RMC
consists of the same members for both the utility and
for the non-regulated operations. Staff review of the
RMC minutes indicates that the Committee does not
consistently support a mandate to first take care of
the system needs before the non-regulated operations,
even though this is the stated policy. Based on a
review of the minutes, Staff believes that the RMC has
not focused enough energy on the utility and as a
result, system costs are higher than they otherwise
would have been.
Recently the Risk Management Committee was
split into two committees, an IDACORP Energy Risk
Management Committee and an Idaho Power Risk
Management Committee. The current members of the
committees are listed on Exhibit No. 131. This split
should allow the respective committees to focus more
directly on its primary responsibilities. The non-
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operating group, now IDACORP Energy can focus on non-
regulated matters and the Idaho Power RMC can focus on
matters pertaining to the regulated operations.
Q.Does this conclude your direct testimony
in these cases?
A.Yes, it does.