20010807Simard and Gale Rebuttal.pdf

Telephone [phone], Fax [phone], E-mail [e-mail]
BARTON L. KLINE
Senior Attorney

August 7, 2001

Ms. Jean D. Jewell, Secretary
Idaho Public Utilities Commission
P.O. Box 83720
Boise, Idaho 83720-0074

Re: Case No. IPC-E-01-16
Rebuttal Testimony

Dear Ms. Jewell:

Please find enclosed for filing nine (9) copies of the Company’s rebuttal
testimony and exhibits of Witnesses Simard and Gale. Copies of this filing have been
hand-delivered, mailed, or sent by overnight mail to the parties as indicated in the
enclosed Certificate of Service.

Also enclosed is a computer disk for the court reporter containing the
testimony of the witnesses. We will send you an e-mail containing all of the documents
involved in this filing.

I would appreciate it if you would return a stamped copy of this transmittal
letter for our file.

Very truly yours,

Barton L. Kline

BLK:jb
Enclosures

CERTIFICATE OF SERVICE, Page 1
CERTIFICATE OF SERVICE

I HEREBY CERTIFY that on this 7th day of August, 2001, true and correct
copies of the TESTIMONY AND EXHIBITS OF WITNESSES SIMARD and GALE in
Case No. IPC-E-01-16 were either sent by overnight mail or hand delivered, as indicated
below, to the following named parties and addressed as follows:

Lisa D. Nordstrom ____ Hand Delivered
Deputy Attorney General ____ U.S. Mail
Idaho Public Utilities Commission ____ Overnight Mail
472 W. Washington Street ____ FAX
P.O. Box 83720
Boise, Idaho 83720-0074

Randall C. Budge ____ Hand Delivered
Racine, Olson, Nye, Budge & Bailey ____ U.S. Mail
Center Plaza-Corner First & Center ____ Overnight Mail
P.O. Box 1391 ____ FAX
Pocatello, Idaho 83204-1391

Anthony Yankel ____ Hand Delivered
29814 Lake Road ____ U.S. Mail
Bay Village, Ohio 44140 ____ Overnight Mail
____ FAX

Peter J. Richardson ____ Hand Delivered
Molly O’Leary ____ U.S. Mail
Richardson & O’Leary ____ Overnight Mail
99 E. State Street, Suite 200 ____ FAX
P.O. Box 1849
Eagle, Idaho 83616

Stuart Trippel ____ Hand Delivered
Trippel Mast Consulting LLC ____ U.S. Mail
506 Second Avenue, Suite 1001 ____ Overnight Mail
Seattle, Washington 98104-2328 ____ FAX

Lawrence A. Gollomp ____ Hand Delivered
U.S. Department of Energy, Room 6D-003 ____ U.S. Mail
1000 Independence Avenue S.W. ____ Overnight Mail
Washington, D.C. 20585 ____ FAX

CERTIFICATE OF SERVICE, Page 2
Dr. Dale Swan ____ Hand Delivered
Exeter Associates ____ U.S. Mail
12510 Prosperity Drive, Suite 350 ____ Overnight Mail
Silver Springs, Maryland 20904 ____ FAX

Conley E. Ward ____ Hand Delivered
Givens, Pursley LLP ____ U.S. Mail
277 North 6th Street, Suite 200 ____ Overnight Mail
P. O. Box 2720 ____ FAX
Boise, Idaho 83701-2720

Ken Tandy ____ Hand Delivered
Astaris LLC ____ U.S. Mail
P. O. Box 4111 ____ Overnight Mail
Highway 30, West of City ____ FAX
Pocatello, Idaho 83202

______________________________________
BARTON L. KLINE

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S INTERIM AND PROSPECTIVE, )
HEDGING, RESOURCE PLANNING, ) CASE NO. IPC-E-01-16
TRANSACTION PRICING, AND IDACORP )
ENERGY SERVICES (IES) AGREEMENT )
)
IDAHO POWER COMPANY
REBUTTAL TESTIMONY
OF
TIM J. SIMARD

SIMARD, DI-REB 1
Idaho Power Company
Q. Please state your name and business address.1
A. My name is Tim J. Simard. I am employed by2
RiskAdvisory. My business address is Suite 610, 1414 8th3
Street S.W., Calgary, Alberta, Canada T2R 1J6.4
Q. What position do you hold with RiskAdvisory?5
A. I am a founding Principal of RiskAdvisory.6
Q. Please describe your experience relevant to7
this testimony?8
A. I began working with energy companies with9
respect to the use of risk management instruments and the10
design of risk management programs in 1986 as an11
institutional energy futures broker with the Burns Fry12
Energy Group in Calgary, Alberta. In 1990, I moved to13
Bankers Trust Canada where I went on to become Vice Chairman14
with responsibilities for managing Bankers Trust’s Canadian15
energy derivatives operation. RiskAdvisory was created in16
1995 and since that time the firm has worked on assignments17
for over 150 energy companies in the United States, Canada18
and New Zealand. I have been involved in assignments with 1619
electric and natural gas utilities as a member of20
RiskAdvisory, primarily with respect to the design and21
implementation of risk management programs. I have served as22
an expert witness on issues pertaining to the financial23
management of energy risk in four regulatory hearings for24
both natural gas and electric utilities.25

SIMARD, DI-REB 2
Idaho Power Company
Q. Have you been retained by Idaho Power Company1
(“IPC”) or its parent IDACORP, Inc. in any other assignments2
prior to your involvement as an expert witness for these3
hearings?4
A. Yes. I was engaged by IDACORP, Inc. in5
September 2000 to work with the non-operating group as an6
Interim Risk Manager. The assignment was to have terminated7
on December 8, 2000. However, my services were retained on a8
part-time basis beyond this period until March 1, 2001.9
Q. As part of this assignment, what involvement10
did you have with the utility risk management activity of11
IPC?12
A. My activity was limited to attendance at most13
of the Risk Management Committee (“RMC”) meetings held14
during the term of my assignment. I listened to the15
discussions around the risk management issues for the16
operating function, but did not actively participate in17
these discussions. My focus was reporting to the Risk18
Management Committee on those issues pertaining to the risk19
portfolio of the non-operating trading and marketing20
activities.21
Q. What is the purpose of your testimony?22
A. The purpose of my testimony is to describe23
several key issues that should drive the implementation of a24
prudent risk management program for a regulated utility. The25

SIMARD, DI-REB 3
Idaho Power Company
testimony will also provide an opinion as to the efforts1
that have been made and continue to be advanced by IPC with2
respect to its risk management program.3
Q. What essential ingredients are required4
before any entity embarks on a risk management program?5
A. The first essential ingredient of a risk6
management program is the determination of the risk appetite7
of the individual or group for whom the risk management8
activity is conducted. Not all participants in a marketplace9
will have the same appetite for market exposure. A good10
example is provided by the appetite for different types of11
residential mortgages. Some homebuyers prefer a mortgage12
with a fixed interest rate while others opt for an interest13
rate that floats with underlying movements in short-term14
interest rates. It is not correct to assume that all market15
participants want to be insulated against market movements.16
Many oil and gas companies, for example, choose to retain17
material exposure to movements in oil and gas prices despite18
the availability of instruments that can protect them19
against these movements. While one can assert that all20
market participants would choose to insulate themselves21
against risk if this can be done without any potential cost,22
the recognition that there can be embedded costs in a risk23
management strategy will change the desirability of that24
strategy for many participants. A risk management program25

SIMARD, DI-REB 4
Idaho Power Company
that could be viewed as prudent for one individual or group1
may prove to be imprudent for another individual or group2
based on the risk appetite or risk preference of these3
market participants.4
The second key ingredient in the development5
of a risk management program is a quantitative assessment of6
the portfolio of risks faced by the market participant. This7
quantitative approach allows one to assess the probability8
of adverse market movements on one’s position. The9
quantitative model must also allow one to determine the10
impact that incremental transactions can have on the risk11
profile of the participant. For complex risk portfolios, it12
is often not clear as to whether a proposed risk management13
transaction actually serves to reduce or exacerbate the14
exposure to market prices.15
Equipped with an understanding of the16
magnitude of market exposures and an assessment of risk17
appetite, one is in a position to define the underlying18
objectives of the risk management program, craft policies19
and procedures associated with any risk management activity20
and develop the program implementation process.21
Q. How should one view the concept of risk22
appetite within the context of IPC’s regulated environment?23
A. It should be understood that any risk24
management activity undertaken by IPC to manage its PCA25

SIMARD, DI-REB 5
Idaho Power Company
balances is primarily on behalf of ratepayers. While there1
is an incentive component to the PCA structure, the majority2
of variances in the PCA account flow through to ratepayers.3
IPC effectively acts as agent for the ratepayers with4
respect to the implementation of risk management5
transactions.6
Q. What role should ratepayer groups and7
regulators play in the IPC risk management program?8
A. Given that the risk management activity is9
undertaken primarily on behalf of ratepayers, it is crucial10
that ratepayer groups and representatives provide their11
input into any hedging strategy. One should not expect that12
IPC will be able to determine the optimal strategy without13
this input. The other factor is that if the ratepayers and14
their groups are not brought into a collaborative process to15
determine the nature of the desired risk profile, IPC could16
be subject to inequitable negative hindsight reviews. If IPC17
establishes a long hedge position in a particular year18
without consultation with ratepayers and prices subsequently19
fall, ratepayers and their representatives could argue after20
the fact that the hedge was imprudent because ratepayers21
wanted to retain exposure to falling market prices.22
Ratepayers should participate in the development of the23
broad guidelines for risk management and be prepared to24
accept the consequences of these hedging actions if they25

SIMARD, DI-REB 6
Idaho Power Company
lead to a sub-optimal PCA balance.1
Q. What role should the market directional views2
of IPC play in the implementation of the IPC risk management3
program?4
A. Market directional views should not play any5
role in the implementation of the IPC risk management6
program. The injection of price views creates a speculative7
component that is inappropriate for a utility risk8
management program. The exercise of a price view can lead to9
instances when “hedges” are established only if one believes10
the market will move in favor of the hedge position.11
Ratepayers and regulators should not expect that IPC has any12
competitive advantage with respect to outforecasting or13
“beating the market” over the long run. If an exposure is14
identified and this exposure is unsuitable relative to pre-15
defined tolerance levels agreed upon between ratepayer16
groups, the Idaho Public Utilities Commission (“IPUC”) and17
IPC, the appropriate hedge should be established without18
regard for IPC’s view on where market prices are likely to19
move.20
Q. Do you agree with the assertion made in the21
testimony of Staff witness Thomas Lord on page 31 that “One22
way to assure that Idaho Power regulated customers receive23
that benefit would be for IES and Idaho Power to adopt a24
corporate policy that, within the acceptable risk tolerance25

SIMARD, DI-REB 7
Idaho Power Company
for regulated customers, IES and Idaho Power would always1
share congruent market views in the region”?2
A. No. IES has been established as a risk-taking3
entity whose profitability will be a partial function of4
speculative transactions that are established to capitalize5
on its speculative perception of future price movements.6
Positions established on the basis of a price view are not7
risk-free. As stated above, there is no room for a8
speculative price view in a defensive risk management9
program established to protect utility ratepayers against10
undue volatility in the PCA balance. To reiterate, it would11
be inappropriate for a proposed risk-reducing transaction to12
be deferred because of a guess on the part of either IES or13
IPC about future market direction. Otherwise, ratepayers are14
taking risk positions based on a speculative element and15
this should not be the foundation of a defensive risk16
management program. With the recognition that price17
speculation should not play a role in the risk management18
activities of IPC, there will be frequent instances when the19
defensive hedge positions established by IPC will be in the20
opposite direction of some of the speculative positions in21
the IES portfolio.22
Q. Should the IPC risk management program be23
benchmarked on the gains or losses generated by the risk24
management transactions?25

SIMARD, DI-REB 8
Idaho Power Company
A. No. Gains and losses on the risk management1
transactions in isolation would only be a benchmarking2
component if price views influenced the implementation of3
these positions. Absent the price view component, the gains4
or losses on the hedge transactions are irrelevant to any5
prudence review of the hedging activity. The hedge6
transactions are established to reduce fluctuations to the7
PCA balance, and are not established to be profitable in8
isolation.9
Q. What are the responsibilities of IPC in the10
development and implementation of a prudent risk management11
program?12
A. IPC should take responsibility for several13
elements of the risk management program. First, IPC is in14
the best position to quantify the risk inherent in the power15
supply portfolio. IPC should provide the IPUC and ratepayer16
groups with a thorough understanding of this risk profile17
and the potential magnitude of adverse PCA balance movements18
based on current market information. IPC should also provide19
these stakeholders with an estimate of the benefit and risks20
associated with several alternative risk management21
implementation strategies. Equipped with this information,22
the ratepayer groups and the IPUC will be in a better23
position to advise IPC on their preferred risk management24
implementation strategy. The IPUC should also receive25

SIMARD, DI-REB 9
Idaho Power Company
periodic reports on the IPC risk position.1
As part of the responsibility stated above,2
IPC should work towards the implementation of a quantitative3
risk model that takes into account the broad range of4
varying factors that can affect the PCA balance.5
IPC should develop a Policy Manual and a6
Procedures Manual governing the risk management activity.7
The Policy will outline the objective of the risk management8
activity, the responsibilities of various groups within IPC9
who are involved in the risk management program taking into10
account the importance of segregation of various duties, any11
volumetric or dollar risk limits established in conjunction12
with input from ratepayer groups and the IPUC, an overview13
of the market risk quantification process, the credit policy14
with respect to an overview of the quantification of credit15
risk and the establishment of credit risk limits, and a16
discussion of the management reporting infrastructure,17
namely the report contents, the report distribution list18
(including periodic reports to the IPUC) and the frequency19
of reports. The Procedures Manual will provide more detail20
on actual execution procedures to ensure prudent execution21
and no affiliate abuse and to reduce the operational risks22
inherent in risk management programs. It will also provide23
more detail on quantification procedures for both market and24
credit risk. The detailed involvement of risk monitoring and25

SIMARD, DI-REB 10
Idaho Power Company
accounting responsibilities would also form part of the1
Procedures Manual.2
IPC should be responsible for the actual3
execution of term transactions (which might be brokered by4
IE or others) and the preparation and distribution of5
reports.6
IPC must have a senior management committee7
that provides high-level oversight of the risk management8
program, including the responsibility for interactions with9
ratepayer groups and the IPUC, and the implementation of the10
risk management program in line with the strategy prescribed11
by the ratepayer groups and the IPUC.12
Q. Power marketing companies have access to13
quantitative systems that allow for the daily measurement of14
risk in their portfolios. Can the risk measurement15
technology employed by marketing groups be applied directly16
to the risk position of a utility?17
A. No. The risk profiles of electric utilities18
are materially different from the risk profiles of marketing19
entities. The first difference lies in the timeframe20
associated with the risk analysis. Marketing entities are21
only concerned with the deterioration in the value of their22
portfolio over a short period of time, typically one day to23
one month. The marketing approach is based on the principle24
that if risk limits are violated, the portfolio can be25

SIMARD, DI-REB 11
Idaho Power Company
liquidated in a short period of time. On the other hand,1
utilities are more concerned about the impact to ratepayers2
on movements over a longer timeframe. In the case of IPC3
with a one-year PCA period, it is the risk of movements in4
this PCA balance over the course of the year that need to be5
quantified. Risk models that allow for price movements over6
a full year are materially different from a marketing risk7
system that serves to quantify risk over a much shorter term8
period.9
The second critical difference between10
modeling utility risk positions and modeling marketing11
company risk positions centers on the issue of volumetric12
uncertainty. Marketing companies tend to know with certainty13
the volumes underlying most of their committed future power14
market purchases and sales. Most trades are done in standard15
block transactions where the volumes are contractually16
fixed. With electric utilities, there can be significant17
variations around the volumetric availability both on the18
resource side and on the load side. With respect to the19
supply from generators, forced outages can lead to sudden20
drastic reductions in available resources. A host of factors21
can also cause material variations in load requirements22
versus expectations. The end result is that one’s forecast23
surplus/deficit position can change radically as resource24
availability and load obligations change. This creates25

SIMARD, DI-REB 12
Idaho Power Company
significantly more modeling complexity for utilities. Using1
a marketing company risk model that assumes volumetric2
certainty can lead to materially inaccurate assessments of3
risk which in turn can lead to the implementation of risk4
management transactions that serve to exacerbate risk rather5
than reduce risk. It would be imprudent for a utility with6
varying resource availability and load obligations to use a7
risk management quantification system designed for marketing8
companies.9
Q. Are there facets of the IPC risk profile that10
make the quantification and management of risk in the11
portfolio more difficult than for many other electric12
utilities?13
A. Yes. IPC’s reliance on unpredictable hydro14
generation creates even more uncertainty around resource15
availability than a utility that is less reliant on hydro16
resources. Exhibit 4 details the variance between forecast17
IPC monthly generation resources and actual generation for18
the April 2000 – February 2001 period. The variances can be19
material: actual generation in January and February 200120
fell almost 30% below the 2000 Integrated Resource Plan21
(“IRP”) forecast, amounting to a shortfall of more than 60022
MW for this period. This shortfall represented more than23
one-third of IPC’s combined load and firm sales over these24
two months.25

SIMARD, DI-REB 13
Idaho Power Company
The high degree of volumetric uncertainty has1
a significant impact on risk modeling and the risk2
management decision-making process. As an example, assume3
that the forecast estimate of available hydro generation in4
three months’ time leads to the conclusion that one will be5
in a surplus position for this month. Assuming no change in6
the hydro resource from the forecast (which is the7
volumetric certainty assumption used in most marketing risk8
models), one might establish a short forward position in9
three months to reduce this surplus and return the system to10
a more balanced position. However, assume in three months’11
time that actual hydro availability falls well below initial12
forecast expectations, resulting in a situation where even13
without the short forward position the system is in deficit.14
At the same time, market prices have risen. This will result15
in losses on the “hedge” position even though the hedge was16
not needed. The establishment of the hedge in this scenario17
serves to exacerbate the risk of fluctuations in the PCA.18
Any system or risk management implementation program that is19
employed which ignores the variability in forecast hydro20
availability will likely create unfavourable results for21
ratepayers.22
Q. Are risk measurement models available in the23
marketplace today that can quantify effectively all the24
volumetric and market-based risks in IPC’s portfolio?25

SIMARD, DI-REB 14
Idaho Power Company
A. I am not aware of any comprehensive risk1
models available in the marketplace today that can assess in2
an accurate fashion the combined volumetric/price risk3
embedded in the IPC portfolio.4
Q. What efforts has IPC made to develop its risk5
management program?6
A. During the 2000 – 2001 PCA year, the IPC risk7
position was discussed regularly at the RMC meetings. A8
report was circulated at each meeting which detailed9
forecast resources and the net surplus/deficit position by10
month , along with the impact of the expected forecast and a11
worst case price/hydro scenario on the PCA balance. This12
input was used to assess the appropriateness of any risk13
management strategy. Members of the RMC were fully cognizant14
of the difficulties associated with establishing hedge15
positions when there was so much uncertainty around the16
forecast hydro availability.17
In response to the unprecedented degree of18
market price volatility in the latter half of 2000 and early19
2001, IPC has established its own RMC separate from the20
IDACORP RMC which historically provided oversight to both21
the operating and non-operating market risk positions. This22
will ensure a focused review of risk management issues23
specifically pertaining to the IPC risk position.24
IPC has also embarked on a program to25

SIMARD, DI-REB 15
Idaho Power Company
establish a detailed framework for its risk management1
activities on behalf of ratepayers, including the2
development of a process to include ratepayer groups and the3
IPUC in a collaborative approach to the issue of risk4
management, the mapping of several proposed implementation5
strategies, a commitment to continue to advance its risk6
quantification methodologies and the recognition of the need7
for a Policy Manual and a Procedures Manual to govern the8
risk management activity of IPC.9
The historical recognition on the part of IPC10
management of the need to manage PCA fluctuations and the11
initiative to establish a more formal framework for the risk12
management program should provide the IPUC with comfort13
surrounding the level of prudence employed by IPC in the14
area of risk management.15
Q. Does IPC currently possess the requisite16
skills to implement a prudent term risk management program17
on behalf of its ratepayers?18
A. The three key risk functions that are19
required for the IPC risk management program center around20
execution capabilities, the risk monitoring and reporting21
function (“the middle office”) and the senior oversight22
function. On the execution front, to-date these services23
have been performed for IPC by the non-operating trading24
function. Should this relationship continue, the skills25

SIMARD, DI-REB 16
Idaho Power Company
certainly exist within the non-operating trading group to1
execute risk management transactions in an efficient2
fashion. It should be noted that in a defensive risk3
management program without a price view component, the4
execution process becomes a straightforward process where5
bids or offers are solicited from a number of risk6
management counterparties over a short period of time and7
the best price is selected subject to credit risk limits8
with these counterparties. If the execution of term9
transactions is transferred to the IPC operating entity,10
there will be an immediate need to hire a staff member with11
power market execution expertise, or train a staff member on12
the basic protocol associated with the execution of term13
transactions in the regional power market. This would not14
require an onerous training program. However, this15
individual should also have the ability to identify other16
types of risk management transactions that could prove17
advantageous to ratepayers like option structures, weather18
derivatives and unit- or hydro-contingent forward market19
sales. This individual could also assist the Risk Manager20
and the RMC evaluate recommendations provided by IE under21
the Electricity Supply Management Services Agreement.22
The middle office is responsible for23
developing the systems and quantification procedures used to24
track the risk in the IPC portfolio. As I have already25

SIMARD, DI-REB 17
Idaho Power Company
discussed, this is a very complex process for IPC. Some of1
the requisite skills for this position already exist within2
IPC, most notably with respect to modeling hydro3
availability. However, this information needs to be4
consolidated within a broader risk analysis and this will5
require incremental quantitative modeling skills and systems6
expertise. This middle office position is normally referred7
to as the Risk Manager. The Risk Manager could also assist8
the RMC in evaluating recommendations provided by IE under9
the Electricity Supply Management Services Agreement.10
The Idaho Power RMC would provide the senior11
management oversight function. From the RMC perspective,12
most of the members of the IPC RMC committee have served or13
been observers on the IDACORP RMC. This has resulted in a14
group that has a good understanding of the use of basic risk15
management tools and risk quantification methodologies.16
Ongoing training is required to stay abreast of the latest17
risk quantification advances and risk management vehicles18
available in the marketplace, and to ensure a thorough19
comprehension of the ramifications of any proposed hedge20
transaction on PCA balances.21
Q. How should the IPC risk management program be22
benchmarked in the future?23
A. The performance of IPC with respect to its24
risk management program should be benchmarked against25

SIMARD, DI-REB 18
Idaho Power Company
several factors. First, IPC has a commitment to educate1
ratepayers and IPUC on the magnitude of risk in the PCA2
balance, the difficulties associated with estimating this3
risk, and the types of risk management strategies that can4
be employed, including the costs, benefits and risks5
associated with these strategies. IPC should be benchmarked6
against its ability to communicate these difficult concepts7
to ratepayers and the IPUC.8
IPC should also continue to look for improved9
methodologies to quantify the risk in its portfolio taking10
into account the volumetric variability and the price11
variability. The risk management program can be benchmarked12
on the effort made by IPC to improve this quantification13
process.14
IPC should prepare best industry practice15
Policies and Procedures Manuals and part of the benchmarking16
process should include a review of these manuals.17
IPC is responsible for the prudent18
implementation of the risk management program based on the19
implementation framework agreed to by ratepayers and the20
IPUC. If this framework includes volume limits and PCA21
variance limits, IPC can be benchmarked against its ability22
to remain within the stated risk tolerances of its23
stakeholders. If limits are violated, the onus would be on24
IPC to explain why the limits could not have been defended25

SIMARD, DI-REB 19
Idaho Power Company
in a prudent fashion.1
Finally, IPC is responsible for ensuring2
appropriate segregation of duties and to ensure the absence3
of any affiliate abuse. IPC can be benchmarked against its4
ability to ensure that these best industry practice5
standards are met.6
Q. Does this conclude your testimony?7
A. Yes.8
Exhibit 4
Apr-00 May-00 Jun-00 Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec-00 Jan-01 Feb-01
Generation Forecast (MWh)1,597,680 1,466,424 1,498,320 1,580,256 1,386,816 1,353,600 1,340,688 1,155,600 1,322,832 1,701,528 1,490,496
Actual Generation (MWh)1,675,382 1,211,760 1,177,995 1,357,008 1,207,981 1,224,788 1,244,552 1,150,200 1,207,899 1,213,677 1,068,343
Difference (MWh)77,702 (254,664) (320,325) (223,248) (178,835) (128,812) (96,136) (5,400) (114,933) (487,851) (422,153)
Difference (MW)108 (342) (445) (300) (240) (179) (129) (8) (154) (656) (628)
Percentage Variance 5%-17%-21%-14%-13%-10%-7%0%-9%-29%-28%
Exhibit No. 4
Case No. IPC-E-01-16
T. Simard, IPCo-Reb
Page 1 of 1
Comparison of Forecast versus Actual Generation
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Forecast per IRP Actual

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S INTERIM AND PROSPECTIVE, )
HEDGING, RESOURCE PLANNING, ) CASE NO. IPC-E-01-16
TRANSACTION PRICING, AND IDACORP )
ENERGY SERVICES (IES) AGREEMENT )
)
IDAHO POWER COMPANY
REBUTTAL TESTIMONY
OF
JOHN R. GALE

GALE, DI-REB 1
Idaho Power Company
Q. Please state your name and business address.1
A. My name is John R. Gale and my business2
address is 1221 West Idaho Street, Boise, Idaho.3
Q. Please state your name and business address.4
A. My name is John R. Gale and my business5
address is 1221 Idaho Street, Boise, Idaho.6
Q. By whom are you employed and in what7
capacity.8
A. I am employed by Idaho Power Company as the9
Vice President of Regulatory Affairs.10
Q. Have you previously submitted prefiled direct11
testimony in this proceeding?12
A. Yes.13
Q. Please summarize your understanding of Staff14
witness Lord’s testimony related to the issues the15
Commission identified for investigation in this case.16
A. Mr. Lord is concerned with Idaho Power17
Company’s potential over-reliance on the spot market to meet18
its system needs in the future. He is also concerned with19
Idaho Power’s ability to manage the system on a prospective20
basis. He specifically mentions the lack of requisite skill21
sets in the utility along with the lack of appropriate22
management tools and safeguards. Mr. Lord also discusses23
additional areas of perceived value that IDACORP Energy24

GALE, DI-REB 2
Idaho Power Company
(“IE”) receives from the arrangement with Idaho Power that1
may not be compensated under the current terms of the2
Agreement for Electric Supply Management Services (“the3
Agreement”) between the two entities.4
Q. On page 18, line 3 of Mr. Lord’s direct5
testimony, he states that he is unable to determine whether6
IE charges a brokerage fee for arranging transactions for7
Idaho Power. Is there a brokerage fee?8
A. No, under the agreement between Idaho Power9
Company and IDACORP Energy, any brokering services are10
included in the annual fee. That pricing arrangement was11
explicitly addressed in the Code of Conduct that was filed12
with this Commission and the Code of Conduct approved by the13
FERC when it approved the Agreement.14
Q. Mr. Lord indicates that the Company may not15
be taking hedging positions in the future. How do you16
respond?17
A. I cannot find in my direct testimony where18
this conclusion can be drawn. Nevertheless, so there is no19
confusion, let me state that Idaho Power Company will take20
hedging positions in the future when the Idaho Power Risk21
Management Committee deems it appropriate. It has not been22
our practice to maintain a completely open position in the23
past, nor will it be in the future. Neither has it been24

GALE, DI-REB 3
Idaho Power Company
Idaho Power’s practice to take speculative positions on1
behalf of the system and its retail customers. Mr. Lord’s2
testimony discussing the problems that could occur if the3
Company maintains a completely open position is not relevant4
to Idaho Power’s situation.5
Q. Does Idaho Power Company have the skill sets6
to manage the system and the risks associated with it?7
A. Yes, the Company has always had and in the8
future will retain and enhance the requisite skills to9
manage the system and its risks. Idaho Power Company still10
retains senior management experienced in power supply and11
wholesale market issues. The bulk of the information and12
analytical staff and tools needed to support the Company’s13
planning decisions still resides in the utility. This14
information includes all customer information and the15
information associated with customer consumption patterns as16
well as the software that analyzes load. To enhance the17
resident skills within Idaho Power with additional risk18
management expertise, Idaho Power has retained the services19
of Mr. Tim Simard of RiskAdvisory who is also a Company20
witness in this case. Mr. Simard describes in his rebuttal21
testimony some of his initial findings and recommendations22
concerning Idaho Power’s prospective risk management effort.23
Idaho Power’s Internal Audit Manager is also in the process24

GALE, DI-REB 4
Idaho Power Company
of reviewing and developing recommendations to enhance the1
formal accounting controls necessary to manage the agreement2
with IDACORP Energy on behalf of the utility and its3
customers. The Company’s outside auditors, Deloitte &4
Touche, will review those controls to confirm their5
efficacy. In addition, Idaho Power continues to have access6
to the expertise within IDACORP Energy as part of the7
services provided to the utility under the Agreement between8
the two entities. The whole discipline of utility risk9
management has been a rapidly evolving part of the industry.10
We stand ready to do whatever is needed to be a “best11
practices” company in this regard.12
Q. What is Idaho Power Company doing to better13
manage its power supply cost risks in the future?14
A. As the Commission well knows, Idaho Power’s15
hydroelectric generation has often been a mixed blessing.16
In the past, low cost has often been confused with low risk.17
First the seven-year drought and now the “perfect storm” has18
painfully underscored that the production volume exposure of19
a hydroelectric utility is high risk, particularly during20
times of high price volatility. The impact of the extended21
drought, along with its temporary surcharges, ultimately led22
to the implementation of the Company’s Power Cost Adjustment23
(“PCA”) mechanism. For a number of years prior to the24
recent price spikes, Idaho Power was able to concentrate on25

GALE, DI-REB 5
Idaho Power Company
operating its system primarily to optimize its resources by1
accessing northwest and southwest markets for economy sales2
and purchases. Some seasonal patterns led to energy3
exchanges, while some longer-term wholesale contracts gave4
us the ability to mitigate some of our generating capacity5
costs. Risk management models for hydro systems were not6
contemplated until recently because the price volatilities7
just did not justify their development. Company experience8
and operating knowledge were the most practical and cost-9
effective tools during this era.10
In the late 1990’s when the trading business11
began to develop, a new set of skills was added to the12
experience of the past. While these skills are readily13
applicable to pure trading activities, they are a work-in-14
progress for the utility itself. We are sorting through15
such things as whether it is appropriate for the Company to16
have a directional price view, what is the risk appetite17
level for the Company’s customers and Commission, can we18
establish objective risk management procedures to operate19
within a specified risk level, and can we develop or obtain20
a risk model that can address the complexities of a21
hydroelectric system. The Company will be evaluating the22
recommendations of Mr. Simard and others to incorporate into23
its future risk management program. Some of these24
recommendations have already been adopted, while others may25

GALE, DI-REB 6
Idaho Power Company
be developed with the assistance of those who have a vested1
interest in the process. Other recommendations, such as the2
development of enhanced modeling capability will take some3
time to implement.4
Q. How do you respond to Mr. Lord’s discussion5
regarding IDACORP Energy’s potential misuse of Idaho Power’s6
operating information?7
A. First I want to emphasize that while Mr. Lord8
raises some theoretical possibilities, neither Mr. Lord nor9
anyone else has submitted actual evidence of abuse.10
Further, as IDACORP Energy’s purchases and sales have grown11
dramatically over time, they have dwarfed the utility’s12
comparable purchase and sales – both in terms of volume and13
dollars. In both dollars and volume, IDACORP Energy’s14
business with Idaho Power is projected to be less than four15
percent (4%) of IE’s overall energy business. Nevertheless,16
perception can be unsettling by itself. Since the actual17
separation of IDACORP Energy from Idaho Power, both18
physically and organizationally, the utility has become19
increasingly more autonomous from its affiliate. The20
umbrella Risk Management Committee (“RMC”) of the past has21
been separated into one for Idaho Power and one for IDACORP22
Energy. The committees are comprised of officers and senior23
managers of their respective entities. Mr. LaMont Keen, the24
Chief Financial Officer for the corporation, is the only25

GALE, DI-REB 7
Idaho Power Company
common member to both committees. Mr. John Prescott, the1
designated Oversight Manager for Idaho Power is the Chair of2
the Idaho Power RMC and functions as the supply officer for3
the Company. Mr. Prescott and the Idaho Power Company RMC4
are systematically reviewing current market information5
practices with the assistance of RiskAdvisory. In6
accordance with the Agreement, IE will make recommendations7
to the Idaho Power RMC for possible actions to be initiated8
by Idaho Power. Any appropriate information safeguards will9
be incorporated into future Company policies and procedures.10
Q. Mr. Lord discusses potential value to IDACORP11
Energy in the Agreement with Idaho Power that has, to date,12
not been recognized formally in compensation from IDACORP13
Energy to Idaho Power. What is Idaho Power’s view on14
additional compensation from its affiliate?15
A. In the initial Agreement between Idaho Power16
and IDACORP Energy, mutual cost savings were identified that17
left the Company’s customers in a more favorable position18
than they would have been without the arrangement. Under19
the settlement stipulation in Case IPC-E-00-13, $2 million20
in value flowed through immediately to the Idaho retail21
customers. Much has evolved since the time that the22
Commission originally approved the stipulated settlement and23
accompanying Agreement. The Company has gone through24
proceedings at the Federal Energy Regulatory Commission and25

GALE, DI-REB 8
Idaho Power Company
Oregon Public Utility Commission, the actual separation of1
IE and Idaho Power has occurred, and we have been engaged in2
an extended procedure before this Commission. Many parties,3
including Idaho Power and IE, have considered the potential4
value in the arrangement. The Company and IDACORP Energy5
have identified the need to attempt to quantify any6
additional value that IE could prospectively obtain from the7
use of system transmission and system capacity services, as8
well as other potential intangible benefits. At the time9
this testimony is being prepared, both parties are10
negotiating a proposed compensation amount that might be11
applied prospectively for these items. I hope to report on12
the result of these negotiations at the hearing.13
Q. Please summarize your understanding of Staff14
witness Sterling’s testimony related to the issues the15
Commission identified for investigation in this case.16
A. Mr. Sterling discusses some of the17
difficulties in managing a hydro system during volatile18
times and the interaction between long-term planning and19
shorter-term operations. He also makes recommendations20
regarding the composition and role of Idaho Power Company’s21
Risk Management Committee on a going forward basis.22
Q. How do you respond to his comments and23
recommendations regarding planning and operations?24

GALE, DI-REB 9
Idaho Power Company
A. I believe there are substantial areas of1
agreement between my prefiled direct testimony and Mr.2
Sterling’s recommendations. The Company agrees that there3
should be a direct link between planning criteria, the4
Integrated Resource Plan (“IRP”), and general revenue5
requirements. If, as a matter of public policy, the6
Commission determines that the system resource planning7
should be performed on the basis of a more critical water8
year or if generating reserve margins need to be increased,9
the Company can act upon that direction. Again the trade-10
off will be higher base rates (to reflect the costs of11
additional capacity) against potentially lower PCA price12
volatility. I believe the logical time to discuss these13
issues is during the development of the next IRP. Idaho14
Power contemplates a significant level of public involvement15
in the preparation of the 2002 IRP.16
Q. Please respond to Mr. Sterling’s comments17
regarding Idaho Power Company’s Risk Management Committee.18
A. I agree with Mr. Sterling’s comments on this19
issue. As mentioned in Mr. Sterling’s testimony, the20
Company has established separate Risk Management Committees21
for both IDACORP Energy and Idaho Power Company. Idaho22
Power’s RMC is comprised of officers and senior managers23
from Power Supply, Finance, Delivery, Legal, and Regulatory.24
As previously mentioned, the only common member to both the25

GALE, DI-REB 10
Idaho Power Company
Idaho Power RMC and the IDACORP Energy RMC is Mr. LaMont1
Keen, the Chief Financial Officer for IDACORP, INC. – the2
parent company for both companies.3
Q. Please summarize your understanding of Staff4
witness Carlock’s testimony related to the issues the5
Commission identified for investigation in this case.6
A. Ms. Carlock states that certain conditions7
relating to separation, control, information, and8
compensation need to take place in order for the Staff to9
once again become comfortable with the IPC/IE arrangement.10
She recognizes as Mr. Lord did in his testimony, that the11
“lower-of-cost or market” basis is unsustainable for any12
period of time for the type of service performed by IDACORP13
Energy and that Mid-C pricing for intra-month transactions14
is an "appropriate pricing mechanism once control objectives15
are quantified and operational".16
Q. What is your general response to her17
testimony related to IPC-E-01-16?18
A. I am in general agreement with Ms. Carlock on19
the desirability of enhancing the existing level of20
management of the IPC/IE relationship. I do believe that21
the Company is in the best position to lead on the22
development of the “best practices” for risk management23
policy and procedure. The Company is dedicated to enhancing24
our procedures in this area and welcomes the input of Staff25

GALE, DI-REB 11
Idaho Power Company
and others in developing an ongoing risk management plan1
that may be acceptable to all. Initially, the elements of2
such a plan involve agreement on the role of a price view3
(or lack thereof) within the utility, some consensus on the4
risk appetite of the parties, control procedures,5
information protocols, and the development of a model that6
can deal with the complexities of a hydroelectric system.7
I also agree with Ms. Carlock that the8
" . . .market pricing for intra-month transactions is9
appropriate, once control objectives are quantified and10
operational." I believe that with renewed confidence in the11
autonomy, controls, value compensation, and risk plan, that12
the transfer price issue will be behind us.13
Q. Witness Carlock testifies on p. 17 that the14
FERC rejected use of the Mid-C index for setting transfer15
prices for real-time transactions. What is the status of16
the Company's real-time pricing methodology at the FERC?17
A. First, I must correct a misunderstanding18
evidenced in Ms. Carlock's testimony on this matter. The19
FERC did not reject the use of the Mid-C price index for20
real-time transactions. There is no Mid-C price index for21
real-time transactions. If there was, I am confident that22
the FERC would have approved its use for pricing real-time23
transactions. As noted on page 2 of the April 27, 2001 FERC24
order (Staff Exhibit No. 118), the FERC found that tying the25

GALE, DI-REB 12
Idaho Power Company
price of affiliate transactions to a regional market index,1
which is not subject to manipulation, is an effective2
mechanism to prevent affiliate abuse.3
Because there is no market index for real-4
time transactions, the FERC directed Idaho Power to amend5
the Agreement and to revise the tariff and service6
agreements consistent with Commission precedent governing7
the sale of power at market-based rates to an affiliated8
entity. Ms. Carlock correctly notes in her testimony that9
on May 14, 2001, Idaho Power and IE made a compliance filing10
in accordance with the FERC's order.11
Q. If Idaho Power has made a compliance filing12
with the FERC, why has it not made a filing with the IPUC to13
implement that compliance filing?14
A. Because the FERC's April 27, 2001 order was15
rather cryptic on this point, Idaho Power's compliance16
filing suggests two alternative ways of complying with the17
FERC's order. In Idaho Power's opinion, both alternatives18
comply with the FERC's order, but they would have very19
different effects on transfer pricing for real-time20
transactions. As of the date of the filing of this21
testimony, Idaho Power has not received an order from the22
FERC addressing the May 14, 2001 compliance filing.23
Q. Does Idaho Power concur with the FERC's24
decision regarding real-time pricing?25

GALE, DI-REB 13
Idaho Power Company
A. No. In fact, you will note on Page 2 of the1
FERC Order (Staff Exhibit 118), that after it directed Idaho2
Power and IE to revise the Agreement with respect to real-3
time transactions, the FERC order indicates that "Applicants4
may, in a new Section 205 filing, either; (1) make a showing5
as to why their real-time pricing proposal is consistent6
with that precedent; or (2) offer another proposal that is7
consistent with that precedent." It is Idaho Power's8
intention to make a new Section 205 filing in the near9
future. In addition, it is the Company’s intention to meet10
with the FERC staff personnel familiar with the Agreement in11
the very near future to discuss the potential adverse12
impacts on Idaho Power's customers arising out of the FERC's13
decision to modify the real-time pricing methodology that14
was acceptable to the parties that signed the Stipulation in15
the IPC-E-01-13 case.16
Q. Please comment on how the fee structure under17
the IPC-IE Agreement should be evaluated prospectively.18
A. I believe the fee structure should continue19
to provide demonstrated cost savings to the utility. Also,20
I believe the fees should be able to withstand a market21
test. The market value should become easier to assess as22
more of these arrangements are introduced and implemented.23
It is my understanding that other utilities that serve Idaho24
customers have risk management agreements with third25

GALE, DI-REB 14
Idaho Power Company
parties. The Staff could certainly use its audit1
capabilities to obtain and compare the services and fees2
under those arrangements against the Idaho Power/IDACORP3
Energy arrangement. Ultimately it may be determined that4
service agreements like the IPC/IE Agreement should be put5
out to bid.6
Q. Your testimony describes an evolving,7
collaborative process through which the Company, the Staff,8
and the Company’s customers develop mutually acceptable9
revisions and enhancements to the IE/IPC arrangement. Until10
that process is completed, what are the “ground rules” that11
should apply to transactions between Idaho Power and IE12
under the Agreement?13
A. It is my belief that there is a strong14
likelihood that the interested parties will ultimately be15
able to agree on revised and enhanced controls, practices16
and compensation that will restore confidence in the IPC/IE17
arrangement. Achieving that consensus will take some time.18
During the period when those discussions are being pursued,19
Idaho Power and IE need to know what the “ground rules”,20
including transfer prices, are. It is not fair to expect21
that Idaho Power and IE can continue to incur millions of22
dollars in costs without a reasonable assurance that they23
will be able to recover those costs so long as they obey the24
rules which have been accepted by the Commission.25

GALE, DI-REB 15
Idaho Power Company
Q. What is your recommendation for the interim1
rules governing transactions between Idaho Power and IE2
during the period where the parties are working through the3
issues on a prospective basis?4
A. As indicated in my direct testimony, until5
such time as the Commission makes a final determination that6
the existing rules should be changed, Idaho Power believes7
that the rules governing the conduct of transactions between8
Idaho Power and IE (including transfer prices) should be the9
existing rules accepted by this Commission, the FERC and the10
OPUC. Idaho Power believes this approach is consistent with11
prior Commission decisions requiring that practices and12
rules adopted by the Commission remain in effect until13
changed by subsequent order.14
Q. Does that conclude your testimony?15
A. Yes.16