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IDAHO POWER COMPANY
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BOISE, IDAHO 83707
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An IDACORP Company r,r"H "1"""" l;A J ' '
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BETSY GAL TNEY
Regulatory Affairs Representative
Pricing & Regulatory Services
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(208)388 5309UTILI1 \L:3 CUr;,f'-j;::J~IOr~ FAX (208) 388-6449
MAIL bqaltnevcw.idabQQower.com
October 27 I 2004
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
PO Box 83720
Boise, Idaho 83720-0074
RE:Compliance Filing
Dear Ms. Jewell:
In Order No. 29102, issued on August 28, 2002, in Case No. IPC-01-, the
Commission directed Idaho Power Company to file with the Commission an analysis of its
three-tiered risk management strategy detailing its effect on customers and the Company
once it had been in place for two years. Accordingly, attached to this compliance filing is an
original and six copies of the October 2004 analysis of the Idaho Power Company Risk
Management Policy Strategy. Three extra copies of this compliance filing are enclosed for
Randy Lobb, Lisa Nordstrom, and Terri Carlock. Copies have also been sent to the
Customer Advisory Group.
Very truly yours
BG:ma
Enclosures
Randy Budge
David Hawk
Pam Eaton
Dan Kincaid
Francis McDonnell
Don Reading
Peter Richardson
Janice Stover
Lynn Tominaga
Ric Gale, PCO (w/o attachment)
Bart Kline, IPCO (w/o attachment)
Idaho Public Utilities Commission
Office of the SecretaryRECEIVED
NOV - 1 2004
Boise, Idaho
ANALYSIS OF THE IDAHO POWER RISK MANAGEMENT STRATEGY
OCTOBER 2004
IPC-Ol-
In Order No. 29102 issued in Case No. IPC-01-16 on August 28,2002, the
Commission directed Idaho Power Company to file with the Commission an analysis of
its three-tiered risk management strategy detailing its effect on customers and the
Company once it had been in place for two years. The attached analysis will include a
monthly comparison of loads resources and RMC Strategy, demonstrate that Idaho
Power considered purchase alternatives consistent with its IRP, and show what hedge
products were considered and used.
On December 4, 2002, the Company submitted the Policy Manual and Risk Guidelines to
the Commission for final review and approval. Since that time, the Company, with input
from the Customer Advisory Group and the Idaho Public Utilities Commission Staff, has
revised the Policy Manual and adopted Risk Guidelines for each successive PCA year.
The Revised Policy Manual and Risk Guidelines represent a collaborative effort among
Idaho Power customer representatives and the Idaho Public Utilities Commission Staff.
At this time the Company does not recommend any further changes or modifications to
the three-tiered risk management program.
IMPACT OF RISK MANAGEMENT PROGRAM ON CUSTOMERS
Representatives from Idaho Power, the Commission Staff and various customer groups
began settlement meetings in the fall of 2001 to discuss changes to the Company
existing practices for managing risk. Based on those discussions the Company agreed to
implement a number of changes to its risk management and hedging practices as well as
develop an extensive set of policies and guidelines. The customer groups and
Commission staff played an influential role in the development of the Company s Energy
Risk Management Policy Manual that was ultimately filed with the Commission.
Because the ongoing risk management activity undertaken by the Company is on the
behalf of its customers, the Company felt it was essential to maintain the collaborative
spirit born of the settlement process. Continuing collaboration with customers
surrounding the framework of the risk management program and specific implementation
procedures became a goal of the Company.
As a result, the Company s current risk management program is characterized by the
following collaborative features:
IPC staff will undertake to conduct an annual collaborative review and additional
workshops as needed with IPUC Staff and customer representatives to enhance the
understanding of the risk profile faced by IPC's customers;
IPC will seek input from IPUC Staff with respect to desired risk tolerances and solicit
upfront support for proposed implementation procedures;
IPC will provide IPUC Staff with regular updates on the status of the IPC risk
position and its impact on the accumulated power supply costs.
In the summer of 2002 the Company created the Customer Advisory Group ("CAG"
The Customer Advisory Group is comprised of representatives from a cross section of
customer groups. The customer groups represented include the AARP, the Industrial
Customers of Idaho Power, Micron Technology, Idaho Irrigation Pumpers Association,
the J .R. Simplot Company and the Idaho Retailers Association group. Representatives
from the IPUC Staff complete the membership.
The inaugural CAG meeting took place on August 15th 2002 and all CAG members were
in attendance. Although only required to meet once a year, the Company and the CAG
found the process to be so beneficial that multiple workshops have been conducted
throughout each PCA year to provide updates on the Company s risk program and to
elicit feedback on various issues related to implementation of the program.
These meetings serve four major purposes. First, to provide a forum for input from IPUC
Staff and customers with respect to desired risk tolerances and confinn consensus for
proposed PCA Year Risk Guidelines. Second, provide an opportunity for CAG members
to review and comment on the Company s implementation of its risk management
policies. Third, the workshops provide the Company with an opportunity to enhance
CAG member s understanding of various aspects of risk management. Lastly, they
encourage round table discussion on how to enhance or modify the Company s risk
management strategy and policy manual.
Sample copies of the CAG meeting minutes are attached to this analysis. The material
underscores the depth of infonnation discussed at each CAG meeting, shows the
Company s efforts to educate participants on various facets of risk management, serves
as evidence of the collaborative nature of the decision making forum especially with
regard to the adoption of Risk Guidelines, and depicts the upfront support garnered for
proposed implementation procedures.
The Company and CAG members have been committed to making the collaborative
process productive. CAG members have been vocal in the decision making process and
contributed significantly to the roundtable debate. All participants have made substantial
time commitments. The Company appreciates the time and efforts dedicated by these
parties and is especially appreciative of the pursuit of a mutually acceptable resolution of
the issues.
Based on input from CAG members (comments follow) and an internal assessment, the
Company is confident that it collaborated effectively with IPC Staff and customer
representatives with regard to its Risk Management Program. The Company is confident
that this successful collaborative approach will serve to mitigate negative regulatory
hindsight reviews of the risk management activity it undertakes on the behalf of its
customers.
The Idaho Power Company Customer Advisor Group (CAG) for Risk
Management has been a good forum for education, discussions and
updates. I believe this process has helped the various
stakeholders understand the various components of the Risk
Management Policy. It has also helped all stakeholders obtain
insight into the Commission Staff review process while discussingissues.
Terri Carlock, IPUC Staff
IMPACT OF RISK MANAGEMENT PROGRAM ON COMPANY
History and Overview
By resolution of the Idaho Power Company Board of Directors, the Company is
mandated to engage in a program on behalf of both customers and shareholders that
systematically identifies, measures, evaluates, actively manages and reports on the
market-driven risks associated with its commercial operations.
On an interim basis the Company has defined market risk as the exposure to adverse
movements in regional power prices in conjunction with adverse hydro conditions. The
Company has identified the major factors driving variations in purchased power cost, and
each year establishes Risk Guidelines that serve to limit the Company s market risk over
a maximum I8-month period. Because the ongoing risk management activity undertaken
by the Company is primarily on the behalf of its customers, the annually established Risk
Guideline limits reflect the desired risk tolerances of customers, the Company, and
regulators. The Company then applies hedges to limit risk to these tolerances.
In order to establish annual limits, the Company conducts one or more collaborative
workshops with Commission Staff and customer representatives (via the Customer
Advisory Group) to review the resource-related risks facing the Company and its
customers. The Company also solicits input from IPUC Staff concerning appropriate risk
tolerances for the coming year. The Company then establishes consensus Risk Guidelines
that define levels of risk which require the Company to take action (i., Tier One
guidelines limit the risk arising from the total dollar exposure (System Risk Limit) to
changes in loads, resources and market prices from a base case, Tier Two guidelines limit
the risk arising from changes in the monthly load resource balance, and Tier Three
guidelines limit the risk arising from potential upward price movement).
As the Company manages to these tolerances, it notifies the Commission and Staff, in
confidence, any time it enters into forward monthly contracts whose price exceeds a pre-
defined Market Review Trigger. This mechanism provides the potential for the IPUC to
issue early consumer price signals (i.e., by adjusting retail rates) in a rising market. The
Company also has organized an internal Risk Management Committee (RMC) that is
separate from IDACORP (its corporate parent) to document decisions for possible audit
by Commission staff.
2002- 2003 PCA Year
Among the three risk-limiting mechanisms, (i.e., Tier One, Tier Two and Tier Three),
Tier Two tended to dominate IPC's system. By effectively hedging Tier Two risks, the
Company was able to control overall risk to acceptable levels. Throughout the
management of the 2002-2003 PCA year the Tier One System Risk Limit was not
breached and Tier Three activity was rare. Despite our own low hydro output for the
2002-03 PCA-year, the higher level of regional hydro output helped to contain the cost of
replacement power. The result was a potential variance from Baseline Expected Cost
Forecast (BECF) that did not approach the System Risk Limit.
2003-2004 PCA Year
The BECF for the 2003-04 year was established during a time of fairly low regional
market prices. Prices gradually increased as regional accumulation of snow-pack trended
lower than normal. Idaho Power s stream-flow forecasts since October also trended
below normal, bringing a steady stream of Tier Two purchase signals, at gradually
increasing prices. Despite forecast poor hydro production and market prices higher than
Base, Idaho Power was well below the Tier One limit as the year began. As time
progressed the Company experienced further degradation of summer hydro output and
much higher summer market prices. In early 2004 the Company saw the breach of Tier
One System Limit for the first time since the program s inception due to a combination of
higher than expected prices and lower than expected water. To limit exposure related to
these events the Company significantly increased its hedging activity under Tier Two in
order to fill the shortage caused by the poor hydro outlook. There was no Tier Three
activity during this PCA year period.
The continual breach of the System Risk Limit and the fact that the breach did not
necessarily con-elate to a significant rise in the PCA defen-al balance called into question
the efficacy of the Tier One risk management strategy. (For example the 2003-2004 PCA
deferral balance was $44.3. million including interest.) This issue was discussed within
the RMC and with the Customer Advisory Group and Staff, those parties that had
collaborated to establish the annual System Risk Limits. All parties recognized that there
was a difference between the Tier One variance and PCA defen-al balance. The three
tiered risk management policy cun-entl y in place protects against adverse movements in
net power supply costs as measured by the variance between a baseline established in
October of each year and the forecast of power supply costs under a low waterlhigh-price
case scenario (Tier One) while the accumulated PCA defen-al balance records the
variance of actual PCA "formulated" power costs from a forecasted number set in the
Spring of each year. The issue put before the collaborative was whether the System Risk
Limit calculation should be modified to prevent hedging activity that could drive the
Company to be carrying an excessively long portfolio if the low water case did not
materialize. The collaborative, Company and Staff evaluated the issue and decided to
maintain the policy described process and guidelines for calculating and reporting Tier
One Variance without modification.
Conclusion
The interim risk management policy has worked well for the Company. Its simplicity has
made it an excellent entry vehicle for education and customer understanding of
complicated risk management principals. The Company has built new skills regarding
risk assessment and the design and management of related hedging strategies. The
Company s strategy has changed from one in which it tried to anticipate market
movements, to one that implements hedges with an unemotional mechanical process.
Under the tiered risk management program the Company is a frequent early entrant into
the market. To date this agility has benefited customers, as the company has been able to
diversify its hedge portfolio by buying and selling blocks of power far in advance of
forecasted needs or surpluses. The Company s discipline has been rewarded with market
purchases earlier in the year and at lower prices then if it had waited.
COMP ARISION OF LOADS, RESOURCES, AND RMC STRATEGY
2002- 2003 PCA Year
Idaho Power experienced gradually worsening forecasts for hydro generation throughout
the year. Tier Two guidelines encouraged regular purchases, at (generally) increasing
market prices. Regional hydro generation remained near long-term average levels,
holding market prices lower than they might have been otherwise. This was a
contributing factor to maintaining Tier One variance well below the System Risk Limit.
2003- 2004 PCA Year
Again, Idaho Power experienced a gradual reduction in forecast hydro generation as
snowpack failed to accumulate to normal levels. As during the prior year, Tier Two
purchases were made to bring monthly deficiencies within tolerance. Regional hydro
generation was also below normal for the year, which increased the cost of replacement
power for all utilities in the region. Tier One-initiated transactions were rare, but
variance remained near the System Risk Limit throughout the year.
Attached to this analysis, as Attachment One is the backcast summary data for the 2002-
2003 and 2003-2004 PCA years. The report depicts in daily average MWs the interplay
of loads, resource and hedges. Any resulting surplus or deficit was balanced by
purchases or sales in the real-time or day ahead market.
Attached to this analysis, as Attachment Two is the Tier One variance graphs for the
2002-2003 and 2003-2004 PCA years. The graphs depict the variance in net power
supply costs (as defined by the Policy) from the baseline forecast or BECF.
PURCHASE AL TERNA TIVES AND THE INTEGRA TED RESOURCE PLAN
(IRP)
At the end of the 1990's Idaho Power Company and others assumed the market would
provide incremental system resources. For a number of reasons including the 2000-2001
energy crisis, the market model did not materialize. As a result, the Company has built
both new resources and acquired them through an RFP process. In the 2002 IRP, the
Company identified a strategy that incorporated the following key components:
Continue to make seasonal market purchases of 100 aMW in the months of June,
July, November and December
Integrate demand-side measures where economically feasible to address short
duration peaks of the system load,
Solicit proposals for approximately 100 MW of peaking resource to be available
beginning in 2005,
Purchase up to 250 MW of capacity and associated energy during peak periods
beginning June 1,2005 (Garnet Project)
Proceed with the Brownlee-Oxbow #2 transmission line project,
Proceed with the Shoshone Palls upgrade, targeting an in service date of 2007
The Garnet Project was ultimately cancelled. On October 30,2002, Idaho Power filed
the Garnet Report, which outlined alternatives and Idaho Power s recommendations to
replacing the Garnet PP A. The recommendations contained in the Garnet Report are
summarized as follows:
Continue negotiations for potential seasonal exchanges or power purchases
Acquire firm transmission rights across PacifiCorp s system to Idaho Power s east
side
Issue an RFP for a Mona/Red Butte firm wholesale power purchase agreement
Increase the size of the 100 MW peaking resource identified in the 2002 IRP.
2002- 2003 PCA Year
Consistent with the Risk Management Policy and action plan outlined in the 2002 IRP,
before April 2002 Idaho Power had purchased 100 aMW for June 2002 and July 2002.
Before the end of August 2002, approximately 100 aMW had been purchased for
December 2002. Given the anticipated November surplus/deficit, the Company was able
to comply with the Risk Management Policy without entering into the full 100 aMW ofNovember purchases.
2003-2004 PCA Year
Consistent with Risk Management Policy and the action plan outlined in the 2002 IRP,
before May 2003 Idaho Power had purchased in excess of 225 aMW for June 2003 and
400 aMW July 2003. These purchases were made over several months with the earliest
purchases occurring in October 2002. Given the anticipated November surplus/deficit, the
Company was able to comply with the Risk Management policy without making the 100
aMW of November purchases. By November of 2003, Idaho Power had purchased in
excess of 100 aMW for December 2003
Demand-side measures have been implemented to address short-term peaks; examples
include the AlC cycling program (summer 2003 & summer 2004), inigation TOU rates
(beginning Summer 2001), and the irrigation peak-clipping pilot (summer 2004).
addition, seasonal rates were proposed and implemented as part of the recent General
Rate Case.
Proposals were solicited for the 100 MW peaking resource identified in the 2002 IRP,
and as suggested in the Garnet Report, the option of increasing the size of this resource
was investigated. Ultimately, the Bennett Mountain project (162 MW) was selected. The
project is cuITently under construction and is scheduled to be on-line before June 2005.
Idaho Power proceeded with the Brownlee-Oxbow #2 transmission line as outlined in the
2002 IRP. This line is currently in service.
The Shoshone Falls upgrade is still planned. However, due to delays in receiving the
new Shoshone Falls license, this project is currently expected to be complete in 2008.
Idaho Power has executed the strategy outlined in the Gamet Report. The actions are
summarized as follows:
In May of 2003, Idaho Power entered into a firm wholesale Power Purchase
Agreement with PPL Montana, LLC. The agreement provides Idaho Power with
83 MW (g) $44.50/MWh during the HLH of June, July and August. The
agreement runs through August 2009.
In May 2003, Idaho Power entered into a Service Agreement with PacifiCorp for
long-term firm, point-to-point transmission services from Red Butte to
BorahlBrady. The Service Agreement provides 75 MW of firm transmission
service from June through October and 0 MW of transmission service from
November through May. There is no charge for the 0 MW of service from
November through May. The Service terminates on May 31 2006. Since this is
long-term firm, point-to-point transmission service, Idaho Power has renewal
rights.
In January 2003, an informal RFP for MonalRed Butte firm wholesale power
purchases was issued. Based upon the response received, Idaho Power decided
not to act on any of the proposals received as a result of this solicitation.
The size of the peaking resource identified in the 2002 IRP was increased.
Ultimately, the Bennett Mountain project (162 MW) was selected. This project is
currently under construction and is scheduled to be on-line before June 2005.
In summary, Idaho Power believes that its actions have been consistent with both the
Risk Management Policy, and the plans for securing long-term resources outlined in the
2002 IRP ands the Gamet Report. Idaho Power will continue to work toward securing
additional long-term resources as further detailed in the 2004 IRP filed with the IPUC onAugust 27, 2004.
HEDGE PRODUCTS CONSIDERED AND USED
All electricity purchases and sales have been standard fixed-price contracts for physical
delivery. Also considered (but not executed) were physical transactions priced at index.
An index-based transaction, if executed, would have been paired with a financial
transaction, such as a swap, to provide delivered physical power at a risk-limiting fixed-
pnce.
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n
IDAHO POWER COMPANY
Minutes of Spring Meeting of
The Idaho Power Company
Customer Advisory Group (CAG)
March 1 2004
A scheduled meeting of the Idaho Power Customer Advisory Committee
was held in the Corporate Headquarters building on Monday, March 1 2004, at 9:00am.
A list of those in attendance is attached. Mr. Gale acted as facilitator and Ms. Galtney
acted as Secretary of the meeting.
Mr. Gale welcomed the participants and presented the Agenda. A copy of the
agenda is included by reference in these minutes. Mr. Bart Kline reminded the
participants that the information, charts, and calculations provided to participants during
the workshop contain commercially valuable data and should remain confidential and
should not be used for purposes outside of the scope of the workshop or disclosed to
persons not participating in the CAG. In addition Mr. Kline stated that the information
could not be us~d as discovery in the general rate case proceedings.
To begin the meeting, Mr. Gale called upon Mr. Vern Porter to report on current
and future prices for wholesale energy. Mr. Porter presented a written report showing
the electricity forward price curves for Palo Verde and Mid-Columbia. Supplementing
Page
his written repprt, Mr. Porter discussed the Company s ability to access southwest
power, northwest peaking scenarios and the Brownlee constraint. Mr. Porter then
answered questions.
Mr. Gale then asked Mr. Bokenkamp to review portions of the February
12, 2004, Operation Plan that had previously been presented to the Idaho Power
Energy Risk Management committee. Supplementing his report Mr. Bokenkamp
presented a written Operation Plan to the group. Mr. Bokenkamp reviewed the
operating assumptions associated with the Operations Plan , highlighted the hedging
activity that had been implemented as a result of the Three tiered Risk Guidelines and
he concluded with a discussion of why Tier One breaches for the '03-04 and '04-
PCA years had occurred. Mr. Bokenkamp then answered questions. He clarified that
the Operation Plan analyzed average surplus and deficits and did not model peak
scenarios. CAG members expressed favorable opinions with regard to the prices at
which Idaho Power had covered surplus and deficits under Tier Two. CAG members
also expressed interest in the Company considering summer electricity purchases for
05 and '06 based on probable need under expected conditions.
Mr. Bokenkamp then distributed a graph that highlighted Tier Three
indications since October 2003. The graph showed that prices had general followed the
shaped floor limits approved by the CAG. He suggested that the floor limits be
reviewed again at the Fall Meeting.
Page 2
Mr. Bokenkamp concluded his remarks with an explanation of why the
Company was experiencing variances from the BECF greater then $100 million.
stated that the breach for the '03-04 PCA year was due to the continual erosion of the
water forecast from the BECF (established in October of every year) and the
underperformance of the thermal fleet. He advised that due to the lack of significant
deficits for March '04, no transactions could be recommended to eliminate the breach
for the '03-04 PCA year without making the system extremely long under the expected
case. He also stated that the RMC had approved a significant number of hedges in
order to reduce the '04-05 Tier One breach. Meeting participants discussed whether
the BECF calculation should be refined to better reflect current price expectations or if
the BECF calculation should be left static with the understanding that the Company
could provide an explanation for the breach. It was agreed that the Company and Staff
would discuss the options(including the Tier One Calculations and if additional
evaluations need to be shown or any changes made to the calculation), determine the
best way to inform the Commissioners of Tier One breaches and report back to the
CAG at the Fall Meeting.
Mr. Gale then called upon Mr. Greg Said to report on the PCA. Mr. Said
presented a written report showing the PCA components and possible 2004 PCA rates.
After his presentation Mr. Said answered questions. He clarified the misconception that
normal snow pack would lead to normal stream flows by explaining that many years of
drought had depleted water storage. Accordingly much of the snow pack melt would be
absorbed by the soil and aquifers and not contribute to stream flow.
Page 3
Mr. Gale called upon Mr. Bokenkamp to report on the Company s gas
procurement strategy. Mr. Bokenkamp presented a written report outlining the current
gas and transportation contracts, the Company s gas strategy for Danskin and Bennett
Mountain for 2004 , hedging details, and forecasted gas requirements through June
2008 necessary to meet system peaks. Mr. Bokenkamp stated that the Company was
considering commodity purchases based on a Dollar Cost Averaging Approach or the
Delta Hedge Model. CAG members generally expressed an interest in the Company
locking gas supply out thru 2007 based on obvious need. A CAG member felt that now
was the time to lock in supply as gas prices were steadily rising. Staff expressed
concern that purchases match demonstrated need and stated that gas purchases to
cover heavy load generating requirements appeared to be a closer match. There
wasn t a common CAG position or directive on how far in advance to purchase or hedge
gas prices.
Mr. Gale called upon Mr. Bokenkamp to discuss the relationship between
short-term and long-term resource planning. Mr. Bokenkamp stated that the AMC
reviews operating needs of the Company out over an 18-month period and that the lAP
reviews operating needs of the Company during the current year out to ten years. Staff
expressed concern that there was a mismatch between the Operations Plan and the
lAP. Mr. Bokenkamp explained that the AMC had oversight over both the 18 month
operating plan and the lAP. Longer-term resources are identified under the lAP.
resources are procured they are incorporated in the18 month operating plan. However,
Page 4
a supply side resource such as Danskin may be available to serve load but may not be
economically dispatched in the Operating Plan. This does create the potential for a gap
or mismatch between the Operating Plan and the I RP. The RP uses the peaking
resources (Danskin and Bennett Mountain) up to their operational limitations in its
assessment of resource adequacy. For example , the IRP's assessment of monthly
energy surplus/deficit under the 70th percentile water & 70th percentile load planning
criteria might include using both peakers for the entire month to meet monthly energy
needs, yet the peakers may not be economically dispatched during the same month in
the Operating Plan. Idaho Power recognizes this potential mismatch and will consider
it during preparation of the 2004 lAP. As fuel is procured for the peakers, or as they
are economically dispatched, they will be reflected in the Operating Plan.
Mr. Gale then asked Mr. Whittaker to review some comparative Tier One
System Risk Limit scenarios at the request of GAG members. Mr. Whittaker presented
a written report highlighting the Tier One variance impact of a $60 million System Risk
Limit. His analysis indicated that based on the erosion of the low water forecast since
the October 2003 establishment of the BEGF it would have been impossible to keep the
variance under the $60 million. Mr. Whittaker concluded his remarks by answering
questions.
There being no other business to come before the Committee , Mr. Gale
reviewed the outstanding items; discuss with Staff whether or not to modify the BECF
calculation or the timing of the calculation, and take CAG recommendations to the RMC
regarding summer electricity purchases for '05 and '06 and gas purchases for June and
July of '
, '
06 and '07.
Page 5
Ms. Betsy Galtney stated that a draft copy of the minutes from today
meeting would be distributed via email and that comments should be returned by the
end of the month. With consent of the GAG and Staff, Ms. Galtney tentatively
scheduled the next CAGmeeting for August 12, 2004.
At 12:45 pm the meeting was adjourned.
Page 6
IDAHO POWER COMPANY
Minutes of Fall Meeting of
The Idaho Power Company
Customer Advisory Committee (CAG)
August 19, 2003
A scheduled meeting of the Idaho Power Customer Advisory Committee
was held in the Corporate Headquarters building on Tuesday, August 19, 2003, at
10:00am. A list of those in attendance is attached. Mr. Gale acted as facilitator and Ms.
Galtney acted as Secretary of the meeting.
After opening remarks from Idaho Power CEO, Mr. Packwood and Vice
President - Power Supply, Mr. Prescott, Mr. Gale welcomed the participants and
presented the Agenda. A copy of the agenda is included by reference in these minutes.
Mr. Kline reminded the participants that the information, charts, and calculations
provided to participants during the workshop contain commercially valuable data and
should remain confidential and should not be used for purposes outside of the scope of
the workshop or disclosed to persons not participating in the CAG.
To begin the meeting, Mr. Gale called upon Mr. Bud Hild to report on current and
historical prices for wholesale energy. Mr. Hild presented a written report showing
observed energy prices for Mid C, Palos Verde, and gas prices for Henry Hub and
Page
Sumas. Supplementing his written report, Mr. Hild discussed forward prices, price
differential between the east and west side of the system , the impact of warm weather
on market price, reservoir data, and Val my maintenance information. After answering
questions Mr. Hild excused himself from the meeting.
Mr. Gale explained to the group that Mr. Hild is considered by the FERC to be a
merchant function" employee. To ensure that there is no improper disclosure of
transmission information in all GAG meetings, "merchant function" employees will
present their information at the beginning of the CAG meetings and then be excused for
the remainder.
Mr. Gale then asked Mr. Bokenkamp to review portions of the August 12,
2003 Operation Plan that had previously been presented to the Idaho Power Energy
Risk Management committee. Mr. Bokenkamp presented a written Operation Plan to
the group.
A recommendation was made to consider revision of the Flow Forecast
graph and Reservoir Plan graph to make it easier to read. A question was asked by
Commission Staff as to whether hedging activity took place outside of the time period
for the current Risk Guidelines. Mr. Bokenkamp stated that outlying months were
managed and that hedging did occur but that the Hedge summary sheet only
recognized those hedges that were required under the currently effective Risk
Page 2
Guidelines. After a discussion of reservoir management Mr. Bokenkamp concluded his
comments.
Mr. Gale then asked Mr. Whittaker to review the forward pricing
methodology that was used in the Operation Plan. Mr. Whittaker presented a written
report highlighting the steps used to create forward prices at major trading hubs. Mr.
Whittaker concluded his comments after answering questions.
Mr. Gale then asked Mr. Bokenkamp to review Oanskin Operations
including the Oanskin gas contract. Mr. Bokenkamp presented a written report. Mr.
Bokenkamp supplemented his written report by commenting that Danskin operated
approximately 680/0 of the heavy load hours in July. Mr. Bokenkamp stated that Oanskin
was helping the Company meet heavy load needs in July and August in addition to
providing reliability and optionality in the marketplace. The CAG members discussed
gas purchasing concerns for the August 2004 time period and generally agreed that
scaling into required volumes was an appropriate purchasing strategy.
Mr. Gale then asked Mr. Bokenkamp and Mr. Whittaker to present the
Company s proposal for the 2004-2005 PCA Year Risk Guidelines. Mr. Bokenkamp
presented a written report outlining the Company s proposal. A copy of the report is
attached to these minutes. The Company s recommendation for proposed limits is
summarized:
Tier 1- System Risk Limit-$1 00 million-no change
Page 3
Tier 2 -Volumetric Limit-100 MW- no change
Tier 3- Floor Limit- Drop $30 guideline to $25, no change to the others and
shape floor limits to reflect historical seasonality of prices.
The CAG participants and Staff were in agreement with the Company
proposal for Tier One and Tier Two. However they requested that at the spring meeting
a backcast be provided for review and that a comparative analysis be created so that
CAG members could evaluate the impacts of higher and lower System Risk Limits and
Volumetric Limits. CAG participants agreed with the Company s position to shape Tier
Three but advised that the heavy load floor limit under the expected case should remain
at $301 MWh , but should be seasonally shaped rather then the recommended $25/MWh
seasonally shaped. The Company pointed out that $25 seasonally shaped would still
allow for summer purchases near $30, however CAG members were comfortable with
economy purchases at slightly higher prices. CAG members stated that they were
comfortable with the current amount of Tier 3 activity and that decreasing the floor limit
would potentially lead to the Company not making advantageous purchases in the
summer months. The Company accepted the GAG recommendation to maintain the
$301 MWh heavy load floor limit under the expected case and indicated that they would
provide a revised Risk Guideline for the upcoming PCA year for GAG and Staff review.
Mr. Gale then asked if the workshop participants recommended a revision
to the Market Review Trigger (MRT) currently set at $60. Participants indicated that
they were satisfied with MRT at $60 and recommended no change. Staff requested that
Page 4
the communication regarding MRT events be expanded and the Company agreed to
supplement MRT notification in the future. There being no further discussion , it was
agreed by all parties that the MRT trigger would remain unchanged for the 2004-2005
PCA year.
The Chairman then asked Ms. Galtney to review the proposed changes to
the Energy Risk Management Policy Manual (Policy). Ms. Galtney presented a written
report highlighting the proposed changes to the Policy that she reviewed with the
meeting participants. Supplementing her written report, Ms. Galtney distributed a copy
of th~ revised Policy for review by CAG members and Staff. Ms. Galtney stated that the
document had been presented to the Audit Committee of the Board of Directors and
that the Policy would be presented to the Board for final approval by October of this
year. After a brief discussion the CAG and Commission Staff members indicated their
approval of the changes to the Policy. This concluded Ms. Galtney remarks.
There being no other business to come before the Committee, Mr. Gale
reviewed the outstanding items; expansion of the Hedge Summary sheet in the Op Plan
to reflect the review of months outside of the PCA period, further review of the gas
purchasing strategy for Danskin and the development of comparative scenarios for Tier
1 and Tier 2 analysis purposes. Mr. Gale stated that the minutes from the meeting as
well as the revised Risk Guidelines for the 2004-2005 PCA year would be circulated for
review and comment. With consent of the CAG and Staff, Mr. Gale tentatively
scheduled the next CAG meeting for February 2004. Mr. Gale advised that any agenda
Page 5
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items not addressed during today s meeting would be discussed at the February
meeting. These include an update on the status of Low Risk Arbitrage Opportunities,
Short-Term Resource Planning along with a documented explanation of how it fits with
Long-Term Resource Planning, and discussion of the outstanding issues listed above.
At 3:00 pm the meeting was adjourned.
Betsy Galtney, Secretary
Page 6