200408171st Request of Staff to IPC.pdf

SCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
472 WEST WASHINGTON STREET
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 1895
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Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR APPROVAL
OF AN AGREEMENT FOR SALE AND
PURCHASE OF ELECTRIC ENERGY
BETWEEN IDAHO POWER COMPANY AND
RENEWABLE ENERGY OF IDAHO, INC.
CASE NO. IPC-04-
IPC- E-04-1 0
FIRST PRODUCTION
REQUEST OF THE
COMMISSION STAFF TO
IDAHO POWER COMPANY
The Staff of the Idaho Public Utilities Commission, by and through its attorney of
record, Scott Woodbury, Deputy Attorney General, requests that Idaho Power Company (Idaho
Power; Company) provide the following documents and information on or before MONDAY,
AUGUST 30, 2004.
This Production Request is to be considered as continuing, and Idaho Power is requested
to provide, by way of supplementary responses, additional documents that it or any person acting
on its behalf may later obtain that will augment the documents produced.
Please provide answers to each question; supporting workpapers that provide detail or are
the source of information used in calculations; the name and telephone number of the person
preparing the documents; and the name, location and telephone number of the record holder.
FIRST PRODUCTION REQUEST
TO IDAHO POWER AUGUST 17, 2004
For each item, please indicate the name of the person(s) preparing the answers, along
with the job title of such person(s) and the witness who can sponsor the answer at hearing.
Reference IDAP A 31.01.01.228. For documents provided please include the name and phone
number of the person preparing the document, and the name, location and phone number of the
record holder.
For all responses to the following requests, please provide all workpapers, diskettes
(3.5 in.) and all underlying formulas in Excel (version 5) language.
Request No.1: On page 16, lines 9 - 11 of Kip Runyan s rebuttal testimony on behalf of
U. S. Geothermal, he states
On May 21 2004, two months after U.S. Geothermal filed its
Complaint, Idaho Power sent a letter to U.S. Geothermal that
for the first time in negotiation, denied entitlement to the
published rates for the U.S. Geothermal project.
a) Using the AURORA model, consistent with the methodology as described in the
attached document as accepted in the Settlement Stipulation in Case No. IPC-95-
and using assumptions consistent with Idaho Power s 2002 IRP, please compute an
avoided cost rate for the proposed U.S. Geothermal project. Also attached for
reference is a document previously prepared by Idaho Power with its own description
of the same methodology.
b) Please provide to Staff in an AURORA format all input and output files used in the
foregoing analysis.
Respectfully submitted this
/? ~
day of August 2004.
Scott Woodbury
Deputy Attorney General
Attachments
Technical Staff: Rick Sterling
i:umisc:prodreq/ipceO4.10swrps prl
FIRST PRODUCTION REQUEST
TO IDAHO POWER AUGUST 17 , 2004
STAFF'S PROPOSED AVOIDED COST METHODOLOGY
FOR PROJECTS LARGER THAN ONE MEGA WAIT
CASE NO. IPC-95-9
Introduction
On January 31 , 1995, the Idaho Public Utilities Commission issued Order Nos. 25882
25883, and 25884 which required that utilities utilize their Integrated Resource Plans (IRPs) to
establish avoided cost rates for projects larger than one
megawatt. The Commission stated thefollowing in its orders:
We believe that the adoption of the least cost planning methodology is consistentwith our goal of maintaining a regulatory climate that allows our elecnic utilities toretain their advantageous posture in a marketplace
that is likely to becomeincreasingly competitive, This will ultimately work to the advantage of ratepayersin the fonn of rates lower than would otherwise be in effect. By treating QFs(Qualifying Facilities) in the same manner as utility acquired resources, we arefurther removing the shelter that has been constructed around the QF industry.Requiring those projects to prove their viability by market standards insures that
utilities will not be required to acquire resources priced higher than would result from
a least cost planning process. Ratepayers will not be disadvantaged and QFs will be
treated fairly and consistently with the requirements and goals
ofPURP A.
See, e.g. Order No. 25884 at page 6.
In accordance with Order No. 22299, all utilities are required to prepare IRPs biennially. Thefollowing elements are included in the development of the IRP:
1. Integrated evaluation of all resource options;
2. Least cost selection criterion for the resource plan;
3. Inclusion of environmental impacts and external costs of resources;
4. Analysis of planning uncertainties and risks; and
5. Public involvement in the planning process.
STAFF PROPOSAL
IPC-E-95-9Exhibit 1 toSettlerrent Stipulation
An IRP fonns the basis for utility decisions regarding the timing, quantity, and type of future
resource acquisitions. The end result of integrated resource planning is a set of resource options
which represent the least cost means of meeting expected future loads considering a reasonable range
of planning uncertainties and risks. The set of options with the highest probability of having the
least cost, and which has an acceptable level of risk, is usually referred to as the "
base case" plan.The base case plan is the starting point of the analytical process described in this document for
determining project-specific avoided cost rates for QF projects larger than
1 MW.
In the past, utilities have submitted IRPs to the Commission for filing, but no formal process
has been in place for detailed review or approval
of the IRPs. However as a result of their increasedutilization and importance as something other than a planning document, utilities should expect their
plans to be scrutinized more carefully in the future. The Commission Staff intends to conduct
thorough reviews of the plans, and anticipates that hearings may be held to
provide an opportunity
to seek COIIll1lent. As in the past, utilities should not be bound to follow their IRP without exception.
In fact, when good cause is shown, they should be expected to deviate from it. But absent good
cause, they should now expect to be held to it more closely. More importantly, the IRP will establish
the standard against which all resource acquisitions will be judged, both utility and non-utility owned
alike.
Public participation is required in the preparation of utility IRPs. Developers and theirrepresentatives shall be welcome to participate in any public meeting
related to the development of
a utility IRP. It is the utility's responsibility to offer invitations to participate to a broad cross section
of interested parties. The responsibility to actually participate lies with the interested parties.
The opportunity for developers or other interested parties to ultimately influence thecalculation of avoided cost and the rates for QF projects that are derived
from that calculation, is inthe development of a Utility's IRP, not in the application of the avoided cost methodology. The IRPis the source of all inputs used in the calculation of avoided costs.
It is the real basis for
STAFF PROPOSAL
calculating avoided cost rates. Once the avoided cost methodology is established, Staff does notexpecta hearing or other formal Commission proceeding to be initiated each time a utility
s avoidedcosts are calculated.
General Methodology
PURP A defines avoided cost as "the cost to an electric utility of electrical energy or capacity
or both which, but for the purchase &om such cogenerator or small power producer
, such utilitywould generate itself or purchase from another source
18 CFR, 292.101.
, As explained by FERC:
This definition is derived from the concept of "the incremental cost ofalternative electric energy" set forth in section 210(d) ofPURPA. It includesboth the fixed and the running costs on an electric utility system which can
be avoided by obtaining energy or capacity from qualifying facilities. One
way of detennining avoided cost is to calculate the total (capacity andenergy) costs that would be incurred by a utility to meet a specified demand
in comparison to the cost that the utility would incur if it purchased energy
or capacity or both from a qualifying facility to meet part
of its demand andsupplied its remaining needs from its 0\-VIl facilities. The difference betweenthese two figures would represent the utility's net avoided cost. In this casethe avoided costs are the excess
of the total capacity and energy costs of thesystem developed in accordance with the utility's optimal capacity expansionplan, excluding the qualifYing facility, over the total capacity and energycosts of the system (before payment to the qualifying facility) developed in
accordance with the utility's optimal capacity expansion plan including the
qualifying facility. (Order No. 69 (45 Fed. Reg. 12 216, 1980)).
In the proposed methodology, the avoided cost of a QF project is determined as the cost
which the utility would avoid if it purchased power from
the QF, rather thanacquiring the samepower from the resources selected in its base case resource plan.
Put another way, the avoided cost
STAFF PROPOSAL
of the QF project is the difference in the present value of revenue requirements (PVRR) between the
base case resource plan and a modified resource plan that includes the QF resource.
The avoidedcost determination involves the following steps:
1. AnIRP is prepared for the utility. The IRP should consider a range
of load forecasts for
various sets of possible economic conditions. The IRP should also
consider all possible
resources for meeting load, both supply side and demand side. In addition, consideration
should be given to the risks and uncertainties associated with each scenario examined.
Theleast cost combination of resources is selected to meet each scenario. The most likely
scenario is identified as the base case plan.
2. An initial simulation analysis using a power supply and/or capacity
expansion model
chosen by the utility is used to calculate the PVRR of the base case resource plan over the
lifetime of the proposed QF contract.
3. The proposed QF resource is added to the base case resource plan during all years of the
proposed contract. The required description of the QF project" includes all data and
infonnation needed to model the intended dispatchable or non-dispatchable operation of the
project on the power supply system (see pps. 9-10 for a list of data and information needed
from QFs).
4. A second simulation analysis, including the QF resource, is perfonned which results in
an adjustment of the amount and/or timing of the new resources in the base case plan. Themodified plan including the QF purchase is constructed to maintain resource
adequacy and
system reliability equivalent to that of the base case plan.
5. The PVRR of the modified resource plan including the QF is calculated over the full tenn
of the QF contract, excluding the total purchase costs of the QF resource itself.
STAFF PROPOSAL
6. Finally, the present value of the QF project avoided cost is calculated by subtracting the
PVRR of the modified plan, with costs of the QF set to zero, from the PVRR of the base case
resource plan.
7. Rates for capacity and energy from the QF project can now be developed for which, on
a present value basis, the expected payments to the QF are equal to the project's avoided cost
over the life of the contract.
IRP Data for Avoided Cost Calculations
Many of the same variables must be chosen and many of the same assumptions must be made
by each utility in the development of their IRP. For example, each utility must make assumptions
about inflation, the price of natural gas, or the cost of building a coal plant. Some planning variables
will probably be the same for all utilities, but many will be different. In the past, the Commission
has specifically detennined both generic and company-specific variables used to calculate avoided
cost for large proj ects. With implementation of the IRP methodology, the Companies will be
responsible for detennining these variables. As long" as the values and assumptions fall within a
reasonable range, utilities are free to choose values most appropriate for their own situation. It
follows then, that different utilities will likely assume different values for the same variables. No
variables will be considered generic; all variables will be utility specific
, as are the utilities' IRPs.In granting utilities the freedom to select their own variables, utilities should be aware that they wilJbe required to analyze their own resources on an equal footing with QF resources.
Portfolio Resources
The resource portfolio of each utility should include a variety of both supply and demand
sideresources. Market purchases also represent a future supply option, and will likely comprise an
increasingly larger portion of utilities' resources in the future. In fact, for some utilities, marketpurchases may constitute the primary source of new resources. The cost
of market resources, to the
STAFF PROPOSAL
extent a utility relies on them, should be one component in determining utilities' avoided costs.However, in order for market resoW'Ces to be considered in the detennination of avoided costs in an
IRP-based methodology, those market resources must be included in the IRP.
Any market purchasesmade that are not anticipated in the IRP cannot be used in the calculation of avoided costs.However, due to the fact that Pacificorp' s RAMPP -4 calibration of its !PM model does not provide
for the IPM's calculation of avoided costs, PacificoIp will be allowed to propose modifications to
the !PM calibrations for the purpose of determining avoided costs, subject to Commission approval
in Case No. IPC-95-
Predicting the price and availability of market resources
, particularly in the long tenn, isdifficult and uncertain. Consequently, forecasts made in the IRP should be fmnly based on sound
reasoning and analysis. The degree of planned reliance on market resources should be a
mattl?" ofinterest to ratepayers, shareholders, the Commission and the public. Review of the utilities' plannedreliance on the market however should occur in the context
of an IRP filing, not in an avoided cost
proceeding.
Demand side resources to which the utility has made a finn commitment should be, considered as reductions in the load forecaSt rather than as supply side resources
, in part, todiscourage double counting.
Load and Resource Forecasts
Forecasts of electricity load growth are made by each utility at two-
year intervals as a partofIRP filings. These forecasts serve as the basis for avoided cost calculations.
Staff contends thatonly known, measurable, and easily documented changes should be made to the forecasts during the
interim periods between required filings. For example, discrete changes in load that could be traced
to the addition or loss of a single major customer would be a known, measurable, and easilydocumented change. The signing or expiration of a power
sales or exchange agreement would also
be a known, measurable, and easily documented change, as would the signing of a new QF contract.
STAFF PROPOSAL
On the other hand, a load change due to population growth may be known, but would not be easily
measured or docwnented.
Updating IRP Data
F or the most part, utilities' resource plans as set forth in their IRPs should guide resource
acquisition activities, including the resource cost effectiveness and avoided cost determinations
, untiJreplaced by subsequent IRPs.
One of the goals of this avoided cost methodology is to
achieve adynamic resource evaluation process that recognizes changes in loads, technologies, costsavailabilities, and economic conditions so that utilities' avoided costs are accurately determined.
However, QF developers seek to maintain some stability of avoided cost rates so that they are able
to plan projects with some degree of certainty. In addition, the public must have the opportunity to
participate in the planning process to provide input regarding variables that are ultimately used in
each utility's IRP.
To achieve some balance between these competing objectives, this methodology allows
periodically scheduled changes to some variables, while keeping other variables fixed between IRP
filings. In essence, there will be a core set of variables that are used in the IRP and in thedetennination of avoided cost rates, but a subset of those variables will be changed periodically for
the purpose of accurately calculating avoided costs. Every two years, a new IRP will be filed with
new core variables and variables that will be adjusted periodically.
Generally, variables which are acquired from independent third party sources and which are
updated at regular intervals can be adopted by utilities for use in avoided cost calculations.However, the same source must be consistently used. Any change in the source of the data must also
be agreed to by the Commission. Semi-annual updates will be allowed for the following based on
verifiable forecasts:
STAFF PROPOSAL
Escalation rates for capital costs;
. Escalation rates for O&M expenses;
. Escalation rate for fuel prices;
. Fuel prices.
If multiple sources are used to establish values for these variables,
such as for gas prices, orif a utility wishes to make adjustments to values in consideration of regional circumstances, theutility should propose the sources and adjustment mechanisms at the time of their next IRP filing
for consideration by the Commission. The utility should consistently use the same sources and
adjustment mechanisms in the future for determining avoided cost rates unless changes areauthorized by the Commission.
At such time as easily verifiable infonnation is readily available from independent third
partysources, the following variables may also be updated semiannually:
. Wholesale power price;
. Wholesale power price escalation rates;
. Wholesale power available for purchase.
The variables must be reflective of the same wholesale power products used for analysis in the IRP
so that no adjustment of the variables is needed before they can be used in the
IRP or in calculatingavoided cost rates. Pennission must be obtained from the Commission before these variables may
be updated on a semi-annual basis for avoided cost
purposes.
Staff recommends that updates to resource portfolio data, such as plant capital costs
Operation and maintenance costs, heat rates, generation capacities, plant factors, economic life, etc.not be allowed except during biennial IRP submissions.
Updates to load forecasts, except for knownand measurable changes as discussed previously, should also not be allowed except during
IRPsubmissions.
STAFF PROPOSAL
Variables that go into calculating utilities' before and after tax cost of capital should be
updated on a regular basis also. Staff proposes that these variables be updated biennially upon
submission of new IRPs. Utilities may use estimated values for weighted cost of capital
, and should
assume a hypothetical capital structme reflecting the typical degree ofleveraging for electric utilities
with "AU grade bond ratings. Alternatively, utilities may use the weighted cost of capital asestablished in the utility s most recent general rate case.
To the extent they affect resource costs, the passage of new laws and the imposition of new
regulations may trigger changes in variables. Staff recommends Commission approval be required
however, before variables can be changed for the purpose of detennining avoided costs as a result
of these types of factors.
Publication of Rates
In order to provide benchmark avoided cost rates which potential QF developers can use for
planning purposes, Staff recommends utilities be allowed to publish avoided cost rates forhypothetical projects. The rates should be published semiannually at the time changes in variables
are submitted to the Commission. The rates
should be for hypothetical 10 , 20 MW, and40 MW gas-fired, non-dispatchable projects with 100% capacity factors. The rates would be non-binding on the utility and would serve only as an approximation of rates for similar projects.Alternatively, utilities may forego publishing hypothetical rates if they can provide, within working days of receiving a request, approximate rates based on IRP model runs.
Rate Quotations
Before a developer requests a rate quotation from a utility,
Staff recommends a meeting be
held between the utility and the developer to discuss details of the
project and to discuss the process
for calculating rates. Once a request for binding rates is made, Staff contends the utility should
STAFF PROPOSAL
respond to the request within 30 days. In order to receive a fum quotation, the developer must be
able to provide the utility with the following infonnation:
1. Dev~loper name;
2. Proof of QF status (notice of self-certification will suffice);
3. Project location, and point of power delivery if the project is located outside
of the stateof Idaho;
4. Project size, including ambient conditions for this rating;
5. Capacity factor and proposed time shape of production;
6. Fuel source and mode and route of delivery;
7. Whether fuel supply is firm or non-finn and whether there are any constraints
affecting its availability or dependability;
8. Proposed contract tern! (final term -length and timing to be subject to negotiation);
9. On-line month and year;
10. Maintenance schedule;
11. Other factors affecting operation;
12. Wheeling uti1ity(ies) between point of interconnection and point of delivery;
13. Expected delivered energy by month during heavy and light load hours;
14. Guaranteed minimum capacity.
If a project desires to be operated according to a negotiated schedule or dispatched under specific
circumstances, the utility may request additional infonnation as needed in order to provide an
accurate rate quotation.
In response to a request for rates, Staff believes the utility should provide the difference in
cost by year between the base case plan and the same plan with the QF included. Using an
energy components.
acceptable methodology, utilities should separate the annual differences in costs into capacity and
STAFF PROPOSAL
Actual contract tenDS should be negotiable between the utility and the developer, subject to
the rules and guidelines set forth in this document Rate quotations should be effective for a
minimum of 120 days. Except for the signing of other QF contracts, the acquisition of other
generating resources, or major discrete changes in load, under no other circumstances should the rate
be changed during the 120-day period, even if changes occur in variables. When providing a rate
quotation, utilities should be obligated to divulge whether any other rate quotation has been made
for another project and is still within its 120-day effective period.
In addition, utilities must agree
to meet with the developer within 15 working days after the date on which the rate quotation is
made.
Access to Utility Models
Utilities should be allowed to utilize any model they desire in calculating avoided costs, aslong as the same model is used in the development of the utility's IRP. If the utility is required to
sign a licensing agreement for use of the model that restricts its use to utility personnel only, then
access to the model may be restricted to the Commission Staff, subject to restrictions
of the licensingagreement. However, in order to minimize the "black box" effect created when rates are calculated
by the utility using proprietary software, utilities must be willing to accommodate requests fromdevelopers and Commission Staff for a reasonable number of model runs for alternative project
plans. The model runs must be meaningful and requested in support of negotiating a commerciallyviable contract. Staff recommends that no fee be charged by the utility for these model runs.Funhermore, utilities should have the obligation to assist developers in
optimizing their projects sothat developers maximize the value of their project to the utility'
s system. To do so is in the bestinterests of both the developer and the utility.
STAFF PROPOSAL
11 .
Seasonalized and On-PeaklOfJ-Peak Rates
Staff believes utilities should be permitted to continue to offer different rates for peak and
off-peak hours, and to continue to seasonaIize rates (where cllITently allowed for Idaho Power andWashington Water Power) using the same seasonaIization factors allowed
for proj ects smaller thanIMW.
rs:gdk:jo: bp/ipce959c.avclh /commentsli( 5/28/96)
ST AFP'PROPOSAL
IDAHO POWER COMPANY
AVOIDED COST INFORMATION FOR RATE NEGOTIATIONS
WITH QUALIFYING FACILITIES LARGER THAN 1 MW
How IRP-based Avoided Costs Are Calculated
Project specific avoided costs for QFs larger than one megawatt are determined during
contract negotiations between Idaho Power and a QF developer by modifying Idaho
Power s IRP base case resource plan to include a QF. The cost of the modified plan and
the cost of the base case plan are then compared. The avoided cost for the QF project is
the implied purchase cost of the QF for which the modified resource plan is equal in cost
to the IRP base case plan. The avoided cost determination follows these steps:
1. An initial analysis of power supply costs is used to determine the cost of the
base case resource plan over the lifetime of the proposed QF contract. The
base case plan for avoided cost determinations includes all supply side
resources in the current Idaho Power IRP but, in accordance with IPUC Order
No. 25884, only those conservation programs already implemented.
2. The QF resource is added to the base case plan during all years of the
proposed contract. The required description of the QF project includes all
. data and information needed to model the intended dispatchable or
nondispatchable operation of the project on the power supply system.
3. A modified resource plan is constructed, including the QF resource, which
eliminates or delays the timing of new resources in the base case plan in such
a manner as to maintain the resource adequacy and system reliability of the
original base case plan.
4. The cost of the modified resource plan including the QF is calculated over the
full term of the QF contract, excluding purchase costs of the QF resource
itself.
5. Finally, the cost avoided by the QF project is calculated by subtracting the
present value of the cost of the modified plan, with costs of the QF set to zero
from the present value of the cost of the base case resource plan.
6. Rates for capacity and energy from the QF project are then developed for
which, on a present value basis, the expected payments to the QF are equal to
the project's avoided cost over the life of the contract.
An important characteristic of the IRP avoided cost methodology is its ability to evaluate
the operational capabilities of the QF in a simulated economic dispatch of Idaho Power
total power supply system. The avoided cost value of individual QF resources are thus
measured in a manner consistent with the evaluation of portfolio resources in
development of the IRP.
Project Data Submission
As the flrst step toward determining negotiated avoided cost rates for projects larger than
one megawatt, the project developer will submit to Idaho Power a completed and signed
copy of the Project Description form included as Attachment 1. Section 1 requests
general information needed from all QFs about the project. Section 2 requests specific
generation and fuel source information required of projects which intend to provide
generation on a fixed schedule rather than being available for dispatch by Idaho Power
according to electrical load requirements. Section 3 requests alternative information
needed to evaluate avoided cost if the project generation will be dispatched by Idaho
Power as part of the Company s integrated power supply system.
IRP-based Avoided Cost Calculation
Power supply data from Idaho Power s Draft 1997 Integrated Resource Plan affecting the
Company s avoided costs for QF purchases is contained in Attachment 2. Table 1 of this
attachment shows the Company s 10-year service territory load forecast, existing supply
system and planned resource additions for the 1997-2006 planning period. Capacity,
energy and cost information are shown in Table 2 for the planned system resourceadditions.
Idaho Power s planned resources also include purchases of capacity and energy from the
wholesale power market in some months during the 10-year IRP planning period. The
planning values of capacity, energy and price for these purchases, and the times when
they are expected to occur according to the base case load forecast, are shown in Table 3.
The Company s forecast of electricity load growth for the planning period is described in
Appendix B Sales and Load Forecast~and Appendix C Technical Appendix to the 1997
IRP. Existing resource data meeting the resource management reporting requirements set
forth by the Idaho Public Utilities Commission in Order No. 22299 are also contained in
the J:'echnical Appendix. References to the location of particular load and resource data
are listed in Table 4.
Financial assumptions used in cost analyses for the 1995 IRP and avoided cost
determinations are listed in Table 5. Idaho Power s before-tax weighted cost of capital is
the appropriate discount rate for use in avoided cost calculations in order to obtain rate
payer indifference to the purchase of the QF resource.
. .
Rate Negotiation
The project specific IRP-based avoided cost calculation described above is intended to be
used in contract negotiations between Idaho Power and the QF project developer. Unique
characteristics and circumstances of the Q F which may not taken into account by the
avoided cost calculation methodology, but which materially affect the value of the project
as a power resource, will also be considered in contract negotiations. Such items may
include, but are not necessarily limited to, fuel supply risk and project location in relation
to transmission and system load centers. These factors shall be considered along with the
avoided cost calculation within the scope of negotiations to detennine appropriate
contract rates, terms and conditions.
Updating IRP Data
Values of certain of the data used in development of the IRP will be updated on a regular
basis or changed as needed, in response to significant known and measurable events. The
following will be updated semiannually to reflect new forecasts published by the
independent sources of the data:
Interest rate for cost of capital
Inflation rate (CPI),
Escalation rates for capital costs, O&M expenses and fuel prices.
In addition, IRP data shall be adjusted as necessary to reflect significant knoWIi and
measurable changes in the following variables affecting avoided costs:
Firm loads
Resource additions and losses
Gas price
Return on common equity used to set regulated rates, and
. New laws and regulations affecting resource costs.
By incorporating such changes in the IRP data base as they occur QF purchase
negotiations conducted between IRP filings will benefit from the use of current
information while maintaining continuity in use of the IRP to guide resource acquisition.
TT CHMENT
PROJECT DESCRIPTION
IDAHO POWER COMPANY
PROJECT DESCRIPTION
NON-UTILITY GENERATION LARGER THAN 1.0 MW
DATE RECEIVED BY IPCo
PROPOSED FIRST ENERGY DATE:
PROJECT NAME:Project No.
(Assigned by IPCo)
LEGAL OWNER OF PROJECT PROJECT DEVELOPER
COMPANY:
CONTACT:
MAILING
ADDRESS:
Zip Code Zip Code
PHONE #:
FAX#:
TYPE OF PROJECT:
PURPA/QF - Small Power Producer Cogenerator
OTHER
PROJECT LOCATION: (Please provide sketch or map)
General Location
Quarter Section
Range County
Street Address
Nearest Intersection
Township
State
, ,
3/97 - Idaho 10-1 MW397.doc
DESCRIPTION OF ENERGY SOURCE:
Hydro
FERC No.Head
Hydraulic Capacity
Feet
CFS
Wind
Unit size(s)Number of units
Geothermal
Reservoir Cap
No. of Wells
Resource Temp.
Total Flow Rate
Deg. F
Conversion Type
Condensing
Injection
Other Uses
Biomass or Waste
Type of Fuel
Source of Fuel
Storage BTUs
Heat Rate
Alternate Fuel
Alternate Fuel Use
BTU/KWH
Coaeneration
FuelNet Heat Rate BTU/KWH
Net Heat Rate = Turbine fuel - fuel value of heat recovery = BTU/KWH
KW Out
Heat Recovery Process
OTHER
Description
GENERATION DATA:
A) Non-Dispatchable Plant:
Expected Seasonal Energy (kWh)
Heavy Load
Light Load~0~J)I~ SIm
~~' ;_(;-
i~L_
~~~_~~_
2i~E"f:i2~
~~~
f~l~~i~ if~1~\~~IB-(f~I
:g~
~1fd~L~
Heavy Load
Light Load
(Heavy Load hours are 7:00 a.m. to 11 :00 p.
Guaranteed Minimum Capacity (kW)
Fuel Source:
(Describe contractual and other conditions and constraints affecting
availability, dependability, and flexibility of fuel supply)
. .
3/97- Idaho 10-1 MW397.doc
3/97 - Idaho
Dispatchable Plant:
Project Capacity (MW):
:~,
:JT~i~
" ., "
::J.;
:'
;:;:i Rf',t'H;;' /\jr
~ ". '
Total
Dispatchable
::'
:0: .
~~~-
;L:~~"\~j~Ei~:
: ..~:. '
:~i
' .' '' ':' .
iJ ;~(i;i:j ~:/t~;i'/;.:i
;j"\,
~~.i
:,,:'
;r)i;::~r ,
:., .. :' :,
Total
Dispatchable
Minimum Baseload Energy to be Delivered (kWh):
" ,
Heavy Load
Light Load
~j~d1~1~;1~~~~mJI~22f~l~Zj ~ ~~~~~1E'~ ~Y~~Ej ~~:v ~E:~r.?i~ ~~!0C~~1 ji~~~
Heavy Load
Light Load
(Heavy Load hours are 7:00 a.m. to 11 :00 p.
Maintenance Schedule:
(Describe maintenance requirements, including constraints and flexibility in maintenance scheduling.
Other Factors Affecting Operation as a Dispatchable Power Resource:
(Describe constraints on power operations imposed be non-electric requirements of the project)
10-1 MW397.doc
GENERATION FACILITIES:A) Type:
Synchronous - Total Cap.
Power Factor Range:
kW (unity power factor)
Induction - Total Cap.kW (at . power factor)
DC Generator with Inverter - Total Cap.
Generator Data:
Make:
No. of Units:
Voltage:
Model No.
Winding: Delta orY
In multiple unit installations, if all generators are not of the same type, capacity, etc., list each
unit separately.
Inverter: 0Nave Form Data Must Be Provided)Make ModelVoltage Rating Output Rating
No. of Phases
kVA
Step up Transformers: Idaho Power will specify the connection
Will Idaho Power supply, own and maintain the step up transformers?No YesKV A Voltage
Pole Mount
Size
Pad Mount
SINGLE LINE DIAGRAM:
Provide a generation facility single-line diagram showing all unit protection and control equipment withthis application.
OTHER PERTINENT DATA:
Submitted By:
Signature
Name (Type or Print)
Title
Date
3/97 - Idaho -4-10-1 MW397.doc
ATTACHMENT 2
IRP AVOIDED COST DATA
Table 1
Draft Base Case 1997-2006 Resource Plan
Annual Energy Loads and Resources
(Average Megawatts)
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
LOAD
Load Before DSM
DSM Savings
Total Load 785 . 1 828 835 841 870 904 935 911 944 983
EXISTING RESOURCES
Thermal
Bridger 612 616 619 623 623 623 623 623 623 623
Valmy 224 224 224 224 224 224 224 224.224 224
Boardman
Hydro
E. Roach 696 696 696 696 696 696 696 696 696 696
Upper Snake 340 340 340 340 340 340340340340340
Purchases
Total Existing Resources 011 015 018 022 022 014 014 014 005 005
PLANNED RESOURCES
Market Purchases
Summer
Winter
Efficiency Improvements
Boardman . 2
Distribution System
Total Planned Resources 109 109 109 109 109 109
RESOURCES 068 074 077 081 131 123 123 123 114 114
SURPLUS 283 245 241 240 260 219 188 212 170 131
Table 2
Draft 1997 Integrated Resource Plan
Data For Planned Supply System Resource Additions
Base Case Plan
Boardman Distribution
Resource Data Efficiency Efficiency
Improvement Improvement
IRP Reference
Year Online 1998 1997
Fuel Type Coal
Heat Rate (MMBTU/MWH)000
Economic Life (Years)
Capacity (MW)14.
Annual Generation (Average MW)
E~valem Fo~ed Ournge Rate
Scheduled Maintenance 2 Weeks
Base Year for Costs 1997 1997
Base Year Plant Investtnent ($/KW)$240 $151
Plant Investment Escalation Rate (%)74%740/0
Base Year Fixed O&M Cost ($/KW $0.$0.
Fixed O&M Cost Escalation Rate (%)740/0
Base Year Variable O&M Cost ($/MWH)$0.$0.
Variable O&M Cost Escalation Rate (%)74%
Base Year Fuel Cost ($!M:MBTU)
Base Year Fuel Cost ($/MWH)$0.
Fuel Cost Escalation Rate (%)
Monthly Generation (MWH):
January 488 824
February 344 230
March 488 073
April 440 437
May 488 742
June 440 435
July 488 970
August 488 645
September 440 707
October 488 628
November 440 936
December 488 923
Indexed Variables Index Source
Plant Construction Cost Escalation CPI - All Urban WEF A Group
O&M Cost Escalation CPI - All Urban WEF A Group
Gas Price Escalation Mtn Region Delivered Natural Gas WEF A Group
Debt Interest Rate Moody's BAA Utility Bond Index WEF A Group
Inflation Rate CPT - All Urban WEF A Group
, ,
TABLE 3
Draft 1997 Integrated Resource Plan
Planned Seasonal Purchases of Capacity and Energy
Base Case Plan
Capacity Purchase Winter Summer 1997 Price
(SlMwlMo)
IRP Reference
Starting Year 2001
1997, 2003 2003, 2005
Endin~ Year None None
Capacity (MW):
January
February
March
April
May
June 150
July 150
August 150
September
. October
November 100
December 100
Annual Price Escalation (%)74%
Energy Purchase Winter Summer 1997 Price
(SlMwh)
IRP Reference
Starting Year 1997 2001
1997 2001 2004, 2005
Ending Year None None
Energy Purchase (MWH)
January
February
March
April
May
June
July 111 600 14.
August 111 600 17.
September
October
November 108 000 16.
December 111 600 18.
Annual Price Escalation (%)70%
TABLE 4
Existing Loads and Resources Data Sources
Resource IRP Reference
System Loads
Finn Surplus Sales Agreements References will be cited upon publication of the 1997 IRP
Hydroelectric Plant Data Technical Appendix
Hydroelectric System Generation
Thennal Plant Data
QF Purchases (MWavg)
Power Exchan~e Agreements
TABLE 5
Other Planning Variables
Input Variable Wei2;ht Value IRP Reference
Debt 45.4750/0 024%
Preferred Equity 103 %083%References will be cited upon publication of the
Common Equity 45.422%11.5000/0 1997 IRP Technical Appendix
Before-tax Weighted Cost of Capital (%)0000/0
Nominal After-tax Discount Rate (0/0)0000/0
Real After-tax Discount Rate (%)120%
....
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PORTLAND OR 97204
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~~.
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