19960614Sterling Direct.pdf

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BEFORE THE :=:; COt;
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IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AN ORDER APPROVING THE METHOD-
OlOGY FOR AVOIDED COST RATE
NEGOTIATIONS WITH QUALIFYING
FACILITIES lARGER THAN MEGAWATT.
CASE NO. IPC-95-
DIRECT TESTIMONY OF RICK STERLING
IDAHO PUBLIC UTILITIES COMMISSION
JUNE 14, 1996
Please state your name and business address
for the record.
My name is Rick Sterling.My bus ine s s
address is 472 West Washington Street , Boise, Idaho.
By whom are you employed and in what
capaci ty?
I am employed by the Idaho Public Utilities
Commission as a Staff engineer.
What is your educational and professional
background?
I received a Bachelor of Science degree in
Civil Engineering from the University of Idaho in 1981
and a Master of Science degree in Civil Engineering from
the University of Idaho in 1983.I worked for the Idaho
Department of Water Resources from July of 1983 to April
of 1994.I received my Idaho license as a registered
professional Civil Engineer in 1988.I began working at
the Idaho Public Utilities Commission in April of 1994.
I have since attended the annual regulatory studies
program sponsored by the National Association of
Regulatory Commissioners (NARUC) at Michigan State
University, the 1995 Lawrence Berkeley Laboratory
Advanced IRP Seminar , and an advanced IRP course
sponsored by EPRI entitled "Resource Planning in a
Competitive Environment.My duties at the Commission
IPC-95-06/14/96 STERLING (Di)Staff
include analysis of utility rate applications, rate
design , tariff analysis and customer petitions.
Have you testified before the Commission
previously on avoided cost matters?
Yes, I provided testimony in the combined
avoided cost cases IPC-93-28, WWP-93-10, PPL-93-
UPL-E- 93 - 7 , and UPL-E- 93 -3 /PPL-E- 93 - 3.
What is the purpose of your testimony in
this case?
I will discuss the settlement reached in
this case in which the parties were able to resolve a
number of the issues related to the formulation of a
generic avoided cost methodology for larger QF proj ects.
Did you participate in formulating the
settlement in this case?
Yes, I participated in all negotiation
meetings in this case.I was also the primary author of
Staff's Proposed Avoided Cost Methodology, which is
referenced in the settlement stipulation in this case.
The stipulation is included as Exhibit No. 101.
Incidentally, I have been informed that Mssrs. Don
Olowinski , John Runft and Peter Richardson will not sign
the stipulation and intend to neither actively support
nor oppose the settlement.
Briefly describe the process followed in
IPC-E- 95 - 9
06/14/96 STERLING (Di)Staff
formulating the stipulation.
At the conclusion of the combined avoided
cost case, Order Nos. 25882 , 25883 and 25884 were issued
by the Commission on January 31, 1995.The orders
required that a least cost planning methodology be used
to calculate avoided cost rates for projects with a
capacity of one megawatt or larger.The stipulation
described here represents a general agreement between the
parties in response to the Commission s orders.
The process began with a meeting on
April 11 , 1995 to review the utilities ' IRP modeling
capabilities and to discuss the general elements of a
workable methodology.On July 17, 1995, Idaho Power
Company filed an application requesting the approval of a
methodology for conducting avoided cost rate negotiations
with qualifying facilities (QFs) one megawatt or larger
thereby initiating Case No. IPC-E- 95 - 9.
Idaho Power s filing included a description
of a proposed methodology along with sample input and
output from the IRP model and the resulting avoided costs
for a hypothetical project.In response to Staff
production requests , Idaho Power made model runs and
calculated avoided costs for ten hypothetical scenarios.
The various scenarios were intended to evaluate the
effects on avoided costs of dispatchabili ty, deferral of
IPC-95-06/14/96 STERLING (Di)Staff
on-line dates, the signing of another QF contract during
proj ect development , proj ect size, gas price and load
growth , in addition to calibration runs.Staff
thoroughly evaluated these results to assess the proposed
methodology.
On August 29, 1995 Staff conducted the first
settlement negotiation between all interested parties.
The parties were subsequently invited to submit comments
and concerns which they felt should be addressed in a
settlement proposal to be drafted by Staff.
additional settlement meeting was held on January
1996.Staff provided a draft of a settlement proposal to
interested parties on January 30 , 1996.
As a result of the January 3 meeting, the
Commission , in the February 9, 1996 Notices of Scheduling
in each utility s pending IRP case (Case Nos. IPC-95-
UPL-95-5, and WWP-95-2) , allowed the utilities 45
days in which to make revised IRP filings so that avoided
costs would be reflective of changes that had occurred in
the interim between IRP filings.Only Idaho Power chose
to make a revised filing.A final settlement negotiation
and a prehearing conference were held on March 20, 1996.
A final draft of the stipulation was provided to the
parties on May 7, 1996.
Do you believe the stipulation complies with
IPC-E- 95 - 9
06/14/96 STERLING (Di)Staff
addition , consideration should also be given to the
risks and uncertainties associated with each
scenario examined.The least cost combination of
resources is selected to meet each scenario.The
most likely scenario is identified as the base case
plan.
An initial simulation analysis using a power
supply and/or capacity expansion model chosen by
the utility is used to calculate the present value
of revenue requirements (PVRR) of the base case
resource plan over the lifetime of the proposed QF
contract.
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
proj ect includes all data and information needed to
model the intended dispatchable or non-dispatchable
operation of the proj ect on the power supply
system.
A second simulation analysis, including the QF
resource, is performed which results in an
adjustment of the amount and/or timing of the new
IPC-95-06/14/96 STERLING (Di)Staff
resources in the base case plan.The modified plan
including the QF purchase is constructed to
maintain resource adequacy and system reliability
equivalent to that of the base case plan.
The PVRR of the modified resource plan
including the QF is calculated over the full term
of the QF contract , excluding the total purchase
costs of the QF resource itself.
Finally, the present value of the QF proj ect
avoided cost is calculated by subtracting the PVRR
of the modified plan , with the costs of the QF set
to zero, from the PVRR of the base case resource
plan.
Rates for capacity and energy from the QF
project can then be developed for which, on a
present value basis, the expected payments to the
QF are equal to the proj ect' s avoided cost over the
life of the contract.
Do you believe the methodology results in
avoided cost rates that fairly reflect utili ties ' true
avoided costs?
IPC-E- 95 - 906/14/96 STERLING (Di)Staff
Yes, to the extent that they are
representative of the costs of avoiding acquisition of
the mix of resources in the utili ties ' IRP.However
utilities frequently acquire resources from the market
that are not included in their IRP.The IRP serves as a
benchmark for comparison with market alternatives.The
resources actually acquired by the utility, whether
market resources, company-owned generation or DSM,
represent thei~ true avoided costs.
Can the cost of market alternatives be
considered using the methodology described in the
stipulation?
Yes , but only to a limited extent.To the
extent a utility is able to make estimates of the future
cost and availability of firm and non-firm market
resources, the utility can consider them as options in
its IRP.However , the cost of market resources can vary
considerably and cannot be predicted with certainty.
Short-term resources are particularly volatile due to
water conditions, seasonal availability and other
factors.Consequently, utilities must forecast the price
of market resources and update those forecasts frequently
to insure that they are accurate.
How is the uncertainty related to market
price forecasts any different than the uncertainty in
IPC-95-06/14/96 STERLING (Di)Staff
other variables used to calculate avoided cost rates?
The primary difference is that market
resource acquisitions are typically of only a few years
duration , whereas other generating resources or DSM
programs have longer lives.Comparing a five-year market
purchase for example, to a 35-year generating resource
requires that assumptions be made about how resource
needs would be met after the five-year purchase expires.
As far as updating market assumptions to
reflect current price and availability however , I see
little difference between these assumptions and the need
to keep assumptions for other variables updated.
Admittedly, up until now , market prices have been
somewhat difficult to predict since there has been no
source for discovering the prices at which wholesale
transactions are being made.However, the market is
quickly maturing.Electrical price indexes are now
available and the electric futures market is now trading.
Energy products are also becoming more standardized
making price comparisons easier.
If the market is a better indication of a
utility s actual avoided costs , why not use market prices
to determine avoided cost rates instead of utility IRPs?
I believe it would be premature to use the
market to determine utili ties ' avoided cost rates at this
IPC-95-06/14/96 STERLING (Di)Staff
time.Although the market is quickly maturing, I believe
it must mature further before it can be reliably used to
establish avoided cost rates.Market trading must
increase, products must become further standardized,
utilities must gain more trading experience, transmission
access must be made available to all , and price
information must be more readily available.
I believe that it is still appropriate to
use utilities ' actual resource portfolios in determining
avoided costs.Relying solely on the market to establish
avoided cost rates would presume that utili ties ' only
source of future resource acquisitions is the market.
Although in the foreseeable future utilities may expect
most new resources to be acquired from the market, they
also plan to acquire new resources through efficiency
improvements, system upgrades , DSM , and in the more
distant future, construction of new generating plants.
I contend that all of these resource options should be
considered in the calculation of avoided cost rates.
I believe that the avoided cost methodology in the
stipulation does that.
Are there any additional issues which you
believe need to be addressed?
Yes, I believe that the issues of 20 -year
contract length and fully levelized rates need to be
IPC-E- 95 - 906/14/96 STERLING (Di)Staff
addressed.In the combined avoided cost case, the
Commission did not say whether it intends for levelized
20 -year contracts to be options available for proj ects
one megawatt or larger.
What is your opinion on 20-year contracts?
I believe that 20 -year contracts should
continue to be available to all QF proj ects.I concede
however , that for the most part, utilities at the present
time are not acquiring long-term resources.Except for
PacifiCorp s Hermiston contract, utilities are meeting
their needs with short-term market purchases.There is
no assurance that this will continue indefinitely
however.Utilities continue to consider long-term
options in their IRPs, and I believe they would pursue
those options if the economics and risk were favorable.
Consequently, I believe it is reasonable to require 20-
year contracts for QFs, since utilities ' long-term
resource acquisition planning is still primarily based on
acquisition of long-lived resources.As long as the
rates utilities pay for QF power are based on the
utility s avoidance of planned resources, they should be
required to offer 20-year contracts if the planned
resources have lives of 20 years or more.At the present
time, I believe that some utilities may be reluctant to
make investments in new company-owned generation due to
IPC-95-06/14/96 STERLING (Di)Staff
uncertainties about restructuring and the risks of
stranded investments.These concerns, I believe, tend to
cause utilities to favor short-term market acquisitions
over construction of long-term , company-owned generation.
Do you believe that fully levelized rates
are an issue in this case?
No, I do not.In the combined avoided cost
cases WWP-E- 93 -10 IPC-93 -28 PPL-E- - 5 UPL-E- 93 - 7
and UPL-93-3/ PPL-93-3, the Commission stated the
following in Order Nos. 25882 , 25883, and 25884:
The levelization of avoided cost payments
is another tool that this Commission has
historically relied upon in encouraging
and assisting smaller QFs by providing a
cash stream that better enables them to
satisfy their debt service in the early
years of their contracts. Although we
have taken considerable strides towardmarket-based pricing we find thatlevelization for proj ects above 1 MW
should be continued. We believe that
levelization more accurately reflects
the way in which costs are recovered forutility-owned proj ects. The utilities
are directed to provide levelized rates,
for all QF proj ects who desire it, utilizing
the same procedure incorporated in the SAR
methodology.
I believe that the Commission s statement is
clear and speaks for itself.
Do you have any obj ections to anything
contained in the stipulation?
No, I do not.
IPC-E- 95 - 9
06/14/96 STERLING (Di)Staff
EXHIBIT NO. 101
CASE NO. IPC-95-
RICK STERLING
STAFF
JUNE 14, 1996
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BARTON L. KLINE
Idaho Power Company
P. O. Box 70
Boise, Idaho 83707
[phone]
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Attorney for Idaho Power Company
Street Address for Express Mail
1221 West Idaho Street
Boise, Idaho 83702
FAX Telephone No.: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR AN
ORDER APPROVING THE METHODOLOGY 0 )FOR AVOIDED COST RATE
NEGOTIATIONS WITH QUALIFYING
FACILITIES LARGER THAN 1 MEGA WATT
CASE NO. IPC-95-
SETTLEMENT STIPULATION
Pursuant to Rules 271-277 of the Commission s Rules of Procedure (IDAPA
31.01.01), the undersigned, including but not limited to the Staff of the Idaho Public Utilities
Commission ("Staff'), Idaho Power Company, ("Idaho Power ), the Washington Water Power
Company ("WWP"), PacifiCorp ("PacifiCorp ), and Rosebud Enterprises, Inc. ("Rosebud"), herein
collectively referred to as the "Parties , by and through their respective counsel of records, hereby
stipulate as follows:
SETTLEMENT STIPULATION -
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 1 of24
I. BACKGROUND
On July 17, 1995 , Idaho Power filed an application for an order approving a
methodology for conducting avoided cost rate negotiations with qualifying facilities (QF's) I MW
or larger. Idaho Power s application was docketed as Case No. IPC-95-
Idaho Power s application was anticipated by the Commission in Order No. 25884
(issued in Idaho Power s most recent avoided cost proceeding, Case No. IPC-93-28) in which the
Commission stated:
We expect the Company to include with its 1995 IRP filing, a more detailed
proposal of how the least cost planning based avoided cost methodology will
operate. We will treat that filing as a generic discussion of the issue and
expect all interested parties, including the other utilities, to intervene and
participate so that all issues may be resolved and the methodology can be
refined.id at P.
On August 14, 1995 in Order No. 26115 , the Commission provided public notice of
Idaho Power s application and made WWP and PacifiCorp parties to Case No. IPC-95-
On August 16, 1995 , the Commission staff issued a Notice of settlement negotiations
to be undertaken pursuant to Rule 272 of the Commission s Rules of Procedure, ID AP A 31.01.0 I.
Subsequently, the following parties intervened in Case No. IPC-95-, and to varying degrees
participated in the settlement negotiations that were undertaken pursuant to the August 16, 1995
notice of settlement negotiations: Idaho Power Company, Commission Staff, Washington Water
Power Company, PacifiCorp, the Independent Energy Producers of Idaho, Myers Engineering
Company, Earth Power Resources, Inc., Irrigation Districts and Rosebud Enterprises, Inc.
SETTLEMENT STIPULATION - 2
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 2 of 24
Following the August 16, 1995 Notice, settlement negotiations were undertaken at
the Commission s offices on August 29, 1995, January 3, 1996, and March 20, 1996. As a result
of the settlement negotiations, the Parties developed a methodology for conducting avoided cost rate
negotiations which is entitled "Staff's Proposed Avoided Cost Methodology for Projects Larger than
1 MW, Case No. IPC-95-9" ("Staff Proposal"). The Staff Proposal methodology was the subject
of both written comments and substantial discussions at the settlement conferences. The most recent
version of Staffs Proposal is attached hereto as Exhibit 1. In conformance with the Parties
settlement discussions, the Parties hereby submit this Settlement Stipulation to the Commission and
request that the Commission accept and approve the attached Exhibit 1 Staff Proposal as the
methodology for computing avoided costs and for conducting avoided cost rate negotiations for QF
projects 1 MW and larger.
II. AGREEMENTS
(1)The Parties have negotiated this Settlement Stipulation and Exhibit 1 as a part
of a settlement proceeding. Each of the Parties may not agree with all of the provisions of Exhibit
1 but they are each willing to accept Exhibit 1 as a reasonable compromise of contested positions.
If the Commission does not accept this Stipulation and Exhibit 1 in their entirety, without
modification, it will be withdrawn and shall be without any force or effect.
(2)By executing this Stipulation, the Parties agree to recommend that the
Commission issue an order adopting Exhibit 1 as the methodology for computing avoided costs and
SETTLEMENT STIPULATION - 3
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 3 of 24
for conducting avoided cost rate negotiations for QF projects 1 MW and larger and agree to file
testimony in support of the Stipulation.
(3)This Settlement Stipulation may be signed in counterparts.
III. ADDITIONAL ISSUES
As Exhibit 1 evidences, the Parties were able to resolve the vast majority ofthe issues
that are associated with establishing the IRP methodology. Nevertheless, there were several issues
raised during the negotiations upon which the Parties were unable to achieve consensus. The
unresolved issues generally relate to rate levelization and length of contract. On those issues, the
positions of the Parties fell into two general categories. One group, primarily the utilities
maintained that contract length and rate levelization should be individually negotiated based on the
utilities' specific IRPs and the individual characteristics of the project. In addition, the utilities
argued that long term contracts must include a mechanism to allow periodic rate adjustments to track
changes in market prices for electric capacity and energy. The other position, as expressed primarily
by QF developers, was that the Commission should require that QF developers have the option of
obtaining long term contracts containing levelized or non-Ievelized avoided cost payments.
addition, the parties were unable to agree on the treatment of non-deferrable resources within the
methodology. The consensus of the Parties was that the Commission could address all unresolved
issues at the hearing scheduled for consideration of the Settlement Stipulation.
SETTLEMENT STIPULATION - 4
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 4 of 24
fL, --
DATED This day of -1J u'-'\ C
SETTLEMENT STIPULATION - 5
1996.
IDAHO PUBLIC UTILITIES COMMISSION
BY:
Brad Purdy
Deputy Attorney General
IDAHO POWER COMPANY
By:
Barton L. Kline
WASHINGTON WATER POWER CO.
By:
R. Blair Strong
P ACIFICORP
By:
John M. Eriksson
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 5 of24
DATEDThis~dayof ,1996.
IDAHO PUBLIC UTILITIES COMMISSION
By:
Brad Purdy
Deputy Attorney General
IDAHO POWER COMPANY
By:
WASHINGTON WATER POWER CO.
By:
R. Blair Strong
ACIFICORP
By:
John M. Eriksson
SETTLEMENT STIPULATION - 5
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 6 of 24
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DATED This day of -May, 1996.
IDAHO PUBLIC UTILITIES COMMISSION
By:
Brad Purdy
Deputy Attorney General
IDAHO POWER COMPANY
By:
Barton L. Kline
WASHINGTON WATER POWER CO.
jS~.sjyR, Blair Strong
ACIFICORP
By:
John M. Eriksson
SETTLEMENT STIPULATION - 5
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 7 of24
DATED This-S~day of .:ru 'fl e.-
SETTLEMENT STIPULATION - 5
, 1996.
IDAHO PUBLIC UTILITIES COMMISSION
By:
Brad Purdy
Deputy Attorney General
IDAHO POWER COMPANY
By:
Barton L. Kline
WASHINGTON WATER POWER CO.
By:
R. Blair Strong
ACIFICORP
By:
John M. Eriksson
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 8 of24
05/07/1995 11: 48 2083450314JI:li(.ItJ,.~tI n: l~ 1:1'208 '\~ :1762
ORNDORFF&TROUT
IDAHO Pl:C
PAGE 02
ilIOO2.'Oll2
DATED This day of 1996.
INDEPENDENT ENERGY PRODUCERS
OF IDAHO
By:
Peter J. Richardson
MYERS ENG~E~G CO~A~Y
By:
John Runft
EARTH POWER RESOURCES. INC.
By:
Peter J. Richardson
IRRIGATION DISTRlCTS
By;
SETILEMENT STIPULATION. 6
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 9 of 24
DATED This day of
SETTLEMENT STIPULATION - 6
1996.
INDEPENDENT ENERGY PRODUCERS
OF IDAHO
By:
Peter J. Richardson
MYERS ENGINEERING COMPANY
By:
John Runft
EARTH POWER RESOURCES, INC.
By:
Peter J. Richardson
IRRIGATION DISTRICTS
By:
Don A. Olowinski
ROSEBUD ENTERPRISES , INC.
By:
Owen H. Orndorff
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 10 of
STAFF'S PROPOSED AVOIDED COST METHODOLOGY
FOR PROJECTS LARGER THAN ONE MEGAWATT
CASE NO. IPC-95-
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 the
following in its orders:
We believe that the adoption of the least cost planning methodology is consistent
with our goal of maintaining a regulatory climate that allows our electric utilities to
retain their advantageous posture in a marketplace that is likely to become
increasingly competitive. This will ultimately work to the advantage of ratep~yers
in the form of rates lower than would otherwise be in effect. By treating QFs
(Qualifying Facilities) in the same manner as utility acquired resources, we are
further 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 of PURP A.
See, e.g. Order No. 25884 at page 6.
In accordance with Order No. 22299, all utilities are required to prepare IRPs biennially. The
following 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.
IPC-E-95-9Exhibit 1 to
Settlement Stipulation
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 11 of24
STAFF PROPOSAL
An IRP forms 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 oftheir increased
utilization 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 comment. 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 their
representatives 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 the
calculation of avoided cost and the rates for QF projects that are derived from that calculation, is in
the development of a utility's IRP, not in the application of the avoided cost methodology. The IRP
is the source of all inputs used in the calculation of avoided costs. It is the real basis for
STAFF PROPOSAL
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 12 of24
calculating avoided cost rates. Once the avoided cost methodology is established, Staff does not
expect a hearing or other formal Commission proceeding to be initiated each time a utility's avoided
costs are calculated.
General Methodology
PURP A defmes avoided cost as "the cost to an electric utility of electrical energy or capacity
or both which, but for the purchase from such cogenerator or small power producer, such utility
would generate itself or purchase from another source" 18 CFR, 9292.101.
As explained by FERC:
This definition is derived from the concept of "the incremental cost of
alternative electric energy" set forth in section 21O(d) ofPURPA. It includes
both 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 determining avoided cost is to calculate the total (capacity and
energy) 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 and
supplied its remaining needs from its own facilities. The difference between
these two figures would represent the utility's net avoided cost. In this case
the avoided costs are the excess of the total capacity and energy costs of the
system developed in accordance with the utility's optimal capacity expansion
plan, excluding the qualifying facility, over the total capacity and energy
costs 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 than acquiring the same
power from the resources selected in its base case resource plan. Put another way, the avoided cost
STAFF PROPOSAL
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 13 of 24
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 avoided
cost determination involves the following steps:
1. An IRP 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. The
least 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
information 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 performed which results in
an adjustment of the amount and/or timing of the new resources in the base case plan. The
modified 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 term
ofthe QF contract, excluding the total purchase costs of the QF resource itself.
STAFF PROPOSAL
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 14 of24
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 determined both generic and company-specific variables used to calculate avoided
cost for large projects. With implementation of the IRP methodology, the Companies will be
responsible- for determining 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.
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 will
be 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
side resources. 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, market
purchases may constitute the primary source of new resources. The cost of market resources, to the
STAFF PROPOSAL
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 15 of
extent a utility relies on them, should be one component in determining utilities' avoided costs.
However, in order for market resources to be considered in the determination of avoided costs in an
IRP-based methodology, those market resources must be included in the IRP. Any market purchases
made 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 IPM model does not provide
for the IPM's calculation of avoided costs, Pacificorp will be allowed to propose modifications to
the IPM 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 term, is
difficult and uncertain. Consequently, forecasts made in the IRP should be firmly based on sound
reasoning and analysis. The degree of planned reliance on market resources should be a matter of
interest to ratepayers, shareholders, the Commission and the public. Review of the utilities' planned
reliance 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 firm commitment should be
considered as reductions in the load forecast rather than as supply side resources, in part, to
discourage double counting.
Load and Resource Forecasts
Forecasts of electricity load growth are made by each utility at two-year intervals as a part
oflRP filings. These forecasts serve as the basis for avoided cost calculations. Staff contends that
only 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 easily
documented 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
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 16 of24
On the other hand, a load change due to population growth may be known, but would not be easily
measured or documented.
Updating IRP Data
For 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, until
replaced by subsequent IRPs. One of the goals of this avoided cost methodology is to achieve a
dynamic resource evaluation process that recognizes changes in loads, technologies, costs
availabilities, 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
periodicaliy 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 the
determination 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 ITom 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
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 17 of
. 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, or
if a utility wishes to make adjustments to values in consideration of regional circumstances, the
utility 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 are
authorized by the Commission.
At such time as easily verifiable information is readily available from independent third party
sources, 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 calculating
avoided cost rates. Permission 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 known
and measurable changes as discussed previously, should also not be allowed except during IRP
submissions.
STAFF PROPOSAL
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 18 of24
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 structure reflecting the typical degree of leveraging for electric utilities
with "A" grade bond ratings. Alternatively, utilities may use the weighted cost of capital as
established 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 determining 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 for
hypothetical 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 MW, 20 MW, and
40 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 10
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
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 19 of 24
respond to the request within 30 days. In order to receive a firm quotation, the developer must be
able to provide the utility with the following information:
1. Developer 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 state
ofldaho;
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-firm and whether there are any constraints
affecting its availability or dependability;
8. Proposed contract term (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 utility(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 information 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
acceptable methodology, utilities should separate the annual differences in costs into capacity and
energy components.
STAFF PROPOSAL
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 20 of 24
Actual contract terms 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, as
long 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 licensing
agreement. '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 from
developers 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 commercially
viable contract. Staff recommends that no fee be charged by the utility for these model runs.
Furthermore, utilities should have the obligation to assist developers in optimizing their projects so
that developers maximize the value of their project to the utility's system. To do so is in the best
interests of both the developer and the utility.
STAFF PROPOSAL
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 21 of24
Seasonalized and On-Peak/Off-Peak Rates
Staff believes utilities should be permitted to continue to offer different rates for peak and
off-peak hours, and to continue to seasonalize rates (where currently allowed for Idaho Power and
Washington Water Power) using the same seasonalization factors allowed for projects smaller than
IMW.
rs :gdk:jo: bp/ipce9 59c. avclh comments/i( 5/28/96)
STAFF PROPOSAL
Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 22 of 24
CERTIFICATE OF SERVICE
ll\I HEREBY CERTIFY that on this day of May, 1996, I served a true and
correct copy of the within and foregoing SETTLEMENT STIPULATION, to the following
individuals by the method indicated below, and addressed to the following:
Brad Purdy Hand Deliver
Idaho Public Utilities Commission S. Mail
472 W. Washington Overnight Mail
Statehouse Facsimile
Boise, ID 83720
Gregory N. Duvall Hand Deliver
PacifiCorp U. S. Mail
920 S.W. Sixth Avenue, Suite 1314 Overnight Mail
Portland, OR 97204-1256 Facsimile
R. Blair Strong Hand Deliver
Paine Hamblen Coffin, et al.U. S. Mail
717 W. Sprague Avenue, Suite 1200 Overnight Mail
Spokane, VV A 99204 Facsimile
Thomas Dukich, Mgr.Hand Deliver
Rates & Tariff Administration U. S. Mail
Washington Water Power Company Overnight Mail
O. Box 3727 Facsimile
Spokane, VV A 99220
Don A. Olowinski Hand Deliver
Richard B. Burleigh U. S. Mail
Stephanie W. Gillette Overnight Mail
Hawley Troxell Ennis & Hawley Facsimile
O. Box 1617
Boise, ID 83701
John L. Runft Hand Deliver
Attorney at Law U. S. Mail
Alaska Center Overnight Mail
1020 W. Main Street, Suite 440 Facsimile
Boise, ID 83702
CERTIFICATE OF MAILING Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 23 of24
Owen H. Orndorff
Orndorff & Trout
1087 W. River Street, Suite 230
Boise, ID 83702
Peter J. Richardson
Davis Wright Tremaine
999 Main Street, Suite 911
Boise, ID 83702
Hand Deliver
U. S. Mail
Overnight Mail
Facsimile
Hand Deliver
U. S. Mail
Overnight Mail
Facsimile
Hand Deliver
U. S. Mail
Overnight Mail
Facsimile
James F. Fell
John M. Eriksson
Stoel Rives
One Utah Center
201 S. Main Street, Suite 1100
Salt Lake City, UT 84111-1904
Steve Tackes
Crowell Susich Owen & Tackes
O. Box 1000
Carson City, NY 89702
Hand Deliver
U. S. Mail
Overnight Mail
Facsimile
Ronald C. Barr, President
Earth Power Resources, Inc.
2534 East 53rd Street
Tulsa, OK 74105
Hand Deliver
U. S. Mail
Overnight Mail
Facsimile
(pi Barton L. Kline
CERTIFICATE OF MAILING Exhibit No. 101
Case No. IPC-95-
R. Sterling, Staff
06/14/96 Page 24 of24
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 14TH DAY OF JUNE 1996
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING IN CASE
NO. IPC-95-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L. KLINE
LARRY D RIPLEY
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
R BLAIR STRONG
PAINE HAMBLEN COFFIN ET AL
717 W SPRAGUE AVE STE 1200
SPOKANE WA 99204
GREGORY N DUVALL
ACIFICORP
825 NE MUL TNOMAH STE 485
PORTLAND OR 97202
THOMAS DUKICH MGR
RATES & TARIFF ADMIN
W ASHIGTON WATER POWER CO
PO BOX 3727
SPOKANE WA 99220
JOHN M ERIKSSON
JAMES F FELL
STOEL RIVES BOLEY ET AL
201 S MAIN ST STE 1100
SALT LAKE CITY UT 84111-4904
PETER J RICHARDSON
DAVIS WRIGHT TREMAINE
999 MAIN ST STE 911
BOISE ID 83702
CARL MYERS
MYERS ENGINEERING P
750 WARM SPRINGS AVE.
BOISE ID 83712
RONALD C BARR
EARTH POWER RESOURCES INC
2534 EAST 53RD STREET
TULSA OK 74105
DON A OLOWINSKI
RICHARD B BURLEIGH
STEPHANIE W ALTER GILLETTE
HAWLEY TROXELL ENNIS
& HA WLEY
PO BOX 1617
BOISE ID 83701-1617
OWEN H ORNDORFF
ORNDORFF PETERSON & HAWLEY
1087 W RIVER ST., SUITE 230
BOISE ID 83702
jJU~,SECRETARY