20040416Comments.pdf

SCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
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Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR APPROV AL )
OF AN AGREEMENT FOR SALE AND
PURCHASE OF ELECTRIC ENERGY
BETWEEN IDAHO POWER COMPANY AND
THE J.R. SIMPLOT CO MP ANY.
CASE NO. IPC-O4-
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Scott Woodbury, Deputy Attorney General, and in response to the Notice of
Application, Notice of Modified Procedure and Notice of Comment /Protest Deadline issued on
March 23 , 2004 submits the following comments.
BACKGROUND
On March 5 , 2004, Idaho Power Company (Idaho Power; Company) filed an Application
with the Idaho Public Utilities Commission (Commission) requesting approval of a Firm Energy
Sales Agreement (Agreement) between Idaho Power and JR Simplot Company (Simplot) dated
February 19 2004.
Simplot currently owns, operates and maintains a 15.9 MW cogeneration facility (Project) at
its industrial site near Pocatello, Idaho. The Project is a qualified cogeneration facility under the
applicable provisions of the Public Utilities Regulatory Policy Act of 1978 (PURP A). Attachment 1
STAFF COMMENTS APRIL 16, 2004
shows graphically the actual historical generation of the Project, along with contractual allowed
base generation by month.
As reflected in the Company s Application, the Simplot Project is currently interconnected
to Idaho Power and is selling energy to Idaho Power as a Qualifying Facility (QF) in accordance
with a Firm Energy Sales Agreement dated January 24, 1991 (Order No. 23552) and as
subsequently amended on November 30, 1993 (Order No. 25353) and February 23 2001 (Order
No. 28730), and by two letter agreements signed by the Parties that extended the term of the 1991
Agreement to February 29 2004. Although copies of the letter extensions were forwarded to the
Commission, the Company admits that it did not make a separate filing requesting approval. The
Company as part of its filing in this case requests approval of purchases made under the two letter
extensions. The rate paid for energy during the months of January and February 2004 was the same
rate specified in the 1991 Agreement for December 2003 (0.04201t per kWh) and is less than the
current published avoided cost rates for those same months.
Under the terms of the submitted Agreement, Simplot has elected to contract with Idaho
Power for a 10-year term. The Agreement contains non-levelized published avoided cost rates as
currently established by the Commission for energy deliveries less than 10 MW (Order No. 29391)
and a negotiated price for energy over 10 MW.
The submitted Agreement, the Company states, is similar in many respects to recent QF
contracts between Idaho Power and Tiber Montana LLC (IPC-03-l), United Materials of Great
Falls, Inc. (IPC-04-l) and Renewable Energy ofIdaho, Inc. (IPC-04-5).
As reflected in the Agreement, the Company has defined energy delivered to Idaho Power
exceeding 10 000 kW in a single hour as "Optional Energy." Optional energy is identified through
hourly metering. Because Simplot has made no firm commitments as to the delivery of this
optional energy, the energy delivered to Idaho Power is considered to be non-firm energy. As non-
firm energy, Idaho Power and Simplot have agreed the value of this energy to be the variable
current market-based price as defined in Agreement ~ 1.11.
As incentive for Simplot to deliver energy to the Company during times when it is of greater
value to Idaho Power, the Company has refined the seasonalization of rates to coincide to the
months in which Idaho Power has identified actual energy needs and periods of higher demands.
Reference Agreement Section 6.
STAFF COMMENTS APRIL 16, 2004
Agreement Section 24 provides that the Agreement will not become effective until the
Commission has approved without change all the Agreement terms and conditions and declared that
all payments that Idaho Power makes for purchases of energy to Simplot will be allowed as
prudently incurred expenses for ratemaking purposes. Should the Commission approve the
Agreement, Idaho Power intends to consider the effective date of the Simp lot Agreement to be
March 1 2004. As reflected in the Company s Application, the Agreement contains non-levelized
published avoided cost rates in conformity with applicable Commission Orders.
ANALYSIS
Commission-Approved Methodology for Rates for Projects Larger Than 10 MW
Staff opposes approval of this Agreement because the rates contained in the Agreement have
not been determined in accordance with the approved Commission methodology for projects 10
MW and larger. Staff expressed opposition to another recently submitted contract for similar
reasons. See IPC-04-, Renewable Energy ofIdaho, Inc.
Idaho Power states in its Application that the Simp lot Agreement is similar in many respects
to the Tiber Montana, LLC contract that the Commission approved on April 28, 2003 in Order No.
29232. While the contracts are indeed similar, Staff believes there are differences between the
projects that clearly distinguish them. The Tiber project is at the site of an existing dam, and the
project has neither history nor capability to generate more than 7.5 MW. Moreover, Tiber has a
transmission firming agreement with Northwestern Energy whereby Northwestern will only deliver
a flat 7 MW to Idaho Power. Simp lot, on the other hand, has both the generation capability and the
history of regularly exceeding 10 MW of capacity. As shown in Attachment 1 , generation from the
Project regularly exceeded 10 MW; this despite seller s expressed intention in the 1991 Firm
Energy Sales Agreement to deliver estimated monthly net energy amounts below 10 MW.
Similarly, the submitted Agreement does not preclude generation exceeding 10 MW and in fact
establishes market pricing for all energy exceeding 10 000 kWh in any hour. For these reasons
Staff believes it is appropriate to consider the proposed Agreement to be larger than 10 MW, thus
subj ect to the approved methodology for proj ects larger than 10 MW.
In Case No. IPC-95-, a Settlement Stipulation was approved by the Commission and
included as part of its final Order. See Order No. 26576 and the Settlement Stipulation included as
Attachment No.2. The Settlement Stipulation describes in detail how avoided cost rates are to be
STAFF COMMENTS APRIL 16, 2004
determined for projects 1 MW and larger. In later Order Nos. 29029 and 29069, the Commission
raised the threshold for published avoided cost rates from 1 MW to 10 MW; therefore, since then
Staff has assumed that the methodology described in the Settlement Stipulation is to be used for all
projects 10 MW and larger.
The Settlement Stipulation approved by the Commission in Order No. 26576 was signed by
Idaho Power, thus indicating Idaho Power s endorsement of the methodology. In fact, Case No.
IPC-95-9 was initiated by Idaho Power s own Application for an Integrated Resource Plan (IRP)-
based methodology to be used as a new basis for avoided cost rate negotiations with QFs larger than
I MW. Staffs recollection is that Idaho Power was more instrumental than any other party in
developing the details of the methodology. The IRP-based methodology was chosen specifically
because the parties felt that it more accurately reflected the value of a large QF to the utility and was
more appropriate than the SAR-based method for large projects and long-term contracts. The risk
of overpayment or underpayment was believed to be less under the IRP-based methodology,
especially for long-term contracts.
Basically the IRP-based methodology requires that the utility make two runs of its power
supply model- one using assumptions consistent with its most recent IRP, and a second with the
proposed QF included as a no-cost resource. The difference in net power supply costs computed by
the model over the term of the proposed contract represents the value of the QF to the utility and is
supposed to serve as the basis for establishing an avoided cost rate for the proposed QF. The
methodology is intended to capture and fairly value the different individual generation
characteristics of proposed projects.
Since the methodology was adopted, it has only been utilized once to establish a rate for a
project larger than 10 MW because only one contract larger than 10 MW has been sought by a
project owner in the interim (except for the noted recent exception of Renewable Energy of Idaho
Inc). In Case A VU-02-, Potlatch and Avista negotiated an agreement with rates based on the
methodology for Potlatch's 60 MW QF. Avista used the AURORA model, the same model Idaho
Power uses for various purposes including its current rate case and its upcoming 2004 IRP.
In production requests, Staff asked Idaho Power to use the IRP-based methodology as
prescribed in the Settlement Stipulation to compute rates for the Simplot contract. In its response
STAFF COMMENTS APRIL 16, 2004
the Company stated:
Idaho Power no longer uses the forecast model upon which the
methodology described in the Settlement Stipulation referenced in this
request was based and the Company does not believe that using the
AURORA model to calculate avoided costs for a 20-year contract is
appropriate. In addition, the AURORA forecast model is currently being
extensively updated for use in the 2004 IRP and is simply not available to
perform the requested analysis in the near future.
Staff contends that no particular model was specified when the Settlement Stipulation was
adopted. Various models are available and capable of performing the necessary computations. In
fact, for the recently approved Potlatch QF contract, A vista used AURORA in accordance with the
methodology described in the Settlement Stipulation. Idaho Power possesses AURORA, has used it
in the past, and used it in its present rate case to compute normalized power supply costs. The
Company s states that it intends to use AURORA in developing its 2004 IRP, which is due to be
submitted to the Commission in approximately two months. In order to meet the deadline, Staff
believes Idaho Power should be using AURORA now; therefore, Staff cannot understand why
AURORA is not available now for avoided cost computations and cannot be used to compute rates
for this contract.
Idaho Power filed reply comments on April 15, 2004 in Case No. IPC-04-, Renewable
EnergyofIdaho. In its comments, the Company acknowledges that Order No. 26576, the Order
that spells out the avoided cost methodology to be used to compute rates for projects larger than 10
, remains in effect until it is changed by Commission order. The Company also admits that it
did not follow the prescribed methodology in the Order and offers reasons why the Order was not
followed. Idaho Power cites its lack of experience in using AURORA, in addition to problems it
has experienced in using the model that cast doubt on the results it expects to obtain. Idaho Power
does not indicate that it even made an attempt to use the model to compute rates. Nevertheless, the
Company expresses its belief that AURORA can successfully provide accurate analysis for IRP
purposes and seeks Commission approval of normalized power supply costs determined using
AURORA for its ongoing rate case. However, illogically, it has no confidence that AURORA
would produce accurate pricing and cost data if it were used to compute avoided cost rates for
PURP A QFs. This explanation confounds Staff.
In its reply comments in Case No. IPC-04-, Idaho Power also notes the expediency with
which it had to negotiate the Renewable Energy of Idaho contract and the difficulty in correcting
STAFF COMMENTS APRIL 16, 2004
problems with AURORA and in developing experience in using the model. Staff assumes such
expediency was also an issue in developing the Simp lot contract, since the prior Simp lot contract
expired at the end of 2003. Staff agrees that it would have been punitive to both Simp lot and
Renewable Energy to delay their contracts, yet Staff believes both contracts have been in
negotiation for many months. Staff cannot accept Idaho Power s argument that the AURORA
model is unavailable for use for other purposes until the Company completes its 2004 IRP.
Despite its excuses, the fact remains that Idaho Power has still not computed rates using its
IRP model in accordance with the methodology in Order No. 26576. Staff simply cannot accept the
Company s contention that AURORA will produce inaccurate results when those results have yet to
be produced and evaluated.
Idaho Power s Method for Establishing Prices in This Contract
Rather than following the methodology prescribed in the Settlement Stipulation, Idaho
Power offered the non-levelized published avoided cost rate for the first 10 MW and offered an
Optional Energy Rate for generation above 10 MW. The Optional Energy Rate is a market-based
price equal to 85% of the weighted average of the daily on-peak and off-peak Dow Jones Mid-
Index prices for non-firm energy.
The contract prices developed by Idaho Power for this contract are not necessarily
unreasonable. In many respects, the rates included in this proposed Agreement are structured
similarly to the rates in the 1991 Agreement. However, the 1991 Agreement pre-dated development
of the IRP-based methodology, which was not developed until 1996. The proposed Agreement is
clearly presented as a new contract and not as an amendment to an existing contract. As a new
contract, it must comport with all Commission orders currently in effect.
Letter Extension Agreements
Idaho Power requests Commission approval of energy purchased from Simp lot in January
and February 2004 pursuant to letter agreements dated December 22 2003 and January 30, 2004.
The letters reflect that the expiration of the Commission approved agreement (January 24, 1991)
and associated amendments (Nov. 30, 1993; Feb. 23 , 2001) was December 31 , 2003. The Company
recites in the extension letters that the parties were engaged in diligent contract negotiation for a
new QF firm purchase power agreement and by letter agreements the parties were extending the
expiration date of the Commission approved agreement to February 29 2004. The extension
STAFF COMMENTS APRIL 16, 2004
agreements were submitted under the signature of Randy Allphin, Contract Administrator for Idaho
Power.
Staff contends that extension of the expiring contract was a significant change or
modification that required Commission approval. No Commission approval of the extension
agreement was requested. As part of its unified regulatory scheme in implementing PURP A, the
Commission has long required that signed power purchase contracts be presented to it for review
approval and lock-in of avoided cost rates. The parties cannot by letter agreement deprive the
Commission of its ratemaking authority under PURP A and Idaho Code ~ 61-902 or relieve the
utility of its obligations under Idaho Code ~ 61-307.
As the Company neither sought nor obtained Commission approval of the contract extension
periods, Staff recommends that the purchases of energy in January and February 2004 be treated for
ratemaking purposes as a voluntary purchase of power and not a purchase mandated under PURP
CONCLUSIONS
The simple fact is that Idaho Power failed to follow Commission orders in developing an
avoided cost rate. It is presumptuous for Idaho Power to dismiss the Commission-approved
methodology as no longer valid without even making an attempt to compute rates in accordance
with the methodology. If rates had been computed in accordance with the methodology then judged
unreasonable, Staff might agree that an alternate method was warranted. That was not the case
here, however. Idaho Power has provided no credible reason for not following Commission orders.
Consequently, Staff is unable to recommend that the proposed contract be approved.
If the Commission refuses to approve the Agreement, Simplot might be forced to suspend its
generation. Simp lot has been generating power and selling it to Idaho Power for more than 13 years
and Staff assumes Simp lot desires to continue to sell its generation uninterrupted. So that Simp lot
can continue to sell its generation and not be unfairly penalized, Staff proposes that, for now, Idaho
Power be required to purchase Simplot's generation under the rates, terms and conditions contained
in the proposed Agreement. For ratemaking purposes however, until new rates can be computed in
accordance with the prescribed avoided cost methodology, Staff recommends that the purchase be
treated as a voluntary purchase of power and not a purchase mandated under PURP
STAFF COMMENTS APRIL 16, 2004
RECOMMENDATIONS
Because Idaho Power has failed to follow the Commission s Orders regarding how avoided
cost rates are to be determined for QFs 10 MW and larger, Staff recommends that the submitted
Agreement be disapproved. Staff recommends that Idaho Power be directed to compute an avoided
cost rate in accordance with the prescribed methodology, resume contract negotiations with
Simplot, and submit a revised agreement for Commission consideration.
Staff recommends that purchases of power made under the two letter extensions for the
months of January and February of 2004 be treated as a voluntary purchase of power and not a
purchase mandated under PURP A. Beginning in March 2004 and until a new contract acceptable to
the Commission is filed, Staff recommends the Commission order Idaho Power to continue to pay
Simplot for generation under the rates, terms and conditions contained in the proposed Agreement.
For ratemaking purposes however, until new rates can be computed in accordance with the
prescribed methodology, Staff recommends that the purchase be treated as a voluntary purchase of
power and not a purchase mandated under PURP A.
Respectively submitted this 1'J, day of April 2004.
(:)),
Scott Woodbury
Deputy Attorney General
Technical Staff:Rick Sterling
i :umisc/commentslipcO4, 7 swrps
STAFF COMMENTS APRIL 16, 2004
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Attachment 1
Case No. IPC-04-
Staff Comments
04/16/04
Office of the SecretJI\
Service Date
September 4. .19Q6
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR AN ORDER
APPROVING THE METHODOLOGY FOR
A VOIDED COST RATE NEGOTIATIONS WITH)
QUALIFYING FACILITIES LARGER THAN MEGA WATT.
CASE NO. IPC-95-
ORDER NO. 26576
BACKGROUND
On July 17, 1995, the Idaho Power Company (Idaho Power; Company) filed an
Application for an Order approving a methodology for conducting avoided cost rate negotiations
with qualifying facilities (QFs) I megawatt (MW) or larger.
Idaho Power s Application was anticipated by the Commission in Order No. 25884
(issued in Case No. IPC-93-28) in which the Commission stated:
Vie expect the Company to include with its 1995 IRP filing. amore detailed proposal of how the least cost planning basedavoided cost methodology will operate. We will treat that filing
as a generic discussion of the issue and expect all interestedparties, including the other utilities, to intervene and participateso that all issues may be resolved and the methodology can be
refined.
Order No. 25884 at p. 7
Pllfsuant to the Commission s directive, The Washington Water Power Company (Water
Power) and PacifiCorp were designated as parties to this proceeding. In addition, a number ofindependent power developers intervened as parties.
Subsequent to the filing ofIdaho Power s Application, a number of interested parties
conducted a series of settlement negotiations in an attempt to craft an avoided cost methodology for
larger projects that was acceptable to all concerned. With the exception of several issues
, the partieswere ultimately able to agree upon a methodology which was formulated primarily by the
Commission Staffbut with the assistance of all those who participated in the settlement negotiations.
ORDER NO. 26576
The proposed methodology, which is based essentially on each utility
s integrated resource plan. was
Attachment 2
Case No. IPC-O4-
Staff Comments
04/16/04 Page 1 of34
included as Exhibit No.1 0 I to the testimony of Commission Staff witness Rick Sterling presented
at the technical hearing conducted by the Commission in this case on July 2. 1996.
Under 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 ITom the resources selected in its base case resource plan. The value of power from the QF
is dictated by the type, amount, timing and cost of the resources in the IRP which would be displaced
or deferred.
With the exception of three issues discussed below, none of the parties who participated
in this case objected to Staffs proposed methodology. In fact, Idaho Power, Water Power.
PacifiCorp and Rosebud Enterprises, Inc. executed the Settlement Stipulation agreeing to Staffs
proposed methodology with the three exceptions. The other parties to the case chose not to sign the
Stipulation but did not oppose the methodology.
The three unresolved issues relate to the standard contract term over which QFs are
entitled to receive the avoided cost rate, whether levelized rates should be offered to QFs and
whether PacifiCorp should be allowed to adjust the input data used in the Company s IRP model to
reduce PacifiCorp s reserve margin from 12% to 10%.
DISCUSSION AND FINDINGS
what has long been one of the most contentious matters to come before this Commission; the setting
We commend the parties for the considerable time and energy expended in addressing
of avoided cost rates. When we issued Order No. 25884, we recognized that the use of a surrogate
avoided resource (SAR) for setting avoided cost rates for larger QF projects was no longer adequate
given the rapidly changing nature of the industry and the manner in which utilities actually acquire
resources. The Commission Staff and the other parties to this case have answered the call in
devising a methodology that more closely reflects the manner in which utilities acquire and price
generation resources than did the use of a single, hypothetical power plant. As we discuss below
the industry is changing with such speed that the use of any particular formula for setting avoided
cost rates will have inherent shortcomings. Nonetheless, we find that the methodology proposed by
the parties in this case is the most reasonable means of establishing avoided cost rates for larger QFs
at this time. We now turn to the issues left unresolved by the Settlement Stipulation. Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 2 of34ORDER NO. 26576
Contract Length
The Commission s current policy, as established in Order No. 21630, Case No. l:-1500-
170, is that QFs are entitled to contracts up to 20 years. Although the actual useful life
of the project
may exceed that time period, the QFs are :&ee to renegotiate a contract with the utility or with any
other buyer at the expiration of the 20-year term. In this proceeding, the Commission Staff
advocates maintaining the standard 20-year contract term. Staff contends that it is reasonable to
require 20-year contracts for QFs since utilities ' long-term acquisition planning is still primarily
based on the acquisition of long-lived resources under long-term commitments including the
relicensing of hydro projects and DSM programs. Staffreasons that
as long as the rates that utilities
pay for QF power are based on the utility s avoidance of planned resources, the utilities should be
required to offer 20-year contracts if the planned resources have lives of 20 years or more.
Staffbelieves that although utilities are currently relying on short-term market purchases to satisfy their
short-term needs, the fact that their respective IRPs call for the acquisition of long-term resources
cannot be overlooked and justifies requiring 20-year contract terms for QF projects. Staff argues that
short-term market purchases can be used in the proposed methodology, but only to
the extent those
market purchases have been included in the utility's IRP.
Idaho Power proposes that the standard contract terms for QF projects larger than I
megawatt should no longer be a fixed contract length. Rather, the expectation should be that QFs
will be offered contracts with terms. "similar in length to those offered by the utility for other
resources being acquired contemporaneously." Idaho Power s witness John Willmorth argues that
due to the current surplus of resources in the region and the uncertainty about future resource needs
resources are being acquired by utilities for periods generally no longer than five years.Consequently, the maximum contract length which should be offered to large QFs at this time should
not exceed five years, he argues. Idaho Power contends that it has no plans to build, own or operate
new generating facilities to meet load growth. Instead, as the competitive wholesale power markets
expand, Idaho Power plans to supplement its existing resources as necessary with market purchases
of capacity and energy. These will be short-term purchases, the Company argues, and consequently,
Idaho Power should not be required to offer QF contracts greater than five years during this period
of transition.
ORDER NO. 26576
Attachment 2
Case No. IPC-04- 7
Staff Comments
04/16/04 Page 3 of34
Willmorth argues that although Idaho Power had originally proposed the IRPmethodology, it win not remain a viable basis for calculating utility avoided costs given the dynamic
nature of the industry. He suggests that competition is likely to radically change or eliminate the
need for the IRP and to erode the relationship between the determination of avoided cost and the
resource plans of individual utilities. Consequently, avoided costs will
need to be calculated using
a more direct market price methodology. He urges the Commission to convene a proceeding shortly
after concluding this case to investigate the future role of the IRP and the feasibility
of eliminatingadministratively detennined avoided costs in favor of a direct detennination of the QF rate from the
published price of an equivalent market purchase.
PacifiCorp also believes that avoided cost rates must soon be established by a more
market-based methodology but agrees that Staff's proposed methodology is appropriate for the
interim. Like Idaho Power, PacifiCorp opposes the standard 2a-year contract term for QFs arguing
that it unduly protects them from the competitive market forces with which an other wholesale
market participants have to contend and leads to overstated avoided cost prices.
PacifiCorp proposes
that any QF contracts offered in excess of five years should include a market adjustment clause to
avoid the risk that utilities' customers will pay prices for QF power that is in excess of current
market prices.
PacifiCorp proposes that the contract structure and prICIng terms offered to QF
argues that the optima! contract structure the Commission should adopt includes a five-
year term
developers should reflect those in the market, i., what is avoided by a QF contract. The Company
with a developer option for full levelization during that term. If the terms are kept to five years or
less, the Company does not believe that market adjustments would be necessary or appropriate.
Pricing in the subsequent periods would be based on subsequent market conditions. If theCommission decides to continue with contract terms in excess of five years
, PacifiCorp proposes thatit be allowed to include provisions in its contracts which would anow the risk of longer term
contracts to be shared. For instance, the Commission could adopt contracts which have five years
of initial pricing fonowed by market adjustments at the beginning of the sixth
, eleventh and sixteenth
years. The market adjustment would true-up prices to a published market index such as
theCalifornia-Oregon Border or Palo Verde electricity indexes or other indices which are a good
ORDER NO. 26576
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 4 of
measure of current electricity prices. Prices between adjustment years could be based on the prior
. year s price adjusted by an inflation index.
The second option could involve a plus or minus lO% deadband being placed around a
predetennined price. If the actual price of electricity in the market were outside the deadband.
prices would automatically be reset to the published market price with a new deadband established.
Water Power also opposes maintaining the 20-year contract tenD. As an alternative to
Staffs proposal, Water Power recommends that utilities be required to offer fixed prices for
tenDSno longer than five years. Water Power witness Douglas Young suggests that QF developers should
be able to request long-tenD contracts up to ten years, but after five years the price provisions of the
contracts should be renegotiated or revised to reflect then current market conditions.
Young assertsthat the electric industry is in such a state of flux that 20-
year price forecasts are not possible.
Furthennore, he argues that five years is closer to the average length of electric purchase and sales
transactions which Water Power has recently experienced in the power market.
Rosebud's wimess Richard Slaughter advocates maintaining the standard 20-year contracttenD. He notes that short-tenD market prices could just as easily rise as fall and that this has alwaysbeen the case in the industry. He suggests, in fact, that there are reasons to believe that the low gas
prices experienced in recent years may soon start to rise as utilities become increasingly reliant upon
this resource and supply becomes increasingly scarce. In any event, he contends, it is unlikely that
shareholders and ratepayers would bot~ benefit in the event that market prices decline.
If they were
gas prices will fall much lower. Slaughter notes that under the various utilities' proposals , utility
to increase, however, ratepayers would bear the entire burden because contracts with QFs would be
renegotiated 'at higher prices. Finally, Slaughter notes that no developer can obtain financing for a
project with a guaranteed price of only five years. Consequently, he asserts, that without contracts
of at least 20 years, there will be no competition in the energy market from qualified developers.
Slaughter also questions the credibility of utilities who, on the one hand contend that they wish to
treat QF resources the same as their own, yet are not proposing to forego rate base treatment of long-
lived, Company-owned assets, e., hydro relicensing, DSM, etc.
We find:
ORDER NO. 26576
PURP A was enacted to encourage the promotion and development of renewable energy
technologies as alternatives to fossil fuels and the construction of new
generating facilities by
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 5 of34
electric Utilities. American Paper Institute, Inc. v. American Electric Power Service Corp.. 461 U.
402, 103 S.Ct. 1921 , 76 LEd.2d 22 (1983). Pursuant to congressional directive, FERC promulgated
rules implementing sections 201 and 210 of PURP A. Section 210 requires electric utilities to
purchase electricity produced by QFs. 16 U.
c. ~ 824a-3(b), (d).
Under FERC rules, utilities are required to purchase QF power at a rate of payment equal
to the utility s full avoided cost. 18 c.F.R. ~ 292.304(b)(2). "Avoided costs" are the incremental
costs to the electric utility of power which, but for the purchase from the QF, such Utility would
generate itself or purchase from another source. 18 C.R. ~ 292.1 01 (b)(6).
FERC promulgated the general scheme and rules but left the actual implementation of
establishing avoided costs to the regulatory authorities of the individual
states. The grant of
authority to the states in implementing the regulation of sales and purchases between QFs and
electric utilities, both substantively and procedurally, is broad. See, Federal Energy Regulatory
Commission v. Mississippi 456 U.S. 472, 102 S.Ct. 2126, 72 LEd.2d 532 (1982).
PURP A, and the implementing regulations, require only that avoided costs be established
and made available to QFs with a capacity of 100 kilowatts or
less. 18 c.F.R. ~ 292.304(c). The
Act and regulations are silent as to the length of the contract over which the QF is entitled to receive
the avoided cost rate. Consequently, this is a matter that lies within this Commission
s discretion.
The Commission s policy with respect to the standard contract length has evolved over the years.
issued in Case No. 0-1500-170, the Collunission shortened the standard contract length to 20 years
Prior to 1987, utilities were obligated to provide QFs with 35-year contracts. In Order No. 21630
reasoning that risk and uncertainty inherent in long-range forecasting increases dramatically with
time and that a shorter contract tenn would reduce that risk. The Commission ruled that contracts
longer than 20 years would be available to QFs only upon a persuasive showing of need.
Significant changes have swept through the electric industry since we last
examined the
issue of contract length. The FERC has mandated open access to the transmission system
, thennaltechnologies have improved, gas prices are low, there is a considerable surplus of energy available
in this region resulting in very low spot market prices for electricity and
, finally, even the continued
existence ofPURPA is being called into question. We find that as the industry as a whole continues
for PURP A power.
to transfonn to a more free market model, we cannot justify obligating utilities to 20-year contracts
ORDER NO. 26576
As the utilities in this case note, such an obligation does not reflect the manner
Attachment 2
Case No. IPC-04- 7
Staff Comments
04/16/04 Page 6 of34
in which they are currently acquiring power to meet new load; through short-term (five years or less)
purchases. Consequently, it would be nothing more than an artificial shelter to the QF industry to
provide those projects with contract terms not otherwise available in the free market. Vie can find
no justification for insisting that Idaho s investor-owned utilities and their ratepayers assume such
an obligation simply to foster one particular segment of an increasingly competitive industry. We
find, therefore, that Idaho s investor-owned utilities shall not be required to offer contracts to QFs
in excess of five years until further action is taken by this Commission.
This ruling, however. does
not prevent utilities from offering for approval QF contracts with terms that exceed five years should
the utilities believe that such contracts are in the best interests of their ratepayers.
Levelized Rates
Under the Commission s current policy, levelized rates are available to any QF developer
who desires them. Nonlevelized rates are high in later years of the contract while levelized rates are
equal throughout the contract term. Levelized rates are often considered essential by developers of
projects with high, up-front capital costs.
The arguments for and against offering levelized rates for QF projects are essentially the
same as with respect to contract length. Staff simply argues that the levelization of rates is not an
issue in this case. In the combined avoided cost cases, WWP-93-, IPC-93-, PPL-93-5/UPL-37 and UPL-93-3IPPL-93-, which initiated the present proceeding, the
Commission stated in Order Nos. 25882, 25883 and 25884:
The levelization of avoided cost payments is a.i1otI~er tool that thisCommission has historically relied upon in encouraging andassisting smaller QFs by providing a cash stream that betterenables them to satisfy their debt service in the early years of
their contracts. Although, we have taken considerable stridestoward market-based pricing, we find that levelization for projects
above I MW should be continued. We believe that levelizationmore accurately reflects the way in which costs are recovered for
utility-owned projects. The utilities are directed to providelevelized rates, for all QF projects who desire it, utilizing thesame procedure incorporated in the SAR methodology.
Idaho Power does not support mandatory rate levelization but agrees that it is a legitimate
item for contract negotiations on a case-by-case basis. Willmorth suggests that an appropriate
standard is that QFs should be offered the same opportunity for rate
ORDER NO. 26576
levelization as is
Attachment 2
Case No. IPC-04- 7
Staff Comments
04/16/04 Page 7 of
contemporaneously being offered by the utility for similar alternative purchases. He
argues that the
issues of contract length and rate levelization are related. When actual avoided costs tend to increase
year after year, rate levelization results in shifting avoided costs from the later years of the QF
contract into the earlier years of the contract thereby producing QF rates which systematically exceed
avoided costs through a portion of the contract life. The shorter the contract length, the less the cost
shifting and early overpayment in rates due to rate levelization.
PacifiCorp argues that rate levelization should be offered but under the condition that
contract length not exceed five years.
Water Power disagrees with Staff's contention that rate levelization is not an issue in this
case. According to witness Douglas Young, levelization is incident to the pricing provisions of
purchase contracts. Water Power simply argues that so long as contract length does not exceed five
years, the risks attendant to rate levelization are acceptable to the Company.
Finally, Rosebud witness Slaughter argues that leve1ization is as important as a 20-
yearcontract term for facilities with high capital cost and low fuel expense. He
argues that levelization
also presents the ratepayer with a rate risk most similar to that experienced with utility-owned plants.
He suggests that a levelized long-term contract is the resource whose attributes are most like utility-
owned plant. He concedes that there are risks in such arrangements but argues that there are also
potential rewards especially as the energy market approaches the lower bound
of its long-term costhistory.
We find:
The three utilities in this proceeding agreed that if the standard contract length were
reduced to five years, that levelized rate should be offered to any QF desiring them. We find
therefore, that all QFs larger than I MW shall be entitled to levelized rates should they so desire
them.
Resenre Margin
PacifiCorp, through the prefiled testimony of witness Laren Hale
, proposed a number of
changes to the input data used in the Company s IRP model to calculate avoided cost rates that are
different than data contained in RAMPP-4; the most recent IRP.
Staff believes that all of the changes should be allowed with one exception; reducing the
reserve margin from 12% to 10%. According to Staff witness Sterling, all of the other changes are
ORDER NO. 26576
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 8 of34
l,-
either identified in the section of the Company s IRP titled "Revisions to Inputs " are necessary in
order to use the model for avoided cost calculations or allowed by the Settlement Stipulation to be
updated on a semi-annual basis. Sterling argues, however, that a reduction in PacifiCorp' s reservemargin was not identified in the IRP or its revisions and is not specifically permitted by the
Stipulation.
In rebuttal, PacifiCorp witness Weaver concedes that the Settlement Stipulation does not
allow for a revision to the Company s reserve margin which is why the Company is now seeking
Commission approval. Weaver notes that the issue of reserve margin is
cUITently under discussion
in the Company s RAMPP-5 IRP. Because of the regional surplus of capacity, PacifiCorp believes
that a reduction in reserve margin is warranted.
We find:
Pursuant to the settlement discussions, the three investor-owned utilities that are party
to this proceeding were allowed 45 days in which to make amended IRP filings for the purpose of
making avoided cost calculations. This invitation to make amended filings was set forth in the
Notice of Scheduling in the three utilities' pending IRP cases. PacifiCorp never made an amended
filing in response to this invitation. Instead, it included proposed changes to its reserve margin for
the first time in the prefiled testimony of one of its witnesses.
We fInd that it would be inappropriate to allow PacifiCorp a last minute amendment to
its IRP in a case not initiated for that purpose, and in which no notice was given that such an
amendment may occur. This CmnJ.-nission has previously established a methodology for the filing
and review of utilities ' IRPs and we are not compelled to bypass that methodology by allowing a last
minute change in an unrelated case. We further note that PacifiCorp will file its next IRP (RAMPP-
5) in early 1997. That is the proper proceeding in which to review the adequacy of the Company
reserve margIn.
ORDER NO. 26576
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 9 of34
ORDER
IT IS HEREBY ORDERED that the Settlement Stipulation set forth in Staff Exhibit
No.1 01 establishing a methodology for setting avoided cost rates for QFs
1 MW and larger is herebyapproved subject to the termsand conditions set forth herein.
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues finallydecided by this Order) or in interlocutory Orders previously issued in this Case No. IPC-
95-9 maypetition for reconsideration within twenty-one (21) days of the service date of this Order with regard
to any matter decided in this Order or in interlocutory Orders previously issued in this Case
No. IPC-95-9. Within seven (7) days after any person has petitioned for reconsideration
, anyother person may cross-petition for reconsideration. See
Idaho Code ~ 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise
, Idaho this -:L
$'p'& ~-
day of AJIguM 1996.
~.-1q/~
RALPH NEL ON, PRESIDENT
. ~7~
Iv'1ARSHA H. SMITH, COMMISSIONER
ENNIS S. HANS N, COMMISSIONER
ATTEST:
// /j ./' .. /.
-L/.-i.....-.-t::::Z
y, ......-:
::f"rz::::c
Myrna J. Walters
Commission Secretary
v!dlO:IPC-95-bp2
ORDER NO. 26576 10-
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 10 of34
- :- '~;. --- ,-. - _: , .
BARTON 1. KLINE
Idaho Power Company
P. O. Box 70
Boise, Idaho 83707
[phone]
, , -:: -
':1 (:1,
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~....; 111/1 vi Illi
.u L:'"
. "'" . , -.- -.
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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
: )
FOR AVOIDED COST RATE
NEGOTIATIONS WITH QUALIFYING
FACILITIES LARGER THAN 1 MEGA WAIT )
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 -
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 11 of34
1. 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 andparticipate so that all issues may be resolved and the methodology can be
refIlled.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, IDAPA 31.01.01.
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 Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 12 of34
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 I 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 I as the methodology for computing avoided costs and
SETTLEMENT STIPULATION - 3
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 13 of
, .
for conducting avoided cost rate negotiations for QF projects I 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 of the 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. In
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
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 14 of34
, .
f~
DATED This day of \ J \.00\ C.
SETTLEMENT STIPULATION - 5
1996.
IDAHO PUBLIC UTILITIES COMMISSION
Brad Purdy
Deputy Attorney General
IDAHO POWER COMPANY
By:
Barton L. Kline
WASillNGTON WATER POWER CO.
By:
R. Blair Strong
ACIFICORP
By:
John M. Eriksson
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 15 of34
, ...
DATED This.l.:. day of , 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
SEITLEMENT STIPULATION - 5
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 16 of34
06:"07':'95 U4: 20PMFROM PAINE HAMBLEN
. .
? 03~...
.J""""'"DATED This -2- day of-Mey, 1996.
IDAHO PUBLIC Ul1LmES COMMISSION
SEITLEMENT STIPULATION.
By:
BI1Id Purdy
Deputy Anomey General
IDAHO POWER. COMPANY
By:
Barton L. Kline
WASHINGTON WATER POWER CO.
.----::? ..--" /./ /
By: :Ii.
'j
,1-(r ) h"R. Blair Strong ..:
. "
PAC!FICORP
By:
John M. Eriksson
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 17 of34
. ,
DATED This day of .:ru n e.1996.
IDAHO PUBLIC UTILITIES COMMISSION
By:
Brad Purdy
Deputy Attorney General
IDAHO PO~R CONW ANY
By:
Barton 1. Kline
WASIDNGTON WATER POWER CO.
By:
R. Blair Strong
ACIFICORP
By:
John M. Eriksson
SETTLEMENT STIPULATION - 5
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 18 of34
~O/~I/~~~O !!:~o ~~b~q~b~14
1llf/lltl'ltit t~: 18 t:fZ(18 33~ :1782
ORNDiJRFF&TROUT
IDAHO PFC ?..GE EJ2
~OO2,O(!~
DATED This day of , 1996.
INDEPENDENT ENERGY PRODUCERS
OF IDAHO
By:
Peter J. Richardscm
MYERS ENGINEERING CaMP A. 'ly
By:
John RWlft
EARTH POWER RESOURCES. INc.
By:
P~er J. FUchardson
IRRIGA nON DISTRlCrS
By:
SETTLEMENT STIPULA TlON . 6
Attachment 2
Case No. IPC-04- 7
Staff Comments
04/16/04 Page 19 of34
DATED This day of 1996.
INDEPENDENT ENERGY PRODUCERS
OF IDAHO
By:
Peter J. Richardson
MYERS ENGINEERING COMPANY
By:
John Runft
EARTH POWER RESOURCES , INe.
By:
Peter J. Richardson
IRRIGATION DISTRICTS
By:
Don A. Olowinski
ROSEBUD ENTERPRISES, me.
By:
Owen H. Orndorff
SETTLEMENT STIPULATION - 6
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 20 of34
STAFF'S PROPOSED AVOIDED COST METHODOLOGY
FOR PROJECTS LARGER THAN ONE MEGA WATT
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 becomeincreasingly competitive. This will ultimately work to the advantage of ratep~yersin 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 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 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.
STAFF PROPOSAL
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 21 of34
IPC-E-95-9
Exhibit 1 to
Settlerrent Stipulation
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 refeITed to as the "base case" plan.
The base case plan is the starting point of the analytical process described in this document for
detennining 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 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 ca~se 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
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 22 of34
, .
calculating avoided cost rates. Once the avoided cost methodology is established, Staff does not
expect a hearing or other fonnal Commission proceeding to be initiated each time a utility
s avoided
costs 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 from such cogeneratbr or small power producer, such utility
would generate itself or purchase from another source
" 18 CFR, J 292.101.
As explained by FERC:
This definition is derived from the concept of "the incremental cost ofalternative electric energy" set forth in section 2l0(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 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 expansionplan, 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, 198OJ).
In the proposed methodology, the avoided cost of a QF project is detennined 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
Attachment 2
Case No. IPC-O4- 7
Staff Comments
04/16/04 Page 23 of34
i '
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 detennination 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 Wlcertainties 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 amoWlt 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
of the QF contract, excluding the total purchase costs of the QF resource itself.
STAFF PROPOSAL
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 24 of34
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, nom 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 Conunission
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 arid 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 withQF 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
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 25 of34
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
lRP-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 fumly 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
ofIRP filings. These forecasts serve as the basis for avoided cost calculations. Staff contends that
only known, measurable, and easily docwnented 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
docwnented change. The signing or expiration of a power sales or exchange agreement would also
be a known, measurable, and easily docwnented change, as would the signing of a new QF contract.
STAFF PROPOSAL
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 26 of34
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
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 detenninations, 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
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 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 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
Attachment 2
Case No. IPC-O4-
Staff Comments
04/16/04 Page 27 of34
. 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 infonnation 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
Attachment 2
Case No. IPC-04- 7
Staff Comments
04/16/04 Page 28 of34
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 I 0 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
Attachment 2
Case No. IPC-O4-
Staff Comments
04/16/04 Page 29 of34
- - -
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 infonnation:
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
of 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 tenn (fmal 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 infonnation as needed in order to provide an
accurate rat~ 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
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 30 of34
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
Attachment 2
Case No. IPC-04- 7
Staff Comments
04/16/04 Page 31 of
, "
Seasonalized and On-PeaklOff-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 cun-ently allowed for Idaho Power and
Washington Water Power) using the same seasonalization factors allowed for projects smaller than
IMW.
rs:gdk:jo: bp/ipce9 5 9c.avc/h 1 comments/i( 5/28/96)
STAFF PROPOSAL
Attachment 2
Case No. IPC-04- 7
Staff Comments
04/16/04 Page 32 of34
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 2q day of May, 1996, I served a true andCOITect copy of the within and foregoing SEITLE1\.1ENT STIPULA nON, to the followingindividuals by the method indicated below, and addressed to the following:
Brad Purdy
Idaho Public Utilities Commission
472 W. Washington
Statehouse
Boise, ill 83720
Gregory N. Duvall
PacifiCorp
920 S.W. Sixth Avenue, Suite 1314
Portland, OR 97204-1256
R. Blair Strong
Paine Hamblen Coffm, et al.
717 W. Sprague Avenue, Suite 1200
Spokane, W A 99204
Thomas Dukich, Mgr.
Rates & Tariff Administration
Washington Water Power Company
O. Box 3727
Spokane, W A 99220
Hand Deliver
S. Mail
Overnight Mail
Facsimile
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U. S. Mail
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Don A. Olowinski
Richard B. Burleigh
Stephanie W. Gillette
Hawley Troxell Ennis & Hawley
O. Box 1617
Boise, ID 83701
John L. Runft
Attorney at Law
Alaska Center
1020 W. Main Street, Suite 440
Boise, ID 83702
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CERTIFICATE OF MAILING Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 33 of34
Owen H. Orndorff
Orndorff & Trout
1087 W. River Street, Suite 230
Boise, ill 83702
Peter J. Richardson
Davis Wright Tremaine
999 Main Street, Suite 911
Boise, ill 83702
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, NV 89702
Ronald C. Barr, President
Earth Power Resources, Inc.
2534 East 53rd Street
Tulsa, OK 74105
'--'
CERTIFICATE OF MAILING
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GJiBarton L. Kline
Attachment 2
Case No. IPC-04-
Staff Comments
04/16/04 Page 34 of
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 16TH DAY OF APRIL 2004
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-04-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
MONICA MOEN
BARTON L KLINE
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
RANDY C ALLPHIN
CONTRACT ADMINISTRATOR
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
DAVID HAWK
J R SIMPLOT COMPANY
PO BOX 27
BOISE ID 83707
~.&.
SECRETARY
CERTIFICATE OF SERVICE