20110120Reply Comments, Request for Hearing.pdf

~r.~pu ollq:3'ATTORNEYS AT LAW IBn J~N\9 i n
Peter Richardson
Tel: [phone] Fax: [phone]
pete rti tichatdso n andoleary. com
P.O. Box 7218 Boise, ID 83707 - 515 N. 27th St. Boise, ID 83702
January 19, 2011
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
PO Box 83720
Boise I D 83720-0074 c;~
RE: Case No.J-E-10-0
Dear Ms. Jewell: p.éll.I.
We are enclosing an original and seven (7) copies of tha&OMMENTS OF THE
NORTHWEST AND INTERMOUNTAIN POWER PROÓÙCERS COALITION
in the above case.
An additional copy is enclosed for stamping and return to our offce.
~/' ¿W1-15
Nina M. Curtis
Administrative Assistant for Peter Richardson
encl.
REC
Peter J. Richardson ISB# 3195
Gregory M. Adams ISB# 7454
Richardson & O'Lear, PLLC
515 N. 27th Street
P.O. Box 7218
Boise, Idaho 83702
Telephone: [phone]
Fax: [phone]
peterririchardsonandoleary.com
gregririchardsonandolear .com
Lon JArl 19 PH 4= 3 l
Attorneys for Nortwest and Intermountain
Power Producers Coalition
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT PETITION )
OF IDAHO POWER COMPANY, AVISTA ) CASE NO. GNR-E-I0-04
CORPORATION, AND PACIFICORP DBA )
ROCKY MOUNTAIN POWER TO ADDRESS ~ REPLY COMMENTS IN OPPOSITION
AVOIDED COST ISSUES AND TO ADJUST ) BY THE NORTHWEST AND
THE PUBLISHED AVOIDED COST RATE ) INTERMOUNTAIN POWER
ELIGIBILITY CAP ) PRODUCERS COALITION AND
) ALTERNATIVE REQUEST FOR AN
) EVIDENTIAY HEARNG
)
)
COMES NOW, the Northwest and Intermountain Power Producers Coalition ("NIPPC")
and pursuant to that Notice of Scheduling Order No. 32131 issued on December 3,2010, by the
Idaho Public Utilities Commission (the "Commission") hereby provides its Reply Comments in
Opposition to the requested reduction in the eligibility cap for published avoided cost rates.
NIPPC respectfully requests that the Commission deny the request to reduce the published
avoided cost rate eligibilty cap, and alternatively requests that the Commission hold an
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-l
evidentiar hearng prior to issuing any order reducing the cap. NIPPC fuher requests that the
Commission make any reduction in the cap effective on the date of the Commission's order
reducing the cap, not on the retroactive and arbitrarly-determined date of December 14,2010.1
REPLY COMMENTS
A. THE IRP METHODOLOGY is FLAWED AND PRODUCES ILLEGAL
AVOIDED COST RATES.
Idaho Power, Rocky Mountain Power, and Avista (collectively the "Utilties") propose to
reduce the eligibility cap at which a PURP A qualifying facility ("QF") project is entitled to the
Commission's published avoided cost rates from 10 average monthy mega-watts ("aMW") to
1 00 kilowatts ("kw"). They concede, however, that they stil have an obligation to offer to
purchase QF power from PURP A developers that offer projects greater than 100 kw. PURPA
and the Federal Energy Reguatory Commssion's ("FERC's") regulations require each of the
Utilities to buy energy and capacity from QFs of all sizes at "the incremental costs to an electric
utility of electrc energy or capacity or both which, but for the purchase from the qualifying
facilty or qualifying facilties, such utilty would generate itself or purchase from another
source." 16 U.S.C. § 824a-3 (d). The Utilities and Commission Staff propose to set the avoided
cost rates for projects greater than lOO kw based on the individua operating characteristics of
each QF - through the "IRP Methodology." Avista's Initial Comments, at p. 3; Rocky Mountain
Power's Initial Comments, at p. 4; Idaho Power's Initial Comments, at p. 5; Commission Staff's
NIPPC provided additional factual and legal background in its Answer in Opposition to
the Joint Motion to Adjust the Published Eligibility Cap, which NIPPC fied on November 8,
2010 in this docket, as well as extensive background and argument in its initial Comments filed
December 22,2010. NIPPC hereby incorporates its prior filings into these Reply Comments by
reference. NIPPC stads by all comments made earlier, and in no way concedes any point
previously made.
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Initial Comments, at pp. 3-4, 12.2 For this IRP Methodology, each utilty would use the power
supply model it uses in preparation of its bianual integrated resource plan ("IRP"). Idaho
Power's proposed IRP Methodology will use a power supply model called Aurora. Avista is not
sure which power supply model it will use. See Avista 's Response to NIPPC Request No. 23(a)
(stating Avista "would likely propose to use its AURORA and/or PRiSM models").3 Rocky
Mountain Power will use the power supply model developed by its parent company known as the
Grid ModeL.
The solution proposed in the Utilties and Commission Staffs Initial Comments is
unworkable and ilegaL. The curent system of using published avoided cost rates for projects up
to ten average monthly megawatts has been fuly and exhaustively litigated and vetted. It is not
perfect - hence the need for the additional tweakng that will be the subject of the next phase of
this docket. The IRP Methodology, on the other hand, has rarely been used, never been litigated
and has not been proven as a reliable way to estimate avoided cost rates. See Case No. IPC-E-
95-09; Order No. 26576. Furhermore, it will be applied inconsistently and on a blind-to-
developer basis. It may be possible to create an IRP Methodology that is workable, but the
curent methodologies being proposed by the Utilities are not capable of complying with PURP A
and do not accurately reflect the Utilties' avoided costs. For the following reasons, the curent
IRP Methodology is flawed and ilegaL.
2 Commission Staff recommends that the drop in the eligibilty cap apply only to wind
QFs.
3 In these Reply Comments, NIPPC cites extensively to discovery provided in ths case.
NIPPC will not submit the discovery into the record at ths time, however, because the
Commission's procedural schedule provides for no evidentiar hearing where NIPPC can fully
contest all factual issues by cross-examining the witnesses providing the responses to adequately
develop an evidentiar record in this matter.
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1. The IRP Methodology imposes impossible time constraints on PURP A
developers.
PURPA developers spend signficant amounts of time to bring a project forward to a
point the developer is confident enough to execute a contract. For example, a prudent wind
developer must conduct at least two years of wind measurement to evaluate the motive force
with a level of confidence necessar to invest additional resources and request power purchase
and interconnection agreements. All QF project developers must spend a significant amount of
time and money securing and analyzing the motive force before they are in a position to execute
project contracts. There must be a high degree of certainty as to the availability of published
rates for a developer to invest the time and money to do the necessar studies. But until the
motive force is studied and measured, under the IRP Methodology the utilities are, by definition,
unable to provide an avoided cost rate to the developer. Developers will have few incentives to
even begin analyzing projects in Idaho without any prior indication that the rate may be
profitable.
2. The IRP Methodology is a black box that wil instil no confidence in the
PURP A development community.
The models used by the Utilities are purchased under licensing agreements that prohibit
the licensee from allowing third paries access. See Avista's Response to NIPPC Request No. 23
(a) (stating Avista "canot provide the models"). As a result, the models are "black boxes" to a
PURP A developer. The confidence necessar to invest vast sums of money in preliminar
ground work on a PURP A project can only be engendered by complete and unettered access to
the working models used to set avoided cost rates. Allowing the Utilities to essentially hide their
work inside a black box would violate this Commission's mandate to encourage the development
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of PURP A projects.
3. The IRP Methodology violates several of FERC's requirements for an
avoided cost methodology.
FERC's implementing reguations allow states, in setting rates for purchases, to
differentiate among various technologies on the basis of the supply characteristics of such
technologies. 18 C.F.R. § 292.304(c)(3)(ii). However, when states tae into consideration the
supply characteristics of varous technologies in determining avoided cost rates, they must
incorporate a laundr list of factors that have been largely ignored by the Utilities. Incorporating
FERC's list of factors in setting rates is not optional. See 18 CFR 292.304(e). There has been no
showing that the IRP Methodology complies with several of these requirements, including the
following:
The expected or demonstrated reliabilty ofthequalifingfacility.
18 C.F.R. § 292.304(e)(2)(ii).
The Utilties have not demonstrated that they have incorporated the fact that all of the
QFs on line and, hence in all likelihood all proposed QFs, are extremely reliable. Reliabilty is
inherent in the QF's relationship with its purchasing utility because QFs simply do not get paid if
they do not produce, and QFs get paid less if they fail to achieve production or availability
tagets. See Order No. 29632 (requiring PURP A QFs to agree to a PPA term whereby the utilty
penalizes the QF if it fails to deliver energy in an amount within 90 to 110 percent of its
projected monthly generation); Order No. 30488 (allowing wind QFs to agree to an alternative
penalty by which they are penalized if they are not physically capable and available to generate
at full output durng 85% of the hours of the month, excluding times for scheduled maintenance
and events of force majeure). It is doubtful that the value of the high degree of reliabilty
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inherent in the QF commitment to deliver power is incorporated into any of the IRP
Methodologies.
The terms of any contract or other legally enforceable obligation,
including the duration of the obligation, termination notice
requirement and sanctions for non-compliance.
18 C.F.R. § 292.304( e )(2)(iii).
The Utilties have not demonstrated they have incorporated the unque Commission-
vetted contract terms into their calculation of avoided cost rates using the IRP Methodology. For
example, the Utilities just recently unilaterally staed insisting on delay default liquidated
damages security provisions in all new PURP A contracts in the amount of $45 per kw of
capacity.4 The Utilties have been silent on the added value to them of a QF agreeing to ths
delay securty provision and have apparently therefore failed to account for that value in their
IRP Methodologies.
The extent to which scheduled outages of the qualifing facilty can
be usefully coordinated with scheduled outages of the utilty's
facilties.
18 C.F.R. § 292.304(e)(2)(iv).
The Utilities have not demonstrated that they have made any effort, in the IRP
methodology, to coordinate scheduled outages of the QF with scheduled outages ofthe utility's
facilities. Nor have they, as far as NIPPC is aware, assigned a value to such coordination of
outages with QFs.
The usefulness of energy and capacity supplied from a qualifing
facilty during system emergencies, including its abilty to separate
its load from its generation.
18 C.F.R. § 292.304(e)(2)(v).
4 For example, a 10 MW QF project must post $450,000 after contract approval, and would
forfeit that entire amount if it failed to come online as scheduled, even if the market price for
replacement power were below the contract price.
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The Utilities have not demonstrated that they conduct, in the IRP Methodology, an
analysis of the abilty of QFs to provide energy and capacity during periods of system
emergencies.
The individual and aggregate value of energy and capacity from
qualifingfacilties on the electric utilty's system.
18 C.F.R. § 292.304(e)(2)(vi).
It appears from the Utilties' fiing, that they ignore the aggregate value of energy and
capacity from all of the qualifying facilities on their respective systems. The aggregate value of
energy and capacity from all of the QFs on line is, in all likelihood, extremely valuable and
apparently has historically been ignored by the Utilities in setting avoided cost rates using the
IRP Methodology.
The smaller capacity increments and the shorter lead times
available with additions of capacity from qualifingfacilties.
18 C.F.R. § 292.304(e)(2)(vii).
To NIPPC's knowledge, the fact that QFs are brought on line in smaller capacity
increments and with shorter lead times than utilty base load units has never been considered by
the Utilties in setting avoided cost rates under their respective IRP Methodologies. The costs
associated with the long lead times and massive capital commitments required for the Utilties to
constrct new facilities are simply ignored when the Utilities determine avoided cost rates using
the IRP Methodology. There is an obvious moneta value to investor-owned utilties and their
ratepayers of not having to pay for constrction work in progress and the elimination of the
regulatory uncertinty of successfully rate-basing new constrction projects. See infa
(discussing Avista's Reardon wind project).
The relationship of the availabilty of energy or capacity from the
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qualifingfacilty as derived in paragraph (e)(2) of this section, to
the abilty of the electric utilty to avoid costs, including the
deferral of capacity additions and the reduction of fossil fuel use.
18 C.F.R. § 292.304(e)(3).
The Utilities have not demonstrated that they have conducted an analysis of either the
abilty of the purchasing utility to defer capacity additions or to calculate the value in the
reduction of fossil fuel use. The value associated with the reduction in fossil fuel use allowed by
purchases from QFs is not incorporated into the avoided cost rates using the IRP Methodology.
Futue increases in coal costs are addressed in detail later below, but certainly are not included in
the IRP Methodology. In addition, the cost to the utility of extreme natural gas volatility has
never, as far as NIPPC understads, been added to the Utilities' avoided cost calculations under
either the SAR or the IRP Methodologies. This is a value that FERC rules require to be
considered which is completely ignored by the Utilities.
The costs or savings resulting from variations in line losses from
those that would have existed in the absence of purchases from a
qualifing facilty, if the purchasing electric utilty generated an
equivalent amount of energy itself or purchased an equivalent
amount of electric energy or capacity.
18 C.F.R. § 292.304(e)(4).
The Utilities have not demonstrated that they have conducted an analysis of the savings
they realize by purchases from QFs in varations in line losses. Upgraded transmission lines and
related facilities paid for by QFs (as discussed in more detal below) benefit all ratepayers,
reduce costs to the utility and create a more robust transmission system. Those benefits are
ignored using the IRP Methodology. Furermore, a QF located at or near load centers - such as
cogenerators at large industrial facilities - create avoided transmission costs for their host
investor-owned utilty.
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For the additional items contaned in 18 C.F.R. § 292.304(e) not directly addressed, the
curent IRP Methodology mayor may not comply with the applicable provision. But without
any transparency to QF developers, there is no way to test the utilty's analysis in any individua
case.
4. Idaho Power's Langley Gulch plant demonstrates the wildly inaccurate
avoided costs generated by the IRP Methodology.
The Commission recently granted Idaho Power a Certificate of Public Convenience and
Necessity ("CPCN") to construct the Langley Gulch 330 MW natural gas fired combined cycle
combustion tubine ("CCCT") in Southern Idaho. See Order No. 30892.
The Commission estimated that the output from Langley Gulch would cost the Idaho
ratepayers approximately $126 per MWh, and Idaho Power has confirmed that cost estimate is
stil accurate. Id. at p. 6; Idaho Power's Response to NIPPC Request No. 46(a). That figure is
much higher than the avoided cost rates in effect at the time, but utilties in Idaho do not use their
avoided cost rates as a ceilng or benchmark against which they measure the reasonableness of
utility-built resources. As the Staff witness in the Langley Gulch case explained in prefied
testimony:
I do not believe avoided cost rates used for PURP A QF contracts
are a fair comparison to the cost Idaho Power will pay for power
produced by the Langley Gulch plant. Although avoided cost rates
are computed based on a surogate combined cycle combustion
tubine (SAR) very similar to Langley Gulch, assumptions about
how the SAR and the Langley Gulch plant would be operated are
much different. Avoided cost rate computations assume that the
SAR plant is not economically dispatched and is instead operated
at nearly its maximum achievable capacity factor. This is
consistent with PURPA QFs that are not dispatchable and operate
at as high a capacity factor as they can. The Langley Gulch plant
clearly will be dispatchable, and will be operated only when it is
cost effective to meet load or make surlus sales. Unlike the
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assumptions for the SAR or PUR A QFs, it will not be operated
when it is not needed or when it is not profitable.
Direct Testimony of Rick Sterling, Case No. IPC-E-09-03, p. 83.
Now, in discovery in this case, Idaho Power has calculated the 20-year levelized rate for
Langley Gulch using the IRP Methodology and concluded that, if it were modeled as a high
(90%) capacity factor must-run unit as Mr. Sterling described for PURPA QFs, it would have a
levelized avoided cost of$75.88/MWh. Idaho Power's Response to NIPPC Request No. 46(d).
If a PURP A developer brought Langley Gulch to Idaho Power as a QF, the cost to the ratepayers
would be approximately $50/MWh less than Langley Gulch as a dispatchable, rate-based facility.
Thus, according to the IRP Methodology, the value to the ratepayers of a PURP A Langley Gulch
plant is $50/MWh cheaper than the cost to the ratepayers of a dispatchable, rate-based Langley
Gulch plant. The $50-difference should merely represent the value of the capacity or
dispatchability of the plant, and on its face $50/MWh for capacity is far out of the realm of
reality in today's market. See Avista's Response to NIPPC Request No. 19(f (stating Avista's
dispatchable Lancaster plant cared a fixed cost of $20. 87/MWh in 2010).
Another way to look at this scenaro is that the ratepayers would have a non-dispatchable
330 MW must-run plant that is operating 90% of the time. The ratepayers would realize
$50/MWh in savings for not having a dispatchable plant at their disposaL. The ratepayers could
actually pay fifty dollars a megawatt hour to an off-taer to tae and use the excess power and
stil be indifferent in terms of cost to them of either a Langley Gulch QF or a Langley Gulch rate-
based facility.
Because $50/MWh is obviously a gross overestimate of the cost of dispatchability, the
Langley Gulch IRP Methodology calculation demonstrates that the IRP Methodology generates a
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value that is far below Idaho Power's actul avoided costs. The Langley Gulch cost of
$ 126/MWh is the real life avoided cost for Idaho Power to constrct and operate a fuly
dispatchable generation facility; it is therefore the real-life value ofIdaho Power's avoided cost
for a dispatchable facility. If the IRP Methodology provided an accurate measure ofIdaho
Power's tre avoided costs, the value it generated for the non-dispatchable Langley Gulch would
be equal to the true costs for the dispatchable plant ($ 126/MWh) minus a reasonable cost for
dispatchabilty, which we can assume to be even as much as the $20/MWh in the Lancaster
agreement. Thus, the IRP methodology should generate a value of at least $1 06/MWh for a non-
dispatchable Langley Gulch. That it actually generates a value of$75.88/MWh for the "Langley
Gulch QF" proves that it vastly underestimates the avoided costs ofQF power.5
B. THE COMMISSION'S PROCEDURA SCHEDULE VIOLATES THE FILED
RATE DOCTRINE.
NIPPC commented extensively on the legal and practical shortcomings ofthe
Commission's proposal that the effective date of its eligibility cap order which will likely be
issued in Februar, 2011, will be retroactively effective on December 14,2010. The
Commission Staff and the Utilities' Initial Comments appear to support this proposed schedule.
FERC's PURPA rules prohibit discrimination against QFs in establishing avoided cost rates,
including in the processes by which the Idaho Commission establishes published rates. See 18
C.F.R. § 292.304(a)(ii), -.304(c)(3)(i). For the Idaho Commission to apply the fied rate doctrne
to Idaho utilties in other ratemaking contexts, see e.g. Order No. 30431 at pp. 6_7,6 but not in the
5 The only other logical explanation is that Langley Gulch is an excessively expensive and
imprudent investment, which should not be included in Idaho Power's rate base.
6 See NIPPC's Initial Comments, at p. 9.
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context of the availability of the published avoided cost rates, would constitute discrimination
against QFs in violation ofFERC's regulations and thus be subject to FERC enforcement action.
See 16 U.S.C. § 824-3(f), (h).
Since the filing of Initial Comments, the Utilities have confirmed NIPPC's fear that the
availability of published rates in the interim between December 14,2010 and the final order is
unown. NIPPC requested that the Utilities explai the eligibility cap for published avoided
cost rates after December 14, 2010, and whether the cap is different for different resources.
A vista responded most succinctly by stating, "the actual level of the published avoided cost rate
eligibility cap is curently an open issue to be decided by the Commission in this proceeding."
Avista's Response to NIP PC Request No. 53. In other words, Avista does not know what the
curent eligibility cap is for any given QF resource. Although Idaho Power's response
referenced to Order No. 31025, Idaho Power has begu filing for Commission orders "accepting
or rejecting" QF contracts. See, e.g., Application, Case No. IPC-E-I0-51, ii 3 (noting the
purorted effective date of December 14,2010, for the Commission's yet-to-be-issued eligibilty
cap order). Idaho Power has likewise begu instrcting developers with fully executed contracts
that they must post thousands of dollars for network transmission upgrade studies even though
according to Idaho Power "(t)he adjustment requested in this filing could affect your project's
eligibility for the published avoided cost rate."
The Commission should reverse course and reject this approach as it did in the last wid
moratorium in Case No. IPC-E-05-22. There, the Commission initially declared that its ruling
on the Utilities' request for a reduction in the eligibilty cap would be retroactively effective.
But in its final order the Commission declared that the effective date of its order would be the
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date of the final order.
The Commission acknowledged its earlier Notice Order, but the Commission stated it
was nevertheless "obliged. . . to enforce PURP A and FERC rues and regulations that require
utilty purchases of QF capacity and energy. . . . Mandatory PURP A resources offered under the
Commission approved avoided cost methodology canot be declined by Idaho Power(. J" Order
No. 29872, at p. 9. The Commission stated "we find it reasonable to grant reconsideration and to
change the date forgrandfathering eligibilty from July 1 (,2005), the date of our Notice, to
August 4,2005, the date of our interlocutory Order No. 29839." Id. at p. 11. The Commission
reasoned "that until published rate eligibility was changed by Commission Order on August 4,
2005, Idaho Power had a continuing obligation under PURPA, FERC rules and the Orders of this
Commission to offer to purchase QF power at the published rate and to engage in contract
negotiations with eligible QFs." Id.
Ths prior approach regarding the effective date is consistent not only with the legal
requirements of federal and state law, but also with Idaho's proud tradition of requiring Idaho
utilties to honor the existing published rate schedules. In a seminal Idaho PURP A case, Idaho
Power attempted to absolve itself of the obligation to negotiate and execute contracts containing
the then-curent published rates on the ground that it had requested the Commission lower the
rates. The Commission extensively admonished Idaho Power, with the following order:
Such a defiance of final ratemakng orders is unparalleled in the
experience of this Commission. We remind Idaho Power
Company that it is a regulated utility and that its announced
Company policy in this matter makes it an outlaw--in that word's
precise meaning of operating outside the law. The so-called "-200
rates" do not exist as a matter oflaw. They are simply a proposal
put forward by Idaho Power without even a proposed effective date
in a case that has not yet been heard. . . .
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11 is unheard gffi g regulated utilty to charge fi its
services at rates other than those approved!l and posted at the
Public Utilties Commission. This is true even though the
Company has fied fi new rates and believes that its old rates are
inadequate or even confiscatory. To unlaterally change rates that
are charged for sales or rates that are paid for purchases is to wage
a collateral attack on final Commission orders in the precise
maner prohibited by Idaho Code § 61-625. Thus, the fact that on
July 29, 1982, Idaho Power fied for revised avoided cost rates to
be paid cogenerators and small power producers does not provide
any justification for refusing to purchase power at rates that are
now approved and on file.
Order No. 17796, at pp. 4-5 (emphasis added).
In this case, the Utilities each have published rates on fie with an eligibility cap
developed in an intensely litigated case. The Commission should not allow the Utilities to
subvert the filed rate doctrine and prior Commission precedent by issuing a retroactively
effective eligibilty cap reduction.
C. A VISTA AN ROCKY MOUNTAIN POWER HAVE MADE NO CASE THAT
THEY AR BEING INDATED WITH LARGE LEVELS OF QF POWER.
A vista and Rocky Mountain Power have not even submitted evidence that they curently
have substantial QF power online or that they face a significant amount of QF projects which are
near execution of contracts. To the extent that Avista states QFs attempting to sell to Idaho
Power or Rocky Mountain Power could wheel the power into Avista's terrtory, the discovery
responses indicate that transmission capacity between A vista and those two utilities is curently
unavailable. See Idaho Power's Response to NIPPC Request No. 12(d); Rocky Mountain
Power's Response to NIPPC Request No. 12(e). Furher, Avista has confirmed that, although
many QFs have contacted Avista, it curently has no wind QFs online, and that it is essentially
not concerned with non-wind and non-solar QFs aggregating their projects to obtain published
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rates. Avista's Response to NIP PC Request Nos. 7 and 18. The char of Idaho PURP A contracts
and proposals attched to Rocky Mountain Power's Intial Comments demonstrates that it has
only a pittce ofPURPA projects in Idaho, with only 8.3 MW online, and only an additional 43
MW under Commission-approved contract. The speculative assertion that 500 MW of QF wind
projects are proposed - without supporting evidence of how far along those projects may be in
the development process - is hardly a basis to eliminate the availabilty of published rates. This
is especially so in light of Rocky Mountain Power's assertions in other regulatory contexts
(discussed below) requesting cost recovery for transmission upgrades to build generating
facilties in Idaho and its assertions of the need for additional wind capacity.
D. THE CURRNT, PUBLISHED, AVOIDED COST RATES ARE A FAIR
APPROXIMATION OF THE UTILITIES' AVOIDED COSTS FOR A LONG
TERM POWER PURCHASE AGREEMENT.
The Utilties' initial Joint Motion filed on November 5, 2010, requested a reduction of the
eligibilty cap during pendency of this docket solely on the grounds that Idaho Power and Rocky
Mounta Power were receiving substantial requests for wind QF contracts and to "establish
greater adminstrative control of contracts durng pendency of the Commission's and paries'
investigation of the issues." Joint Petition and Joint Motion, at p. 6. The Utilties' fiing did not
include any assertion that the published avoided cost rates were too high. Then, for the first time
in their Initial Comments filed December 21 st and 22nd, the Utilties each argued that the
published avoided cost rates are too high, and do not accurately approximate their tre avoided
costs. NIPPC disagrees. And the Utilties' responses to discovery requests demonstrate that the
curent, published avoided cost rates for long term contracts are a fair approximation of "the
incremental costs to an electric utility of electric energy or capacity or both which, but for the
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purchase from the qualifying facility or qualifyng facilities, such utility would generate itself or
purchase from another source." 16 U.S.C. § 824a-3 (d).
The staing point for estimating the real world cost of energy and capacity provided
under a long term contract - and thus the adequacy of curent rates generated in the SAR
methodology - should be the price in recently executed contracts or contract offers, and the cost
to ratepayers of the generation facilities built by the utilities. Analysis of such information
demonstrates that the curent 20-year, levelized, SAR rate of approximately $82/MWh, or
$56.85/MWh for 2010 alone, compares favorably to other contracts and prices available to the
Utilities and their ratepayers. See Order No. 31025.
First, the rates generated in the gas SAR and paid to QF developers appear to be lower
than the actual cost to ratepayers when the utilties build or contract for the output of a gas plant.
Idaho Power admits that its Langley Gulch gas plant wil have a levelized cost of approximately
$ 126/MWh. See Idaho Power's Response to NIPPC Request No. 46(a). Likewise, Avista
acknowledges that for its Lancaster gas plant, the Commission recently approved of projected
2010 fixed costs of $20.87/MWh and energy costs of $58/MWh to $72/MWh - for a total of
$78.87/MWh to $92.87/MWh for 2010, a year in which the published rate was $56.85/MWh.
Avista's Response to NIPPC Request No. 19(/. Avista's Lancaster tolling agreement allowed
for a reduction of Lancaster total price to $55.90/MWh for 2010, which even with lower than
expected gas prices is stil barely less than the applicable SAR rate for that year.7 Id.
Idaho Power's recently approved Neal Hot Springs geothermal PPA fuher demonstrates
Unlike a QF resource tang the published SAR rate for a non-fueled project, these utilty
gas resources saddle ratepayers with a serious gas price volatility risk, as discussed below.
7
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PRODUCERS COALITION
PAGE-16
the reasonableness of the curent published rates. That contract, as approved by the Commission
on May 10,2010, contains a price which begins at $96/MWh in 2012, and escalates anualy,
resulting in a 25-year levelized price of approximately $117 . 56/MWh. See Order No. 31087, at
p. 2. Although the contract provided Idaho Power with certain benefits not provided in PURP A
agreements, such as the renewable energy credits,8 the price is far higher than the published SAR
rates and demonstrates the reasonableness of the curent SAR rates in a long term contract.
To the extent that Idaho Power asserts that the SAR rate is higher than the price it could
obtain in a competitively bid wind contract, Idaho Power has provided no evidence in support of
its claim. Indeed, Idaho Power stated that the range of bids into the 2012 request for proposals
("RFP") was between $85/MWh and $150/MWh. See Idaho Power's Initial Comments, at p. 23.
Idaho Power correctly notes that the curent, levelized, published, SAR rate is $82.38/ MWh for
a project that would come on-line during 2011, but failed to note that price would decrease by
$6.50/MWh for the wind integration charge and compares favorably at $75.88/MWh to all bids
into the 2012 RFP. Id 9 It is impossible to understad how ratepayers are hared by wind
developers agreeing to build their projects at the lower PURPA rates instead of the higher rates
8
The other benefits cited by the Commission included: "(1) the Company's rights to any of
the project's renewable energy credits, (2) the limited abilty to curl energy, (3) the right of
first offer on ownership of other site development, (4) exploration, development and constrction
milestone requirements and associated damages, and (5) the right to extend the terms of the
contract." Id. NIPPC does not intend to suggest that the Neal Hot Springs contract was
uneasonable, but only provides its price for comparison puroses.
9 In Idaho Power's Response to NIPPC's Request No. 42, Idaho Power compares the 2012
RFP bids to the 2009 avoided cost rates for wind at $89.06/MWh. But that comparson is
improper and useless for puroses of this docket because the wind contracts curently submitted
for Commission approval all contain the lower rate of $75. 88/MWh, and therefore all compare
favorably with the costs bid into Idaho Pòwer's most recent wind RFP. See Case Nos. IPC-E-I0-
47 to -62.
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PRODUCERS COALITION
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bid into the RFP.
Idaho Power's Initial Comments also improperly evaluated the reasonableness ofthe
curent SAR rates available for a long term contract by comparng them to a curent Mid-
Columbia price cure. See Idaho Power's Initial Comments, at p. 18. By doing so, Idaho Power
compares apples to oranges because Idaho Power admits that "it is unlikely that Idaho Power
could enter into a 20-year contract today for energy and capacity at the rates in the graph on page
18 ofIdaho Power's Comments for Mid-C prices." Idaho Power's Response to NIPPC Request
No. 45(b). This is because, as Idaho Power adts, Mid-C prices over the next 20 years could be
higher or lower than those shown in Idaho Power's char, See id. at No. 45(e), and it would be
very risky to enter into an obligation to sell power for 20 years at the curently very low Mid-C
prices. Furher, in the Langley Gulch proceeding, Commission Staff stated, "Relying on the
market as an alternative to building new generation. . . cares greater risk and the potential for
price volatility. Staff notes, as does the Company, tht there are transmission constraints on
imports from the Northwest that make locating new generation near its load center a prudent
planng decision." Order No. 30892, at p. 14. It is interesting to note that, had Idaho Power
compared the prices for its non-PURP A projects and PPAs discussed above to the low market
price cure in its comments in this case, those projects would also appear to be quite
uneconomical.10 To now compare the PURP A rates to a market price cure borders on frivolous.
10 Indeed, Idaho Power's use of the curently low Mid-Columbia price cure as a
comparison to a long term PURP A PP A rate is paricularly disingenuous because in the context
of analyzing wind integration costs - which decrease as market prices decrease - Idaho Power
insisted on including as a component of its analysis of historic energy prices the extraordinarily
high average market price of $ 132/MWh from 2000. See Enernex's Idaho Power 2007 Wind
Study, Case No. IPC-E-07-03, pp. 5, 50, 85 (Febru 6, 2007). By doing so, Idaho Power very
clearly overestimated the costs of wind integration in its study. A fair comparison of the curent
REPLY COMMENTS IN OPPOSITION OF THE NORTHEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-18
Even the recently abandoned wind SAR docket fuher demonstrates that the gas SAR
rates are not too high. Commission Staffs Wind SAR Strawman assumed that but for the QF
purchase the utility would build its own wind far, and it therefore analyzed the avoided costs as
the cost to a utilty to build its own wind far. Staff stated that a 20-year levelized wind rate
with a 2010 online date would be as follows for each utility for both a wind and a gas SAR:
Utilty Wind SAR Gas SAR
Avista $86.31/MWh $79. 17/MWh
Idaho Power $ 84.72/MWh $79. 19/MWh
PacifiCorp $85.06/MWh $79.31/MWh
See Commission Staff's Wind SAR Strawman, Case No. GNR-E-09-03, at p. 12 (May 27,2010).
Even with a reduction in the wind SAR rates for the value the utilty would obta from federal
tax credits, this wind SAR generated a rate that was higher than the curent gas SAR prices. Ths
wind SAR demonstrates that the gas SAR rate is not too high. This is especially so because, for
a non-wind QF such as a co-generation plant which imposes no wind integration costs on the
utilty, the wind SAR rate would need to be increased by $6.50/MWh to over $90/MWh to
account for the wind integration cost avoided by the utilty purchase from the non-wind QF.11
Finally, the utilities all rely on the "dispatchability" of their own resources as a basis for
PURPA rates to market prices over the 20-year lives of the contracts would also utilze historic
prices and perhaps include that high 2000 price to demonstrate that Idaho Power may well be
sellng excess PURP A wind power on the open market at a substatial profit, or be utilzing it
during a similar market price spike as it surely did in 2000 with QFs then online.
11 Although the parties to the wind SAR docket debated ownership of the RECs in a Wind
SAR rate, Staff itself assumed that "it could be implied from these rates, that the approximate 20-
year levelized value ofRECs is between $5.50 and $7.10." Id. at p. 13. With that assumption,
the wind SAR Strawman demonstrates that the curent gas SAR rates are at least as accurate as
the cost of a utilty to build and operate its own wind project for delivery in Idaho.
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-19
their assertion that the published rates are too high because QF power canot be dispatched.
This arguent, however, ignores that the curent PURPA contracts do not compensate QFs for
any right to dispatch or curl their facilities. The Utilities admit that under an Idaho PURPA
PPA they "would not compensate a QF when the QF is not delivering energy." See, e.g.,
Avista's Response to NIPPC Request No. 19(b). In contrast, "Avista makes a payment under the
Lancaster Power Purchase Agreement (tollng arangement) when no energy is delivered. Ths
payment provides A vista with the right to call on this capacity when it wants it." Id. at No.
19(d). That fixed cost is approximately $20/MWh. Id. at No. 19(f. Additionally, Idaho Power
justifies the difference of $44/MWh between the cost of Langley Gulch to ratepayers and the
published avoided cost rate ($ 126/MWh - $82/MWh = $44/MWh) on the ground that the plant is
available whenever the utility needs to use it. See Idaho Power's Response to NIPPC Request
No. 46(b). No QF receives a flat rate payment of $20/MWh to $44/MWh at times when no
energy is delivered, and the Utilities complaint about QFs' lack of dispatchabilty is therefore
misplaced.
Further, there is no question that certn QF technologies can provide capacity on call to
the utility. See Comments in Opposition ofDynamis Energy, at p. 2 (December 22,2010). There
is no incentive to do so, however, because the Utilities have not provided for a QF capacity
payment available at times when no energy is delivered. If the Utilities wish to contract for the
right to dispatch QF facilities, they should offer to provide QFs a fixed capacity payment option
similar to those provided by ratepayers for Langley Gulch and the Lancaster Plant. But the
Commission should not accept ths "dispatchabilty" arguent as a ground to eviscerate the
availability of published rates for virtally all QF projects.
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PRODUCERS COALITION
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E. THE UTILITIES' INITIAL COMMENTS MISREPRESENT THE DATA
REGARDING THE PROPOSED WIND QF PROJECTS AND IGNORE THE
BENEFITS OF THOSE PROJECTS TO RATEPA VERS.
To justify the request for an immediate reduction in the eligibilty cap, the Utilties each
ignore the benefits of the wind QF projects to reach a conclusion that the inundation of wind
projects will overload their systems in light load hours and impose upward pressure on rates. See
Idaho Power's Initial Comments, at p. 19 (speculating through a series of highy questionable
assumptions that market prices wil be $301MWh lower than QF contract rates, and that therefore
614 MW of wind contracts submitted for approval "equates to a rate increase of around 5 percent
in the Company's PCA"). Ths arguent, of course, ignores that all new resources will increase
rates when compared to the curently low market prices, or to Idaho Power's existing generation
resources. See Order No. 30892, at p. 31 (wherein Idaho Power acknowledged for Langley
Gulch if you 'just simply lay that rate base and depreciation and such onto our
curent rates, you get a number close to . . . six or seven percent" of rate increase, but asserted
"you can't just view the rate impact in isolation."). More importantly, the Utilities' arguent
overlooks the benefits of these new renewable energy projects to their resource portfolios.
1. The QF wind wil enable to Utilities to reduce their exposure to future coal
regulation.
Idaho Power and Rocky Mountain Power both assert that "excess wind events" during
light load months or hours will require them to back down their "low cost" coal resources to their
minimum generation levels. According to them, "the avoided cost pricing that the QF receives
should be adjusted down to reflect the Company's obligation to accept the QF's higher cost
power and back down the Company's lower cost resources such as Q coal plant." Rocky
Mountain Power's Initial Comments, at p. 7 (emphasis added); see also Idaho Power's Initial
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-21
Comments, at pp. 16-17. Ths argument is absurd because coal is unlikely to be a low cost
resource even a few short years from now, and the Utilities would be prudent to pursue
renewable fuel resources to limit exposure to futue coal reguations.
Rocky Mounta Power admits, "It is possible that PacifiCorplR's coal plants could
experience increased costs as a result of ongoing (Environmental Protection Agency ("EPA"))
rulemakng proceedings. . . . PacifiCorplRP will seek recovery of such costs from its
customers." Rocky Mountain Power's Response to NIPPC Request No. 48; see also Idaho
Power's Response to NIPPC Request No. 48. Indeed, Rocky Mountain Power's parent
company, MidAerican Energy Holdings Company, stated in the ongoing EPA rule-making
regarding coal combustion residuals ("CCRs"), that the proposed regulation of CCRs alone
would "cost each facility tens of milions of dollars." See Comments of Mid American Energy
Holdings Company on Hazardous and Solid Waste Management System; Identifcation and
Listing of Special Wastes; Disposal of Coal Combustion Residualsfrom Electric Utilties;
Proposed Rule (hereinafter "MidAmerican Comments"), U.S. EPA Docket ID No. EPA-HQ-
RCRA-2009-0640, at p. 12 (November 19,2010); see also See 75 Fed. Reg. 35,128 (June 21,
2010) (setting forth the proposed CCR regulations).
And CCRs are but one of many future regulatory hurdles that wil substatially increase
the price of each incremental unit of electrcity generated by a coal plant. "PacifiCorp operates
eleven CCR surace impoundments. . . . (and the proposed CCR reguations impose) a
significant undertng paricularly considering all of the other regulatory requirements that
electric generating facilties may be required to comply with in the next few years including the
Clean Air Transport Rule, regional haze BART determinations and reasonable progress goals,
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-22
the utilty hazardous air pollutat maximum achievable control technology rulemaking, climate
change-related regulatory requirements, and a potential Clean Water Act section 316(b) final
rulemaking." MidAmerican Comments, at p. 12. EPA is therefore processing six separate
regulatory changes that will increase the cost of coal-fired electrcity.
Yet the Utilties provided only very limited analysis of the increased costs to their
ratepayers toNIPPC in discovery. See Rocky Mountain Power's Response to NIPPC Request
No. 48 (setting fort a very high confidential cost estimate for pollution upgrades for one
hazardous pollutat - mercur - at only three of its several coal plants, and similarly high
estimates for the CCR rule); see also Idaho Power's Response to NIP PC Request No. 48
(providing no cost estimates, but stating, "Idaho Power would expect to be able to include any
additional capital costs associated with future regulations in its rate base, and recover any
additional operating expenses incured").
Indeed, since this PURP A docket commenced, EPA anounced its plans to proceed
forward with perhaps the most economically signficant regulation that will affect existing coal
plants. On December 23,2010, EPA anounced that it would commit to issuing proposed
regulations of greenhouse gas emissions from existing power plants by July 26, 2011, and fial
regulations by May 26, 2012.12 There is no doubt that greenhouse gas reguation will increase
coal prices and require curilment for Idao Power and Rocky Mountain Power.
12 This ruemakng is a result of the Supreme Cour's ruing in Massachusetts v. EPA, 549
U.S. 497 (2007), where the Cour rued that EPA has authority to regulate greenhouse gas
emissions under the Clear Air Act. EPA agreed to commence this rulemakng in settlement of a
Clean Air Act lawsuit brought against EPA by thirteen States and Cities, as well as individual
advocacy groups. It therefore appears unikely that EPA can abandon its rulemaking schedule.
Information is available online at http://ww.epa.gov/airquality/ghgsettlement.html.
REPLY COMMENTS IN OPPOSITION OF THE NORTHWST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
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Rocky Mountain Power provided a link to a study conducted by the Oregon Public Utilty
Commission into the cost of reducing greenhouse gas emissions 10% below 1990 levels by 2020,
or 15 % below 2005 levels by 2020, and there is no reason to expect any less of a regulatory
burden from the EPA rulemakng. See Public Utilty Commission of Oregon, Electric and
Natural Gas Company Rate Impacts to Meet 2020 Greenhouse Gas Emission Reduction Goals,
(November 1,2010), available online at htt://ww.oregon.govIPUC/2020 Greenhouse
Gas Emission Reduction Goals.shtml. The report indicates that PacifiCorp would have to
reduce its greenhouse gas emissions in 2020 by 54%, and Idaho Power by 16%, from levels in
their respective IRPs. Id. at p. i. PacifiCorp would meet the more strngent taget by "reduc(ing)
generation from its coal fired plants" and adding "a signficant amount of wind power . . . ,
totaling 1,340 MW by 2020." Id. at pp. i, 7.13 Idao Power too would meet the goal "by
curailing coal fired generation priarly in the spring and fall months when the company
typically has surlus generation capacity." Id. at p. 8.14 Coal curailment and replacement oflost
generation could be necessary as soon as the EPA's rule goes into effect in May 2012.
With EPA's six ruemakngs, ratepayers will pay more for coal generated power and need
13 It is worth noting in ths context that PacifiCorp recently obtained incentive transmission
rate treatment from FERC for its Populus to Termnal line, in par on its asserted basis that
southwestern Idaho would be a "hub," from which "power will be collected and moved in
different directions." See 125 FERC' 61,076, Docket No. EL08-75-000, , 3 (October 21,
2008). PacifiCorp sought recovery also from its retail ratepayers in its 2010 Idaho general rate
case on the ground that the project will facilitate the integration of potential new energy
resources in Wyoming, Utah, Idaho and Oregon, and help support economic development in
those states. See Direct Testimony of Darell Gerrard, Case No. PAC-E-I0-07, pp. 4, 8 (May
2010). This appears inconsistent with Rocky Mountain Power's aversion to Idaho PURA
projects.
This plan to curil in times of surlus energy assumes that the greenhouse regulation wil
look only at output on an anual basis, which is far from certn with the EPA's ruemaking.
14
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-24
to replace energy not generated due to the necessar curilments. Yet Rocky Mountain Power
asserted in its Initial Comments in ths docket -almost at the same time that it argued the
opposite elsewhere regarding these future coal expenses - that the proposed wind projects are too
costly in par because they will force it to scale back operation of its "low cost" coal unts.
Baning on coal units owned by the utilty as a money saving proposition for ratepayers over
wind projects under contract with independent developers is simply not reasonable. Indeed,
because QF's will enable the Utilities to avoid the cost of future fossil fuel regulatory
compliance associated with that incremental unt of generation provided by the QF, the avoided
cost rate could be increased by an approximation of that avoided cost once the regulations are in
place. See California Public Utilties Commission, 133 FERC ir 61,059, at ir 31 (Oct. 21, 2010)
(order denying rehearing) (stating QFs may receive a higher avoided cost rate for providing
energy and capacity that enables a utilty to avoid environmental compliance costs, "if the
environmental costs 'are real costs that would be incured by utilties"'). Based on the Utilties'
own statements cited herein, these future coal costs are real costs and the wind QF projects will
allow the Utilities to avoid those costs.
2. The QF contracts wil reduce the Utilities' exposure to future fuel price
variabilty.
A tyical QF contract contains a fixed rate for a 20-year term. "Idaho QF contracts do
not allow for the QF to increase avoided cost prices in their contract in the event that QF
projects' costs increase." Rocky Mountain Power's Response to NIPPC Request No. 49. There
is therefore no opportunity for the QF taking non-fueled rates to increase the price ratepayers pay
it if its fuel price increases over time. See Avista's Response to NIPPC Request No. 47(a); see
also Idaho Power's Response to NIP PC Request No. 47 (a) (not directly answering the question,
REPLY COMMENTS IN OPPOSITION OF mE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-25
but nevertheless stating, ''there is the risk that a QF wind project will not produce its expected or
forecast amount of generation. . . . potentially resulting in additional market purchases or
increased generation from other utility owned resources, which would subject the utility and its
customers to market or fuel risk."). Additionally, for a QF using no fuel- such as a wind QF - a
drastic increase in fuel prices is unikely to have any impact on the QF's abilty to perform
because the QF has no operating fuel cost. A renewable QF project therefore provides the utilty
with a strong hedge against futue increases in fuel costs.
In contrast, the cost to ratepayers of a typical utility built or contracted fossil fuel plant
increases when the price of the fuel increases. For example, "fuel and transportation costs
associated with operating the (Lancaster) plant are subject to market conditions and they will
change from time to time." Avista's Response to NIPPC Request No. i9(f. Whle those
Lancaster costs were lower than expected in 2010, they could just as easily be far higher than
expected in future years. And natural gas is not the only fuel subject to increases. The price to
supply Idaho Power's and PacifiCorp's jointly owned Bridger coal plant increased significantly
in 2010, and that cost increase was passed on directly to ratepayers. See Order No. 31093, at pp.
13-14 (noting that the increased cost was $63.7 milion in 2010 to Idaho Power customers alone).
3. QFs pay disproportionately for interconnection and network transmission
upgrades when compared to utilty built resources, which provides
ratepayers with system benefits while relieving them of associated costs.
Idaho Power improperly alluded to possible additional transmission costs related to QF
projects without noting that ratepayers are relieved of substantial interconnection and
transmission costs for a QF resource as compared to a utility-owned resource. See idaho
Power's Initial Comments, atp. 19.
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
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In discovery responses, however, Idaho Power acknowledged that "PURP A QF projects
are solely responsible for the interconnection costs required to interconnect their proposed
projects to Idaho Power's system." Idaho Power's Response to NIPPC Request No. 41 (a), It
also admitted, "PURPA QF projects are almost always responsible for the network upgrades, or
transmission upgrades, required to bring their energy from the point of interconnection with
Idaho Power's system to load." Id at No. 41 (b). In some cases, Idaho Power and the ratepayers
have shared in the cost of network upgrades, but even then Idaho Power and its ratepayers
contributed only 25% of the cost of the needed transmission upgrades. See id. (discussing Order
No. 32136). Under the approved methodology, the QF would "make a non-refudable 25
percent contribution in aid-of-constrction ("CIAC") to support the transmission upgrades," and
"an advance in aid-of constrction ("AIAC") for the remaining balance of the cost of the
upgrades. The AIAC will be refuded to (the QF) over time if it fully performs (on) its Firm
Energy Sales Agreement with Idaho Power." Id Thus, the QF pays 25% of the tota cost
regardless of its performance, and it obtains a refund of an additional 50% paid up front only if it
performs.
In contrast, all prudently incured interconnection and transmission costs associated with
a utilty-owned project wil be "included in customer rates." Id at No. 41 (d). Similarly, when
the federal jurisdiction applies and the Idaho Commission does not determine cost sharng, all
independent developers receive a refud for the entire cost of network transmission upgrades
required for their projects under FERC interconnection rues. "The Interconnection Customer
initially fuds the cost of any required Network Upgrades (i.e., Upgrades to the Transmission
System at or beyond the Point of Interconnection) and it is then subsequently reimbursed for this
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-27
upfront payment by the Transmission Provider." Standardization of Small Generator
Interconnection Agreements and Procedures, FERC Order No. 2006, at ~ 40, Docket No. RM02-
12 (May 12,2005) (addressing Small Generator Interconnection Agreements and cross
referencing same rule in Order No. 2003 regarding Large Generator Interconnection
Agreements).15 Thus, under curent Idaho Commission precedent, Idaho ratepayers have
received a great deal from the Idaho QFs who are helping fud necessar network transmission
upgrades.
F. THE COMMISSION SHOULD NOT DEPRI RATEPAYERS OF THE
BENEFITS QF PROJECTS MAE POSSIBLE BY REGIONAL AND
NATIONAL POLICIES DESIGNED TO PROMOTE THOSE RESOURCES, OR
RELY UPON THE UTILTIES TO TAK ADVANTAGE OF THOSE
OPPORTUNITIES THEMSELVES.
According to Idaho Power, the "curent avoided cost rates, combined with tax credits and
other incentives, have created a situation where independent developers can easily justify the
economics of (and finance) PURA projects." Idaho Power's Initial Comments, at p. 13. "The
result is that the Company's extensive IRP process, which is mandated and overseen by the
Commission, is being circumvented by the curent Idaho requirements of PURP A." Id But
Idaho Power points to no long term resources planed in the IRP process that cary as low a cost
to ratepayers as the curent avoided cost rates. That PURPA wind QFs are now able to build
cost-effective projects in Idaho is a result of the many years of sweat equity invested by
independent developers in wind studies, securng wind leases, and other time-consuming and
15 FERC has argued in cour successfuly in defense of sharng of transmission costs "that
its policy has been that all transmission customers must share the costs of network upgrades
because the integrated transmission grid is a cohesive network, and the upgrades benefit all
users, not just the newly interconnecting generator." Energy Servs., Inc. v. FERC, 319 F.3d 536,
539,544 (D.C. Cir. 2003) (emphasis in original).
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
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costly development efforts. It is a risky and often unewarded enterprise, and one that is entitled
to PURPA's mandatory purchase requirement at the utilty's avoided cost, regardless of the costs
to the developer.
PURPA's mandatory purchase provisions require utilties to purchase QF output at "the
cost to the electric utilty of the electric energy, which, but for the purchase from such
cogenerator or small power producer, such utility would generate or purchase from another
source." See California Public Utilties Commission, 133 FERC ~ 61,059, at ~ 29 (quoting 16
U.S.C. § 824a-3(d)). The focus is on calculating the cost to the utility of energy alternatives to
the QF energy. The curent gas SAR methodology does just that. But the Utilties' fiings to
date improperly focus on the cost to the QF to build their resource. See Idaho Power's Initial
Comment, at p. 10 (stating that the QFs are gaining "double recovery windfall" though RECs
and ta credits).
If the utilties want to take advantage of the available tax credits and REC markets, they
should endeavor to build their own renewable projects. But perhaps it is not appropriate for an
investor-owned utility to be engaged in the risky business of developing a wind project. Avista
received preferential construction work in progress ("CWIP") ratemaking treatment for its
Reardon wind project in 2008, at which time it informed the Commission constrction would
begin in 2011. See Order No. 30611, at p. 2 (stating "Avista believe(d) it (wa)s cost effective
and prudent to secure land rights and equipment now, even though actual constrction will not
begin until 2011 "). The Commission approved of CWIP for Reardon, which allows A vista,
unlike a QF wind developer, to accrue a caring charge at its authorized rate of retu before the
project is online, and indeed before constrction has even begu. Id. To date, Avista has
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-29
invested $3.7 milion in its Reardon wind project. See Avista 's Response to NIP PC Request No.
21 (b) '.
But the Reardon project "is not under constrction and will not be online in 2012," so
Avista will need to revaluate its options as a renewable resource requirement in Washington's
RPS statute approaches in 2016. Id at No. 21 (a). If Reardon is ever constructed, "it would
likely be in the 2014-2016 timeframe." Id. at No. 21 (d). Avista purort to not possess $/MWh
cost estimates of Reardon. Id So one must presume - and A vista will surely have to prove at
some point - that the all-in costs for Reardon with CWIP are cost-effective against the $76/MWh
rate it would pay to the wind QFs knocking on its door in this case. Avista also appears to assert
that its ratepayers will not suffer any economic damage from the constrction delay, but on this
point, Avista's treatment of its own resource is inconsistent with its requirement that QFs post
$45/klowatt of nameplate capacity as delay default liquidated daages securty to A vista.
Compare id at No. 21 (b) (stating that the delay in the online date projected in the IRP for
Reardon is immaterial because the IRP process "does not commit the Company to build any
project. Damages are inapplicable."), with id at No. 54(a) (stating, "Avista could suffer
substantial costs if a PUR A resource that it has a contract with does not achieve commercial
operation within the time provided in the contract. .... for example, anytime a PURP A contract
is executed, Avista reflects the contract in its Loads and Resources tabulations and IRP work.").
A vista's preferential and off-handed treatment of the delay event in its own wind project's on
line date vis a vis how it treats delay for PURP A projects is a blatat example of that utility's
discriminatory treatment of QFs.
In any event, Avista's apparent strggle with Reardon, even with preferential CWIP
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-30
financial benefits, demonstrates that developing a wind far is not easy, and the Commssion
should not impose additional hurdles for the QF developers whose projects are at risk in this
docket. A QF developer will obviously need to find a way to build and operate its project at a
cost that is lower than the avoided cost rate it will be paid for the output. Otherwse, the QF
would go out of business. That QFs are able to tae advantage of federal ta credits, Idaho sales
tax exemptions, and neighboring states' RPS stadards to build and operate projects profitably is
simply not a justification to lower the avoided cost rates through the IRP methodology or
otherwse.
The Utilties have demonstrated no reason to deprive ratepayers of the benefits of long-
term contracts for renewable resources which car no fuel cost or regulatory risk to ratepayers.
QFs' abilty to provide energy and capacity at the Utilities' avoided costs and stil tu a profit
only demonstrates that recent federal and state policies to promote renewable energy are
working. It would be ilegal and improper for this Commission to undo the effect of those
policies and undermine the investment-backed expectation of QF developers by granting the
Utilties' request to retroactively eviscerate the published rate schedule and require all QFs to
proceed under the IRP methodology effective December 14,2010.
CONCLUSION
The assault on Idaho's PURP A implementation in ths docket is paricularly troubling in
light ofIdaho Power's admission in Response to NIPPC' Request No. 43, that Idaho Power,
though an affiliate named IdaWest Energy, owns a 49% interest in four PURPA projects
totaing over 33 MW of capacity curently sellng their output to Idaho Power. Thus, Idaho's
proud PURP A tradition under assault by the utilities in this docket even includes utilty-owned
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-31
PURP A projects.
For all of the reasons set forth above, NIPPC respectfully requests that the Commission
deny the request to reduce the published avoided cost rate eligibilty cap, and alternatively
requests that the Commission hold an evidentiar hearng prior to issuing any order reducing the
cap. NIPPC fuher requests that the Commission make any reduction in the cap effective on the
date of the Commission's order reducing the cap, not on the retroactive and arbitrarily-
determined date of December 14,2010.
In closing, it may be helpfu to remind the Commission of its goals when it was in the
early days of implementing PURP A. Such goals are as valid today as they were in 1982. The
Commission stated, in Order No. 17796, pp. 17-18:
Given ths background, the Company has the abilty to
serve as a catalyst for economic growth in the state. Rather than
building costly plants out-of-state, it could haress the power of
Idaho streams, canals and irrigation ditches in cooperation with
farers, ranchers, canal companes and irrigation districts. It could
enter a parership with the state's depressed forest products
industry and its food processing industr to put waste heat from
those industres to work. It could pump life into local municipal
and county governents by aiding constrction of muncipal waste
incineration facilities that produce electricity and by increasing the
employment and tax base from diversified cogeneration and small
power projects located throughout the state. The state cries out for
such vision and for the leadership to car it out. Instead, the
management of Idaho Power is mired down in an expensive war of
attrition against co-generators and small power producers tring to
tur back the clock to a time when the Company had absolute
control over the production of electricity in its service terrtory.
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-32
Respectfuly submitted this 19th day of Januar, 2011.
RICHARSON AND O'LEARY, PLLC
€¿¡~ ~
Peter J. Richardson (ISB No: 3195)
~
Attorneys for the Northwest and
Intermountain Power Producers Coalition
REPLY COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION
PAGE-33
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 12th day of Janua, 2011, a true and correct copy of the
within and foregoing NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS
COALITION'S REPLY COMMENTS was served as shown to the following paries:
Jean Jewell
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702
jean. jewellripuc.idaho. gov
1L Hand Delivery
_U.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
Donald L. Howell II
Kristine Sasser
Idaho Public Utilties Commission
472 W. Washington
Boise, ID 83702
don.howellripuc.idaho. gov
kris.sasser~uc.idaho. gov
L Hand Delivery
_U.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
Donovan E. Walker
Lisa D. Nordstrom
Idaho Power Company
PO Box 70
Boise, ID 83707-0070
dwalkerriidahopower .com
lnordstromriidahopower .com
_ Hand Delivery
XU.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
Michael G. Andrea
A vista Corporation
1411 E. Mission Street
Spokane, W A 99202
michael.andreariavistacom.com
_ Hand Delivery
iU.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
Danel Solander
Pacificorp/dba Rocky Mountain Power
201 S. Main St., Suite 2300
Salt Lake City, UT 84111
daniel.solanderripacificorp.com
_ Hand Delivery
LU.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
Ronald L. Wiliams
Wiliams Bradbur PC
1015 W. Hays Street
Boise, ID 83702
ronriwilliamsbradbury.com
_ Hand Delivery
x.U.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
Scott Montgomery
President, Cedar Creek Wind, LLC
668 Rockwood Dr.
North Salt Lake, UT 84054
scottriwesternenergy. us
_ Hand Delivery
X-U.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
DanaZenta
Sumit Power Group, Inc.
2006 E. Westminster
Spokane, W A 99223
dzentzrisummitpower .com
Thomas H. Nelson
PO Box 1211
Welches, OR 97067
nelsonrithnelson.com
JohnR. Lowe
Renewable Energy Coalition
12050 SW Tremont St
Portland, OR 97225
jravensanarcosriyahoo .com
Don Stuevant
J.R. Simplot Company
PO Box 27
Boise,ID 83707-0027
don. sturtevantrisimplot. com
Robert A. Paul
Grand View Solar II
15690 Vista Circle
Desert Hot Springs, CA 92241
robertapauI08(lgmail.com
James Carkulis
Exergy Development Group of Idaho, LLC
802 W. Banock, Ste 1200
Boise, ID 83702
jcarkulisriexergydevelopment.com
R. Greg F emey
Mimura Law Offices, PLLC
2176 E. Franlin Rd., Ste 120
Meridian, ID 83642
gregrimimuralaw.com
Bil Piske
Interconnect Solar Development, LLC
1303 E. Carer
Boise, ID 83706
bilpiske(ßcableone.net
_ Hand Delivery
iU.S. Mail, postage pre-paid
Facsimile
.x Electronic Mail
_ Hand Delivery
iU.S. Mail, postage pre-paid
Facsimile
X- Electronic Mail
_ Hand Delivery
XU.S. Mail, postage pre-paid
Facsimile
.x Electronic Mail
_ Hand Delivery
XU.S. Mail, postage pre-paid
Facsimile
.x Electronic Mail
_ Hand Delivery
XU.S. Mail, postage pre-paid
Facsimile
.x Electronic Mail
_ Hand Delivery
LU.S. Mail, postage pre-paid
Facsimile
.x Electronic Mail
_ Hand Delivery
LU.S. Mail, postage pre-paid
Facsimile
.x Electronic Mail
_ Hand Delivery
LU.S. Mail, postage pre-paid
Facsimile
.x Electronic Mail
Dean J Milere
McDevitt & Miler, LLP
PO Box 2564
Boise, ID 83701
joerimcdevitt -miler .com
_ Hand Delivery
LU.S. Mail, postage pre-paid
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lL Electronic Mail
Paul Marin
Intermountain Wind, LLC
PO Box 353
Boulder, CO 80306
paulmarinriintermountainwind.com
_ Hand Delivery
LU.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
Ronald L. Wiliams
Wiliams Bradbur, PC
1015 W. Hays Street
Boise, ID 83702
ronriwillamsbradbury.com
_ Hand Delivery
lLU.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
Wade Thomas
Dynamis Energy, LLC
776 W. Riverside Dr., Ste. 15
Eagle, ID 83616
wtomasridynamisenergy.com
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LU.S. Mail, postage pre-paid
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lL Electronic Mail
Shelley M. Davis
Barker Rosholt & Simpson, LLC
PO Box 2139
Boise, ID 83701
smdriidahowaters.com
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Brian Olmstead
Twin Falls Canal Company
POBox 326
Twin Falls, ID 83303
olmsteadritfcanal.com
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lL Electronic Mail
Ted Diehl
Nort Side Canal Company
921 N. Lincoln St.
Jerome, ID 83338
nscanalricableone.net
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lL Electronic Mail
Bil Brown
Board of Commissioners of Adams County, ID
PO Box 48
Council, ID 83612
bdbrownrifrontiernet.net
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lL Electronic Mail
Glen Ikemoto
Margaret Rueger
Idaho Windfars, LLC
672 Blair Avenue
Piedmont, CA 94611
glennirienvisionwind.com
margaretrienvisionwind.com
Ted Sorenson, P.E.
Birch Power Company
5203 South 11 th East
Idaho Falls, ID 83404
ted(ftsorenson.net
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LU.S. Mail, postage pre-paid
Facsimile
lL Electronic Mail
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Signed .~l\\WA~\
Nina M. Curis