20110228Petition for Reconsideration.pdf

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ATTORNEYS AT LAW ?nl! Fe-l' ")0 p'" l "'9L.'Ll:l ' L0 '- t.J" !"'i1f= j ".
Peter Richardson
Tel: [phone] Fax: [phone]
pere rll ri chard.on andol eary. com
P.O. Box 7218 Boise, in 83707 - 515 N. 27th St. Boise. ID 83702
February 28, 2011
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 West Washington
Boise 10 83702 ~¡.te
RE: Case NoJP-E-10-04
Dear Ms. Jewell:
We are enclosing an Original and seven (7) copies of the PETITION FOR
RECONSIDERATION OF THE NORTHWEST AND INDEPENDENT POWER
PRODUCERS COALITION for filing in the above case.
An additional copy is enclosed for stamping and return to our offce.
Sincerely,
~)'.WAçN
Nina M. Curtis
Administrative Assistant for Peter Richardson and Greg Adams
enc!.
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]
petercgrichardsonandoleary.com
gregcgrichardsonandoleary .com
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Attorneys for Northwest 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-IO-04
CORPORATION, AND PACIFICORP DBA )
ROCKY MOUNTAIN POWER TO ADDRESS ~ PETITION FOR RECONSIDERATION
AVOIDED COST ISSUES AND TO ADJUST ) OF THE NORTHWEST AND
THE PUBLISHED AVOIDED COST RATE ) INTERMOUNTAIN POWER
ELIGIBILITY CAP ) PRODUCERS COALITION
)
)
)
)
COMES NOW, the Northwest and Intermountain Power Producers Coalition ("NIPPC")
and pursuant to Idaho Administrative Rules ("IDAPA") 31.01.01.331, hereby respectfully
requests that the Idaho Public Utilities Commission (the "Commission") reconsider Order No.
32176. Without waiving any arguments raised in its prior filings in this docket, NIPPC
respectfully requests that the Commission (l) take official notice of the documents and records
cited by NIPPC; (2) hold an evidentiar hearing on the issues addressed in Order No. 32176; (3)
PETITION FOR RECONSIDERATION OF THE NORTHWEST AND
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order the investor-owned utilities in Idaho to immediately implement changes to the Integrated
Resource Plan Methodology ("IRP Methodology") for calculating avoided cost rates such that it
compensates qualifying facilities for the utilties' full avoided costs; and (4) re-instate the 10
average mega-watt ("aMW") published avoided cost rate eligibility cap for wind and solar
projects.
INTRODUCTION!
On Friday, November 5, 2010, Idaho Power Company ("Idaho Power"), Avista
Corporation ("Avista") and PacifiCorp, DBA Rocky Mountain Power ("Rocky Mountain" or
collectively "the Utilities") lodged a Joint Motion ("Motion") and Joint Petition ("Petition" or
collectively the "Pleading") with the Commission. In their Petition, the Utilties asked the
Commission to initiate a docket to investigate various avoided cost and other related issues
regarding implementation of the mandatory purchase provisions of the Public Utility Regulatory
Policies Act of 1978 ("PURP A"). In their Motion, the Utilities asked the Commission to
immediately adjust the published avoided cost eligibility cap for qualifying facilities ("QFs")
from 1 0 average monthly megawatts ("MW") to 1 00 kilowatts ("kw") of nameplate capacity, on
less than 14 days notice if possible.
In response, in Order No. 32131, the Commission refused to act on the Utilities' Joint
Motion to immediately reduce the eligibilty cap. In refusing to immediately act on that request,
the Commission stated:
NIPPC incorporates by reference all of its prior filings in this docket, and hereby requests
reconsideration of each arguent raised by NIP PC in its opposition to the reduction in the
published avoided cost rate eligibility cap.
PETITION FOR RECONSIDERATION OF THE NORTHWEST AND
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The Petitioners also request that while the investigation is pending,
the Commission lower the published avoided cost rate eligibilty
cap immediately "on fewer than foureen days notice, if possible."
Petition at 7. The Petitioners note that a reduction in the eligibilty
cap on an interim basis was previously authorized in Case No.
IPC-E-05-22. However, there is a significant difference between
the Joint Petition in this case and Idaho Power's request to
temporarily lower the eligibility cap in the 05-22 case. In the 05-
22 case, Idaho Power's petition was accompanied by supporting
testimony. The Commission subsequently conducted an
evidentiary hearing and oral argument to develop the record.
Order No. 32131, at p. 5 (emphasis added).
But the Commission's procedural order in this case required only "comments in support or
opposition" followed by an oral arguent on January 27, 2011. Id. at p. 6. In addition to
receiving comments on the requested reduction in the eligibilty cap, the Commission asked that
the paries comment on whether such a reduction should apply to non-wind QFs and the
"consequences of dividing larger wind projects into 10 aMW projects to utilize the published
rate." Id. at p. 5. After close of the QF eligibility cap phase of this docket, the Commission
stated it will move to a new phase of the case in order to explore the other PURP A issues raised
in the Joint Petition.
The Commission accepted two rounds of comments and held oral argument. Rocky
Mountain Power filed testimony of its proffered witness, Bruce Grswold, but withdrew the
testimony in response to NIPPC's objection to accepting testimony from only one pary and
providing no opportunity for cross examination. Tr., at p. 11; NIPPC's Motion to Strike the
Direct Testimony of Bruce Griswold or in the Alternative to Amend Schedule (Januar 21,2011);
Order No. 32176, at p. 4. At oral arguent, NIPPC requested to properly submit information
produced in discovery into the record, Tr., at pp. 6-7, 11, and to provide the testimony of
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NIPPC's witness regarding the flaws of the IRP Methodology. See id. at pp. 6-7,48,96-99. But
the Commission did not allow NIPPC to establish an evidentiary record. Id. The record in this
docket therefore contans no evidence whatsoever.
Then, on Februar 7, 2011, the Commission issued Order No. 32176, wherein it granted
the Utilities' request to "temporarly" reduce the eligibility cap to 100 kw for wind and solar QF,
but rejected their request to reduce the cap from 10 aMW as to all other QF resource types. See
Order No. 32176, at pp. 11-12. The Commission rejected NIPPC's request for an evidentiary
hearing, made in NIPPC's Initial Comments and Reply Comments, apparently on the ground that
the Commission was only rendering policy determinations. Id. at p. 4. The Commission also
rejected NIPPC's request, made at oral argument, that the Commission take official notice of
several public records and fiings in proceedings before the Commission, other regulatory
agencies, and a federal cour proceeding. Id. at pp. 4-5. The Commission justified the reduction
in the eligibility cap for wind and solar projects on the ground that those projects wil be able to
secure contracts with avoided cost rates calculated under the IRP Methodology. Id. at pp. 8-9.
ARGUMENT
A. The Commission should take official notice of filings cited by NIPPC.
At oral arguent NIPPC requested, pursuant to IDAPA 31.01.01.263, that the
Commission take official notice of several filings and orders in Commission cases and Federal
Energy Regulatory Commission ("FERC") proceedings, as well as three items related to coal
costs cited in NIPPC's Reply Comments. Tr., at pp. 8-10. NIPPC distributed to each of the
paries and the Commissioners a formal request for official notice containing a list of the
Commission and FERC fiings and orders for which it requested official notice. Commissioner
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Smith stated:
I think your passing this out gives people notice of what you want
us to take notice of and certainly we can tae notice of our own
orders and those of any other regulatory agency, state or federal,
matters of common knowledge, technical, financial or scientific
facts, matters judicially noticeable and data contained in periodic
reports of regulated utilities filed with the Commission or federal
agencies. So as long as they fall in one of those categories, there's
no problem with us taking notice.
Tr., at p. 10 (emphasis added).
No pary voiced any objection to offcial notice of NIPPC's listed Commission and
FERC documents and orders, or objected to Commissioner Smith's statement that the list
provided the paries with adequate notice. NIPPC therefore assumed the Commission was
proceeding under the provision of Rule 263, whereby official notice taes place if "agreed by the
paries and approved by the presiding offcer," rather than the provision requiring the pary
requesting notice to submit each one of the documents to the Commission and the paries.
In Order No. 32176, however, the Commission rejected NIPPC's request for official
notice of all listed documents except for the Commission's own "notices and orders," on the
purorted basis that the "Commission acknowledged official notice of its own notices and
orders," but apparently no others. Order No. 32176, at p. 5. As is plainly obvious from the
above-quoted text, however, Commissioner Smith made no distinction between the
Commission's willngness to acknowledge its own notices and orders and those of other
regulatory agencies. At a minimum, therefore, the Commission should reconsider its decision,
and take offcial notice of the FERC orders.
Order No. 32176 also stated that the "majority of the 'filings, testimony and exhibits from
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the 24 PUC dockets are not documents or information subject to official notice." Id. But filings
in the Commission dockets are judicially noticeable, and therefore fall within the confines of
Rule 263. See Idaho Rule of Evidence 201. A trial court may take judicial notice of records in
cases before the trial cour, and there is no reason this Commission may not do the same for
records in its own proceedings. Larson v. State, 91 Idaho 908, 909, 435 P.2d 248, 249 (1967).
Denying official notice under these circumstaces is paricularly unfair because "documents
generally should be placed in evidence through the ordinar avenues specified by the rules of
evidence. This is done by laying an appropriate foundation to demonstrate the documents'
authenticity and relevance." Newman v. State, 149 Idaho 225, 227, 233 P.3d 156, 158 (Ct. App.
2010). If necessar, NIPPC intended to admit its documents through the witness it offered, but
the Commission rejected NIPPC's request to call its witness.
NIPPC therefore respectfully requests that the Commission tae official notice of all
items cited in the fiing provided by NIPPC at oral argument, as well as the following items
regarding coal costs, which NIPPC intended to submit into evidence through its witness, and are
readily available:
(l) Settlement Agreement in State of New York, et al. v. EPA, No. 06-1322,
before the United States Circuit Cour of Appeals for the District of Columbia,
regarding initiation of an EPA rulemaking on regulation of greenhouse gas
emissions at existing electricity generating units; available at
http://ww.epa. gov / airquality/pdfs/boilerghgsettlement.pdf .
(2) Public Utility Commission of Oregon, Electric and Natural Gas Company
Rate Impacts to Meet 2020 Greenhouse Gas Emission Reduction Goals,
(November 1, 2010), available online at http://ww.oregon.govIPUC/2020
Greenhouse Gas Emission Reduction Goals.shtmL
(3) Comments of MidAmerican Energy Holdings Company on Hazardous and
Solid Waste Management System; Identifcation and Listing of Special Wastes;
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Disposal of Coal Combustion Residuals from Electric Utilties; Proposed Rule,
U.S. EPA Docket ID No. EPA-HQ-RCRA-2009-0640 (November 19,2010).
B. The Commission should hold an evidentiary hearing.
NIPPC has repeatedly requested an opportunity to present evidence in support of its
opposition to the reduction in the eligibilty cap. See NIPPC's Initial Comments, pp. 1, 12-13;
NIPPC's Reply Comments, at pp. 1-2; Tr. a pp. 6-7, 48, 96-99.1 The Commission denied
NIPPC's request in Order No. 32176. "The Commission finds that the paries' positions have
been adequately presented through initial comments, reply comments and oral argument, and that
a technical hearing is not necessary to resolve the question of whether the eligibility cap should
be reduced." Order No. 32176, at p. 4. "We find that the comments and oral argument provide
sufficient information to resolve the policy question of temporarily reducing the eligibility cap."
Id. (emphasis added). NIPPC is not the only par that sought to introduce evidence though a
witness. Both PacifiCorp and A vista attempted to present factual assertions of their expert
witnesses. Although PacifiCorp and A vista appear to have backed down from their initial offer
of witnesses in response to NIPPC's attempt to provide its own evidence, the utilities' initial
requests to provide factual assertions from their experts fuher demonstrates the highly factual
nature of the issues before the Commission. Because the Commission's decision was necessarily
based on factual findings, the Commission must hold an evidentiar hearng.
2 NIPPC notes the Commission stated in Order No. 32176, at p. 4, that at oral argument
NIPPC "referenced the need for a technical hearing, but did not renew (its L Motion" for an
evidentiar hearing. There is no requirement that a pary "renew" a motion at an evidentiar
hearng. NIPPC has very clearly advocated with each fiing in this docket, and at oral argument,
that the Commission must consider evidence to properly address the eligibility cap issue. NIPPC
never waived that request, and again adamantly asserts in this petition that the Commission must
hold an evidentiar hearing.
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"The procedure chosen by the Commission must of course give the paries fair notice of
exactly what the Commission proposes to do, together with an opportty to comment, to
object, and to make written submissions; and the final order of the Commission must be based
upon substantial evidence." Intermountain Gas Co. v. Idaho Public Utilties Commission, 97
Idaho 113, 129, 540 P.2d 775, 791 (1975) (emphasis added) (quoting American Public Gas
Association v. Federal Power Commission, 498 F.2d 718 (D.C. Cir. 1974)). "Due process
requires that a pary to contested proceedings before the commission must be afforded a full
opportity to meet the issues." Id. (quoting Washington Water Power Co. v. Idaho Public
Utilities Commission, 84 Idaho 341, 372 P.2d 409 (1962)).
The paries made factual allegations in the fiings in this docket, which the Commission
specifically noted in Order No. 32176. The Commission noted, "The utilities argue that the
number of QFs currently requesting contracts under the published 10 aMW avoided cost rate is
excessive and the utilities' ability to continue to accept the QF energy without negatively
impacting the electric system and the utilities' customers is at risk." Order No. 32176, at p. 6.
"The Intervenors generally contend that lowering the threshold is an imposition on legally
permissible QF projects that canot absorb the costs of negotiating with a utility and the
increased difficulty of obtaining financing created by the uncertainty of the payments they wil
receive under PURP A contracts negotiated through use of the Integrated Resource Plan (IRP)
Methodology." Id. at p. 7. "NIPPC maintains that a reduction in the published avoided cost rate
eligibility cap is not warranted for any resource because the utilities have not demonstrated that
the published avoided cost rate is too high." Id. "Staff emphasizes that, '(w)hen large QFs are
added to a utility's renewable portfolio, but the QFs disaggregate in order to qualify for the
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published rate, the avoided cost paid to the QF becomes inaccurate, because under the published
rate methodology, there's no mechansm to reflect the utility's reduced avoided cost.'" Id. at p. 8
(quoting Tr., at p. 88).
The issues in dispute are therefore whether the Intervenors or the StafflUtilities are
correct regarding the accuracy of the published rates and the IRP Methodology rates, as well as
the impact on the each of the Utilities' system of the amount ofQFs requesting contracts at this
time. Those are purely factual questions that must be decided before the Commission can render
any policy determination.
Thus, the Commission made factual determinations in Order No. 32176. "Based upon
the record, the Commission finds that a convincing case has been made to temporarly reduce the
eligibilty cap for published avoided cost rates from 10 aMW to 100 kW for wind and solar
only(.)" Order No. 32176, at p. 9. "The purose, . .. of distinguishing between small and large
QFs with the application of the IRP methodology for large QF projects is to more precisely value
the energy being delivered." Id. at p. 10. "We believe that the IRP Methodology appropriately
assesses when the QF is capable of delivering its resources against when the utilty is most in
need of such resources. The resultant pricing is reflective of the value of QF energy to the
utility." Id. That is simply not a matter of policy. If the Commission did not make factual
determinations, there would be no basis for it to decide, over NIPPC's objection, that the IRP
Methodology more accurately reflects a larger-sized QF's production and capacity than the
surogate resource methodology. Thus, the Commission's order is indefensible without at least
some evidence supporting the relief granted to the Utilties.
In Intermountain Gas Co., the Cour reversed the Commission because "Intermountain
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did not have an opportunty to meet the issue of whether the continuation of its retail sales
business was in the public interest and thus the order denied it due process." Intermountain Gas
Co., 97 Idaho at 129, 540 P.2d at 791. Likewise, here, NIPPC did not have the opportunty to
meet the issue of whether the IRP Methodology curently implemented by the Utilities actually
calculates the utilities' full avoided costs. NIPPC offered the testimony of its witness on that
matter, and the Commission rejected the request, accepting no evidence whatsoever on the issue.
Nor did NIPPC have the opportity to fully challenge the Utilities' assertion that system
reliability concerns and excessively high published avoided cost rates warranted a reduction in
the eligibility cap. These are factu matters, not a policy determination upon which the
Commission may render a decision based solely upon the arguments of lawyers. The
Commission should accept evidence and reconsider its factual findings.
C. The Commission should reconsider its "findings" relative to the accuracy of the
IRP Methodology in settg avoided cost rates for larger projects because the IRP
Methodology violates Federal Law by dramatically understating actual avoided
costs.
NIPPC commented extensively on the shortcomings in the IRP Methodology in its Reply
Comments. See NIPPC's Reply Comments, pp. 5-11. NIPPC argued that the IRP Methodology
fails to adequately implement eight distinct provisions of FERC's implementing rues for
determining avoided cost rates. These eight distinct provisions require that the avoided cost rates
"shall, to the extent practicable," take into account the following factors: (1) reliability, (2)
contract terms, (3) ability to schedule outages, (4) ability to provide service in emergencies, (5)
contribution to the system in the aggregate with other QFs, (6) contribution to savings due to
shorter construction times, (7) ability to allow the utility to avoid fossil fuel risk, and (8) abilty
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to allow the utilty to avoid line losses. See id. at pp. 5-8 (citing 18 C.F.R. § 292.304(e)). The
IRP Methodology fails to even attempt to tae each of these eight factors into account, and
therefore violates FERC' s guidelines.
In addition to pointing out that the IRP Methodology fails to comply with these
provisions in calculating avoided cost rates, NIPPC proved that it produces wildly inaccurate
results. NIPPC asked Idaho Power to run its AURORA model for the Langley Gulch plant as if
it were operated as a QF. As noted on page 11 of NIP PC's Reply Comments, the results of that
exercise demonstrated that the IRP Methodology actually understated avoided costs rates by
almost one third?
In its Order, the Commission did not address any of NIPPC's assertions. Instead, the
Commission merely relied on an unsubstantiated "belief' - supported only by a record
completely devoid of evidence -- that the IPR Methodology is both a legally and factually sound
vehicle for insuring that the State of Idaho is in full compliance with PURPA. The Commission
stated, "We believe that the IPR Methodology appropriately addresses when the QF is capable of
delivering its resources against when the utility is most in need of such resources." Order No.
32176, p. 10. Thus, based on that belief: "The resultant pricing is reflective of the value of QF
energy to the utility," and, "Based on the foregoing, the Commission temporarily reduces the
eligibility cap for published avoided cost rates from 10 aMW to 100 kW for wind and solar
resources only, effective December 14,2011." Id. It is nothing short of arbitrar to base such a
3 "Thus, the IRP Methodology should generate a value of at least $1061MWh 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 of QF power." NIPPC Reply
Comments, at p. 11.
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sweeping and fact-based decision on a mere "belief' when faced with compellng arguments that
the "belief' may, in fact, be in error, and when possessing no evidence that the belief is correct.
The question of the ability of AURORA and the other power supply models to accurately
estimate avoided cost rates was discussed at length during oral argument. No less than three
paries attempted to produce a witness to help the Commission come to a complete
understading of the issues. NIPPC offered Dr. Don Reading to explain the fact that the
AURORA model fails to account for avoided capacity costs. Tr. at pp. 6-7, 48, 96-99. NIPPC
has attached to this petition, as Attachment 1, a White Paper by Dr. Reading, in which he
identified the three methodologies commonly used for setting avoided cost rates in various
jurisdictions around the country, including Idaho. Dr. Reading demonstrates that the IRP
methodology, as currently implemented, simply fails to account for capacity. Indeed, the
Commission in its final order in this docket makes clear that it is only concerned with the value
of energy and not capacity: "The resultant pricing is reflective of the value of QF energy to the
utility." Order No. 31276, at p. 10 (emphasis provided).
Using information taken directly from Idaho Power's IRP process Dr. Reading
demonstrated that the IRP Methodology, when used for setting avoided cost rates does not even
calculate avoided costs consistent with how the utilities actually calculate the cost of new
resources in their own IRP processes. This flaw highlights the black box nature of the IRP
Methodology. The Utilities have not provided enough data for QFs to properly vet the
individually provided results, and are hence in violation of the 18 C.F.R. 292.302(b) by failing to
provide for public inspection of basic system cost data listed in the regulation.
The reason "disaggregation" ever even began occurng is that the IRP Methodology, as
PETITION FOR RECONSIDERATION OF THE NORTHWEST AND
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curently implemented, provides a rate that is a gross underestimate of the true avoided costs.
See Tr., at p. 49. As the comments of counsel for Cedar Creek Wind demonstrated, the utilties
will not provide a developer with a fair and accurate avoided cost rate through the IRP
Methodology. See id. at pp. 55-57. That QF developer requested an IRP Methodology rate in
good faith, and, after three months of waiting, Rocky Mountan Power provided it with an
unbelievably low calculation of $37 per MWh. Id.; see also Affdavit of Dana Zentz, Case No.
PAC-E-II-0l (Jan. 26, 2011). If the rates for the IRP Methodology were accurate and verifiable
to the QFs, there would be no need to disaggregate an otherwse larger project into smaller
projects to obtain the fair rate at which the project would be financially viable.
Federal law requires the utilities to contract with each QF at the full avoided cost rates.
16 U.S.C. § 824a-3(b), (d); 18 C.F.R. § 292.304(a), (b); see also Small Power Production and
Cogeneration Facilties; Regulations Implementing Section 210 of the Public Utilty Regulatory
Policy Act of 1978,45 Fed. Reg. 12,214, 12,222-12,223 (Feb. 25, 1980) (promulgating avoided
cost regulations and directly rejecting proposals to provide QFs with rates of less than the full
avoided cost). Any QF using a renewable fuel source up to 80 MW in size is a "small power
production facility" entitled to a contract at the utility's full avoided cost rate under FERC's
rules. 16 U.S.C. § 796(17)(A); 18 C.F.R. § 292.204.
It is the blatant inaccuracies and black-box natue of the IRP Methodology that has led
QF developers to find ways to act within the existing regulatory strctue to obtain the published
rate which more accurately reflects the Utilities' full avoided costs. The published rate
methodology has been thoroughly litigated throughout the years, and is curently a very
sophisticated pricing mechanism that taes into account all components of the Utilties' actual
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avoided costs. For example, it includes a discount for wind integration, and discounted
payments to QFs at times of the year and day when the value of the output is less to the Utilities.
Requiring wind and solar QFs to resort to the IRP Methodology on account of the
"disaggregation" problem is in violation of PURPA and FERC's implementing regulations
because, unike the surrogate resource methodology used for published rates, the IRP
Methodology is not designed to provide QFs with the full avoided costs.
D. The Commission should re-instate the 10 aMW published avoided cost rate
eligibilty cap for wind and solar projects because failure to do so constitutes a
failure to implement PURPA's mandatory purchase obligation at each utilty'sfull
avoided costs.
As discussed above, PURPA requires the utilities to contract with each QF at the full
avoided cost rates. 16 U.S.C. § 824a-3(b), (d); 18 C.F.R. § 292.304(a), (b). If a state utilty
commission does not require the utilities within its jurisdiction to pay the full avoided costs for
QF output, that state commission would be in violation of FERC's rules and subject to FERC
enforcement action, or a federal cour challenge to its implementation ofPURPA. See 16 U.S.C.
§ 824-3(f), (h). Because the IRP Methodology, as curently implemented, produces rates below
the full avoided cost rates, the Commission should reconsider its decision and raise the eligibility
cap to 10 aMW so that it wil be properly implementing PURP A for at least some larger wind
and solar QFs.
E. The Commission misconstrued NIPPC's legal position.
In Order No. 32176, the Commission stated, "Contrar to NIPPC's assertions, FERC
rules insist that rates for purchases from QFs be just and reasonable to ratepayers and in the
public interest - not in the interest of the QFs." Order No. 32176, at p. 10. But NIPPC did not
PETITION FOR RECONSIDERATION OF THE NORTHWEST AND
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assert that FERC rules insist that rates for purchases be in the "interest of the QFs." NIPPC
merely cited the U.S. Supreme Cour's findings with regard to Congress's reason for enacting
PURPA's mandatory purchase provisions. See NIPPC's Initial Comments, at p. 6. The Supreme
Cour found:
Traditional electric utilties were reluctat to purchase power from,
and sell power to, the nontraditional facilities. In order to
overcome (this problem) § 21O(a) directs FERC, in consultation
with state regulatory authorities, to promulgate such rules as it
determines necessar to encourage cogeneration and small power
production, including rules requiring utilities to offer to sell
electricity to, and purchase electricity from, qualifying
cogeneration and small power production facilties.
FERC v. Mississippi, 465 U.S. 742, 750-51, 102 S.Ct. 2126,2132-
2133, 72 L.Ed.2d 532 (1982) (emphasis added) (citation omitted).
Whle not disagreeing that avoided cost rates should, indeed, be just and reasonable, NIPPC
would add that this Commission also has an obligation to implement PURP A in such a maner
as to actually "encourage cogeneration and small power production" in spite of the "reluctace"
from "Traditional electric utilities to contract for such power."
F. An evidentiary hearing is necessary due to Idaho Power's late admission that
AURORA is incapable of accurately calculating avoided cost rates for QF projects
smaller than two megawatts.
In its Reply Comments, fied Januar 19,2011, Idaho Power admitted that AURORA is
incapable of accurately calculating even an energy component of an avoided cost rate for
projects smaller that 2 MW:
(I)n researching the AURORA modeling capabilities, the software
provider has advised that there may be some issues with the
software producing dependable results for projects that are less that
2 MW. One of the reasons being that the pricing in the IRP-based
methodology is a result of subtracting the base model results (that
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do not include the proposed project) from the model results,
including the proposed project. If the project is small enough that
it does not trigger changes in the base model operations, i.e., it is
lost in the rounding to MW s or MWhs, then the base model results
could be identical to the modeled results that include the project.
This would result in an AURORA pricing of zero.
Idaho Power Reply Comments, at p. 13.
Idaho Power's counsel tried to retract this remarkable revelation durng oral argument, only a
few days later on January 27, 2011, by stating that:
However, since the time, since Januar 19th at the time when we
filed our reply comments, obviously, we've been working on this
issue, we consulted with A vista and found out that A vista routinely
rus their AURORA modeling for 100 kilowatt projects at par of
their IRP process. Also the Company's analysts also ran several
modelings at 100 kilowatt levels and the Company is confident that
the modeling does result in accurate and usable results for projects
smaller than two megawatts. . . .
Tr., at pp. 18-19.
The flip flop between Janua 19 when Idao Power filed its Reply Comments and
Januar 27, the date of the oral argument is remarkable and less than credible. This is especially
true since NIPPC understands that it literally takes several days for a single AURORA model to
be ru. Nevertheless, Idaho Power's counsel asserted that "Idaho Power personnel ran test
models through the weekend." Tr., at p. 20. It is implausible to argue the company had
sufficient time to conduct a thorough investigation into AUORA's ability to accurately estimate
avoided cost rates for projects smaller than two megawatts. Standing alone, these discrepancies
are suffciently compellng such that the Commission must deny the Utilities request to reduce
the eligibility cap pending a full evidentiar hearing into the infirmities inherent in the IRP
Methodology in estimating avoided cost rates. There is no question that by doing otherwise, the
PETITION FOR RECONSIDERATION OF THE NORTHWEST AND
INTERMOUNTAIN POWER PRODUCERS COALITION
PAGE-16
Commission would be completely failng to implement PURP A for the smallest QFs now
required to use the IRP Methodology.
CONCLUSION
Wherefore, NIPPC respectfully requests this Commission issue its order granting
reconsideration of Order No. 32176 by: (1) taking official notice of the documents and records
cited by NIPPC during oral arguent and in this petition; (2) holding an evidentiar hearng on
the issues addressed in Order No. 32176; (3) requiring the Utilities to immediately implement
changes to the IRP Methodology for calculating avoided cost rates such that they compensate
qualifying facilities for the Utilities' full avoided costs; and (4) re-instate the ten average
megawatt published avoided cost rate eligibility cap for wind and solar projects.
Respectfully submitted this 28th day of Februar, 2011.
RICHARDSON AND O'LEARY, PLLCl)~
Peter J. Richardson (ISB No: 3195)
Attorneys for the Northwest and
Intermountain Power Producers Coalition
PETITION FOR RECONSIDERATION OF THE NORTHWEST AND
INTERMOUNTAIN POWER PRODUCERS COALITION
PAGE-17
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 28th day of Februar, 2011, a true and correct copy of the
within and foregoing PETITION FOR RECONSIDERATION OF THE NORTHWEST
AND INTERMOUNTAIN POWER PRODUCERS COALITION was served as shown to
the following parties:
Jean Jewell
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702
jean. jewellcgpuc.idaho. gov
Donald L. Howell II
Krstine Sasser
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702
don.howeiicgpuc.idaho. gov
kris.sasserrmpuc.idaho. gov
Donovan E. Walker
Lisa D. Nordstrom
Idaho Power Company
PO Box 70
Boise, ID 83707-0070
dwalkercgidahopower .com
lnordstromcgidahopower .com
Michael G. Andrea
A vista Corporation
1411 E. Mission Street
Spokane, W A 99202
michael.andrearmavistacorp.com
Danel Solander
PacifiCorp/dba Rocky Mountain Power
201 S. Main St., Suite 2300
Salt Lake City, UT 84111
danieL. solandercgpacificorp.com
Ronald L. Willams
Willams Bradbur PC
1015 W. Hays Street
Boise, ID 83702
roncgwiliamsbradbury.com
lL Hand Delivery
_U.S. Mail, postage pre-paid
Facsimile
i Electronic Mail
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Scott Montgomery
President, Cedar Creek Wind, LLC
668 Rockwood Dr.
North Salt Lake, UT 84054
scott(fwesternenergy. us
DanaZenta
Summit Power Group, Inc.
2006 E. Westminster
Spokane, W A 99223
dzentz(fsummitpower.com
Thomas H. Nelson
PO Box 1211
Welches, OR 97067
nelson(fthnelson.com
JohnR. Lowe
Renewable Energy Coalition
12050 SW Tremont St
Portland, OR 97225
jravensanmarcoscgyahoo.com
Don Sturevant
J.R. Simplot Company
PO Box 27
Boise, ID 83707-0027
don.stuevantcgsimplot.com
Robert A. Paul
Grand View Solar II
15690 Vista Circle
Desert Hot Springs, CA 92241
robertapaul08(fgmaiLcom
James Carkulis
Exergy Development Group of Idaho,
LLC
802 W. Banock, Ste 1200
Boise, ID 83702
jcarkuliscgexergydevelopment.com
R. Greg Ferney
Mimura Law Offces, PLLC
2176 E. Franlin Rd., Ste 120
Meridian, ID 83642
greg(fmimuralaw.com
_ Hand Delivery
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Bil Piske
Interconnect Solar Development, LLC
1303 E. Carter
Boise, ID 83706
bilpiskecgcableone.net
Dean J Milere
McDevitt & Miler, LLP
PO Box 2564
Boise, ID 83701
j oe(ßmcdevitt -miler .com
Paul Marin
Intermountain Wind, LLC
PO Box 353
Boulder, CO 80306
paulmarincgintermountainwind.com
Ronald L. Wiliams
Wiliams Bradbur, PC
1015 W. Hays Street
Boise, ID 83702
roncgwiliamsbradbury .com
Wade Thomas
Dynamis Energy, LLC
776 W. Riverside Dr., Ste. 15
Eagle, ID 83616
wthomas(ßdynamisenergy.com
Shelley M. Davis
Barker Rosholt & Simpson, LLC
PO Box 2139
Boise, ID 83701
smdcgidahowaters.com
Brian Olmstead
Twin Falls Canal Company
PO Box 326
Twin Falls, ID 83303
olmsteadcgtfcanal.com
Ted Diehl
North Side Canal Company
921 N. Lincoln St.
Jerome, ID 83338
nscanal(ßcableone.net
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Bil Brown
Board of Commissioners of Adams
County,ID
PO Box 48
Council, ID 83612
bdbrown(ffrontiernet.net
Glen Ikemoto
Margaret Rueger
Idaho Windfars, LLC
672 Blair Avenue
Piedmont, CA 94611
glenni(fenvisionwind.com
margaret(fenvisionwind.com
Jeffrey S. Lovinger
Lovinger Kaufman LLP
825 NE Multnomah, Suite 925
Portland, OR 97232
lovinger(fLKLaw.com
Kenneth E. Kaufman
Lovinger Kaufman LLP
825 NE Multnomah, Suite 925
Portland, OR 97232
Kaufman(fLKLaw.com
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Signed Q,lff. ~llS
Nina M. Curtis
GNR-E-IO-04
NORTH,WEST AND INTERMOUNTAIN POWER PRODUCERS
COALITION
PETITION FOR RECONSIDERATION
ATTACHMENT 1
Dr. Don Reading's White Paper
Dr. Don Reading
Ben Johnson Associates, Inc
6070 Hil Road
Boise, Idaho 83703
Phone: [phone]
Fax: [phone]
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS
COALITION
WHITE PAPER
IMPLEMENTATION OF THE IRP METHODOLOGY FOR
CALCULATING AVOIDED COST RATES IN IDAHO
Introduction
This White Paper, prepared on behalf of the Northwest and Intermountain Power Producers
Coalition ("NIPPC") by Dr. Don Reading,l reviews and critiques the Idaho utilities' (Avista,
Idaho Power Company, and Rocky Mountain Power) and Commission Staf's proposed "IRP
Methodology" for determining a utility's avoided cost for PURPA projects in Idaho having an
output greater than 100 kilowatts.
Implementation of the IRP methodology in the maner recommended by the utilties and the
Commission Staff will yield an estimate of variable ruing costs for a utilty, not the utilty's
entire avoided cost. The models used by the utilities (AURORA or PRiSM for Avista, AURORA
for Idaho Power, and Grid for PacifiCorp)2 are commonly known as "power supply" models and
produce estimates of the varable rung costs to the utility. The power supply models are ru
first without and then including, at zero cost, the paricular generating facility being examined.3
Dr. Don Reading's curiculum vitae is Attachment 1 to his White Paper.
2 Comments of the Commission Staf, GNR-E-1O-04, at p. 4. Although Staff stated Avista
would use the AURORA model, Avista stated it may also use the PRiSM modeL. Avista's
Response to NIPPC Production Request No. 23(a), GNR-E-1O-04.
3 Idaho Power Company's Response to NIPPC Production Request No. 46(f), GNR-E-1O-
04.
GNR-E-I0-04
NIPPC WHITE PAPER
PAGE 1
The differing costs between the two rus are divided by the facility's expected output to yield a
per MWh value. This method produces the utilities' variable ruing costs. In order to determine
full avoided costs, the capital components of the facility should be included. The public record
indicates the values advocated by the utilities and Commission Staff do not produce full avoided
cost for a utility in compliance with the Commission's approved method.
Stadard Methods for Finding Avoided Cost
State public utility commissions have used three basic approaches for determining avoided costs
since the enactment of PURPA in 1978. Varous states have employed various incarations of
these three basic approaches in finding avoided costs for their jursdictions. The three methods
are: 1) the Peaker Method, 2) the Proxy Method, and the 3) Differential Revenue Requirement
Method.4
When using the Peaker Method, the utilty's power supply model is ru with and without the
given facility, at zero cost, to produce variable costs. Then, the capital costs of a peakng unit are
added to find full avoided costs.
Under the Proxy Method (which is curently used in Idaho for published rates), the capital costs
of the proxy unit are included, along with operation and maintenance expenses, as par of the
calculations to find the utility's avoided cost.
The Differential Revenue Requirement Method calculates the utility's total generation costs (or
revenue requirement) with, and without, the proposed facility. The method first uses an
expansion plan model to generate expansion plans with and without the proposed facility. The
method then uses the two different expansion plans as inputs to a financial planng model to
produce the utility's revenue requirement with and without the proposed facility's output
provided as free energy. That financial model would include items such as interest costs, taes,
allowed rate of retur on the change in rate base and capital, and other "rate case" inputs for the
facility. The difference in the present value of the revenue requirement is the avoided revenue
requirement component and is, in theory, the utility's full avoided cost, including avoided energy
and capacity costs, as well as taxes and other cost factors.
It is importt to note that all three of these basic and accepted methods include the capital cost
of the generating unit being examined.
4 Edison Electric Institute, PURPA: Making the Sequel Better than the Original (Dec.
2006); National Economic Research Associates, Inc., The Role and Nature of Marginal and
Avoided Costs in Ratemaking: A Survey (Jan. 1992); National Economic Research Associates,
Inc., How to Quantif Marginal Costs: Topic 4 (March, 1977).
GNR -E-I0-04
NIPPC WHITE PAPER
PAGE 2
The Commission accepted the Differential Revenue Requirement Method for calculating the
utilties' avoided costs for QF's larger than 10 MW in Case No. IPC-E-95-9. The Commission
approved the Stipulation in that case that was signed by the three utilties, Commission Staff, and
Rosebud Enterprises, Inc. Although the other paries in that case chose not to sign the
Stipulation, they did not oppose the methodology. Attched to Commission Staff witness
Sterling's Direct Testimony filed in that case was Exhibit 101 that contained Sta's proposed
avoided cost methodology that was accepted by the Commission. Ths approach is the IRP
Methodology.
Althgough the paries called it the IRP methodology. the essence of Staff's methodology actually
employs the Differential Revenue Requirement Method described above. This methodology
compares the present value of the revenue requirements (PVRR) of the base case with one that
includes the utilties system including the QF. Items 6 and 7 ofthe Stipulation states,
6. Finally, the present value ofthe QF project avoided cost is calculated by subtracting
the PVRR of the modified plan, with the costs ofthe QF set to zero, from the PVRR of
the base case resource plan.
7. Rates for capacity and energy from the QF project can then be developed for which,
on a present value basis, the expected payments to the QF are equal to the project's
avoided cost over the life of the contract. 5
Note that item 7 states that avoided cost rate for a QF are found by using both capacity and
energy. The end result is that Idaho has two methods for calculating avoided cost, the Proxy
method for smaller projects, and the Differential Revenue Requirement Method for larger
projects.
IRP Methodology as Advocated by the Utilities and Commission Staff
The Commission Staff indicates the "IRP Methodology" has been utilzed in only two PURA
contracts since PURPA was first implemented in Idaho.6 One of these is the Rockland Wind
Project. The Commission Order approving that contract states,
This model provides strictly an energy price based upon the estimated generation
from this Facility being available to meet Idaho Power s customers' energy needs.
This AURORA energy price contains no value for RECs or other items of value
identified within the Agreement. The energy price identified by the AURORA
ru, including a discount of $6.50 per megawatt-hour (MWh) for wind
5
Direct Testimony of Rick Sterling, IPC-E-95-09, Exhibit 101, p. 8.
6
Comments of the Commission Staff, GNR-E-10-04, p. 4.
GNR-E-I0-04
NIPPC WHITE PAPER
PAGE 3
integration, was a levelized price of $56.21. In comparison, the published
avoided cost levelized price for a 10 average MW or less PURP A wind project
with a planed on-line year of2011 is $75.88 per MWh.7
Note the phrases "This model provides strctly an energy price" and "AURORA energy price,"
indicating the model does not include the avoided capital costs. This conclusion is fuher
buttessed by Staff s Comments in the Rockland Wind project case, wherein Staff stated, "Idaho
Power believes, and Staff agrees, that the AURORA-generated avoided cost rate simply
represents a market price alternative that primarily reflects the value of energy and does not fully
reflect capacity value.,,8
Due to the exclusion of capital costs, it is not surrising that the levelized price of $56.21/MWh
is 26% lower than the published PURPA price of$75.88, found by using the Proxy Method to
determine the avoided cost. The use of a power supply model, that estimates just the energy
costs, as a bench mark for a utility'sfull avoided costs is not equivalent to an "IRP
Methodology," which should tae into account all relevant costs, including energy and capital
related costs.
The actual method used by the utilties to evaluate the cost of new resources in the IRP process
includes the use of a power supply model to find the variable cost of the proposed generating
units, and then adds to that variable cost all other expected cost items, such as capital and
transmission. The table below was included in a handout at Idaho Power's Januar 20,2011
Integrated Resource Plan Advisory Council meeting.9 The four columns and total indicate the
net present value of the nine resource portfolios Idaho Power is curently considering for their
2011 IRP. The RECs colum is negative based on the assumption that all futue resources wil
be self built projects, and thus the Company could derive revenue from sellng the RECs.
7 IPUC Order No. 32125, Rockland Wind Project, pp. 3-4.
8
Comments of Commission Staff, IPC-E-1O-24, p. 3. It appears from the documents in
Case No. IPC-E-95-9, wherein the Commission approved the IRP Methodology for large
projects, that Commission Staff may have intended the IRP Methodology to mimic the
Differential Revenue Requirement Method described above. However, that would require a
financial model that would include all capital related costs, not the power supply models
curently being used by the utilities.
9 IRPAC meeting handout, p. 9 (Jan. 20, 2011).
GNR- E-1 0-04
NIP PC WHITE PAPER
PAGE 4
~~~=~e~~:~~~~(~~l~~=-:~~~~~f=~~:~t;~~£~~)~::~~~:-L¡ ¡ Variable I i I I I
i Base Case I (Aurora) I Capital I Trans I RECs ¡ Total i! 1-1 Sun & Steam i $3,042,492 I $804,575 ¡ $17,925 I ($24,396) i $3,84,596 ii=,_._,.,_._...-.__..~..__.__~.v..~.".,~,...,.~*~.._....~'." "'-1"'-'~~'~'~-'~'---~'~r'--'--'-""-"'-"'-r"~"--'.._~_._.~.,.-.,-~---t~---"-'--i
Lt~_2 S~!~r~_n " i ."~.~~"~~L,!S_S~.L.S~~!~.~~Zj~...~~9L~§S.~~lS.~2, 033) I s~Ls~§!Z~?~111-3 B2H $3,088,318 ¡ $0 I $98,929 I ($9,940)' $3,177,307 It._~.._.~-.-...._.-.......... ... ...-......... . ...........-...-..---....:... .. .... ......_--. -.....j.... ~...........-..r .~.-._...._. ---"'.''''''---i! 1-4 SCCT $3,099,863! $108,835! $22,748 ì ($9,940 3,221,506 i
...-...~-_.-~._... .... .....-.....--.- --..__........ .' "'._" .....-..-.-...+......----....- ...1...._....._. _~..n____......j
?:S.~~.~!.__......... ls~Lt1-§..~9~-L-s.!~l.'!!.s..l..-S!~.S.~~_4-1S~-'.~~)4.S?.!~4,430_j¡1-6CHP i $3,163,107. $398,453! $15,798 I ($9,940)1 $3,567,418 !,_...-...~--.~........ - ..........~- .. ...-t... ..._...... n.... ...... .."t.-..............~..~....+.... ....._-..-...... ¡..~..-_.-.~--.i-----..-.-.---...-l
!l::Zl!~an£~~.. ...... .... ....... _.¡..__s_?,0?§'.9~S. Ls~.12_~~t_S!~L~~IJ$lS,3a4~ j s?,528.!Q?~_1
f.!~.~.l:..lJ..rrJ?~~.~!..~~~~~__................._....~.-s.~Q~?'.'!9~-i~_.~j~!.§!~.a~..l..~.S~~~llS!S,-~Q§~tS?.!518, 1~~
l!~~I:!~!r!P.lJ!~~~§~ri eration. ..J........s~,~~~!.~~l__~l:!~!!S~.J ......S??.!Z'!~_LJS~.'~~J.LS?.'?:?!i2S92 i
As is clearly demonstrated in this table produced by Idaho Power in its IRP process, the utilty's
actual "IRP Methodology" includes more than just the power supply model's estimates of
varable costs in determining full costs of future resources. It also includes capital costs and
transmission. The full costs of these futue resources, including both varable and fixed costs,
are the utilty's actual full avoided costs.
In NIPPC's Production Request No. 67, NIPPC asked Idaho Power to provide the IRP
Methodology Model runs that led it to state at oral argument on Januar 27,2011, that it could
accurately calculate avoided cost rates for projects down to 100 kw in size with the IRP
Methodology. In response to No. 67(b), Idaho Power provided a table with its IRP Methodology
rus, and stated the table "shows only the avoided cost of energy modeled by AURORA, and
does not contain the avoided cost of capacity comtc0nent, which is added to the value of the
energy in determining the total avoided cost rate. 0 In (h) of that same Response the Company
added,
A capacity (fixed) cost credit using a combined cycle combustion turbine as a surogate
resource is then added and any applicable deductions are subtracted to calculate an
adjusted avoided cost for each year of the contract.
I I
But the Company did not provide calculations or work papers for this capacity credit, and it has
provided no evidence that it has ever provided a QF requesting IRP Methodology rates with such
a capacity credit using a surogate combined cycle combustion turbine (or any other type of
surogate). As discussed above, the fiings in the Rockland Wind Project case lacked any
10 Idaho Power Response to NIPPC Production Request No. 67(b).
Ibid.11
GNR-E-10-04
NIPPC WHITE PAPER
PAGES
discussion of such a capacity credit being calculated or added to the IRP Methodology rate for
that project.
It should also be noted the Company's discussion of including capital costs within the "IRP
Methodology" focuses on "A capacity (fixed) cost credit" and does not include the implications
for the present value of the revenue requirement with and without the project being modeled as
proscribed by the Commission's as approved method in Case IPC-E-95-9. The methodology by
which the Company now asserts it will include a capacity cost is therefore not a commonly
recognized methodology for calculating avoided cost rates, and is not in line with differential
revenue requirement methodology approved in Case No. IPC-E-95-9.
Conclusion
The "IRP Methodology" curently being utilized to generate PURPA avoided cost rates for
projects over 10 aMW and proposed for use in all projects over 100 kilowatts will not be equal to
a utility's full avoided costs unless the present value ofthe revenue requirement is compared
with and without the project being modeled. The public record indicates the curent
implementation of the "IRP Methodology" does not fit within any of the three standard types of
methodologies used by other states to calculate avoided costs. Only when capital costs are added
and the present value of the revenue requirement calculated can the "IRP Methodology" be
considered an estimate of a utility's full avoided cost under the method approved by the
Commission.
GNR-E-10-04
NIPPC WHITE PAPER
PAGE 6
Don C. Readig
Don C. Reading
Present positiolJ
Vice President and Consultig Economist
EducatiolJ B.S., Economics C Utah State University
M.S., Economics C University of Oregon
Ph.D., Economics C Utah State University
HonorsanCJ
award~
Omicron Delta Epsilon, NSF Fellowship
Professiona.
and busines~
history
Ben Johnson Associates, Inc.:
1989 ---- Vice President
1986 ---- Consultig Economist
daho Public Utities Commssion:
1981-86 Economist/Director of Policy and Admnistration
Teachig:
1980-81 Associate Professor, University of Hawan-Hio
1970~80 Associate and Assistant Professor, Idaho State University
1968-70 Assistant Professor, Middle Tennessee State University
Fir experience Dr. Readig provides expert testiony concerng economic and regulatory issues.
He has testified on more than 35 occasions before utity reguatory commssions in
Alaska, Calforna, Colorado, the Distrct of Columbia, Hawan, Idaho, Nevada,
North Dakota, Texas, Utah, Wyomig, and Washigton.
Dr. Readig has more than 30 years experience in the field of economics. He has
participated in the development of indices reflectig economic trends, GNP growt
ates, foreig exchange markets, the money supply, stock market levels, and
inflation. He has analyzed such public policy issues as the mium wage, federal
spending and taxation, and import/ export balances. Dr. Readig is one of four
economists providig yearly forecasts of statewide personal income to the State of
daho for puroses of establishig state personal income tax rates.
In the field of telecommuncations, Dr. Readig has provided expert testiony on
GNR-E-10-04
NIPPC WHITE PAPER - ATTACHMENT 1
PAGE 1
Don C. Readig
the issues of margial cost, price elasticity, and measured servce. Dr. Readig
prepared a state-specific study of the price elasticity of demand for local telephone
servce in Idaho and recently conducted research for, and diected the preparation
of, a report to the Idaho legislatue regadig the status of telecommunications
ompetition in that state.
Dr. Reading's areas of expertise in the field of electrc power include demand
forecastig, long-range planng, price elasticity, margial and average cost pricing,
production-simulation modelig, and econometrc modelig. Among his recent
cases was an electc rate design analysis for the Industral Customers of Idaho
power. Dr. Readig is cuently a consultant to the Idaho Legislatue=s Commttee
on Electrc Restrctug.
Since 1999 Dr. Readig has been affiated with the Cliate Impact Group (CIG) at
the University of Washigton. His work with the CIG has involved an analysis of
the impact of Global Warmg on the hydo facilties on the Snake River. It also
includes an investigation into water markets in the Northwest and Florida. In
addition he has analyzed the economics of snowmaking for ski area's impacted by
Global Warg.
Among Dr. Readig's recent projects are a FERC hydropower relicensing study (for
the Skokomish Indian Tribe) and an analysis of Northern States Power's North
Dakota rate design proposals affectig large industral customers (for JR. Simplot
Company). Dr. Readig has also performed analysis for the Idaho Governor's
Offce of the impact on the Northwest Power Grid of varous plans to increase
salon runs in the Columbia River Basin.
Dr. Readig has prepared econometrc forecasts for the Southeast Idaho Council of
Governments and the Revenue Projection Committee of the Idaho State
Legislatue. He has also been a member of several Northwest Power Plannig
Council Statistical Advisory Commttees and was vice chaian of the Governor's
Economic Research Council in Idaho
Whe at Idaho State University, Dr. Readig performed demographic studies using
a cohort/survval model and several economic impact studies using input/output
analysis. He has also provided expert testiony in cases concerning loss of income
esultig from wrongfu death, injur, or employment discriation. He is
currently a adjunct professor of economics at Boise State University (Idaho
economic history, urban/regional economics and labor economic.)
Dr. Reading has recently completed a public interest water rights transfer case. He
GNR - E-1 0-04
NIPPC WHITE PAPER - ATTACHMENT 1
PAGE 2
Don C. Readig
has also just completed an economic impact analysis of the 2001 salon season in
Idaho.
Publication "Energiing Idaho", Idaho Issues Onlie, Boise State University, Fal 2006.
. boisestate.edu/his tory / issues onlie / fal2006 _issues / index.h tm
he Economic Impact of the 2001 Salmon Season In Idaho, Idaho Fish and
ildlfe Foundation, Apri 2003.
e Economic Impact of a Restored Salon Fishery in Idaho, Idaho Fish and
ildlfe Foundation, Apri, 1999.
e Economic Impact of Steelhead Fishing and the Retun of Salon Fishig in
daho, Idaho Fish and Wildlfe Foundation, September, 1997.
Cost Savigs from Nuclear Resources Reform: An Econometrc Model~ (with E.
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