20171214Petition.pdf

UNITED STATES OF AMERICA
BEFORE THE , -i,1!1!i
FEDERAL ENERGY REGULATORY COMMISSION
F ER,- E- tr-ot
RECEIVHD
2011BrC lh Fil 3: h7
SION
tqrti-iil FUBLr[5 O0MM
Franklin Enerry Storage One, LLC
Franklin Enerry Storage Two, LLC
Franklin Enerry Storage Three, LLC
Franklin Enerry Storage Four, LLC
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Docket No. EL17-
PETITION FOR DECLARATORY ORDER
AI\iD
PETITION FOR ENFORCEMENT
PURSUAT\T TO SECTTON 210(h)
OF THE
PUBLIC UTILITY REGULATORY POLICIES ACT OF T978
OF
FRANKLIN ENERGY STORAGE ONE, LLC
FRANKLIN ENERGY STORAGE TWO, LLC
FRANKLIN ENERGY STORAGE THREE, LLC
FRANKLIN ENERGY STORAGE FOUR, LLC
Pursuant to Rule 207 of the Federal Energy Regulatory Commission's
("Commission" or "FERC") Rules of Procedure, l8 C.F.R. $ 385.207, Franklin Energy Storage
One, LLC; Franklin Energy Storage Two, LLC; Franklin Energy Storage Three, LLC, and
Franklin Energy Storage Four, LLC (herein collectively, the "Franklin Energy Storage Facilities"
or "Franklin") hereby collectively petition the Commission for a Declaratory Order finding that
certain orders of the Idaho Public Utilities Commission ("IPUC" or "Idaho Commission") are
inconsistent with the Public Utilities Regulatory Policies act of 1978 ("PURPA"). Pursuant to
Section 210(h) of PURPA Franklin also petitions the Commission to initiate an enforcement
action against the Idaho Public Utilities Commission ("IPUC") to remedy the State of ldaho's
improper implementation of PURPA.
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
I
This Petition asking the Commission to issue its Declaratory Order and to initiate an
enforcement action against the IPUC is based on the IPUC's usurpation of the Commission's
exclusive authority over the certification of Qualiffing Facilities under PURPA. The IPUC
denied Franklin's entitlement to IPUC established long-term (twenty-year) power purchase
agreements pursuant to established IPUC precedent based solely on the Idaho Commission's
denial of the QF status of the Franklin Energy Storage Facilities. [n doing so, the IPUC has
usurped the exclusive role of this Commission to establish criteria for, and to adjudicate, the
legal status of Qualifuing Facilities. Specifically, the IPUC ruled that energy storage QFs are not
distinct QFs but rather are defined by the nature of the energy input rnto the energy storage
facility. The IPUC's orders are inconsistent with established FERC rulings that energy storage
systems using renewable resource inputs are distinct Qualifying Facilities. The IPUC's orders
wrongfully allow it to avoid its obligation to implement PURPA and deny the Franklin Energy
Storage Facilities their entitlement to the ldaho Commission's 'standard' twenty-year contract
term and associated rates.
I. PETITIONER DESCRIPTION
The Franklin Energy Storage Facilities are four Idaho limited liability companies, each under
distinct and separate ownership. The Franklin Energy Storage Facilities are each a 25 MWr
"qualifying small power producer" within the meaning of section 210(hX2XB) of PURPA. The
I Alternating current.
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
2
Franklin Energy Storage Facilities are self-certified "QF"s.2 All four projects are similarly
described in their respective FERC Form 556's at Paragraph 7h as follows:
The project consists of an energy storage system Qualifring Facility providing scheduled
and dispatchable electricity in forward-looking time blocks. The energy storage system
that comprises the energy storage Qualifying Facility is designed to, and will, receive
100% of its energy input from a combination of renewable energy sources such as wind,
solar, biogas, biomas, etc. The current initial design utilizes solar photovoltaic (PV)
modules mounted to single-axis trackers to provide the electric energy input to the
Qualifuing Facility's battery storage system. The PV modules are planned to be
connected in series/parallel combinations to solar inverters, rated approximately 2.5
MWac each, (subject to change). The proposed electric energy storage Qualiffing
Facility will consist of an electro-chemical battery and will have a maximum power
output capacity of 25 MWac for a sustained time period of 5 - 60 minutes. The Facility
will consist of an alternate current (AC) to direct current (DC) control system. The
Qualifuing Facility will be utilized to provide the purchasing utility with pre-scheduled
and dispatchable AC energy within pre-determined time blocks. The sole source of
electric power and energy provided to the purchasing utility will be the electro-chemical
reaction giving rise to the discharge of electric power and energy by the battery. In turn,
the sole direct source of energy input to the battery Facility will be, as described above,
renewable sources.3
The four distinct Franklin Energy Storage Facilities will be located in Idaho near the
Nevada/Idaho border about twenty miles north of the town of Jackpot, Nevada. They will be
adjacent to one another and will share an interconnection onto the commonly owned (Idaho
Power and NV Energy) 345 kV Midpoint-Humboldt transmission line.
il. COMMUNICATIONS
All correspondence and communications regarding this Petition should be directed to:
Peter J. Richardson
515 N. 27tr St.
Boise, Idaho 83702
(208) 938-790r
oeter(E richardsonadams. co m
Robert A. Paul
515 N. 27th Street
Boise, Idaho 83702
(760) 861-1 104
robertapaul@ gmai l. com
2 See FERC Docket Nos. QFlT-581, QF17-582, QFlT-583 and QF17-584.
3 FERC Form 556 atfl7h, FERC Docket Nos. QFl7-581 - 584.
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
J
Copies of this filing have been served on the Idaho Public Utilities Commission and Idaho Power
Company by hand delivery of a hard copy and email.
ilI. THE IDAHO COMMISSION'S REFUSAL TO RECOGNIZE ENERGY
STORAGE QUALIFYING FACILITY STATUS
PURPA is implemented in Idaho by the IPUC on an ad hoc, order-by-order basis. There
are no Idaho statutes or rules implementing PURPA. Idaho's electric utilities operate in a
traditional vertically integrated rate-regulated environment.4 The IPUC has established standard-
offer avoided cost rates, with a contract term of up to twenty-years, for all QFs (other than solar
or wind QFs) that have a capacity of ten average monthly megawatts (l0aMW) or less.s For
wind and solar OFs only, the IPUC has restricted the availability of standard offer rates and
twenty-year contract terms to only those solar and wind QFs that have a capacity of 100 kW or
less.
While limiting the availability of published rate 'standard offer' contacts to two years for
iust solar and wind Qualifuing Facilities, the Idaho Commission specifically established standard
contract rates of up to twenty-years for all other Oualifuins Facilities. The Idaho Commission's
rulings in this regard are explicit:
After careful consideration, the Commission [Idaho PUC] ultimately determined that it
was appropriate to maintain the 100 kW eligibility cap for published avoided cost rate for
wind and solar QFs.6
And:
a Idaho Power is scheduled to begin participation in the recently established Western Energy
Imbalance Market in 2018.
s See IPUC Order Nos. 33357 and33419, attached hereto as Exhibit Nos. 1 and2 respectively
6 IPUC Order No. 32697 , at p.3, emphasis provided. Attached hereto as Exhibit No. 3.
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
4
This Commission [Idaho PUC] is confident that, with other changes to the avoided cost
methodologies incorporated in the Order, changing eligibility from 10 aMW for resources
other than wind and solar is unnecessary at this time. We find that at 10 aMW eligibility
cap for access to published avoided cost rates for resources other than wind and solar is
appropriate...T
Finally
We maintain the eligibility cap at 10 aMW for QF projects other than wind and solar
(including but not limited to biomass, small hydro, cogeneration, geothermal and waste-
to-energy.8
Thus, under the tdaho Commission's orders implementing PURPA, standard twenty-year
avoided costs rates and contacts are available to non-solar and non-wind QFs with a monthly
capacity of ten average megawatts or less. Wind and solar QFs are only entitled to standard
twenty-year avoided cost rates and contracts if they have a nameplate capacity of 100 kW or less.
In early 2017, each of the Franklin Energy Storage Facilities proposed to enter into a
twenty-year published avoided cost rate contract with ldaho Power Company pursuant to
established Idaho Commission orders for their respective energy storage facilities. Each of the
Franklin Storage Facilities sought contract terms and rates established by the Idaho Commission
for non-wind and non-solar QFs.
Franklin, therefor, had to meet a simple two-prong test in order to claim eligibility to the
Idaho PUC established twenty-year standard avoided cost rates and contracts. The first prong of
the two-part test is a determination whether the projects are wind or solar QFs. If the QFs are not
wind or solar QFs, then the second prong of the two-part test is whether the generation from the
7 Id. atp.14.
8 tpUC Order No. 32176, at p. 9. Attached hereto as Exhibit No. 4
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
5
proposed non-wind and non-solar QFs is equal to or less than ten average monthly megawatts.e
The second part of this two-part test was not at issue because the Franklin Energy Storage
Facilitie' generation profiles in their respective FERC Form 556 f-rlings clearly demonstrate that
they will generate well below the ten-average monthly megawatt threshold. This fact was never
questioned. Therefore, the sole question to be answered in order to determine whether each of
the Franklin Energy Storage Facilities is eligibile for Idaho Comrnission established twenty-year
contracts and rates was therefore whether or not they are solar or wind QFs.
Idaho Power refused to enter into the requested twenty-year standard rate contracts and
instead filed a Petition for Declaratory Ruling asking the Idaho Commission to "extend the 100
kW published rate eligibility cap to battery storage projects." Idaho Power filed its Petition with
the Idaho PUC on February 27,2017.10
The Idaho Commission ignored ldaho Power's request to establish a 100 kW published
rate eligibility cap for battery storage facilities and instead ruled that battery storage QFs are not
distinct QFs apart from the source of the energy input into the battery system. In direct
contravention of this Commission's clearly established rulings relative to the QF status of battery
storage facilities, the Idaho Commission responded to Idaho Power's Petition by basing the
battery storage facilities' eligibility on their energy source, rather than on their QF status:
e That the Franklin Projects would generate less than l0 average monthly megawatts each was
never questioned or challenged before the Idaho Commission. According to the Franklin FERC
Form 556 filing the average monthly generation is expected to be significantly below 10 average
monthly megawatts.r0 Idaho Power Petition for Declaratory Ruling, at p. 13. IPUC Docket No. IPC-E-17-01.
Attached hereto as Exhibit No. 5, due to size without its accompanying attachments. The entire
filing may be accessed at:
http://www.puc.idaho.gov/fileroom/cases/elec/IPC/IPCE1701/20170227APPLICATION.PDF
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
6
[W]e find it appropriate to base Franklin's ...eligibility under PURPA on its primary
energy source - solar. Solar resources larger than 100 kW are entitled to negotiate two-
year PURPA contracts ... Franklin's argument that this Commission's prior decisions
clearly and unequivocally allow it entitlement to published rates ignores FERC's
pronouncement that energy storage facilities are not per se renewable resources/small
power projection facilities under PURPA.Ir
The Franklin Facilities are, of course, neither wind nor solar QFs. They have been self-
certified as an "Other Renewable Resource"l2 and more specifically described as an "energy
storage (battery) system."13 This Commission (FERC) has previously answered the question of
whether energy storage systems are QFs in their own right in the affirmative. The only
requirement this Commission imposed on energy storage facilities, as distinct QFs, is that the
energy input into the storage system must comply with the same energy source requirements
applicable to any other qualiS,ing faciality:
In sum, energy storage facilities . . . are a renewable resource for purposes of QF
certification. However, such facilities are subject to the requirement that the energy input
to the facility is itself biomass, waste, a renewable resource, a geothermal resource or any
combination thereof...
Luz Development and Finance Corp. 5l FERC fl 61,078 at p. 9, (1990)
As this Commission explained:
[I]n order for a storage facility to be a QF the primary energy source for generation of the
energy must be one of those contemplated by the statute for conventional small power
production facilities e.g., boimass, waste, renewable resources, geothermal resources of
any combination thereof.
Id. atp.8.
rr IPUC Order No. 33785 ,p. 12. Attached hereto as Exhibit No. 6.
12 FERC Form 556 at Paragraph 6, FERC Docket Nos. QFlT-581 - 584.
t3 Id. atParagraph 7h.
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
7
Consequently, our ruling on the narow declaratory issue before us should not be read to
presume that this Commission deems battery storage to be a legitimate qualiffing facility
eligible for the benefits of PURA and subject to the Act's implementing regulations
under FERC.re
ra Form 556 at Paragraph 7h, FERC Docket Nos. QFlT-581 - 584; "The energy storage system
that comprises the energy storage Qualifying Facility is designed to, and will, receive 100% of
its energy input from a combination of renewable energy sources such as wind, solar, biogas,
biomas, etc."
ts Indep. Energt Producers Ass'n, Inc. v. Cal. Pub. Utilities Comm'n, 36 F .3d 848, 853-54 (9m
Cir. 1994), "The structure of PURPA and the Commission's regulations, reflect Congress's
express intent that the Commission exercise exclusive authority over QF status determinations."
'6 r6 u.s.c. g796(17(c).
t7 Indep. Energt Producers,36 F. 3d at 854 (emphasis provided).
r8 IPUC Order No. 33785, Id. atp.10.
te Id. at pp. l0 - I 1.
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
8
There is no question that the Franklin Energy Storage Facilities will utilize a renewable resource
as their primary energy source.14
PURPA grants FERC exclusive authority over OF status determinations.r5 This follows
from section 201 of PURPA, which includes "qualifring small power production facilities" as
QFs under the requirements prescribed by, and as determined by FERC.16 Thus, FERC's
"regulations czury out the statutory regime reposing in [FERC] exclusive authority to make QF
status determinations," and "[n]owhere do these regulations contemplate a role for the state in
setting QF standards or determining QF status."lT The Idaho Commission, therefore, is
preempted from making any determination as to the QF status of the Franklin Energy Storage
Facilities.
The [daho Commission purported to rely on this Commission's Luz decision. However,
the IPUC actually ignored that decision by making the facially untenable assertion that battery
storage facilities are not "presume[d]" to be "a legitimate ... qualifying facility eligible for the
benefits of PURPA:"18
We [the ldaho Commission] are unaware of any reference in PURPA or FERC's
implementing regulations that identifies battery storage as a renewable resource eligibile
for QF status and the benefits provided by the act. Indeed, FERC acknowledged that
"[n]either the statute nor the final rule refers specifically to energy storage systems" Luz at
6l,l7l .21
It therefore concluded that:
[Wle find it appropriate to base Franklin's eligibility under PURPA on its primary energy
source - solar. 22
In sum, the IPUC has completely disregarded this Commission's clear ruling as to the QF status
of energy storage facilities. It did so by denying that energy storage facilities are QFs and
instead ruled that their eligibility under PURPA is not based on their status as self-certified
energy storage facilities but rather is based on their "primary energy source." 23
Iv. PRAYERS FOR RELIEF
A. DECLARATORY RULING
20 Luz, supra at p. 9.
2r IPUC Order No. 33785, Id. atp.l0, citation in original.
22 Id. atp.12.
23 Id. The Idaho Commission did not define what it meant by the phrase "primary energy
source." The Franklin Energy Storage Facilities' FERC Form 556 provides that they may use a
combination of renewable energy sources to energize their battery systems. Thus, there may be a
combination of energy sources, the primary one of which may vary depending on the mix of
renewable energy inputs into the battery system at any one time.
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
9
Although the Idaho Commission cited to this Commission's Luz opinion, it ignored this
Commission's unequivocal ruling that: "In sum, energy storage facilities such as the proposedLuz
battery system are a renewable resource for purposes of QF certification."2o Further ignoring this
Commission's ruling in Luz, the IPUC inexplicably stated that:
PURPA vests in FERC the exclusive jurisdiction to set QF standards and to determine QF
status. Under FERC's rulings each of the Franklin Energy Storage Facilities is a legitimate
Qualifying Facility and a renewable resource that is entitled to all the benefits accruing to it
under PURPA. The Franklin Energy Storage Facilities therefore respectfully request this
Commission issue its order declaring that; (l) the IPUC's decisions discussed herein are contrary
to PURPA and this Commission's implementing rules and orders thereunder; and (2) the
Franklin Energy Storage Pacilities are energy storage QFs; and (3) the Franklin Energy Storage
Facilities are entitlement to all of the benefits under the IPUC's orders as are all other non-solar
and non-wind QFs.
B. ENFORCEMENT ACTION AGAINST TIIE IPUC
Section 210(hX2XA) of PURPA permits the Commission to initiate an enforcement
action against a State for failure to properly implement that statute. The Franklin Energy Storage
Facilities respectfully request the Commission initiate an action to enforce PURPA against the
IPUC to invalidate and permanently enjoin all conditions imposed on energy storage QFs that
prevent them from entitlement to the IPUC's standard long term avoided cost rates available to
non-wind and non-solar QFs.
Respectfully submitted,
/s/ Peter Richardson
Peter Richardson, ISB #3195
Franklin Energy Storage Facilities
515 N.27th Street
Boise, Idaho 83702
(208) 938-7eol
oeter@rri chardsonadams. com
Dated this 14th day of December 2017
Franklin Energy Storage Facilities
Petition for Declaratory Ruling
Petition for Enforcement
10
Exhibit 1
Idaho Public Utilities Commission
Order No. 33357
Office of the Secretary
Service Date
August 20, 20 I 5
BEFORE THE IDAHO PUBLIC UTILITTES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPAI{Y'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
CASE NO. IPC-E.15.01
IN TITE MATTER OF AVISTA
CORPORATION'S PETITION TO MODIFY
TERIVIS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
cAsE NO. AVU-E-ls-or
IN THE MATTER OF ROCKY MOUNTAIN
POWER COMPANY'S PETITION TO
MODIFY TERMS AND CONDITIONS OF
PURPA PURCHASE AGREEMENTS
CASE NO. PAC.E.15.O3
ORDER NO. 33357
On January 30, 2015, Idaho Power Company filed a Petition asking the Commission
to modify the length of prospective contracts under the Public Utility Regulatory Policies Act
(PURPA). Specifically, the Company asked that the length of its new PURPA contracts for
projects that exceed the published rate eligibility cap' be reduced from 20 years to two years.
Avista Corporation and Rocky Mountain Power filed similar petitions and the three cases were
consolidated into a single proceeding. Order No. 33250. The Commission granted temporary
relief to the three petitioning utilities by reducing the length of PURPA contracts to five years
while the Commission investigated the issue of contract length. Order Nos. 33222, 33250,
33253 (clarifying that interim relief applies only to new PURPA contracts that exceed the
published rate eligibility cap), 33286 (denying petition to limit interim relief to only wind and
solar PURPA contracts).
The Commission received almost 200 written cornrnents from the public. The
Commission held two public hearings and a two-day technical hearing. See Order No. 33253.
After the record closed, the Commission received four timely petitions for intervenor funding.
The matter being fully submitted, the Commission issues this Order reducing the length of IRP-
based contracts from 20 years to two years.
I The "published rate" and published rate eligibility cap are explained infra in the Background Section I, B.
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IoRDER NO. 33357
I. BACKGROUND
A. The Parties
The tbllowing parties petitioned for and were granted intervention
J.R. Simplot Company
Idaho Conservation League
Intermountain Energy Partners (IEP)
Snake River Alliance (SRA)
Twin Falls Canal Company, North Side Canal Company, and
American Falls Reservoir District No. 2 (collectively, the Canals)
Idaho Irrigation Pumpers Association, Inc. (IIPA)
Clearwater Paper Corporation
Renewable Energy Coalition (REC)
Amalgamated Sugar Company
Micron Technology, Inc.
Sierra Club
AgPower DCD, LLC and AgPower Jerome, LLC
Ecoplexus, Inc.2
B. PURPA
Congress enacted PURPA in 1978 in response to a national energy crisis. "Its purpose
was to lessen the country's dependence on foreign oil and to encourage the promotion and
development of renewable energy technologies as alternatives to lossil fuels." Order No. 32580
at 3, citing FERC v. Mississippi,456 U.5.742,745-46 (1982). Under the Act, the Federal
Energy Regulatory Commission (FERC) prescribes rules for PURPA's implementation. 16
U.S.C. g 824a-3(a), (b). State regulatory authorities such as the Idaho Public Utilities
Commission implement FERC regulations, but have "discretion in determining the manner in
which the rules will be implemented." Idaho Power Co. v. Idaho PUC,155 Idaho 780,782,316
P.3d 1278, 1280 (2013), citing FERC v. Mississippi, 456 U.S. at 751.
To encourage the development of renewable facilities, PURPA requires that electric
utilities purchase the power produced by designated qualifying facilities (QFs). "This mandatory
purchase requirement is often referred to as the omust purchase' provision of PURPA." Order
No.32697 at 7; 16 U.S.C. $ 824a-3(b); 18 C.F.R. S 292.303(a) (exceptions to the "must
purchase" provision inapplicable in this case). Electric utilities are required to purchase power
from QFs at rates equivalent to a utility's avoided cost and approved by this Commission, 16
2oRDER NO. 333s7
2 Ecoplexus filed its Petition to lntervene a month and a half after the deadline for intervention. The Commission
granted Ecoplexus limited intervention in Order No. 3331 L
U.S.C. $ 824a-3; Idaho Power,155 Idaho at789,316 P.3d at 1287. The purchase or "avoided
cost" rate represents the "'incremental cost' to the purchasing utility of power which, but for the
purchase of power from the QF, such utility would either generate itself or pruchase from
another source." Order No. 32580 at 3, citing Rosebud Enterprises v. Idaho PUC, 128 ldaho
624,917P.2d 781 (1996); l8C.F.R.5292.101(bX6). Theavoidedcostratemustbe'Justand
reasonable to the electric consumers . . . and in the public interest" and "shall not discriminate
against [QFs]." 16 U.S.C. $ 82aa-3(b); l8 C.F.R. g 292.304. The Idaho Supreme Court has
observed that the Commission has the authority to implement PURPA and that this grant of
ar-rthority is broad. Idaho Power,l55 Idaho at787,316 P.3d at 1285; Rosebud,l28Idaho at627,
917 P.2dat784;A.W. Brown v. Idaho Power Conrpany,l2l Idaho 812,814,828 P.2d 841,843
( I ee2).
This Commission has established two methods of calculating avoided cost, depending
on the size of the QF project: (l) the surrogate avoided resource (SAR) methodology, and (2)
the integrated resotu'ce plan (IRP) methodology. See Order No. 32697 at7-8. The Commission
uses the SAR methodology to establish what is commonly referred to as "published" or standard
avoided cost rates. Id.; 18 C.F.R. $ 292.3Oa(c). Published rates are available for wind and solar
QFs with a design capacity of up to 100 kilowatts (kW), and for QFs of all other resowce types
with a design capacity of up to l0 average megawatts (aMW). Order No. 32697 al7-8. For QFs
with design capacity above the published rate eligibility caps, avoided cost rates are
"individually negotiated by the QF and the utility" using the IRP methodology based on the
specific characteristics of the resource. Order Nos. 32697 at2;32176 at l.
C. The Three Petitions
L ldaho Power. In its Petition, ldaho Power asserted it has a total of 1,302
megawatts (MW) of PURPA QF projects under contract and "an additional 885 MW of PURPA
solar capacity in the queue actively seeking PURPA Energy Sales Agreements to be on-line in
2016;' Application at 2, 18; Exh. 2, p. I of 6. Idaho Power further asserted that if all these
proposed solar projects come on-line, it would represent a "long-term financial obligation to
customers of approximately $2.I billion, in addition to the existing $2.6 billion obligation over
the life of the Company's projects already on-line and operational." ld. at3. At the technical
hearing Idaho Power clarified that the amount of PURPA generation under contract had declined
JORDER NO. 333s7
from l,302 MW to 1,161 MW but the amount of new solar projects in the queue had increased
from 885 MW to 1,326 Mw. Exh. 11, p. 4 of 4.
Given the possibility for large amounts of additional PURPA generation, Idaho Power
contended that it is reaching a point at which the capacity of the proposed PURPA projects will
exceed the Company's operational needs. Id. at 20. It asserted that this influx of PURPA
generation is unnecessary given the Company's current surplus of generating capacity (aka
capacity surplus) to 2021.3 The Company maintained that continuation of 2O-year PURPA
contracts "places undue risk on customers at a time when Idaho Power has sufficient resources to
meet customer demands." Id. at 2. According to Idaho Power, if it continues to acquire large
amounts of unneeded. intermittent PURPA generation, it will increase its power supply costs and
degrade its system reliability. Id, at20-27.
The Company asserted that its must-take PURPA generation of 461 MW of solar and
must-run hydro would exceed its total system load by about 33% of all hours . Id. at26. Adding
the proposed 885 MW of additional solar would exceed load by about 40%o in all hours. /d-
Idaho Power concluded that its continued obligation to acquire large amounts of PURPA
generation under PURPA's must purchase provision without considering the Company's need
for additional supply is unreasonable and contrary to the public interest. Id. at27-34.
2. Rockv Mountain. On March 2,2015, Rocky Mountain filed its Petition seeking a
leduction in the length of its PURPA contracts. Rocky Motntain requested a permanent
reduction in its PURPA contracts from 20 years to three years "to be consistent with the
Company's hedging and trading policies and practices for non-PURPA energy contracts and [to
be] more aligned with the [two-year] Integrated Resource Plan ("lRP") cycle." Id. at3-4. Rocky
Mountain asserted that it experienced a significant increase in proposed PURPA projects in the
wake of Idaho Power's Petition. Petition at 2. These new requests combined with the large
number of already executed contracts and proposed contracts prompted Rocky Mountain to file
its Petition. Like Idaho Power, Rocky Mountain asserted that it has no need for generating
resources in the next decade. Id. al3.
Rocky Mountain clairned that within five days of the Commission granting interim
relief to Idaho Power, Rocky Mountain received four requests for PURPA pricing totaling 130
r At the hearing, the Company extended its capacity surplus estirnate to 2024 based upon its 2015 tntegrated
Resource Plan (tRP). Tr. at 281 ; see also Case No. IPC-E-15-19.
4ORDER NO. 333s7
MW "fi'om QF developers who are located in Idaho Power's service territory but are now
planning to obtain a transmission wheel to PacifiCorp in order to secure a more favorable 20-
year contract with [PacifiCorpf." Id. at 4-5. With the addition of the fbur new projects, Rocky
Mountain reported that it has 275.5 MW in proposed PURPA projects seeking Idaho contracts, in
addition to the 189.6 MW of projects already approved by this Commission in ldaho. Thus, the
Company has a total of 465.1 MW of existing and proposed PURPA contracts in Idaho. "This
amount. at full nameplate capacity, would be enough to supply 108% of PacifiCorp's average
Idaho retail load in 2014, and 275% of PacifiCorp's minimum Idaho retail load in2014." Id. at
5.4 Idaho'sallocatedshareofPacifiCorp'sexecutedPURPAcontractsoverthenexttenyearsis
$ 156 million, or about $ 15.6 million per year. Id. at21.
In addition to reducing the length of its PURPA contracts, Rocky Mountain requested
authority to modifr its indicative (or incremental) pricing practice to reflect "all active QF
projects in the pricing queue ahead of any newly proposed QF project that requests indicative
avoided cost rates." Id. at 4. More specifically, the Company seeks relief from a prior
Commission Order that required indicative rates be updated based upon "signed QF contracts."
Id. at 32, 35 (emphasis original), citing Order No. 32697 at 22. Rocky Mountain asserted that
this requirement and the drarnatic increase in the number of proposed QF projects results in
indicative pricing that does not reflect the most accurate and up-to-date avoided cost rates. If its
indicative pricing were more robust, the Company maintained that its avoided cost rates would
be $18 per MW hour (MWh) less on aZ}-year levelized basis. 1d at 37.
3. Avista. Avista filed its Petition seeking relief on February 27,2A15, requesting
the same interim and final relief that the Commission provides to Idaho Power or Rocky
Mountain. Petition at 1. Avista observed that the Commission granted Idaho Power interim
relief by limiting new PURPA contracts to five years during the pendency of its investigation.
Order No, 33222. Avista expressed concern that without being afforded similar relief to the
other two utilities, PURPA developers "may seek to sell such output to Avista." Petition at 3.
D. Granting Interim Reltef
After reviewing Idaho Power's Petition, the Commission found that there was
substantial evidence to grant the Company interim relief while the Commission initiated a formal
a PacifiCorp rnaintained that its average ldaho retail load in 2014 was 432 MW and the minimum Idaho retail Ioad
was 169 MW. Petition at 5 n.6.
5ORDER NO. 33357
investigation into the issue of contract length. Order No. 33222 at 4. More specifically, the
Commission directed that IRP-based contracts be lirnited to five years in lengh until the
Commission completes its formal investigation. Even before Idaho Power filed its Petition, the
Cornmission expressed concern that in "less than four months' time, l3 QFs have contracted
with ldaho Power for nearly 400 MW of solar generation - all expected to be on-line and
producing power by the end of 2016.-s Order No. 33222 at 3, quoting Order No. 33209 at 7.
The Cornmission also noted within seven days of Idaho Power's Petition, the Commission had
received four petitions to intervene and one of the prospective intervenors had already filed
discovery. Order No. 33222 at 4. The Commission tbund that the influx of numerous "PURPA
contracts could significantly and detrirnentally impact customer rates and system reliability
before this matter is fully resolved." .Id Consequently, the Commission found that interim relief
limiting the length of IRP-based contracts pending resolution of the investigation is warranted.
"[T]his interim measure will enable the Commission to address the PURPA implementation
issues raised in this case, without having to simultaneously manage a continued tide of new
PURPA cases." /r/.
After Rocky Mor.rntain and Avista filed their Petitions, the Comrnission also granted
interim relief to the two utilities. Consistent with its prior Order Nos. 33222 and 33250, the
Commission found there was substantial evidence to grant interim relief to the utilities for all
IRP-based projects while the Commission investigated the issue of contract length. Order No.
33253. The Commission ordered that the three Petitions be consolidated into a single proceeding
and set a deadline fbr intervention of March 27,2015. Order No. 33250 at 8. The informal
prehearing conference in the consolidated case was held on March 10,2015. At the prehearing
conference, the parties developed a schedule for processing the consolidated proceeding and
discussed two petitions to clarify the scope of the case (see next Section). In Order No. 33253,
the Commission adopted the procedural schedule recommended by the parties and set the
technical hearing for June 29,2015.
E. The Two Petitions to Clarify the Scope of the Case
1. SAR vs. IRP Contracts. In February 2015, Intermountain Energy Partners (tEP)
and Renewable Energy Coalition (REC) each filed petitions seeking clarification regarding the
scope of this docket. Briefly, IEP and REC sought to clarify whether the proposed reduction in
'The l3 projects were proposed byjust three developers
ORDE,R NO. 33357 6
contract length is limited to those new QF projects that exceed the published rate eligibility cap
(i.e., IRP-based methodology projects). At the prehearing conference on March 10,20l5, the
parties to the case generally agreed the Commission should clarify its Order No. 33222 to
indicate that interirn relief of the five-year contract should apply only to new PURPA IRP-based
contracts not SAR-based published rate contracts. In Order No, 33253, the Commission agreed
and clarified that the scope of this proceeding addressed only the length of IRP-based PURPA
contracts. Order No. 33253 at 4.
2. Limitation to Wind/Solar Contracts. On February 25,2015, Clearwater Paper and
J.R. Simplot Company filed a.ioint petition to also clarify the scope of interim relief granted to
Idaho Power in Order No. 33222, and to limit the scope of the requested permanent relief. In
their petition, Clearwater and Simplot sought to limit the interim relief of five-year PURPA
contracts to only new "intermittent (solar and wind powered) projects." Joint Petition at 4.
Idaho Power, Rocky Mountain and Comrnission Staff opposed the clarification proposed by
Clearwater and Simplot.
In Order No. 33286, the Commission found no basis at this early stage of the
proceeding to restrict the interim relief granted to the three utilities to "only wind and solar
intennittent" resources. The Commission observed that the procedural schedule for the
investigation is "expeditious enough" and that Clearwater and Simplot agreed to the expedited
schedule. Order No. 33286 at 5.
II. PUBLIC COMMENTS
The Commission received nearly 200 written comments in this consolidated case. Of
those, roughly 30 comments suppofted the petitions to shorten the PURPA contract length, and
the rest opposed. At the public hearings, the Commission heard tiom 2l witnesses, all of whom
opposed the petitions. These comments ale discussed below.
A. Supportfor Petitions
Those commenting in favor of shortened PURPA contracts included a number of
companies that are large consumers of electric power. Those companies cited an interest in
keeping power costs low and [air, and ensuring reliable service. Several of the companies
commented that the utility should not "be required to buy electricity it does not need." A number
of Idaho school districts and community colleges also supported the petitions, noting the
7ORDER NO. 33357
importance of "maintaining low operational costs." and supporting "a balanced approach" to
encouraging wind and solar power.
Several large and small municipalities and Boise County also supported the petitions.
These entities noted the importance of power reliability and affordability: some expressed that
the utilities' requested relief was reasonable and balanced. These comments were echoed by a
number of business development organizations and local chambers of commerce, which also
expressed that the requested relief was good for development.
Finally, a handful of individuals supponed the petitions. These individuals listed
concerns for power reliability and maintaining low corlsumer electricity rates. Some expressed
that the requested relief was "best for ratepayers" or in the "best interests of Idaho."
B. Opposition to Petitions
The City of Ketchum, the League of Women Voters, and a number of organizations
tjled comments opposing the petitions. These entities cited the need to promote renewable
energy and distributed generation, and claimed that the requested permanent relief would
eliminate solar development in ldaho. Ketchum also expressed concern that shortening PURPA
contracts would eliminate community solar projects. Zahren Financial commented that
shortening PURPA contracts as proposed by the utilities would impact its ability to invest in
Idaho. Idaho Smart Growth asked that the utilities be required "to do all they can to continue to
shift their power purchasing to renewable sotuces, and . . . to encourage them to embrace new
models of clean energy production and distributed power."
A number of renewable energy developers also commented that shortening PURPA
contracts would make it extremely difficult, if not impossible, for them to obtain the financing
needed to develop their projects. Two developers proposed adopting an alternative to shortening
20-year PURPA contracts. They suggested the Commission maintain 20-yeu contracts, but
allow the energy rate component of the contract to be adjusted annually after the first ten years of
the contract. Pristine Sun and Renewable Northwest Comments.
Finally. more than 130 individuals sent written comments opposing the petitions, and
21 individuals opposed the petitions at public hearing. Most of those comments and public
witnesses expressed the need to foster solar power development or "keep solar [development]
viable." Many comments expressed the need to move away from coal and other fossil fuels
toward clean energy. Several public witnesses noted that ratepayers were required to pay for the
8ORDER NO. 33357
costs ol transrnission lines for 20 or more years, so requiring 2}-year contracts for solal power is
"only fair." A number of comrnents asked that the Cornmission "do what's right" for the future.
And some comments expressed that utilities have not shown the need for their requested relief
except to ensure the utilities increasing profits.
Commissiott Discttssion: The Commission appreciates the considerable time and
expense that participants dedicated to testifying in the public hearings, and the thoughtfulness
evident in so many of the oral and written comments. The Commission recognizes that a large
number of tlre public commenters encouraged the development of more solar and other
renewable energy resources. Many of these same individuals also wanted the use of coal to be
phased out. Finally, there were many concerns about retaining low and reasonable customer
rates.
In direct response to the public concerns, we note that PURPA is not the only avenue
to develop renewable resources. As Dr. Don Reading testified at our technical hearing, utilities
have and will probably continue to develop non-PURPA renewable resources in the future
through a variety of means. Tr. at 868-70. Indeed, as several witnesses pointed out in our
hearing, the utilities have developed or purchased hundreds of MW of non-PURPA renewable as
part of their generation portfolio. Tr. at 93 1, I 1 I , 177 -78. Moreover, acquiring more renewables
while maintaining low rates is consistent with the State's 2012Energy Plan.6
III. CONTRACT LENGTH
A. Do FERC Regulatiotts Dictate the Length of Controcts?
The Commission first addresses whether the proposals to reduce the IRP-based
PURPA contracts from 20 years are inconsistent with PURPA or FERC's regulations. ICL and
Sierra Club's witness Adam Wenner testified that Idaho Power's proposal to reduce the length of
contracts to two years is inconsistent with either FERC regulations or Idaho precedence for three
reasons. First, he maintained that QF contracts were intended to provide both energy and
capacity to the utility. PURPA and FERC's implementing regulations require that QFs be paid
for capacity when a QF contract "enables the utility to replace new capacity with QF purchases."
Tr.at583. Ifcontractsarelirnitedtotwoyears,heinsistedthatthecapacityaQFcouldprovide
under its contract to the utility could not be "counted on to be available after two years. ." Tl'.
6 The Plan states that ldaho's "utilities need to have access to a broad variety of resources, both conventional and
renewable, and nothing in this Energy Plan should be read as precluding a utility from investing in a particular
resource." Section 6.2.2 at I l5 (emphasis added).
9ORDER NO. 333s7
at 587. In other words, a utility could not cancel or displace planned generation based on such a
short two-year commitment.
Second, he rnaintained that short-term contracts impede a QF's ability to perfect a
legally enforceable obligation (LEO), Under either a negotiated contract or a LEO,7 a QF has an
option to receive avoided cost rates either calculated at the time of delivery or at the time the
obligation is incurred. 18 C.F.R.5 292.304(dX2). He noted that in Order No. 69, FERC
mentions that a QF may desire levelized payments (where a QF may wish to receive a greater
percentage of the total purchase price during the begiruring of the obligation than at the end of
the contract term), if it enters into a "long term contract to provide energy or capacity to a
utility." Tr. at 591 , citing 45 Fed.Reg . 12,224 (Feb. 25, 1980).
Finally, Mr. Wenner also relied upon a 1984 Idaho Supreme Court case to support his
opinion that QFs are entitled to a long-term contract. Tr. at 591-93, citing Aflon Energy v. ldaho
Pov,er Co. ("A.fion l/lll"), 107 Idaho 781.786,693 P.2d 427,432 (1984). In Afton l/lll,he
noted that the Supreme Court affrrmed an Order of the Commission requiring Idaho Power to
enter into a 3S-year contract with a QF.
Clearwater and Simplot's witness Dr. Reading supported Mr. Wenner's opinion about
the FERC regulations from an economic point of view. He testif,red that shortening the contracts
to two, three, or five years will inhibit the QF from receiving future capacity payments due to the
shortness of the contract. Tr. at777-79. ICL/Sierra Club witness R. Thomas Beach and Snake
River Alliance witness Ken Miller both opposed shortening IRP contracts. Tr. at 630;734.
The three utilities and Commission Staff disputed Mr. Wenner's opinion that FERC
regulations dictate a long-term PURPA contract. In particular, they point to his testimony where
he acknowledged that FERC rules do not speciff a number of years or other time period for
PURPA contracts. Allphin, Tr. at 215-16; Clements, Tr, at440-41,513-15; Kalich, Tr. at 410-
l2; Wenner, Tr. at 589. Micron also argued in closing that PURPA does not mandate contract
length. Tr. at 988-89. Rocky Mountain Power's witness Paul Clements explained that PURPA
' There are two general methods by which a QF can provide power to a utility: ( I ) by entering into a signed contract
with a utility; or (2) pursuant to a LEO. Order No, 32974 at 13, citing l8 C.F.R. $ 292.30a(d); Power Resources
Grottp v. PUC oJ Texas,422 F.3d 231,237 (5th Cir. 2005); Idaho Power, 155 Idaho at 785, 316 P.3d at 1283.
"FERC specifically adopted the concept of [a LEO] to prevent utilities from circumventing the 'must purchase'
PURPA provision 'merely by refusing to enter into a conffact with' a QF." Order No. 32974 al 13, quoting Power
Resources, 422 F.3d at 238, quoting 45 Fed.Reg. 12,214, 12,224 (Feb.25, 1980).
ORDER NO. 33357 t0
gives state regLllatory agencies the discretion to establish the key terms and conditions of PURPA
contracts. Tr. at 439-441.
Staff witness Rick Sterling testified that FERC regulations "are silent on [the issue ofl
contract length." Tr. at 902. He further maintained that FERC regulations only require utilities
to provide five years of data to calculate the energy component of a utility's avoided cost rates
and only ten years of data to calculate the capacity component of the avoided cost rates. Id. at
902-03. These forecasts "are much less than the 20-year contract." Id. at9O3.
Mr. Clements and several other witnesses also noted that the length of PURPA
contracts in Idaho has not been static. The Commission initially set contract terms for 35 years
"to match the amortization period allowed for similar utility-owned facilities"; later shortened
the contract length to 20 years; and shortened the contract length to five years in 1996 and 1997
"to align the QF contract timeframe with the utilities' acquisition strategies." Tr. at 441-43
(footnotes omitted); Grow, Tr. at 124-26. ln 2002, the Commission raised the contract length
back to 20 years. Tr. at 443; Sterling, Tr. at 897-98. Mr. Clements also noted that the
Washington Commission sets standard avoided cost PURPA contracts in Washington for up to
five years. Id. at513.
Although Rocky Mountain recommended that the length of QF contracts be reduced
to three years to coincide with the Company's hedging and planning process, Mr. Clements
explained that limiting contracts to a three-year term
does not mean that the [QF] project will only have a three-year life. Rocky
Mountain Power will be required to purchase the power produced by the
project as long as PURPA requirements exist and the project qualifies as a QF
under PURPA. Limiting the term of the contract to three years simply means
that the price Rocky Mountain Power and its customers will be required to
pay to the QF will be subject to adjustment every three years and be more
closely aligned with Rocky Mountain Power's current avoided cost.
Tr. at 5ll-12.
Commission Findings: As several parties observed, this Commission has set
different contract lengths for PURPA contracts over the years. When PURPA was first
implemented in Idaho, this Commission established a maximum contract term of 35 years, which
it shortened to 20 years in 1987. Order Nos.21018,21630. The term was reduced to five years
in 1996, and raised back to 20 years in2002. Order Nos.26576,29029. Over the years the
Commission has considered many factors (price risk, forecasting uncertainty, financing needs,
ilORDER NO. 33357
amonization, plant durability) when establishing contract length. Order No. 32125. In February
2015, we granted interim and temporary relief in this matter, reducing the length for PURPA
contracts from 20 years to five years, pending this final Order. Order No. 33222 at 4,6.
As the Idaho Supreme Court recently stated in ldaho Povver Co. v. Idaho PUC, a state
commission "has discretion in determining the manner in which the [PURPA] rules will be
implemented, and may comply by issuing regulations, by resolving disputes on a case-by-case
basis, or by other actions reasonably designed to give effect to FERC's rules." 155 ldaho at782,
316 P.3d at 1280, citing FERC v. Mississippt,456 U.S. at 751. It "is up to the States, not
[FERC] to detennine the specific parameters of individual QF power purchase agreements. . . ."
Id. at786,316 P.3d at 1284, quotittg Power Resources Group v. PUC of Texas,422F.3d23l,
238 (sth Cir. 2005).
Based upon our review of federal court and state Supreme Court precedent, the
testimony of the parties, PURPA, and FERC's implementing regulations, we find that PURPA
and FERC regulations do not specify a mandatory length for PURPA contracts. As noted above,
when PURPA was enacted, it was intended to encourage the development of renewable
resources. Order Nos. 32697, 33250, 32125. PURPA "establishes a program of cooperative
federalism that allows the States, within limits established by federal minimum standards, to
enact and administer their own regulatory programs, structured to meet their own particular
needs." Idaho Power,l55 Idaho at782,316 P.3d at 1280, citing FERC v. Mississippi, 456 U.S.
at767. Even Mr. Wenner acknowledged that FERC regulations do not dictate a specific number
of years or establish a time period for PURPA contracts. Tr, at 589. [t is not contested that
PURPA, and its implementing regulations, are silent as to a specific contract length. Mr.
Wenner's reliance on the Afton l/Iil case is misplaced. As our Supreme Court noted in the first
sentence of its opinion, the basic issue presented in Afton I/III is whether the Commission "has
authority to order an electric utility to purchase power from a [QF] for a fixed term according to
avoided cost rates previoursly approved by the Commission." Afion l/lll, lO7 Idaho at 782,693
P.2d at 428. Consequently, we find the issue of contract length is left to this Commission's
discretion. See Afton l/lll, lO7 Idaho at 785-86, 693 P.2d at 431-32; Idaho Power, 155 [daho at
782,316 P.3d at 1280.
oRDER NO. 33357 12
B. Are 20-Year Contracts Reasonable?
The thlee utilities and Commission Staff generally assert that Z}-year contracts are no
Ionger appropriate and should be shortened. Their witnesses otfer several reasons to discontinue
the 20-yeal contracts. Clearwater, Simplot, ICL, SRA and other parties urge the Commission to
retain 20-year contracts. As an alternative to reducing the length of the 2}-year contract,
Clearwater/Simplot and ICL recommend the Commission consider "modifuing" the 20-year IRP-
based, fixed-rate contract by adjusting the energy component of the avoided cost rates after the
first ten years. We explore those issues in greater detail below.
1. Idaho Power. Idaho Power's Senior Vice President. Lisa Grow, laid out several
reasons why the Company believes that 20-year fixed-rate contracts are no longer reasonable.
First, she asserted it was unreasonable for the Company to enter into long-term, fixed-rate
contracts when the Company does not need additional generation. Tr. al l17,l19. She reported
tlrat the Company's peak-load for its system in2014 was about 3,184 MW, while its minimum
load was approximately 1,073 MW. Tr. at 107-08. In comparison, she noted that the
Company's Exhibit 2 showed that Idaho Power had. 1,2978 MW of renewable, nameplate energy
(both PURPA and non-PURPA) on its system or under contract, excluding the Company's l7
hydroelectric facilities.e Tr. at 109. This renewable generation consists of:
728 MW of wind (including l0l of non-PURPA wind)
320 MW of solar under contractro
35 MW of non-PURPA geothermal
214 MW of PURPA hydro and other renewable
1,297 MW renewable (nameplate capacity)
Tr. at lll, 177; Exh. 11, p.2. Thus, Idaho Power's PURPA and non-PURPA renewable
resources can be used to meet about 40Yo of its 2014 system peak-load and used to meet about
l20Yo of its 2014 minimum system load.
Idaho Power witness Randy Allphin asserted that the Company has no need for
additional generation "in the near term." Tr, at 206. He initially testified that the Company's
recently released draft of its 2015 Integrated Resource Plan shows that the Company has a
t This figure is corrected to show the removal of l4l MW of approved solar contracts that were subsequently
terminatedforfailingtoposttheirrequiredsecurifydeposits. Tr.at376; seeExh. ll,p.2.
o The Company's hydroelectric facilities total more than 1,700 MW of nameplate capacity.
to Id.
ORDER NO. 33357 t3
capacity sLlrplus for l0 years, until2025. Id. In his rebuttal testimony. he noted that the loss of
the 141 MW of contracted soiar generation caused the Company to refine its capacity deficiency
estimate to Jr.rly 2024,1I Tr. at 281; Order No. 33343 at 2 (Case No. IPC-E- 15-20).
When the Company has surplus capacity, it reduces the overall avoided cost rates
paid to QFs. Avoided cost rates ale typically comprised of a capacity component and an energy
component. Ms. Grow explained that if a utility has surplus capacity at the time it enters into an
IRP-based contract with a QF, then the QF does not receive capacity payments until the utility
experiences a capacity deficiency. Tr', at 137. A utility's capacity status (e,g., surplus or
deficient) is determined in each utility's Integrated Resource Plan.
In addition to the operating PURPA projects and those under contract, both Idaho
Power witnesses observed at the time they filed their direct testirnony, that the Company had
received proposals for an additional 885 MW frorn solar developers, Tr, at 120,177; Exh, l-2.
At hearing, the Company subsequently increased this amount of proposed solar projects from
885 to 1,326 MW. Exh. 11, p. 4 of 4. Ms. Grow repeated the concerns voiced by the
Comrnission when it recently approved 400 MW of new solar projects. After recognizing the
"mlrst purchase" provision of PURPA, she quoted fiom the Order:
Idaho Power's 2013 Integrated Resource Plan does not reflect that the
utility is in need of energy to reliably serve its customers. And yet, in less
than four months time. 13 OFs have contracted with Idaho Power for nearly
400 MW of solar generation - all expected to be on-line and producing power
by the end of 2016. The combined 2O-year obligation of these l3 projects is
approx $ I .2 billion.100% of the costs of QF generation are passed
onto ratepayers.
. . . QFs continue to request contracts with Idaho Power in significant enough
numbers that we remain concerned about the Company's ability to balance the
substantial amount of must-take intermittent generation and still reliably serve
customers.
Tr. at I 2I-22 (citations omitted) (emphasis added).
Second, Ms. Grow maintained it was unreasonable and no longer in the public
interest to maintain long-term, fixed-priced ZU-year contracts while PURPA avoided cost rates
continue to decrease. Tr. at 119. On cross-examination, Mr. Allphin agreed that the avoided
cost rate for each new QF will decrease as "older" QFs add capacity to the system. Tr. at 260-
tt 5"" strpru note 8.
ORDER NO. 33357 t4
6l; Exh. 207. Ms. Grow also noted that the Company's Exhibit 7 shows that from 2004 to 2024
the Company's power supply expense increased approximately 575%o. Tr. at 129. Allowing QF
developers to obtain fixed prices over the long term causes eleclric rates to increase. Ms. Grow
pointed out that the Company's Exhibit l0 shows that Idaho Power's average cost for PURPA
generation since 2001 has always exceeded the Mid-Columbia (Mid-C) index price and is
projected to continue to exceed the Mid-C price through 2032. Tr. at 129. She and Mr. Allphin
testified that the average cost for PURPA purchases at 562.49 per MWh is greater than the
average cost of coal (S22.79iMWh), the cost of gas ($33.57iMWh), non-PURPA purchases
($50.64lMWh), and "significantly greater than what is being sold fby the Company] as surplus
sales at 522.41 per MWh." /d; Allphin, Tr. at 191-92. This continued increase in net power
supply costs adversely impacts ratepayers because these escalating costs are passed on to
ratepayers.
Third, the Company's witnesses argued it makes little sense to require Z}-year fixed-
rate contracts for IRP-based PURPA projects when avoided cost rates are reset every two years
under the IRP methodology. Ms. Grow noted that the IRP rnethodology is updated every two
years to reflect current market conditions, customer growth, natural gas forecasts, and other
conditions. Tr. at 127,287. The IRP methodology is a good fit with the Company's risk
management practices which limit power purchases and sales to l8-24 months. Tr. at 127-28,
287. She explained that before Idaho Power can acquire a long-terrn resource like a generating
unit, there is a long and involved process for deterrnining whether it is necessary and in the
public interest for the Company to acquire a generating resource. Id. at 128. Typically, the
Company assesses the need for such a resource; determines the type of resource necessary;
examines how the operating characteristics of the resource fit into the Company's resource stack;
requires that the resource be acquired through bidding and that the Company be able to dispatch
the resource; seeks the approval of the Comrnission for a CPCN; and submits to a public process
before the Commission. Then there is a subsequent case before the Commission permits a new
generating plant to be placed into rate base. Tr. at 140; Allphin, Tr. at 196-200,205. Purchasing
the output of PURPA projects is not subject to these safeguards.
2. Rocky Mountain Power. Rocky Mountain Power's witness Paul Clements also
recommended the Commission reduce the length of IRP-based contracts from 20 years. He
maintained that PURPA was intended to encourage the development of renewable resources at
ORDER NO. 33357 l5
rates that: "(a) are just and reasonable to electric consumers, (b) do not discriminate against QFs,
and (c) do not exceed'the incremental costto the electric utility of altemative electric energy."'
Tr. at 435, citing l6 U.S.C. $ 82aa-3(b). He noted that both this Comrnission and FERC have
indicated that the avoided cost price structure "was to make ratepayers inditTerent as to whether
the utility used more traditional sources of power or the newly-encouraged [QF] alternatives."
Tr. at 439, quoting Southern Califurnia Edison Company, Tl FERC n il,269 at p. 62,080 (1995),
overruledon other grounds,California PUC,l33 FERCfl6l,059(2010); Tr.at435-37.
He requested that the Commission reduce Rocky Mountain's lRP-based contracts
from 20 years to tluee years for several reasons. Tr. at 433. First, like Idaho Power, Mr.
Clements testified that Rocky Mountain/PacifiCorp has a capacity surplus until 2028, and has no
need for additional generation until that time, Tr. at429. tf all the proposed contracts were to
become operational, the existing and proposed PURPA contracts would be enough to supply
108% of PacifiCorp's average retail load and275o/o of its minimum retail load in Idaho in 2014.
Tr. at 427.
Second, Mr. Clements insisted the 20-year, f,rxed-rate contracts violate the rate
neutrality standard and act as a subsidy to the QF "because FERC generally requires a utility to
lock in forecasted avoided cost rates tbr the entire contract term." Tr. a|441,445 (Regulations
ImplementingSection2l0of PURPA,45 Fed.Reg. 12,214,12,224 (1980)). Aproposed}}-year
project can obtain a "fixed-price energy contract at the Company's projected avoided cost,
without any economic considerations or pricing adjustment to account for the risk to utility
customers from this unusual long-term transaction, or to the QF to account for the price certainty
the QF enjoys liom such a contract." Tr. at 445. Granting a2}-year contract with no adjustment
to the price is something no other market participant enjoys and subjects ratepayers to
unreasonable price risk. Tr. at 446-47.
He explained that the Company treats QF contracts as "system resources" and
allocates these resources to the six states served by PacifiCorp. Idaho's share is approximately
6Yo. Tr. at 463. He stated that the expected system-wide payments to PURPA projects over the
next ten years are $2.6 billion. In 2015, this equates to QF payments of $170.5 million, "with
Idaho's allocated share at $10.2 million." Tr. a|463. If the avoided cost rates forthese projects
are priced incorrectly by just l0%o, that would create an additional impact for Idaho ratepayers in
2015 of $1.0 million, and grow to a total of $15.5 million over the next l0 years. Tr. at 463.
oRDER NO. 33357 t6
Consequently, he stated it was imperative that avoided costs accurately reflect the Company's
actLral avoided costs during the term of the contract. Tr. at 464.
Third. Mr. Clements explained that the Company's proposal to reduce the 2O-year
IRP-based contract is intended to match the Company's risk management and hedging policies -
the Company is generally limited to power purchase contracts of 36 months or less. Tr. at 469.
For non-PURPA contracts, the Company enters into purchase transactions that exceed three
years "only when there is a clearly identified long-term resource need in its IRP. Long-term
resource needs are typically identified in the IRP only after lower-cost, lower-risk, short-term
resource opportunities are exhausted." Tr. at 47l. The Company avoids long-term, f,rxed-price
energy contracts because they carry significant price risks. Tr. at 474-75. Shortening the
contract term to three years will more closely align the lRP-based contract to the two-year IRP
cycle, the three-year hedging plan, and the two to four year IRP action plan. Tr. at 479-80,486.
Finally, Mr. Clements noted that PacifiCorp's cogeneration QFs (often referred to as
combined heat and power - or CHP - QFs) do not need long-term contracts for financing
purposes because these facilities are usually financed by their host businesses. Tr. at 476. He
insisted that rnost cogeneration facilities "typically elect short-term contracts with PacifiCorp
even when 20 year terms are available. ln fact, most [cogeneration QFs] elect annual contracts
that are renewed each year at the then-current avoided cost." Tr. at476-77. These QFs prefer to
take the spot or near-term avoided cost price to eliminate the price risk that comes from long-
term fixed-price contracts. Tr. at 477. On cross-examination he stated that all of PacifiCorp's
cogeneration PURPA contracts are short-term, "typically one year or less." Tr. al54l.
He concluded by observing that given the exponential increase in existing and
proposed QF contracts for PacifiCorp,
it is critical to quickly adjust pricing and contracting procedures now that
problems with those procedures have been identified. The current
Commission-approved PURPA contract length puts retail customers at risk of
harm due to significant and turnecessary exposure to long-term price risks. a
level of risk the Cornmission would not accept in the context of a non-PURPA
transaction. The Company has no control over this price risk; it must purchase
essentially an unlimited quantity of QF power under terms and conditions the
Commission controls. Under PURPA, only the Commission can mitigate this
price risk to customers.
ORDER NO. 33357 17
Tr. at 489-93 (empliasis added). The shorter contract term is necessary to rebalance the must
purchase provision that t'avors QFs with the ratepayer indifference standard.
3. Avista. lf the Commission decides to shorten the length of IRP-based contracts
fbr Idaho Power or Rocky Mormtain, Avista requested the Commission to provide it with the
same relief. Tr. at 404, 408. Its witness Clint Kalich requested that the utility be afforded
similar relief "to ensure a level playing field across the Commission-regulated utilities." Tr. at
410. He asserled the Commission has the authority to shorten IRP-based contracts, Tr. al4l2.
Mr. Kalich acknowledged that Avista has not received any proposed solar projects
and that Avista has not been inundated with QF proposals like the other two utilities. Tr. at 414-
15. He explained that different contract lengths among the utilities could cause an increase in
filings at Avista if it had longer term contracts than the other two utilities. Tr. at 406-07.
However, he did want Avista to maintain the option of having lRP-based contracts longer than
five years if the terms of such contracts "are found by Avista and the [Commission] to be in the
interest of utility customers. It is not possible to know every circumstance where a longer term
agreement may be waranted." Id. a|410.
4. SlAft. Commission Staff urged the Commission to reduce the 20-year term for
IRP-based contracts to five years. Staff witness Rick Sterling testified that long-term contracts
"based on fbrecasted rates create greater risks for customers because the rates in the later years
are not reflective of avoided costs." Tr. at 902. He explained that one of the major factors in
IRP-based contracts is the price of natural gas. "A long-terrn f,rxed price could possibly be
accurate just once during its term - at the beginning of the contract when the rates are first
established. The shorter the term of the contract, the more frequently prices can be adjusted to
ensure they accurately represent the true value of the power. A shorter term contract helps to
minimize the risk to ratepayers." Tr, at 905, 903. Because PURPA costs are passed on to
customers through the Power Cost Adjustment (PCA) mechanisms, ratepayers are fully exposed
to the risks if PURPA rates prove to be too high. Tr. at 906. Conversely, fuel costs for utility-
owned resources are tracked annually and the rates adjusted annually.
Mr. Sterling further testified there were legitimate reasons why utilities were
permitted to develop or acquire long-term generating assets but lRP-based PURPA resources
should be restricted to two, three, or five-year contracts. Tr. at 915-16. He explained that when
a utility acquires a resource it is usually a result of the Company's Integrated Resource Plan. As
ORDER NO. 33357 l8
such, the utility resource is picked from a range of alternatives, is procu'ed through a competitive
process, and is contingent upon Commission approval in a public process. /d Moreover, utility
generating facilities have fuel costs that are annually adjusted and these facilities are
dispatchable based upon the Company's load and generation requirements. Tr. at 917. On the
other hand, PURPA projects are entitled to long-term contracts at fixed rates, acquired without
consideration of need, undergo no competitive bidding, and their avoided cost rates are not based
upon cost-based pricing. Tr. at 917,925. He also noted that PURPA projects entirely
circumvent the tRP planning process. Tr. at 91 8.
He also testified that the utilities have developed non-PURPA renewable resources.
For example, Palouse Wind and Clearwater sell their power to Avista, and Elkhorn Wind sells to
ldaho Power. Tr. at 931.
5. Idaho Irrigation Pumpers Association. The Irrigators offered the testimony of
their witness Anthony Yankel, who supported tdaho Power's initial request to limit new [RP
contracts to two years. Tr. at 301. Mr. Yankel explained that the flood of projects presents
Idaho Power with a balancing problern of having to choose between curtailing its own must-run
facilities, or its must-take PURPA contracts. Tr. at 305. He recommended the Commission
reduce IRP contracts to two years as a "stop gap measwe" while the Commission further refines
the Company's models and modeling assumptions with actual Company operations. Tr. at 305.
He also supported limiting new solar and wind projects to two years because of their intermittent
nature. Tr. at 307.
6. lntermountain Enerey Partners. IEP presented the testimony of its president, Mark
van Gulik. He testified that the downward trend in avoided cost rates in Idaho means that fewer
projects will be able to obtain financing and come on-line. Consequently, there is not an urgency
fbr the Commission to shorten contract lengths. Tr. at372.
As the developer of the Clark I through 4 solar projects, he explained the four
projects were terminated when they were unable to make their required security deposits. Tr. at
376-77. He did not indicate that contract length contributed to the termination of these four
projects totaling 141 MW of nameplate capacity. Because Idaho does not have attractive state
tax incentives, he foresaw little likelihood for IRP-based projects to be able to attract the
necessary capital if their contract terms were less than 15 years. Tr. at 386.
oRDER NO. 33357 t9
7. ICL/Sierra Club. ICL's and Sierra Club's second witness was Thomas Beach who
urged the Commission to retain the 2O-year IRP-based contract. Tr. at 630-52. He indicated that
cunent indicative pricing for levelized avoided cost rates continues to decline by "more than
50% below the $60 to $64 per MW range of avoided costs for the recently-approved 2}-year
solar contracts." Tr. at 630-31;Table 3 at Tr. 642 (footnote omitted). Reducing the length of 20-
year long-term contracts as avoided cost rates continue to decline, "appears likely to make
uneconomic QFs that could be developed at avoided cost prices with a long-term agreement."
Tr. at 631 . He noted that when the Commission reduced lRP-based contracts to five years
between 1996 and 2001, only one PURPA contract was executed during that time with Idaho
Power. Tr. at 632.
He maintained that Idaho Power's IRP methodology is generally working well as
indicated in the decline in avoided cost rates for solar contracts as shown in Table 3 of his
testimony. Tr. at642. Of the 48 projects totaling 885 MW, only 14 have progressed far enough
to receive indicative pricing, and of those, only one has requested a contract. Tr. at 644. "As
more solar capacity has been added, the avoided cost price has fallen based on ldaho Power's
capacity position and future needs." Tr. at 644. And, as "avoided cost prices fall, fewer projects
will be built." 1d-
8. Clearwater Paper and J.R. Simpiot Company. Clearwater and Simplot presented
the testimony of their witness Dr. Reading who opposed efforts to reduce the length of the IRP-
based contracts from 20 years. Dr. Reading insisted that conditions have not changed since the
Commission last decided to resumeZ}-year contracts in 2012. In particular, he argued that the
only condition that may have changed since 2012 was that the utilities' avoided costs may have
decreased but that does not mean the term of the contract should be reduced. Tr. at 785-86. He
argued that reducing the contract length to five years or less will not encourage the development
of renewable resources. Tr. at 778-79. He insisted that reducing the contract as proposed by the
utilities and Staff will make it impossible for a QF to obtain financing for their projects. Id. He
noted that the last time the Commission reduced PURPA contracts to five years, "only one
PURPA contract was signed in Idaho with the shortened contract length." Id. at780.
He maintained it would be unreasonable to limit tRP-based contracts to five years
when the recovery of investment for utility-owned resources is much longer, and in some cases
ORDER NO. 33357 20
up to 50 years. He argued that PURPA resources should be placed "on an equal footing with
utility-owned resources . . . [and] should receive longer-term contracts." Tr. at 781.
He next compared the cost of PURPA projects with the cost of Idaho Power's
generating resources. He determined that the price per MWh of Idaho Power's PURPA projects
compare favorably to the Company's facilities. See Chart No. I at Tr. at 793. In preparing his
chart and analysis, he acknowledged that he removed Idaho Power's hydro facilities ("the
Company's lowest cost resource with the depreciated rate base and very low variable running
cost"). Tr. at 794. He removed these lower cost facilities from his analysis because streamflow
conditions vary from year-to-year and the cost of relicensing Idaho Power's largest hydro
complex (Hells Canyon) is not yet known. Tr. at794-95.
He also testified that cogeneration projects are unique from other types of PURPA
projects and are deserving of continued access to long-term IRP contracts. Tr. at 819-23. He
argued that Idaho Power's Petition primarily points to the problem of oversupply from
"intermittent and relatively unpredictable PURPA output from wind and solar projects." Tr. at
823. Consequently, he suggested that any reduction in the length of IRP contracts not apply to
cogeneration proj ects.
9. Snake River Alliance. Ken Miller testified on behalf of SRA. He opposed
reducing the 2O-year IRP-based contract length and expressed concern that development of
utility-scale solar will be impaired. Tr. at 734. As the Environrnental Protection Agency (EPA)
finishes its Clean Power Plan,l2 Idaho's utilities will have greater need for solar as they reduce
tlreir reliance on their coal-fired generating facilities. Tr. at 735-36. Given the projected
reductions in coal-fired generation, the shrinkage in the utility's projected overcapacity will
likely prompt utilities to need more solar generation. Tr. at739-40.
Commission Findings: We recognize that PURPA was intended to encourage the
development of renewable resources. Order Nos. 32580 at 3; 32697 , citing FERC v. lulisstssippi,
456 U.S. at745-46. Indeed, this Commission has a long history of encouraging PURPA projects
and renewable energy development in ldaho. Order No. 32697 at 14. As shown in Idaho
Power's Exhibits 1 and ll, the growth of renewable generation started modestly. Idaho Power
accumulated less than 200 MW in 25 years (roughly from 1982-2007). Since 2007, PURPA
generation has increased dramatically, and for Idaho Power in particular, its PURPA generation
'' EPA issued its Clean Power Plan on August 3, 201 5
oRDER NO. 33357 21
under contract has grown to about I ,l6l MW - nearly a six-fold increase. Exh. I 1. In just three
months (lrlovember 2014 through January 2015), the Commission approved l3 solar contracts
totaling more than 400 MW.
To encourage the development of renewables, PURPA and FERC regulations lay out
several standards, tw'o of which uue paramount in this case. First, PURPA requires that electric
utilities "must purchase" the power produced by QFs. QFs are paid based on costs that the utility
avoids. Order No. 32697 at 7;16 U.S.C. $ 824a-3(b); l8 C.F.R. $ 292.303(a). A utility's
avoided cost represents the incremental cost to the purchasing utility of power which, but for the
purchase of power from the QF. such utility would either generate itself or ptuchase from
another source. Order No. 32580 at 3, citing Rosebud, 128 Idaho at 627,917 P.Zd at 784.
PURPA and FERC regulations require that the avoided cost rate must be "just and reasonable to
electric consumers of the utility and in the public interest, and shall not discrirninate against
[QFs]." Order No. 32697 at 16, ciling 16 U.S,C. $ 824a-3(b); 18 C.F.R. $ 292.30a(aXl)
(internal punctuation omitted).
Second, FERC regulations allow a QF to choose to have the avoided cost rates for the
purchase of its power calculated in one of two ways: ( I ) at the tirne of delivery; or (2) at the time
it enters into the contract/obligation for the delivery of power. l8 C.F.R. fi 292.304(d); 45
Fed.Reg. at 12,224. In Idaho, most IRP projects choose to havethe avoided cost rates calculated
or "fixed" at the time the contract obligation is incurred with their actual operation/on-line dates
one to two years later. Thus, the rates are fixed for the duration of the 2}-year contract.
The Idaho Supreme Court has recognized that PURPA contracts represent a "special
type of contract." Afton l/lll, 107 Idaho at793,693 P.Zd at439; Afton Energy v. Idaho Power
Co. ("AftonV"),114 Idaho 852,854,761P.2d1204,1206 (1988); OrderNo.32802 at 17. We
have also said in prior Orders, PURPA contracts are special because "federal law compels
utilities to purchase power without arrns-length bargaining and without regard to whether the
utility needs the power. Even if QF power replaces power the utility wor-rld otherwise
generate, ratepayers are ultimately paying for both the capital assets of the utility's base load
generatingplant in rates and the QF power." OrderNo.32802 at 17-18.
Returning to this case, there seems to be general agreement among the parties that as
more PURPA power is offered to the utility, the avoided cost rates for IRP projects will decline.
Tr. at 260-61;' 372; 630-31 ; 642, It is therefore axiomatic that long-term avoided cost rates
ORDER NO. 333s7 22
detennined at the tirne parties enter into their contract will "overestimate" future avoided costs
collected from the utilities' ratepayers. Because of the 2}-year term of the cument IRP-based
contracts, this "overestimation" will become more significant over the duration of the contract.
When FERC issued its initial PURPA regulations, it acknowledged that avoided costs
calculated when the parties enter into the contract might result in future avoided costs over the
term of the contract being greater than actual avoided costs at the time of delivery. FERC
recognized that in such cases a utility "would subsidize the [QF] at the expense of the utility's
other ratepayers." 45 Fed.Reg. at 12,224; Tr. at 775-77. In other cases, FERC postulated that
the avoided costs calculated at the time of delivery "will turn out to be lower than the avoided
cost at the time of [contract)." ld. Thus, FERC believed "that, in the long run, 'overestimations'
and 'underestimations' of avoided costs will balance oul." Id.
Based upon our record, we find that 2O-year contracts exacerbate overestimations to a
point that avoided cost rates over the long-term period are umeasonable and inconsistent with the
public interest, We find shorter contracts reasonable and consistent with federal and state law for
multiple reasons. First, shorter contracts have the potential to benefit both the QF and the
ratepayer. By adjusting avoided cost rates more frequently, avoided costs become a truer
reflection of the actual costs avoided by the utility and allow QFs and ratepayers to benefit from
normal fluctuations in the market.
Second, shorter contract lengths do not ultimately prevent a QF from selling energy to
a utility over the course of 20 years - or longer. PURPA's "must purchase" provision requires
the utility to continue to purchase the QF's power. As long as projects continue to offer power to
utilities, utilities must continue to purchase such power under PURPA. A shorter contract length
merely functions as a reset for calculation of the avoided costs in order to maintain a more
accurate reflection of the actual costs avoided by the utility over the long term. Our approach is
not dissimilar to that suggested by witnesses Reading and Beach discussed below.
As an alternative to discontinuing the Zl-year contract, Dr. Reading and Mr. Beach
suggested similar but different alternatives. Dr. Reading suggested that the Commission could
retain the 20-year contract but adjust the energy component in each of the last l0 years of the
contract. Tr. at 842. Mr. Beach suggested that the Commission could make a single adjustment
in the 1l'h year of a2}-year contract. He explained that the 20-year contract could be "repriced
oRDER NO. 33357 L)
after the tjrst l0 years . . . [but] the indicative energy price for Years I 1-20 would continue to be
fixed." Tr. at70l-702.
While we appreciate the concessions evident in these proposed alternatives, we find
the recommendations unpersuasive. An adjustable rate contract runs the risk of violating FERC
regulations that mandate a "fixed rate" at the time of contracting. 18 C.F.R. $ 292.304(dX2Xii);
Tr. at 213-15, Moreover, the same result can be accomplished through successive short-term
contracts. Tr. at 214; 515-17 .
Third, we further find the arguments asking the Commission to treat QFs similarly
with utility resources unavailing, As is evident upon review of the extensive record (explained
by several witnesses), QFs differ from utility resources in several significant and material ways.
A utility "cannot be compensated by its customers for energy produced from a generating facility
until the utility establishes the need for such new generation" by requesting a Certificate of
Ptrblic Convenience and Necessity (CPCN). Idaho Code $$ 6l-526,61-541. Order No. 32697
at l5-16. In contrast, PURPA requires the utility to purchase QF power whether the power is
needed or not. Next, a utility-authorized resource is typically subject to cornpetitive bidding,
cost scrutiny, and oftentimes has dispatch characteristics different than most QFs. Moreover, the
fuel component for utility generating plants is adjusted annually, but is fixed for the duration of
fuel-based. long-term QF contracts. QFs are entitled to receive full avoided cost rates.
However, the calculation of avoided costs is entirely unrelated to what it costs a PURPA project
to be developed. Tr. at 290; see also Tr. at 196-200,205, 507-510, 924-26. The utilities also
demonstrated that avoided cost rates exceed the Mid-C index price and their average costs of
either generating or purchasing power. Tr. at 129,l9l-92,477-80.
Finally, if the goal of PURPA was to "encourage" the development of renewable
resources, Idaho has made significant advancements toward that goal. Both Idaho Power and
PacifiCorp presented persuasive evidence of capacity surpluses. These two utilities have
demonstrated that their supply of PURPA and non-PURPA power exceeds their current average
loads. Tr. at I 1 1, I 17,931. The abundance of PURPA generation extends the utilities' capacity
surpluses to 2024 for ldaho Power and 2028 for PacifiCorp.
A change in the length of lRP-based contracts is not intended to be punitive to QFs.
For several years this Commission has been adjusting terms and conditions of PURPA contracts
in order to establish avoided cost rates that are just and reasonable to electric consumers, in the
ORDER NO. 33357 24
public interest, and not discriminatory against QFs. We find that a change in contract length
aligns with the intent of PURPA, is consistent with FERC regulations and achieves an
appropriate balance between the competing interests of protecting ratepayers and developing QF
generation.
Based upon our review of the evidence, we find that the length of new IRP-based
contracts should be set at two years for all three utilities. There are several reasons to support
our finding. First, given the two-year planning cycle for the Integrated Resource Planning
process, we find it is reasonable to set the length of IRP contracts at two years. Matching IRP
contracts to the IRP planning cycle provides more accurate IRP avoided costs, reduces price risk,
and provides more forecast certainty. Tr. at 486, 127-28,287,902-05,915-17. Further, the two-
year cycle befter matches the utilities' hedging and risk management practices.
We are not persuaded that setting IRP-based contracts to two years will result in a
substantial decline of renewable resources. Tl're utilities all have arnple amounts of PURPA
power on their systems; additional renewable generation is in the queue; SAR-based contracts
are still 20 years; and the o'must purchase" provision will still require utilities to purchase all
renewable generation offered by QFs. Moreover, PURPA is not the only means through which a
utility can obtain and/or utilize renewable resources. All the utilities have acquired non-PURPA
renewable resources and/or shorter term cogeneration projects. As PacifiCotp's Mr. Clements
testified, all of PacifiCorp's cogeneration contracts are for a period of one year. Tr. at 476-77.
And we note that over the years, neithel Clearwater nor Simplot have chosen QF contracts of 20
years. Tr. at 858. In fact, Clearwater's most recent cogeneration agreement was not a PURPA
contract.
In reducing IRP-based contracts to two years, we find that a clarification in
calculating the capacity deficiency of the IRP-based projects is warranted. As we have said in
previous Orders, a utility is to begin payments to a QF for capacity "at such time as the utility
becomes capacity deficient. . . . By including a capacity payment only when the utility
becomes capacity deficient, the utilities are paying rates that are a more accurate reflection of a
true avoided cost for the QF power." Order No. 32697 at2l. We recognize that a new two-year
contract would be unlikely to reach a capacity deficiency date. Therefore, we find it reasonable
for utilities to establish capacity deficiency at the time the initial IRP-based contract is signed.
As long as the QF renews its contract and continuously sells power to the utility, the QF is
25ORDER NO. 333s7
entitled to capacity based on the capacity deficiency date established at the time of its initial
contract. For example, if the QF comes on-line in 2017 and the utility is capacity deficient in
2020, the QF would be eligible for capacity payments in the second year of its second contract
and thereafter if in continuous operation. This adjustment recognizes that in ensuing contract
periods. the QF is considered part of the utility's resource stack and will be contributing to
reducing the utility's need for capacity. This rnitigates the concern that short-term contracts will
not contribute to the avoidance of utility capacity/generation.
We further find that on a case-by-case basis, there may be justification tbr IRP-based
contracts in excess of two years. This is consistent with our prior Orders. Order Nos. 27213;
26576 at 6-7; Order No. 32697 at 25. In those instances when the utility and the project
developer believe that a longer term is justif,red, utilities are directed as part of their standard
negotiation process to fairly evaluate such requests. The Commission will consider those
contract terms when they ale submitted for approval.
C. Indicative or Incremental Pricing
As part of its Petition, Rocky Mountain asked that the Commission allow it to change
its "indicative" pricing practice in the IRP methodology so that it may provide more accurate
avoided cost rates to proposed QF projects. Petition at 4. h'rdicative or'oincremental" prices are
the preliminary estimates of IRP-based avoided cost rates and are the incremental cost a utility
would otherwise incur for the capacity and energy that the QF proposes to sell to the utility. Yin,
Tr. at 876. Incremental prices serve as the starting point for negotiations between QFs and a
utility. 1d
Rocky Mountain seeks relief from a prior Commission Order in Case No. GNR-E-l 1-
03 that generally directed that incremental pricing be updated after "the QF and utility have
entered into a signed contract for the sale and purchase of QF power." Order No.32697 at22
(emphasis added). In other words, the utility's calculation of an updated incremental price is
based upon signed contracts, not all projects seeking to sell power to a utility.
1. Rocky Mountain's Proposal. In its Petition, Rocky Mountain asked for approval
to arrange proposed QF projects in a queue and provide those QFs with incremental pricing as
part of the IRP negotiation process. Rocky Mountain Petition at 37-38. The avoided cost
prices/rates would be based on each QF's place in the queue, and would be calculated using that
QF's proposed power and that of all earlier-queued projects. Id. Rocky Mountain asserted that
ORDER NO. 33357 26
the "drastic increase in the number of QF requests received in both Idaho and over [Rocky
Mountain/PacifiCorp's] six-state system in recent years" results in "artificially inflated avoided
cost pricing." ft/.
Rocky Mountain's witness Brian Dickman explained:
Avoided costs for the first QF in [a] queue are based on displacement of the
highest cost resources on [Rocky Mountain's] systern. Each successive QF
should displace lower and lower cost resources, resulting in lower avoided
costs.
Dickrnan, Tr. at 560. The price of proposed power from queued projects is "not captured if the
recognition of new long-term commitments is limited to signed contracts." Id. at 564. If a utility
cannot update its avoided cost pricing to reflect the price for proposed power from the queue, the
queued projects all receive avoided cost rates or prices that are not up-to-date and too high.
Mr. Dickman also testified that it would be "prohibitively time consuming and
problematic from a contract negotiation standpoint," to recalculate prices for new QF projects as
other proposed QFs sign contracts. Id. at 572. He suggested the Commission should modifl, the
incremental pricing practice in the IRP methodology "to account for proposed QF projects on
[Rocky Mountain's] system prior to the next Idaho QF requesting indicative prices." Id. at 574.
Clearwater and Sirnplot's witness Dr. Reading supported the proposal. Tr. at 831.
No party opposed Rocky Mountain's incremental pricing request.
2. Staff Support. Staff recommended the Commission adopt Rocky Mountain's
proposal to update its incremental avoided cost pricing. Staff witness Dr. Yao Yin testified that
under the incremental pricing practice approved per Order No. 32697, "proposed projects are not
placed in a queue but are instead treated for pricing purposes as if they are all the first project to
receive the next [incremental price]." Tr. at 877 , Although this practice "may result in accurate
avoided cost rates," Dr. Yin observed that "it can be very difficult to recalculate rates for
proposed projects in a timely manner when there are many projects seeking indicative prices at
the same time." Id. at 877-7 8. "ln addition, a QF may not want to renegotiate the new updated
rates, because the new indicative prices may be lower than the original ones." Id. at878.
Dr. Yin noted that current "PURPA project sizes are much larger, both individually
and cumulatively, and rnultiple projects frequently seek indicative prices at the same time." /d
at 879. The pricing practice proposed by Rocky Mountain "would offer more accurate indicative
oRDER NO. 33357 21
prices to QFs by putting all the proposed projects into a queue based on the times they request
indicative prices." 1d-
She explained that ldaho Power and Avista have tariff schedules (Sch. 73 and 62,
respectively) that "specify the information a project needs to submit before requesting indicative
prices," and that "specify timeline milestones for QFs to meet as projects and negotiations
progress." Id. at 876, 881. Dr. Yin recommended that Rocky Mountain be directed to file a
similar schedule in Idaho "so that QF projects can have a better idea of the procedures for
requesting indicative prices in Idaho," and that would "[ay out the PURPA negotiating process
and prevent projects from prematulely requesting indicative pricing." Id. at 876-77, 882. She
further recommended that Rocky Mountain develop "specific criteria. . . for management of the
queue, such as rules for QF entry, re-positioning, and removal from the queue." Id. at 882.
Finally, she recommended that the Commission "discontinue the 'signed contract' requirement in
Order No. 32697 for purposes of giving indicative pricing to IRP-based projects." Id. at 882-83.
Commission Findings: The Commission finds that the "signed contract" language in
Order No. 32697 did not achieve its intended result. When developers flood the utilities with
many proposed projects in a short period of time, the "signed contract" requirement yields
inaccurate avoided costs. The result is artificially inflated pricing.
We find that creation of a queue to track the order in which QF projects have entered
negotiations with a utility, so that incremental pricing can be calculated to reflect the actual
impacts of each project is reasonable and appropriate. Consequently, we elirninate the "signed
contract" requirement of Order No. 32697 and allow utilities to update their incremental pricing
for QFs in their PURPA queue. Idaho Code $ 6l-624. Such a process will improve the accuracy
of proposed prices, and improve the predictability of the process to both the utilities and the QFs.
We also direct Rocky Mountain to file a tariff schedule, like those of Idaho Power and Avista,
which outlines its PURPA negotiating process. The schedule should include specific criteria for
management of the queue to eliminate uncertainty and to facilitate negotiations between Rocky
Mountain and QFs.
IV. INTERVENOR FUNDING
A, Funding Standards
lntervenor funding is available pursuant to ldaho Code $ 61-617A and Commission
Rules 161 through 165. Section 6l-6174.(1) declares that it is "the policy of [Idaho] to
ORDER NO. 33357 28
encourage parlicipation at all stages of all proceedings before this commissior"r so that all affected
customers receive full and fair representation in those proceedings ." Idaho Code $ 6l-617 A(2).
The statute authorizes the Commission to order any regulated utility with intrastate annual
revenues exceeding $3.5 million to pay all or a portion of the costs of one or more parties.
Intervenor funding costs include: Iegal fees, witness fees, transportation and other expenses so
long as the total funding fbr all intervening parties does not exceed $40,000 in any proceeding.
Idaho Code $ 61-617A(2). The Commission must consider the following factors when deciding
whether to award intervenor fllnding:
(l) That the participation of the intervenor has materially contributed to the
Comrnission' s decision;
(2) That the costs of intervention are reasonable in amount and would be a
significant financial hardship for the intervenor,
(3) The recomrnendation made by the intervenor differs materially from the
testimony and exhibits of the Comrnission Staff; and
(4) The testimony and participation of the intervenor addressed issues of
concern to the general body of customers.
Idaho Code $ 6l-617 A(2). To obtain an award of intervenor fi.urding, an intervenor must cornply
with Commission Procedural Rules l6l-165. The petition must contain an itemized list of
expenses broken down into categories; a statement explaining why the costs constitute a
significant financial hardship; and a statement showing the class of customer on whose behalf the
intervenor participated. Rule 162, IDAPA 31.01.01.162.
B. Tlte Intervenor Funding Requests
As set out in greater detail below, the Commission received four petitions for
intervenor funding, requesting a total of about $58,000. It is undisputed that each of the three
electric utilities in this case has intrastate revenues that exceed 53.5 million.
1. Idaho Conservation Leasue. On July 1,2015, ICL filed a Petition fbr Intervenor
Funding seeking recovery of $9,652.50 in expenses. ICL is a non-profit organization and claims
that its members and supporters are ratepayers of all three electric utilities. Petition at 3. ICL
maintained that it receives financial support solely through charitable donations fi'om its
members and foundations. 1d It asserted that it actively strived to reduce its expenditures by not
seeking any travel costs, reproduction fees, and that the services of its witness, Mr. Wenner, were
ORDER NO. 33357 29
provided pro bono. Moreover, ICL requested only 600/o of its other witness's l"rourly rate. ICL
submitted that its witnesses' testimony was materially different from that testimony offered by
the Commission Staff. In parlicular', iCL argued that the Commission should maintain the 20-
year fixed-price contracts for IRP-based projects. Petition at 5. In summary, ICL requested
recovery olits legal fees in the amount of $4,050 and witness fees in the amount of $5,602.50.
2. Renewable Enerey Coalition. On July 9, 2015, REC filed its Petition for
Interuenor Funding seeking an award of $8,751.50.13 REC members represent small hydro
power producers that either have or may seek PURPA contracts with Idaho's electric utilities.
Petition at 3. REC members imposed a special assessment against themselves to support their
intewention in this case. Petition at 4. However, costs for intervenors in this proceeding
exceeded the assessment. ld. In addition, REC has not sought recovery of all of its legal fees
nor the costs of its primary witness, Mr. Lowe, in this case. REC declared that its testimony also
differed from that offered by Commission Staff. It maintains that it is the only party that
recommended the Commission should broadly investigate the issues raised by utilities when
balancing the interest of ratepayers and small QFs, In summary, REC sought to recover its Iegal
fees in the amount of $7,936.50 and its travel expenses in the amount of $815.
3. Snake River Alliance. On July 9, 2015, SRA filed its Petition for Intervenor
Funding seeking $5,800 "rounded down for convenience." Petition at 3. SRA characterizes
itself as a small, non-profit organization "snpported by charitable contributions from individuals,
families, and foundations." Id. Its participation in this case was "necessary to provide a voice
fbr its members and ratepayers that 'face significant econornic and envirorunental risks
associated with the utilities' coal fleet [by] pursuit of clean and renewable altematives to coal
and large hydropower." Id. SRA opposed the utilities' and Staff s proposals to reduce the length
of 20-year PURPA contracts but supported adjusting the energy component of avoided cost rates
at the l0-year mark. Id. at2.
SRA only requested recovery of its legal fees and did not seek reimbursement for its
witness and Energy Director, Ken Miller.
4. [rigation Pumpers Association. On July 10, 2015, the Irrigators filed their
Petition for Intervenor Funding seeking a total of $33,733.72. The Irrigators sought recovery of
'' In irs Petition, REC sought an award of $8,800 (Petition at 2; Exh. A) but the expenses listed in its Exhibit A total
$8.75 r.50.
ORDER NO. 33357 30
their legal fees ($7,500), witness fees ($24,450). and travel expenses (S1,783.72). Petition at
Exh. A. The In'igators are a non-profit corporation representing tarmers' interests in electric
utility matters in southern Idaho. Petition at 3. The Inigators rely solely on dues and
contributions voluntarily paid by its due-paying mernbers. They only have one part-time paid
contractor who shares office space in Boise. The lrrigators' position was materially different
than that addressed by Commission Staff or other parties. They maintained that Idaho Power
was operating its system inconsistently with the assumptions in Idaho Power's avoided cost
models. Id. at 3. They urged the Commission to reduce the length of contracts while the
Commission refines the avoided cost rnethodology.
Commission Findings: The Commission finds that the requests for intervenor
funding satisfy the intervenor funding requirements. Each intervenor participated in the case and
rnaterially contributed to the examination of the issues and the Commission's decision. As set
out above, each intervenor's petition materially differed from Staffls position. We further find
that the lack of intervenor funding would be a significant financial hardship to these intervenors
and that their costs of intervention, for the most part, are reasonable. However, the total amount
requested exceeds that which is available by statute. Therefore, we ltnd it fair, just and
reasonable to award the intervenors the following funding amounts totaling $40,000.
INTERVENOR AWARI)
ICL $ 8,635
REC $ 8,314sRA $ 5,266rrPA $17.785Total $40,000
The intervenor funding award shall be recovered from Avista, Idaho Power and
Rocky Mountain Power based on a proportional share of the total number of Idaho customers
served by each utility. See Order No. 32697. The funding awards to ICL, REC, and SRA shall
be chargeable to the electric residential customer class. The Irrigators' costs shall be chargeable
to the irrigation customer class of the three utilities. Idaho Code $ 6l-61 7A(3).
ULTIMATE FINDINGS AND CONCLUSIONS
The Commission has jurisdiction over this matter pursuant to the authority and power
granted it under Title 61 of the Idaho Code and the Public Utility Regulatory Policies Act
(PURPA). The Commission has authority to set avoided cost rates, to order electric utilities to
ORDER NO. 33357 3l
enter into fixed-term obligation for the purchase of energy and capacity from QFs, and to set the
term of PURPA contracts. The Commission is also empowered to resolve disputes between
utilities and QFs and to approve PURPA contracts.
PURPA and FERC regulations direct not only that the rates for purchases not
discriminate against QFs, but also that avoided cost rates be just and reasonable to the utility's
ratepayers and in the public interest. l8 C.F.R. $ 292.304(aX1). This Order shortens the length
of IRP-based PURPA contracts in order to maintain a morie accurate avoided cost. However, the
"must purchase" obligation of PURPA will allow QFs to continually renew their contracts,
Moreover, QFs will continue to be compensated for capacity calculated at the time they initially
enter their [RP-based contract. AIso, proposed lRP-based contracts that are longer than two
years will be evaluated on a case-by-case basis. This Order strikes a balance between just and
reasonable rates for ratepayers, the public interest and the interests of QFs, as is mandated by
PURPA and FERC regulations.
ORDER
IT IS HEREBY ORDERED that ldaho Power's Petition to reduce the length of its
IRP-based PURPA contracts from 20 years to two years is granted.
IT IS FURTHER ORDERED that Rocky Mountain Power's Petition to reduce the
length of its IRP-based PURPA contracts from 20 years to three years is granted in part and
modified in part. Rocky Mountain shall reduce the length of its lRP-based PURPA contracts to
two years.
IT IS FURTHER ORDERED that Avista's Petition to reduce the length of its IRP-
based PURPA contracts to two years is granted as set out above.
IT IS FURTHER ORDERED that Rocky Mountain Power's request to change its
indicative (incremental) pricing practices is granted as set out above. The requirement that
utilities update their indicative pricing practices based on signed contracts is rescinded. Idaho
Code * 6l-624. PacifiCorp shall file a schedule setting out its PURPA negotiating practices and
queue management.
IT IS FURTHER ORDERED that the capacity components for lRP-based QF
contracts shall be calculated for all new IRP contracts to begin at the time the QF first enters its
two-year contract provided such contract is continued in the future.
ORDER NO. 33357 32
IT IS FURTHER ORDERED that Avista, Idaho Power, and Rocky Mountain Power
may enter IRP-based QF contracts in excess of two years on a case-by-case basis with
appropri ate j ustitication.
IT IS FURTHER ORDERED that the four Petitions for Intervenor Funding are
granted as set out in greater detail above. The utilities ale directed to remit their respective
amounts to the four intervenors within 28 days of the date of this Order, as more specifically
described above. IDAPA 31.01.01 .165.02.
IT IS FURTHER ORDERED that this Order become effective on the service date
shown on the front page.
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues finally
decided by this Order) or in interlocutory Orders previously issued in Case Nos. IPC-E-I5-01,
AVU-E-15-01, and PAC-E-15-03 may petition for reconsideration within twenty-one (21) days
of the service date of this Order with regard to any mafter decided in this Order or in
interlocutory Orders previously issued in these cases. Within seven (7) days after any person has
petitioned for reconsideration, any other person may cross-petition for reconsideration, See
lclaho Code $ 6l-626.
0RDER NO. 33357 JJ
iLofr.DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
day of August 2015.
ENT
Contmissioner Smith did not participate in this case
MARSHA H. SMITH, COMMISSIONER
RAPER, CO SIONER
ATTEST
D
slon
O: IPC-E- I 5-0 I _AVU-E- I 5-0 I -PAC-E- I 5-03*dh2-Final
oRDER NO. 33357 34
kd)rtn^^,., R -a, n
Exhibit 2
Idaho Public Utilities Commission
Order No. 33419
Oftice of the Secretary
Service Date
November 5, 2015
BEFORE THE IDAHO PI]BLIC UTILITIES COMMTSSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
CASE NO. IPC.E.15.O1
IN TIIE MATTER OF AVISTA
CORPORATION'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
cAsE NO. AVU-E-I5-01
IN THE MATTER OF ROCKY MOUNTAIN
POWER COMPANY'S PETITION TO
MODIFY TERMS AND CONDITIONS OF
PURPA PURCHASE AGREEMENTS
CASE NO. PAC.E.Is.O3
0RDER NO. 33419
On September 10, 2015, Clearwater Paper Corporation and J.R. Simplot Company
(the "Petitioners") filed a Petition for Reconsideration in the above-referenced consolidated
cases. The Petitioners requested reconsideration of the Commission's final Order No. 33357 that
reduced the length of certain PURPA contracts from 20 ye.us to two years. The Petitioners
generally raised three arguments. First, they argued that the Commission's two-year contract is
contrary to the PURPA regulation "because it deprives the lRP-based QFs of a long-term, fixed
contract price to sell energy and capacity with prices calculated at the outset of the obligation."
Petition at 1l (underline added). Second, they argued that the new two-year contract term fails
to provide each qualifying facility (QF) with a fixed-price for "energy and capacity calculated at
the time the QF obligates itself to sell its output to an Idaho utility. ." Id. at 2. Finally, they
asserted the Commission's "capacity adjustment" (used to determine the date when the QF
would be eligible for capacity payments) "is made up of whole cloth." Id. at 16. They alleged
that no party discussed the capacity adjustment in its testimony. The Petitioners concluded that
the Commission's creation of the capacity adjustment "is not supported by any evidence on the
record whatsoever." Id. al 17.
Clearwater and Simplot requested that the Commission either retain the prior Zo-year
contract term or adopt their alternative proposal for a "ZO-year contract with an update to energy
prices in new PURPA contracts in contract year 10. ." Petition at 15. The Petitioners
maintained that either alternative would meet the minimum requirements of FERC's regulations.
)
)
)
)
)
)
)
)
)
)
)
)
)
)
oRDER NO. 33419 I
Id. They offered to submit fuither briefing, oral argument, or any further technical testimony the
Commission may request. Id. at 17.
On September 17,2015, Avista Corporation, Idaho Power Company, and Rocky
Mountain Power (collectively the "Utilities") filed a timely joint answer urging the Commission
to deny reconsideration. The Utilities maintained that the Commission's final Order No. 33357
properly found that 20-year PURPA contracts are inconsistent with the public interest. They
argued the Commission's decision to set the maximum standard contract term to two years more
accurately reflects true avoided costs and appropriately balances "the competing interest of
protecting utility customers and developing QF generation." Answer at 1 l. They insisted that
the PURPA regulations issued by the Federal Energy Regulatory Commission (FERC) are silent
as to the length of a contract and the Commission acted within its discretion in reducing the
contract term. Id. al 6. The Utilities also asserted that the Cornmission's final Order is based
upon substantial and competent evidence in the record. Id. at ll.
On October 8,2015, the Commission issued Order No.33395 granting
reconsideration on the issues raised by Clearwater and Simplot. The Commission noted that it
had compiled an extensive evidentiary record in this case and determined that further argurnent
and briefing was not necessary. Order No. 33395 at 2. After having thoroughly reviewed the
issues raised in the Petition for Reconsideration and the record in this case, the Commission
dismisses the issues raised in the Petition for Reconsideration as discussed in greater detail
below.
BACKGROUND
A. PURPA
Congress enacted the Public Utility Regulatory Policies Act (PURPA) in 1978 in
response to a national energy crisis. "Its purpose was to lessen the country's dependence on
foreign oil and to encourage the promotion and development of renewable energy technologies
as altematives to fossil fuels." Order No. 32580 at 3, citing FERC v. Mississippi, 456 U.S. 742,
745-46 (1982). Under the Act, FERC prescribes rules for PURPA's implementation. l6 U.S.C.
$ 824a-3(a), (b). State regulatory authorities such as the Idaho Public Utilities Commission
implement FERC regulations, but have "discretion in determining the manner in which the rules
will be implemented." Idaho Power Co. v. Idaho PUC, 155 Idaho 780,782, 316 P.3d 1278,
1280 (2013), citing FERC v. Mtsstssippi,456 U.S. at 751. The Idaho Supreme Court has
2oRDER NO. 33419
observed that the Commission has the authority to implement PURPA and that this grant of
authority is broad. Idaho Power, 155 ldaho at787,316 P.3d at 1285; Rosebud Enterprises v.
Idaho PUC (Rosebud I),128 Idaho 624,627,917 P.2d781,784 (1996); A.W. Brown v. Idaho
Power Co.,12l Idaho 812, 814, 828 P.2d 841, 843 (1992).
To encourage the development of renewable facilities, PURPA requires that electric
utilities purchase the power produced by designated qualifying facilities (QFs). "This mandatory
purchase requirement is often referred to as the 'must purchase' provision of PURPA." Order
No. 32697 at 7;16 U.S.C. $ 824a-3(b); 18 C.F.R. 5 292.303(a) (exceptions to the "must
purchase" provision inapplicable in this case). Electric utilities are required to purchase power
from QFs at rates equivalent to a utility's "avoided cost" and approved by this Commission. 16
U.S.C, $ 824a-3; ldaho Power, 155 Idaho at789,316 P.3d at 1287. The purchase or avoided
cost rate represents the "'incremental cost'to the purchasing utility of power which, but for the
purchase of power tiom the QF, such utility would either generate itself or purchase from
another source." OrderNo.32580 at3,citing Rosebud l,l28ldaho at 627,917 P.2d at 784; l8
C.F.R. Q 292.101(bX6). The avoided cost rate must be'Just and reasonable to the electric
consumers . . . and in the public interest" and "shall not discriminate against [QFs]." l6 U.S.C. $
824a-3(b); l8 C.F.R. 5 292.304. In addition, utilities shall not be required to pay more than their
avoided costs when purchasing power from a QF. Rosebud Enterprises v. Idaho PUC (Rosebud
II), 128 Idaho 609,614,917 P.zd 766,771 (1996), citing 16 U.S.C. $ 82aa-3(b) (PURPA
regulations shall not "provide fbr a rate which exceeds the incremental cost to the electric utility
of alternative electric energy."), Rosebud I,l2S ldaho at627,917 P.2dal784.
This Commission has established two methods of calculating avoided cost, depending
on the size of the QF project: (l) the surrogate avoided resource (SAR) methodology,and(2)
the integrated resource plan (IRP) methodology. See Order No. 32697 at 7-8. The Commission
uses the SAR methodology to establish what is commonly refened to as "published" or standard
avoided cost rates. Id.; 18 C.F.R. 5 292,304(c). Published rates are available for wind and solar
QFs with a design capacity not to exceed 100 kilowatts (kW), and for QFs of all other resource
types with a design capacity of up to 10 average megawatts (aMW).r OrderNo.32697 at7-8.
For QFs with design capacity above the published rate eligibility caps, avoided cost rates are
I Other types of PURPA generating facilities include: cogeneration (such as Clearwater and Simplot); geothermal;
hydro (both year-round and seasonal); landfill gas; and bio-gas facilities.
3ORDER NO. 33419
"individually negotiated by the QF and the utility" using the IRP methodology based on the
specific characteristics of the resource. Order Nos. 32697 at 2; 32176 at L. Since 2002, the
standard length for both SAR-based contracts and lRP-based contracts was set by the
Commission at 20 years. Order Nos. 32697 at 24-25, 33357 at 11. [n that Order the
Commission also found that shorter or longer contracts would be permissible on a case-by-case
basis. Id. at 25.
At the option of each QF, the utility's avoided cost power rate shall be calculated
either at the time of delivery or at the time the sales obligation is incurred. Rosebttd II, 128
Idaho at 621, 97 I P.2d at 178; 18 C.F.R. $ 292.304(d). Avoided costs are generally divided into
two components: capacity rates and energy rates. See Order No. 32697 at 15. Capacity rates
reflect the ability of the utility to generate electric power at any instant in time and are measured
in megawatts (tvIW). A QF that provides capacity to the utility allows the utility in theory to
avoid building new generation or purchasing firm power from another supplier. Energy rates
reflect the costs of supplying electricity over time and are measured in megawatt hours (MWh).
For example, one MW of capacity supplied for one hour equals one MWh of energy.
B. The Utilities' Requests to Reduce the Length of PURPA Contracts
On January 30,2015,Idaho Power Company filed a Petition asking the Commission
to reduce the length of its lRP-based PURPA contracts from 20 years to two years. Avista and
Rocky Mountain subsequently filed similar petitions and the three cases were consolidated into a
single proceeding. Order No. 33250. While the Commission investigated the issue of contract
length, it granted temporary relief to the tfuee utilities by reducing the length of new PURPA
contracts to five years. Id. at 8; see Order No. 33357 at 6-7 (sumrnarizing petitions to clarify the
scope of the case).
l. Idaho Power. The Company asserted that Z0-year fixed-rate contracts ure no
longer reasonable. Idaho Power insisted it has reached a point where the cumulative capacity of
the proposed PURPA projects will exceed the Company's operational need by a large margin.
Idaho Power's Senior Vice President of Power Supply testified that the Company does not need
the additional generation. She reported that the Company's peak load for its system in 2014 was
about 3,184 MW while its minimum load was approximately 1,073 MW. Order No. 33357 at
13; Tr. at 107-108. Idaho Power asserted it had more than l,l6t megawatts (MW) of PURPA
projects under contract and an additional 1,326 MW of new solar projects in the queue. Order
4ORDER NO. 33419
No. 33357 at 3-4; Exh. 11 at 4. The Company maintained that the recent influx of PURPA
generation places undue financial and operational risks on customers at a time when the utility
has sufficient resources to meet customer demand through 2024. Order No. 33357 at 4; Tr. at
281 .
The Company also asserted in its initial Petition that "the continued creation of 20-
year term [PURPA] contracts places undue risk on customers" and is contrary to the public
interest. Idaho Power Petition at2,27-34. Idaho Power complained that if allthe proposed solar
projects come on-line, it would represent a "long-term financial obligation to customers over 20
years of approximately $2.1 billion, in addition to the existing $2.6 billion obligation over the
life of the Company's IPURPA] projects already on-line and operational." Id. at3.
2. Rocky Mountain Power. Rocky Mountain requested a perrnanent reduction in its
IRP-based PURPA contracts fiom 20 years to three years. The Company asserted in its Petition
that five days after the Commission granted Idaho Power interirn relief, Rocky Mountain
received four requests from solar developers in Idaho Power's service territory seeking to sell or
"wheel" 130 MW of solar power to Rocky Mountain. Rocky Mountain Petition at 4-5, 16.
Rocky Mountain insisted these four projects sought to wheel power to it to obtain a more
favorable Z}-year contract when Idaho Power contracts were temporarily reduced to five years.
Id., n.5.
Like Idaho Power, Rocky Mountain asserted it had no need for additional generating
resources until 2028. Id. at 3, n.4, Tr. at 429. Adding the proposed PURPA projects to the
Company's existing PURPA contracts would total approximately 465 MW. Petition at 5. At full
nameplate capacity, this would be enough to supply 108% of Rocky Mountain's average retail
load in 2014 and 27 5% of its minimum Idaho retail load in 2014. Tr. at 427 . The Company also
insisted that the reduction was necessary to be "consistent with the Company's hedging and
trading policies," the length of its non-PURPA energy contracts, and to more closely align with
the two-year Integrated Resource Plan (lRP) cycle. Petition at 3-4.
3. Avista. If the Commission granted permanent relief to Idaho Power and Rocky
Mountain by shortening their IRP contracts, Avista requested that it be granted the same relief.
Order No. 33357 at 18, citing Tr. at 404,408. Avista's witness acknowledged that Avista had
not received any proposals for solar projects, but testified that having contract lengths in excess
of the other two utilities could cause QF developers to seek contracts with Avista simply to
5ORDER NO. 33419
obtain longer term contracts. Id, Tr. at 406-07. Avista also recommended that the Commission
allow IRP contracts longer than five years if such contracts are in the best interest of ratepayers.
Id.,Tr. at 410.
FINAL ORDER NO.33357
A. 20-Year Contracts are Unreasonable
In its final Order No. 33357, the Commission found based upon substantial and
competent evidence that 20-year IRP contracts are unreasonable and inconsistent with the public
interest. Order No. 33357 at23. The Commission cited several reasons in support of its decision
to shorten IRP-based contracts. First, the Commission found that neither PURPA nor its
implementing regulations "specifly a mandatory length for PURPA contracts." Id. al 12. The
Commission noted that no party contested that "FERC regulations do not dictate a specific
number of years or establish a time period for PURPA contracts." Id., citing Tr. at 589, see also
215-16,41 0-l 1, 5 I 3-l 5.
Second, the Commission found that 20-year contracts are unreasonable because the
length exacerbates overestimations to a point that avoided cost rates are inconsistent with the
public interest. The Commission found there was general agreement among the parties that the
avoided cost rates for IRP projects are declining and will continue to decline in the future. Order
No. 33357 at22, citing Tr. at 260-61,372,630-31,642. With long-term avoided cost rates in
decline, allowing QFs to fix their avoided cost rates for 20 years when they enter into their
contract/obligation, will result in avoided cost rates which exceed or "overestimate" avoided cost
rates in the future. Id. at 23. This "'overestimation' will become more significant over the
duration of the [2O-year] contract." Id. The Commission observed that when FERC issued its
initial PURPA regulations in 1980, FERC recognized that avoided costs calculated at the time
parties enter into a power contract may exceed the actual avoided costs at the time the power is
delivered in the future. 45 Fed.Reg. 12,214 at 12,224 (Feb. 25, 1980). As FERC explained in its
Order No. 69, overestimations will "subsidize the [QF] at the expense of the utility's other
ratepayers." Order No. 33357 at22-23, citing 45 Fed.Reg. al 12,224; Tr. at 575-77. FERC
discounted the concern about long-term avoided costs exceeding actual avoided costs at the time
of delivery (i.e., overestimations) because it theorized that over time "'overestimations' and
'underestimations' of avoided costs will balance out." Id. However, the Commission found that
6ORDER NO. 33419
based upon the record in this proceeding Z}-year IRP contracts with Frxed avoided cost rates will
exceed actual avoided costs and are inconsistent with the public interest. 16 U.S.C. $ 82aa-3(b).
Third, the Commission found that both Idaho Power and Rocky Mountain presented
persuasive evidence that they did not need additional generation and each currently has a
capacity surplus. Order No. 33357 at 24. The Commission specifically found that the two
utilities' supply of PURPA and non-PURPA power exceeds their average Idaho loads. Id., citing
Tr. at 1l l, I17. 931. "The abundance of PURPA generation extends the utilities' capacity
surpluses to2024 for Idaho Power and 2028 for [Rocky Mountain]," Id. at24.
The Commission also rejected two similar but different proposed altematives in lieu
of shortening the term of the contracts. More specifically, the Petitioners urged the Commission
to continue the 20-year contract but "adjust the energy component in each of the last l0 years of
the standard contract." Order No. 33357 at 23 (emphasis added), citing Tr. at 842. The other
altemative proposed by the Sierra Club was to retain the 20-year term but reset the energy rate
just once in the eleventh year of the contract, i.e,, in year 11. Tr. at 701-03. The Commission
rejected both of these alternatives based upon concern that an adjustable rate 20-year contract
runs the risk of undermining FERC regulations that mandate a "fixed-rate" at the time the
contract or obligation is entered. Id., ciring 18 C.F.R. $ 292.304(dX2Xii); Tr. at 213-15. The
Commission also found that the ability to ensure that avoided cost rates remain accurate can best
be accomplished through successive short-term contracts. Order No. 33357 at 24.
B. The Two-Year Contract
Because neither PURPA nor FERC's implementing regulations expressly specify a
length for PURPA contracts, the Commission found that setting an appropriate contract length is
left to its discretion. The Commission noted that the ldaho Supreme Court has stated that the
Commission has the authority to implement PURPA and that this grant of authority is broad.
Order No. 33357 at 3, citing ldaho Power,155 Idaho at787,315 P.3d at 1285; Rosebud I,128
Idaho at627,917 P.2dat784;A.W. Brown, 121 Idaho at 814,828 P.2d at 843. The Commission
also noted that it "is up to the States, not [FERC] to determine the specific parameters of
individual QF power purchase agreements. . . ." Order No. 33357 at 12, quoting ldaho Power,
155 ldaho at 786,3 16 P.3d at 1284, quoting Power Resources Group v. PUC of Texas, 422 F .3d
231, 238 15'h Cir. 2005).
7ORDER NO. 134r9
Having found that the standard Z}-year IRP-based contract was unreasonable and no
longer in the public interest, the Commission determined that the length of new lRP-based
contracts should be set at two years for all three utilities. OrderNo.33357 at25;16 U.S.C. $
82aa-3(b)(l). The Commission cited several reasons to support its finding. First, the
Commission found that shorter contracts have the potential to benefit both the QF and the
utility's customers. "By adjusting avoided cost rates more frequently, avoided costs become a
truer reflection of the actual costs avoided by the utility and allow QFs and ratepayers to benefit
from normal fluctuations in the market." Id. a|23. In other words, when avoided costs increase
or decrease, both the QF and ratepayers have.the opportunity to benefit.
Second, the Commrssion found that reducing the contract length to two years does not
prevent a QF from selling energy to a utility over the course of 20 years - or
longer. PURPA's "must purchase" provision requires the utility to continue to
purchase the QF's power. [6 U.S.C. $ 82aa-3(b); l8 C.F.R. $ 292.303(a).]
As long as projects continue to offer power to utilities, utilities must continue
to purchase such power under PURPA. A shorter contract length merely
functions as a reset for calculation of the avoided costs in order to maintain a
more accurate reflection of the actual costs avoided by the utility over the long
term.
Order No. 33357 at23. In addition, most QFs choose to have their avoided cost rates fixed at the
time the contract/obligation is incurred for the duration of the contract. Id. at22.
Third, the Commission determined it was reasonable and logical to set the length of
IRP contracts at two years to coincide with the two-year planning cycle for the integrated
resource planning process. "Matching IRP contracts to the IRP planning cycle provides more
accurate [RP avoided costs, reduces price risks, and provides more forecast certainty." Id., ciling
Tr. at 486, 127-28,287,902-05, 915-17. The Commission also found that the two-year contract
better matches the utilities' hedging and risk management practices.
C. The Capacity Adjustment and Exceptions to Two-Year Controcts
In reducing the length of lRP-based contracts to two years, the Commission
recognized that two adjustments or exceptions were necessary. The first is referred to as the
"capacity adjustment," and the second is the "exception" to limiting contracts to two years.
1. Capacity Adiustment. The capacity adjustment addressed concerns raised by
parties opposed to reducing the 20-yex contracts because "short-term contracts will not
contribute to the avoidance of utility capacitylgeneration." OrderNo.33357 at 26. The capacity
8ORDER NO. 334r9
adjustment was intended to ensure that the QF will be compensated for providing capacity2 to the
utility when "the utility becomes capacity deficient." Order No. 33357 at25, quoting Order No.
32697 at2l, Because each utility's capacity deficiency date is updated and reset every two years
as part of the IRP methodology, the Commission was concerned that new two-year lRP-based
contracts "would be unlikely to reach a capacity deficiency date." Order No. 33357 at25. In
other words, under the two-year term, a contracting QF might never reach a point where its
capacity is contributing to the utility's system and would, therefore, never receive capacity
payments.
To remedy this concern, the Commission found it
reasonable for utilities to establish capacity deficiency at the time the initial
IRP-based contract is signed. As long as the QF renews its contract and
continuously sells power to the utility, the QF is entitled to capacity [rates]
based on the capacity deficiency date established at the time of its initial
contract. For example, if the QF comes on-line in 2017 and the utility
fbecomes] capacity deficient in 2020, the QF would be eligible for capacity
payments in the second year of its second contract [(i.e., 2020)] and thereafter
if in continuous operation. This adjustment recognizes that in ensuing
contract periods, the QF is considered part of the utility's resource stack and
will be contributing to reducing the utility's need for capacity.
Order. No. 33357 at25-26.
2. Exceptions to Limiting Contracts to Two Years. Avista's witness recommended
that the Commission allow IRP contracts to exceed the standard contract term of two, three or
five years "in the event a very f-avorable PURPA opportunity arises." Tr. at 404,410; see also
Tr. at 908-10. The Commission adopted this recommendation and found there may be
circumstances that justifu lRP-based contracts that are longer than two years. Order No. 33357
at26. [n instances when the utility and the project developer believe that a contract term longer
than two years is justified, "utilities are directed as part of their standard negotiation process to
fairly evaluate such a request." Id. The Commission also noted that approving IRP-based
contracts in excess of the standard length (i.e., two years) "is consistent with our prior Orders."
Order Nos. 272 13;26576 at 6-7; 32697 at 25.
2 See sttpra text on page 4 explaining capacity and capacity rates/payments.
9ORDER NO. 33419
SCOPE OF RECONSIDERATION
A. Legal Standards
Reconsideration provides an opportunity for a party to bring to the Commission's
attention any question previously determined, and thereby affords the Commission with an
opportunity to rectify any mistake or omission. Washington Water Power Co. v. Kootenai
Environmental Alliance, 99 ldaho 875,879,591 P.2d 122, 126 (1979). The Commission may
grant reconsideration by reviewing the existing record, by wrinen briefs, or by evidentiary
hearing. Idaho Code $ 6l-626; Rule 332, IDAPA 31.01.01.332. If the Commission believes its
final order "should be changed, the Commission may . . . change the same." Idaho Code $ 6l-
626(3). An order on reconsideration that changes the original final order, shall have the same
force and effect as the original order. Id.; see also ldaho Code $ 6l-624.
B. Underlying Facts
The scope of final Order No. 33357 was limited to issues of reducing the length of
IRP-based PURPA contracts. Order No. 33253 at 4. The parties proposed and the Commission
approved that the standard length for SAR-based contracts remain unchanged al20 years. Id.,
Order No. 33357 at 7. Clearwater and Simplot are the only parties or persons to seek
reconsideration of the Commission's final Order. Idaho Code $ 6l-626.
Both Petitioners operate existing cogeneration facilities and both expressed an interest
in developing new cogeneration facilities at their industrial plants. Tr. at 769,771. A
cogeneration facility typically relies on a host's industrial process to produce electricity in
conjunction with the activities of the host facility. l8 C.F.R. $ 292.202(c). Cogeneration
projects with power output of l0 average MW (aMW) or less are eligible to receive published
SAR-based, avoided cost energy and capacity rates with 20-year contracts. Order No. 33357 at
3.
Clearwater Paper operates four cogeneration facilities at its manufacturing facility
nearLewistonthatarecapableof generatingatotal of approximately lll MW. Petitionat3;Tr.
al 769. Simplot currently operates a 15.9 MW cogeneration facility that uses waste heat to
generate electricity. Petition at 3; Tr. at 767. Although Simplot's QF has the capability to
generate in excess of 10 aMW, it "has thus far chosen to enter into standard rate contracts for
QFs generating up to l0 aMW of generation." Petition at 3. In other words, Simplot has not
ORDER NO. 33419 l0
sought IRP-based avoided cost rates but has elected to be paid the published SAR-based avoided
cost rates for small cogeneration QFs (less than 10 aMW).
At the technical hearing, the Petitioners' witness Dr. Reading was asked about the
lengths of the Petitioners' PURPA contracts.l He deferred to the Commission's records for the
history of contract length. Tr. at 858. Since enactment of PURPA in 1978, neither Clearwater
nor Simplot has soughl a 2O-year contract for their existing facilities.a The longest PURPA
contract for Simplot's existing tacility was seven years (2006 -2013). Order No. 30028. Simplot
also has had several one and two-year contracts. Order Nos. 28739,29577,32790,33240. In
Clearwater's case, its two longest PURPA contracts were each ten years. Order Nos. 23858,
29418. In 2013, Clearwater agreed to sell its available power output to Avista under a non-
PURPA sales contract that extends to 2018. Tr. at 858-59, 931-32, citing Order No. 32841.
Earlier this year, Clearwater and Avista requested and the Commission approved extending their
non-PURPA contract for an additional three years, untilJune 2021. OrderNo. 33350;Tr. at932,
n.l,
ISSUES TN DISPUTE
A. PURPA cloes not Authorize the QF to Specify the Length of the Contract
The Petitioners raise a number of inter-related arguments generally urging the
Commission to reconsider its decision to shorten IRP-based contracts to two years. They first
insist that FERC's PURPA regulation at l8 C.F.R.5292.304(dx2xii) permits a QF to determine
the length of IRP-based contracts. They argue that this section requires that each QF "shall" be
provided with the following options:
(l) to elect to sell energy and capacity [to the utility];
(2) to elect to sell such energy and capacity over a term specified by the OF;
and
(3) to elect that the obligation contain rates for energy and capacity calculated
at the time the QF incurs that obligation.
r The Commission approves all PURPA contracts and other power sales agreements by issuing final orders. Order
No. 32802 at I I (and citations therein). tdaho Code $ 6 I -502.
a The Commission's procedural Rule 263 allows the Commission to take official notice of its own orders and
notices. IDAPA 31.0 1.01.263.01.a. We take official notice of our prior Orders approving the length of the
Petitioners' PURPA contracts.
llORDER NO. 334 r9
Petition at 9 (emphasis added). They maintain that use of the word "shall" makes it mandatory
that QFs have the authority to dictate the length of IRP contracts.
In their answer, the Utilities assert the Petitioners misrepresent the plain language of
section 292.304(d)(2) and "authorities related to a legally enforceable obligation in an
unsuccessful effort to create a requirement for long-term contractual commitments." Joint
Answer at 3 (emphasis original). They specifically attack the Petitioners' claim that section
292.304(d)(2) allows a QF to specity the term of the contract. They allege that a review of the
section's explicit language reveals that QFs do not have the authority to specify the length of
IRP-based contracts with utilities. Answer al3, 4-6.
The Utilities included Section 292.304(d) in their answer. This section states in full:
Each qualifying facility shall have the option either:
L To provide energy as the qualifying facility determines such energy to
be available for such purchases, in which case the rates for such
purchases shall be based on the purchasing utility's avoided costs
calculated at the time of delivery; or
2. To provide energy or capacity over a specified term, in which case the
rates for such purchase shall, at the option of the qualifying facility
exercise prior to the beginning of the specified term, be based on
either:
(i) The avoided costs calculated at the time of delivery; or
(ii) The avoided costs calculated at the time the obligation is incurred
l8 C.F.R, 5 292.304(d) (emphasis added). They maintained the phrase "over a specified term"
means there is "a term" or contract length - not that the QF is entitled to specify the length of the
contract. Answer at 5.
The Utilities also observed that the Commission's Order recites that there was no
dispute among the parties regarding the fact that FERC regulations "do not dictate a specihc
number of years or establish a time period for PURPA contracts." Answer at 4, quoting Order
No. 33357 at 12. The Utilities asserted that the PURPA regulations are silent as to a specific
contract length and there is nothing in the regulations that allow a QF to specify the length of a
PURPA contract.
Commission Findings: We are not persuaded that the Petitioners' (as qualifying
facilities) get to choose the length or term of IRP contracts for several reasons. First, PURPA
ORDER NO. 33419 t2
requires State Commissions to implement PURPA. 16 U.S.C. $ 824a-3(f)(1); Order 69, 45
Fed.Reg. at 12,216 ("The implementation of these [PURPA] rules is reserved to the State
regulatory authorities. ."), This Commission has authority to implement PURPA and "has
discretion in determining the manner in which the [PURPA] rules will be implemented." Idaho
Power,l55 Idaho at782,316 P.3d at 1280, citing FERC v. Misstssippi,456 U.S. at 751. It "is
up to the States. not [FERCI to determine the specific parameters of individual OF power
purchase agreements. . . ." Idaho Power, 155 Idaho at786,316 P.3d at 1284, quoting Power
Resources Group v. PUC of Texas,422F.3d23l,23815th Cir. 2005) (emphasis added).
Since PURPA was first enacted, this Commission has set the lengths for PURPA
contracts. Over the years, the Commission has set different contract terms of 35 years, 20 years,
and as short as 5 years. Order No. 33357 at I I (citations omitted). In setting contract lengths,
the Commission has "considered many factors (price risks, forecasting uncertainty, financial
needs, amortization, plant durability)." ld. at 12, citing Order No. 32125. We found in Order
No. 33357 and affirm in this Order that the Commission has discretion to set the length of
PURPA contracts. Order No. 33357 at 12. Indeed, the parties did not contest "that PURPA, and
its implementing regulations are silent as to a specific contract length. . . . Even Mr. Wenner
acknowledged that FERC regulations do not dictate a specific number of years or establish a
time period for PURPA contracts. Tr. at 589." Order No. 33357 at l2 (other citations omitted).
Moreover, Clearwater and Simplot have failed to identify any other State where the QF has the
unilateral authority to specily the term of a PURPA contract.
We reject the Petitioners' assertion that they may unilaterally choose the length of
their IRP contracts. As our Idaho Supreme Court has noted on many occasions, "[s]tatutory
interpretation begins with the plain meaning of the statute. If the statutory language is clear and
unambiguous, this Court need merely apply the statute without engaging in statutory
interpretation." Herman v. Herman, 136 Idaho 781,786,41 P.3d 209,215 (2002) (citations
omitted). Statutes and rules must be construed as a whole. Verska v. Saint Alphonsus RMC,l5l
Idaho 889,893,265P.3d 502,506 (2011); Idaho Power v. Idaho PUC,102 Idaho 744,754,630
P.Zd 442,452 (1981) (construing PURPA statutes).
It is the Commission that is tasked with implementing PURPA. It is the Commission
that approves all PURPA contracts - including the terms of such contracts. Order No. 15746, 38
P.U.R. 4th352 (ldaho 1980). It is also the Commission that sets and approves the avoided cost
ORDE,R NO. 33419 l3
rates calculated at either the time of delivery or at the time the contract or obligation is incurred.
l8 C.F.R. $ 292304(dx2)(i-ii). Rosebud II, 128 Idaho at 613,917 P.2d at770. The PURPA
regulations also address factors to be considered in determining avoided costs. In setting
avoided cost rates, the Commission is to consider "the terms of any contract or other legally
enforceable obligation, including the duration of the oblieation, the termination notice
requirement and sanctions for non-compliance." 18 C.F.R. $ 92.30a(e)(2xiii) (emphasis added).
Because the Commission must consider contract terms in calculating avoided cost rates -
especially the length of the contract - we find that setting the length of the contract is a necessary
requirement that falls to the Commission. This is not to say that all contracts must be of the
same duration. Indeed, as set out above, neither Clearwater nor Simplot has had a contract with
a 20-year term. FERC recognizes that there may be instances that would justify a contract for
the delivery of power "for a one year period." 45 Fed.Reg. at 12,226. In addition, our final
Order recognizes that there may be instances where a particular IRP-based PURPA contract is
longer than the standard two years. Order No. 33357 at 26. Consequently, Clearwater and
Simplot's attempt to paraphrase FERC regulations to their advantage is unavailing. It is the
Commission's responsibility to set the length of IRP-based PURPA contracts.
B. The Length of IRP Contracts
L The Leneth of 20-Year Contracts is Unreasonable. The Petitioners next assert that
the FERC regulations require "long-term, fixed-price contracts." Petition at 9 (emphasis added).
They urge the Commission to continue to use the 20-year contract as the standard IRP contract,
or adopt an "alternative proposal of a Zl-year contract with an update to energy prices . , . in
contract year 10." Petition at 4, 5, 15.
The Petitioners assert they are entitled to long-term PURPA contracts "to encourage
the sort of energy production required by PURPA." Petition at 9. They rely on FERC's Order
No. 69 that notes QFs have a "need for certainty with regard to return on investment in new
technologies;' Id. at 9-10, quoting 45 Fed,Reg. at12,224 (1980); Tr. at776. Their witness Dr.
Reading testified that IRP-based PURPA contracts of five years or less would not provide a
sufficient revenue stream for QFs to finance their projects or becorne economically viable. Tr. at
777-79. He indicated that the length of the QF contract is related to "the ability [of the QF] to
obtain funds in order to buitd [the QF] project." Tr. at 785.
ORDER NO. 33419 l4
The Utilities respond that there is nothing in PURPA or its implementing regulations
that specif,v an exact contract length. Answer at 4. They turther note the Commission found it
was uncontested that "FERC regulations do not dictate a specific number of years or establish a
timeperiodforPURPAcontracts." Id.,qttoting OrderNo.33357at 12; Tr.at589. Theyassert
that the Commission relied upon precedents from our Supreme Court and other federal courts
that held the Commission has the discretion in implementing PURPA to set the length of such
contracts. Id., citing Order No. 33357 at2-3,10, 12, 16,21-22.
Commission Findings: Based upon our review of the record, the PURPA regulations
and our prior Orders, we affirm our finding in final Order No. 33357 that PURPA and its
implementing regulations do not require a specific number of years or establish a certain time
period for PURPA contracts. Order No. 33357 at 12. The Petitioners have not directed our
attention to any specific contract length requirement in the PURPA regulations. In addition, our
review of Order No. 69 reveals that the phrase "long-term contract" appears only twice in the 24
pages of the Federal Register and was not further defined. See 45 Fed.Reg. at 12,214. Our
findings are supported by substantial evidence.
First, we are unpersuaded by Dr. Reading's testimony that long-term contracts are
needed to finance Clearwater's or Simplot's existing QF projects. Neither Clearwater nor
Simplot has had a 2}-year contract for their existing facilities during the 37 years for which
PURPA has been in effect. They have provided no explanation why they need Zl-year contracts
for their facilities. Moreover, their existing facilities cannot reasonably be considered "new
technologies" as referenced by FERC.
We specifically note that Clearwater recently entered into a non-PURPA agreement
for the output of its existing facilities until 2021. Thus, Clearwater's existing facilities are
contractually bound in a non-PURPA contract until 2021 and are not subject to Order No. 33357
for six years. The predecessors of Clearwater and Avista executed their first power purchase
contract in 1984 for l0 years. Order No. 23858, WashingtonWater Power,126 P.U.R.4th 61
(1991). Simplot began selling its power to Idaho Power in 1986 and entered its first long-term
PURPA contract (five years) with Idaho Power in 1991. OrderNo.23552, l99l WL 11858077
(ldaho PUC). The Petitioners did not seek Z}-year contracts in the past and have not persuaded
us on reconsideration that 20-year contracts for their existing facilities are needed now. Indeed,
ORDER NO. 33419 l5
Rocky Mountain's witness Mr. Clements testified that all of its cogeneration contracts are for a
period of one year. Tr. at 476-77 .
Also, the Petitioners' contemplation of new PURPA projects does not persuade us to
retain ZO-year contracts for several reasons. First, we find the Petitioners' interests in developing
new PURPA facilities are speculative and undefined. Other than the possible location, neither
Petitioner definitively identified any relevant characteristics of the luture projects on which they
premise their argument - for example, nowhere does the record contain any information
concerning the exact size of any future QF facility nor the proposed operation date. [n particular,
Clearwater and Avista have been having discussions about such a facility for more than five
years. Tr. at 771. While Simplot has asked for indicative pricing for a cogeneration facility up
to 25 MW at its new Caldwell facility, we are unaware of any subsequent progress. Tr. at 769.
While a QF is entitled to a PURPA contract or a legally enforceable obligation, its offer to sell
power to a utility must be firm, binding, and unconditional. Order No. 32974; 310 P.U.R. 4th
304 (2014); Whitehall Wind v. Montana Public Service Commission, 347 P3d 1277 (Mont.
2015); A.W. Brown,l2l ldaho 818,828 P.Zdat847.
Second, the Commission found that the standard lRP-based contract of two years was
not an absolute term. In particular, the Commission recognized there may be justification for
IRP-based contracts in excess of two years. Order No. 33357 at 26. Both Avista and Idaho
Power have tariff schedules approved by this Commission (Nos. 62 and 73, respectively) that
specify the PURPA negotiation process for obtaining a proposed PURPA contract. QFs are
certainly free to seek longer contracts if justified on a case-by-case basis. Consequently, at this
juncture the Petitioners are not foreclosed from seeking longer contracts for their tentative
projects. Order No. 33357 at28', citing Tr. at 876,881.
Third, the Commission found that any asserted need for Zo-year contracts was
mitigated by the "must purchase" provision of PURPA. Order No. 33357 at 23, 16 U.S.C. $
824a-3(b), l8 C.F.R. 5 292.3O3(a). "PURPA's 'must purchase' provision requires the utility to
continue to purchase the QF's power." Order No. 33357 at 25. As long as the projects continue
to offer power to utilities, utilities must continue to purchase such power under PURPA. And as
long as PURPA remains the law, the ability for QFs to earn a return remains. The shortening of
contract length is not intended to inhibit a QF's ability to recover its investment. Rather the
shortening of contract length functions as a means of ensuring that avoided costs remain 'Just
0RDER NO. 33419 l6
and reasonable to the electric consumer of the electric utility and in the public interest" (16
U.S.C. $ 82aa-3(bXl)) and serves "to maintain a more accurate ret'lection of the actual costs
avoided by the utility over the long-term." Order No. 33357 at 23.
Foufth, the Commission concluded that it was unreasonable to continue 2O-year IRP-
based PURPA contracts when utilities have no need fbr additional capacity. See City of
Ketchikan, Alaska,94 FERC n61,293 at62,061 (2001) ("there is no obligation under PURPA
fbr a utility to pay for capacity that would displace its existing capacity arrangements" and "there
is no obligation under PURPA for a utility to enter contracts to make purchases which would
result in rates which are not 'just and reasonable to electric consumers of the electric utility and
in the public interest' or which exceed 'the incremental cost to the electric utility of alternative
energy."'). The Commission found that both Idaho Power and PacifiCorp presented persuasive
evidence of capacity surpluses. More specifically, the Commission found that these "two
utilities have demonstrated that their supply of PURPA and non-PURPA power exceeds their
current average loads." Order No. 33357 a|24, citing Tr. at I ll,117,931. Idaho Power's senior
vice president testified that Idaho Power's PURPA and non-PURPA renewable resources
(approximately 1,297 MW) equaled about 40Yo of its 2014 systern peak-load and was equal to
about l20oh of it2014 minimum system load. OrderNo.33357 at 13, citing Tr. at l1l,177;
Exh. I I at 2. She testified it was unreasonable for Idaho Power to enter into long-term, fixed-
rate contracts when the Company does not need additional generation. Id., citing Tr. at 117, I19.
Rocky Mountain's witness also testified his company has no need for additional
generation until 2028. Order No. 33357 at 16, citingTr. at 429. The Commission found that if
all the proposed IRP-based contracts for Rocky Mountain were to become operational, then the
utility's existing and proposed PURPA contracts would be enough to supply 108% of
PacifiCorp's average retail load and275Yo of its minimum retail load in ldaho 2014. Order No.
33357 at 16, citing Tr. at 427 . The Commission found that the abundance of PURPA generation
extends the utilities'capacity surpluses to2024 for Idaho Power and2028 for PacifiCorp." Id. at
24.s We find these statistics persuasive that Z}-year contracts are unjust and contrary to the
public interest.
Fifth, the Commission found it unreasonable to continue to authorize Z}-year
contracts given the proposition that avoided cost rates for IRP projects are declining. Order No.
5 Avista has a capacity surplus until 2020. Order No. 33014 at 3
ORDER NO. 33419 t7
33357 at 22, citing Tr. at 260-61:372,630-3l 642. Continuing to allow QFs to lock in fixed-
rate contracts for 20 years 'owill 'overestimate' future avoided cost rates collected from the
utilities' ratepayers. Because of the Z1-year term of the current IRP-based contracts, this
'overestimation' will become more signitrcant over the [20-year]duration of the contract." 1d at
23. Given the projected decline in avoided costs, the Commission found and we affirm on
reconsideration that 2}-year contracts will result in unjust and unreasonable rates for utility
ratepayers and are no longer in the public interest. l6 U.S.C. $ 82aa-3(b)(1).6 Thus, substantial
and competent evidence supports our conclusions that 2}-year contracts will result in long-term
avoided cost rates that exceed the utility's incremental costs, thus running afoul of the law. Id. at
824a-3(b).
2. The Petitioners' 20-Year Alternative. The Petitioners also objected to the
Commission's rejection of their altemative proposal to maintain the 2O-year contract but adjust
the energy rate. On reconsideration, they propose a different 2O-year alternative where the
Commission could "re-price the energy component of new contracts in year 10 of the contract
while leaving the capacity rate fixed tbr the entire 2O-year term." Petition at 4, 5.
Commission Findings: First, we observe that the Petitioners' alternative proposal on
reconsideration is at odds with what they actually proposed in their testimony at hearing. At the
technicai hearing, Dr, Reading recommended that:
The Commission maintain a Z}-year contract length with the capacity
component of the rate fixed for the entire 20-year term. However, as a
compromise, the energy portion of the rate would onl), be fixed the first 10
years of the contract. After the first l0 years. the energy component would be
recalculated each year adhering to the Commission-approved method for the
remaining term of the contract.
Tr. at842 (emphasis added); OrderNo. 33357 at23. In other words, the energy rate would be
adjusted annually in each of the last ten years of the contract, The Petitioners either
mischaracterized their alternative proposed at hearing or now on reconsideration advance a
different Z}-year alternative, one offered by the Idaho Conservation League/Sierra Club's
witness, Mr. Beach. At hearing, he suggested that the Commission "make a single adjustment in
6 The Petitioners' reliance on the Hydrodynamics, Cedar Creek LYind, and New York State Electric & Gas cases is
misplaced. These cases are not relevant to the issue of contract length and are factually distinguishable.
Hyrlrodynamics, 146 tT 6l , 193 P. 3 I (201a); Cedar C'reek Wind, 137 FERC ll 6l ,006, P. 32 (201 l); New York State
Electric & Gas Corp.,7 I FERC tT 6l ,027, 6l ,l I 5- l6 ( 1995).
ORDER NO. 314r9 l8
the llth year of aZ}-year contract." Order No. 33357 at23, cithtgTr. at702. Once reset, the
energy rate "for Years I l-20 would continue to be fixed." ft/.
We find the Petitioners' new alternative offered on reconsideration suffers from the
same defect we previously identified in Order No. 33357 and outlined above. "An adjustable
rate contract runs the risk of violating FERC regulations that mandate a 'fixed rate' at the time of
contracting." Order No. 33357 at 24. Further, as long-term avoided cost rates continue to
decline, contracts of 20 years will "'overestimate [the]' future avoided costs collected from the
utilities' ratepayers." Order No. 33357 at 23. This "overestimation" of future avoided costs will
become more significant over the duration of the ZD-yeat alternative proposed by the Petitioners
on reconsideration. Id. The Petitioners' proposed alternative to adjust energy rates a single time
at the mid-point of a Z0-year contract does not mitigate our concerns. Finally, "the same result
can be accomplished through successive short-term contracts" without the risk of violating
FERC regulations or unreasonably burdening customers. Id.
Consequently, we affirm our decisions and findings set out in Order No. 33357.
There is substantial and competent evidence to support our findings that two-year standard IRP-
based contracts are fair and reasonable, absent circumstances that would justify an exemption to
the standard length.
C. The QF is Provided a Capacity Rate and
the Capacity Adjustment does not Bind Future Commissions
ln their Petition for Reconsideration, Clearwater and Simplot insist that the two-year
contract does not provide QFs with a capacity rate, and that the Commission's capacity
adjustment is legally defective. The Petitioners maintain these "errors" caused by the two-year
contract and the capacity adjustment justify the return to 20-year contracts or their alternative
proposal that re-prices avoided cost energy rates in the middle of the 2O-year contract. Petition
at 12-15.
t. The Two-Year Contract Provides a Capacity Rate. The Petitioners acknowledge
the two-year IRP contract allows for short-term, fixed-price compensation for energy but they
argue the Order provides "no price at all for capacity and thereby deprives the QF of the right to
sell capacity." Petition at l2 (emphasis added). They insist that a QF is deprived of a 'fixed
contract price for its energy and capacity at the outset of its obligation' because . . . a two-year
ORDER NO. 33419 l9
contract will not provide a price for capacity that is fixed at this time." Id. at 12 (italics original
and citations omitted).
The Utilities offer three arguments in response. First, the Utilities assert the
Petitioners have misconstrued the Commission's final Order No. 33357. They maintain that the
Order was not intended to establish avoided cost rates, "[The Order] is limited to addressing the
maximum contract length." Answer at 7. Actual avoided cost rates, for both avoided energy and
avoided capacity, are established in other Commission Orders and through the Commission's
approval of individual contracts.
Second, the Utilities maintain that the Petitioners' allegation that Order No. 33357
does not set a capacity rate, is really an impermissible collateral attack on the Commission's
prior Orders that do establish avoided cost rates fbr both capacity and energy in IRP-based
contracts. ldaho Code $ 6l-625 (final and conclusive orders of the Commission "shall not be
attacked collateratly"). The Utilities insist that avoided cost rates for capacity (or energy) are
simply not relevant to this proceeding . ld. at 7 .
Third, the Utilities maintain that when a utility has a capacity surplus, then the
"capacity component of the avoided cost price [is] zero. The capacity price is not absent. . . . it is
set at zero because the utility is capacity sufficient." ld. at 8 (emphasis added). The Utilities
explain that a QF is only entitled to capacity rates when the utility has a need for additional
generation or firm power purchases - i.e., when a QF contributes capacity to a utility with a
capacity deficiency, then the avoided cost rates fbr the QF "will include both avoided energy and
capacity [rates]." Id., citingTr. at276.
The Utilities conclude that the Commission's capacity adjustment was intended to
recognize that the QF will be eligible to receive capacity rates when the utility is no longer
capacity deficient. They insist this is a benefit to QFs in that it allows a QF to establish a right to
capacity payments at the time the initial IRP-based contract is signed or the obligation is
incurred. Answer at 8. They quote from the Commission's Order:
As long as the QF renews its contract and continuously sells power to the
utility, the QF is entitled to capacity [payments] based on the capacity
deficiency date established at the time of [the QF's] initial contract.
Order No. 33357 at 25-26. They maintain the primary difference between the Commission's
previously established 2)-year term and the two-year contract term established in Order No.
or{DER NO. 334r9 20
33357, is that the avoided cost rates "are refreshed at each two-year contract interval, rather than
being erroneously estimated and locked-in over 20 years." Answer at 8.
Commission Findings: We are unpersuaded by the Petitioners' capacity adjustment
arguments fbr several reasons. First, the capacity adjustment does not apply to Petitioners'
existing f-acilities. Because the existing Clearwater and Simplot facilities already contribute
capacity to Avista and Idaho Power respectively, they both currently receive, and remain eligible
to receive, capacity payments when their existing contracts are renegotiated and renewed.
Indeed, the Petitioners concede that renewal contracts for their existing QF facilities would
continue to receive compensation for capacity under the Commission's Order No. 33357.
Petition at 4.
Second, the Petitioners also misconstrue the mechanics of the capacity adjustment as
they relate to any new, unbuilt future QF projects, If the utility has a capacity surplus, then a
tlrst-time QF entering into its initial two-year IRP contract is not eligible to receive any payment
for capacity. However, if the purchasing utility has a capacity deficit in the initial or subsequent
two-year contract, then the QF is eligible to receive capacity payments from that point forward.
Both FERC and this Commission have a long-standing practice of allowing QFs to obtain
capacity payments only when the utility is or
becomes capacity deficient. tf a utility is capacity surplus, then capacity is not
being avoided by the purchase of QF power. By including a capacity payment
only when the utility becomes capacity deficient, the utilities are paying rates
that are a more accurate reflection of a true avoided cost for the QF power.
Order No. 33357 at 25, quoting Order No. 32697 at 2l; Tr. at 586-87. Thus, if a utility has a
capacity surplus during the entire two years of an IRP-based contract, a QF is not eligible to
receive a capacity payment. ln practical terms, the avoided cost capacity rate in this example is
zeto.
As FERC stated in its Order No. 69, avoided cost rates need not include capacity
costs unless the QF purchase will permit the utility to avoid building or buying future capacity.
Order No. 69, 45 Fed.Reg. at 12,225-26. "[C]apacity payments can only be required when the
availability of capacity from a [QF] actually permits the purchasing utility to reduce its need to
provide capacity by defening the construction of new plant or commitments to firm power
purchase contracts." Id. While the utility may have an obligation under PURPA to purchase
oRDER NO. 334r9 2t
power from a QF, "that obligation does not require a utility to pay tbr capaciry that it does not
need." Ciry o.f Ketchikan,94 FERC \61,293 at*6.
2. Forecasted Capacity Rates. The Petitioners also argue that PURPA's
implementing regulations entitle them to a tbrecasted capacity rate when they enter into their
contact/obligation. For example, if Clearwater or Simplot enters into a contract for their unbuilt
and speculative facilities to be effective in 2015 but the utility has a capacity surplus untrl2024,
the Petitioners argue they are entitled to a future capacity rate for 2024, when the utility is
capacity deficient. They allege that this lack of a forecasted capacity rate calculated at the time
they enter into their contract "is obviously not what FERC had in mind when it stated its
[PURPA regulation] provides each QF with a 'capacity credit' through [sic] in a 'fixed contract
price at the outset of its obligation' that provides 'certainty with regard to retum on
investment."' Petition at14, citing 45 Fed.Reg. at 12,224. They assert the capacity adjustment
does not comply with section 292.304(b) which "requires that the QF be provided a fixed price
to sell that capacity at the time of commencement of the [contract or] obligation - not a rate
calculated . . . several years from now." Petition at 14.
Commission Findings: We find the Petitioners misunderstand our Order and FERC
regulations. The regulations provide that a QF has the option to either provide energy or
capacity as available, or at avoided cost rates calculated "over [the] specified term." 18 C.F.R. $
292.304(d)(l), (2) If the QF chooses to sell power to the utility over a specified term, the QF
may have the rates calculated for the term at either "the time of delivery; or . . . at the time the
obligation is incurred." l8 C.F.R. S 292.304(dX2Xl-l l). In Order No. 33357, we determined
that "the specified term" for new standard [RP-based contracts is two years. Thus, Clearwater
and Simplot are entitled to receive avoided cost capacity rates for the specified term calculated at
either the time of delivery or at the time they enter into their contracVobligation.
We also directed the Utilities to establish their capacity deficiency date when a QF's
initial IRP-based contract is signed. Order No. 33357 al 25-26. This capacity adjustment
mechanism recognizes that if a QF continues to provide energy to a utility through when the
utiiity would otherwise experience a capacity deficiency, the QF will be paid for its capacity
contribution. But until a QF enters into a contract during which that capacity deficit date occurs,
the avoided cost capacity rate is zero.
ORDER NO. 334r9 22
As Mr. Wenner opined, a QF "is entitled to receive [capacity] rates based on the
capacity cost that the utility can avoid as a result of its obtainingcapacity from the [QF]." Tr. at
586, quoting 45 Fed.Reg. at 12,225. A capacity rate calculated at the start of each specified term
rather than upon a QF's initial contract, is a truer reflection of the utility's avoided cost for
capacity. The capacity adjustment mechanism thus ensures the QF receives the full avoided cost
of the utility, consistent with FERC regulations.
Notably, FERC comments drafted at the time it was issuing its PURPA regulations
provided:
IFERC] recognizes that the translation of the principle of avoided capacity
costs tiom theory into practice is an extremely difficult exercise, and is one
which, by definition, is based on estimation and forecasting of future
occurrences.
Accordingly, IFERC] supports the recommendation made in the Staff
Discussion Paper that it should leave to the States and nonregulated utilities
"flexibility for experimentation and accommodation of special circumstances"
with regard to implementation of rates for purchases. Therefore, to the extent
that a method of calculating the value of capacity from [QFs] reasonably
accounts for the utility's avoided costs, and does not fail to provide the
required encouragement of cogeneration and small power production, it will
be considered as satisfactorily implementing the Comrnission's rules.
45 Fed.Reg. at 12,226.
As set out in Order No. 33357, Idaho has been very successful in encouraging the
development of renewal QF power. Our changes in this docket are simply intended to ensure the
utility is not paying more than its actual avoided costs when purchasing QF power.
3. The Capacity Adjustment does not Bind Future Commissions. Simplot and
Clearwater also argue that the Commission's capacity adjustrnent suffers from legal defects.
They argue that this Commission cannot bind a future Commission to a capacity deficiency date
at any particular point in a hypothetical future PURPA contract. Petition at 13. In other words,
they allege the present Commission cannot set a future capacity deficiency date in a future 2023
contract. They insist the QFs cannot reasonably rely on the Commission's non-binding decision
to support the QF's right to sell its capacity in a hypothettcal2023 contract. Petition at 14. They
argue in a footnote that the ooreserved powers doctrine" limits the ability of the Commission to
ORDER NO. 33419 23
bind a future Commission. See Petition at footnote l. The Utilities do not respond to this
specific argument.
Commission Findings: Under the reserved powers doctrine, "a state government
may not contract away o'an essential attribute of its sovereignty." U.S. v. Winstar Corp.,5l8
U.S.839,888 (1996),citing UniredStatesTrust Co. v. New Jersey,43l U.S, 1,23 (1977). Such
"essential attributes" of state sovereignty include the power of eminent domain, and the power to
police. This "power to police" is commonly referred to as a state's police power. In ldaho, the
Commission exercises legislative police power when setting rates. Coeur d'Alene Dairy Queen
v. State Insurance Fund, 154 Idaho 379,385,299P.3d 186, 192 (2013); Idaho Power & Light
Co. v. Blontquist,26ldaho222,258,l4l P. 1083, 1094 (1914). The Commission's regulation of
utility rates set by private contract is subject to such police power. Agricultural Products Corp.
v, (Jtah Power & Light Co.,98ldaho 23, 29,557 P.2d 617,623 (197q.1
The related doctrine of "unmistakability" provides, "absent an 'unmistakable'
provision to the contrary, 'contractual arrangements, including those to which a sovereign itself
is a party, remain subject to subsequent legislation by the sovereign."' Winstar,5lS U.S. at877,
citing Bowen v. Public Agencies Opposed to Social Security Entrapment,4TT U.5.41,52 (1986)
(internal quotations omitted).
We believe neither doctrine applies in this PURPA case. First, the Commission's
capacity adjustment is not a "contract" where the Commission is a party to the contract. The
capacity adjustment is also not a "rate." It is a mechanism used to determine when a new QF in
an IRP contract is eligible to receive capacity payments. It is always true that the Commission
can exercise its authority to change a ruling in a subsequent decision, just as a state legislature
can change a law. Our Supreme Court has held on numerous occasions that the Commission is
not rigorously bound by the doctrine of stare decisis. Idaho Power,155 ldaho at1286,316 P.3d
at 788; McNeal-ldaho PUC,l42 Idaho 685, 690, 132 P.3d 442,447 (2006). However, when the
Commission departs from a previously-established policy, it must explain its departure from
prior rulings so that a reviewing court can determine that the decision to change is not arbitrary
or capricious. lntermountain Gas Co. v. Idaho PUC,97 Idaho ll3, 119, 540 P.2d 775,781
'The Commission may only interfere with the utiliry's contract if it finds that a rate is so low or so high as to
adversely affect the public interest; "where it might impair the financial ability of the public utility to continue its
service, cast upon other consumers an excessive burden, or be unduly discriminatory." Bunker Hill Co. v.
Washington ll/ater Power Cct.,98 ldaho 249, 253,561 P.2d 391, 395 (1997) (quoting the elements of the Sierra-
Mobile Doctrine from Federal Power Commission v. Sierra Pac. Power Co.,350 U.S. 348, 355 (1956).
ORDITR NO. 33419 24
(1975). So long as the Commission adequately explains its departure, "orders based upon
positions substantially different than those taken in previous proceedings can be upheld." Id.
Such authority does not diminish the "legal effect" of the Commission's decision,
from any perspective. The determinations and rulings in a final Order are binding on the
affected utilities until they are changed or rescinded in the future. Idaho Code 9$ 6l-406 (every
utility "shall obey and comply with each and every order, decision, direction, rule or regulation .
. "). To the extent Clearwater/Simplot mean to assert that the Commission's decision has no
"practical effect" from a QF's perspective, because a future Commission could enter a contrary
decision, the same could be said of any existing QF contract, any Commission decision, or
indeed any [aw. Thus, we reject the Petitioners claims of a legal defect.
D. The Capacity Adjustment is Supported by
Substantial Evidence in the Record
Finally, the Petitioners assert that the Commission's capacity adjustment was not
advocated by any party and therefore falls outside the record. They allege that no party
discussed this idea in testimony and no party has had an opportunity to address it. They insist
that the "Commission's f,tndings and conclusions must be made upon the record developed
before it, and that when an administrative agency strays from the records its findings are not
supportable on review." Petition at 16.
The Utilities assert that this argument is without merit. They note that the
Commission received extensive testimony from the Petitioners' witness Dr. Reading and from
the Sierra Club's witness Mr. Wenner regarding the need to compensate QFs for capacity.
Answer at 9-10, citing Tr. at 773-79,583-601. The Utilities also argue that the Commission's
resolution of disputed issues is not so strictly limited to relief that "was exactly proposed or
suggested by the parties. The Commission is free to act within it authority and discretion, based
on the evidence before it." Id.
Commission Findings: Despite the Petitioners' argument to the contrary, the
Commission's capacity adjustment was specifically designed to ensure that the reduction in the
standard-length IRP contract from 20 years to two years does not permit Utilities to avoid their
obligation to make capacity payments to QFs "in the first year the utility has an identified
[capacity] deficiency." Tr. at 701. As Mr. Wenner explained, FERC's PURPA regulations
require QFs to be paid for capacity when the QF is providing capacity that enables the utility to
ORDER NO. 33419 25
avoid or forego the construction of new generating facilities or the purchase of firm power. Id at
587. Quoting from FERC's Order No. 69, Mr. Wenner testified that a QF "is entitled to receive
[capacity] rates based on the capacity cost that the utility can avoid as a result of its obtaining
capacity from the [QF]." Tr. at 586, quoting 45 Fed.Reg. at 12,225. He insisted that if QF
contracts are limited to two years, then "that power cannot be counted on to be available after
two years. . . ." Tr. at 587. The Petitioners' witness Dr. Reading also objected to the reduction
in the length of IRP contracts. He opined that if [RP-based contracts are shortened to five or
fewer years, the QF will not be able to cause the utility to avoid future capacity additions. Tr. at
777,778-79. He argued that the shortened contract length is designed to deprive capacity
payments to the QF. 1d at786.
Given these concerns about capacity and capacity payments, the Commission
fashioned its capacity adjustment to remedy these concerns expressed by the parties. Consistent
with FERC regulations and our Orders, a utility is required to pay for capacity contributed by the
QF when the utility no longer has a capacity surplus. Order No. 33357 at 25-26, citing Order
No. 32697 at 21. While the "must purchase" provision requires utilities to purchase capacity and
energy fiom a QF, "that obligation does not require a utility to pay for capacity that it does not
need." City q/'Ketchikan,94 FERC n 61,293 at *6. When a QF enters into its initial
contracVobligation with the utility, the capacity adjustment entitles the QF to know the exact
date when it will be eligible to receive capacity payments as long as the QF continues to
contribute to the utility resource stack. Thus, the Commission created the adjustment in
conjunction with the standard two-year term for IRP-based contracts to prevent utilities from
circumventing their obligations to pay for capacity when the utility becomes capacity deficient.
The Commission's capacity adjustment is based upon ample evidence in the record
olfered by the Petitioners and other parties, and comports with FERC regulations requiring
utilities to make avoided cost capacity payments to the QF at times when the utility is capacity
deficient. The Idaho Supreme Court will uphold the Commission's findings of fact if they are
supported by substantial, competent evidence. ldoho Power,755 Idaho at787,316 P.3d at 1285;
Rosebud II, 128 ldaho at 618,917 P.zd a't 775. In both Order No. 33357 and here, the
Commission has explained its reasoning used to reach its conclusions based on substantial and
competent evidence from the record before it.
ORDER NO. 33419 26
Given the totality of the evidence in the record, we affirm our findings in final Order
No. 33357 that it is reasonable and consistent w'ith PURPA that the standard IRP contract be
reduced from 20 years to two years. It is uncontested that utilities do not need additional
generating capacity and that PURPA and non-PURPA generation exceeds Idaho Power's and
Rocky Mountain's minimum average loads. More importantly, given the undisputed evidence
that avoided costs are decreasing, retaining fixed rates for 20 years would violate PURPA's
Section 210(b) mandate that avoided costs rates shall not exceed a utility's avoided costs. We
find that the Petitioners' alternative proposal to adjust energy rates one time in the middle of a
20-year contract is not consistent with PURPA's intent or FERC's regulations. Consequently,
the Commission denies Simplot's and Clearwater's request to retain 2}-year terms for IRP-based
contracts.
ORDER
IT IS HEREBY ORDERED that Clearwater's and Simplot's request to amend final
Order No. 33357 is denied. The Commission declines their request to continue a 2O-year term
for IRP-based contracts or to adopt their alternative proposal on reconsideration to adjust energy
rates one time at the mid-point of a 2}-year contract.
IT IS FURTHER ORDERED that the Petitioners' other issues raised in their Petition
for Reconsideration are dismissed as set out in the body of this Order.
THIS IS A FINAL ORDER ON RECONSIDERATION. Any party aggrieved by this
final Order on Reconsideration or other final or interlocutory Orders previously issued in this
Case Nos. IPC-E-15-01, AVU-E-15-01, and PAC-E-I5-03 may appeal to the Supreme Court of
Idaho pursuant to the Public Utilities Law and the ldaho Appellate Rules. See ldaho Code g 6l-
627.
ORDER NO. 334r9 27
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 5f^
day of November 201 5
PAUL
Commissioner Smith did not participate in this case
MARSHA H. SMITH, COMMISSIONER
RAPER,IONER
ATTEST:
/ ti rl,^,*l!
idln o.F.*.tI/
CYmmission SUcretary
O:lPC-E-l 5-01 AVU-F.-15-01 PA(]-E-15-03 dh4 Ijinal Rcconsideration
ORDER NO. 334 r9 28
4r o,fro l)-
Exhibit 3
Idaho Public Utilities Commission
Order No. 32697
Office of tre SecteurY
Service Dale
Decernber 18,2012
BEFORE TIIE IDAHO PI.]BLIC UTILMIBS COMNflISSION
IN TEE MATTER (,IF TIIE COMMISSION,S
REVIEW OX'Prru,A QF CONTRACT
PROVISIONS INCLUDING TIIE
STTRRoGATE AVOTDED RESOURCE (SAR)
AT{D INTEGRATED RESOURCE PLAI\INING
(rRP) METHODOLOGTES FOR
CALCTILATING AVOIDED COST RATES.
CASE NO. GNR.E.TT.O3
oRDER NO. 32697
This case began on November 5, 2010, upon a filiqg by Idaho Power Company,
Avista Corporation, and PacifiCorp dba Rocky Motrntain Power requesting that the Commission
investigate various avoided cost rate issues under the Public Utility Regulatory Policies Act of
1978 (Pt RPA). Phase I considered eligibility to published avoided cost rate contacts. In
Febnrary 201l, Phase II undertook an investigation of disaggregation and its effect on published
avoided cost rates.
On September 1, 2011, the Commission issued aNotice of Review that initiated this
most recent proceeding to investigate the standard terms of PLJRPA power purchase agreements.
Order No. 32352; Idaho Code $ 6l-503. This investigation (Phase III) was not limited to the
surrogate avoided resource (SAR) and Integrated Resource Planning (IPJ) methodologies for
calculating published avoided cost rates. Topios such as the dispatchability of varying tresources,
curtailment options, integration costs, renewable energy credits, delay security and liquidated
damages, timing and schedule of negotiations, and conftct milestones were also at issue.
The Commission set an intervention deadline of September 8, 2011. Order No.
32352. All parties of record from the Commission's Phase II PLJRPA investigation (GNR-E-I1-
0l) were automatically granted party status. On September 21, 2011, a Notice of Parties was
issued. On November 2,2011, the Commission issued the procedural schedule for this case
proposed and agreed to by the parties. Order No. 32388. Direct and rebuttal testimony was
filed, legal briefs were submitted and a three-day technical hearing commenced on August 7,
2012. Subsequent settlement discussions were held at the directive of the Commission. Order
No. 32617. On October 16,2012, a partial settlement among some of the parties was submitted
to the Commission for approval.
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IoRDER NO. 32697
By this Order, and as set out in greater detail below, the Commission sets published
and negotiated avoided cost rate pararneters. The Commission furttrer establishes and defines
numerous contract terms for standard power pruchase agreements entered into between regulated
utilities and qualiffing facilities (QFs).
BACKGROUNI}
A. The Joint Petition
GNR-E-10-01@hase I)
On November 5, 2010, Idatro Power Company, Avista Corporation, and PacifiCorp
dba Rocky Mountain Power filed a Joint Petition rcquesting that the Commission initiate an
investigation to address various avoided cost issues related to the Commission's implementation
of PURPA. While the Commission pursued its investigation, the utilities also moved the
Commission to "lower the published avoided cost rate eligibility cap from l0 aNdW to 100 kW
[to] be effective immediately. . . ." Id. ctting Joint Petition at 7. When a QF project is larger
than the eligibility cap set for access to published avoided cost rates, the avoided cost rates for
the project must be individually negotiated by the QF and the utility using the Integrated
Resource Planning (IRP) Methodology.r Order No. 32176.
On December 3, 2010, the Commission issued Order No. 32131 declining the
utilities' motion to immediately reduce the published avoided cost rate eligibility cap from l0
aI/tW to 100 kW. Order No. 32131 at 5. However, the Order did notifu parties that the
Commission's decision regarding the motion to reduce the published avoided cost eligibility cap
would become effective on December 14, 2010. Id. at 5-6,9.
Based upon the record in the GNR-E-10-04 case, the Commission subsequently found
that a "convincing case has been made to temporarily reduce the eligibility cap for published
avoided cost rates from 10 aN{W to 100 kW for wind and solar only while the Commission
further investigates" other avoided cost issues. Order No. 32176 at 9 (emphasis in original). The
Commission also announced its intent to initiate additional proceedings to investigate and
address the disaggregation of large projects. Id. at ll.
' The purpose of utilizing the IRP Methodology for large QF projects is to more precisely value the enerry being
delivered. Id. at 10. The IRP Methodology recognizes the individual generation characteristics of each project by
assessing when the QF is capable of delivering its resources against when the utility is most in need of such
resources. Utilization of ttre IRP Methodology does not negate the requirement under PURPA that the utility
purchase the QF energy.
ORDER NO. 32697 2
On reconsideration, the Commission affirmed its decision to temporarily reduce the
eligibility cap for published avoided cost rates from l0 aN{W to 100 kW for wind and solar
projects. Order No.32212. Thus, the eligibility cap for published avoided cost rates for wind
and solar QF projects was set at 100 kW effective December 14, 2010. No party appealed the
decision to reduce the eligibilif cap.
B. Disaggregation
GNR-E-11-01 (Phase II)
On February 25,2011, consistent with its stated intent to investigate the issue of
disaggregation, the Commission issued a combined Notice of Inquiry, Notice of Intervention
Deadline, Notice of Scheduling, and Notice of Technical Hearing. Order No. 32195.
Specifically, the Commission solicited information and initiated an investigation of a published
avoided cost rate eligibility cap structure that (1) would allow small wind and solar QFs to avail
themselves of published rates for projects producing l0 aMW or less; and (2) would prevent
large wind and solar QFs from disaggregating inlo small projects in order to obtain published
avoided cost rates that exceed a utility's actual avoided cost. .Id.
In initiating Phase II, we stated that "[t]his Commission is supportive of all small
power producers contemplated by PURPA, including wind and solar, and it is not the
Commission's intent to push small wind and solar QF projects out of the market." Order No.
32176 at 11. The Commission was concerned that large QF projects were disaggregating into
smaller QF projects in order to be eligible for published avoided cost rates that may not be just
and reasonable to the utility customers nor in the public interest. Order No. 32195 at 3. The
purpose 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 to the
utility. Id. at l.
After careful consideration, the Commission ultimately determined that it was
appropriate to maintain the 100 kW eligibility cap for published avoided cost rates for wind and
solar QFs. Order No.32262. Wind and solar projects larger than 100 kW are still entitled to
PURPA conffacts with avoided cost rates calculated through use of the IRP Methodology. The
Commission found that any attempt to implement criteria in an effort to prevent disaggregation
"would be met by attempts to circumvent such criteria." Id. at 8. The Commission emphasized
that PURPA and this State's published rate stnrcture were never intended to promote large scale
oRDER NO. 32697 3
I
I
I
wind and solar development to the detriment of utility customers. We further fourd that a 100
kW threshold for wind and solar QFs would provide a certainty to the parties in negotiations that
disaggregation criteria would not. Id. "While we recognize the impact that this decision will
have on small wind and solar projects, it would be erroneous, and illegal pursuant to PURPA, for
this Commission to allow large projects to obtain a rate that is not an accurate reflection of the
utility's avoided cost for the purchase of the QF generation." Id,, citing Rosebud Enterprises v.
Idaho PUC, 128 Idaho 609, 623,917 P.2d 766,780 (1996), citing Connecticut Light & Power
Co.,70 FERC 61,012 (1995), reconsid. denied, Tl FERC 61,035 (1995).
At the conclusion of the Phase II case the Commission stated its intent to initiate
additional proceedings to allow the parties to investigate and analyze both the SAR Methodology
and the IRP Methodology (GNR-E-I l-03, Phase III). On September 1,201l, the Commission
issued a Notice of Review to investigate the standaxd terms of PURPA power purchase
agreements.
C. GNR-E-ll-03 (Phae III) Procedural History
The Commission initiated Phase III to investigate various PURPA topics including,
but not limited to: the sr.urogate avoided resource (SAR) methodology, the Integrated Resource
Planning (IRP) Methodology, the dispatchability of varying resources, curtailment options,
integration costs, renewable energy credits, delay sectrity and liquidated damages, timing and
schedule of negotiations, and consideration of contract milestones. Order No. 32352.
The Commission set an intervention deadline of September 8, 2011. All parties of
record from the Phase II investigation (GNR-E-I l-01) were automatically granted party status in
Phase lll. Id. at 5. On September 2l,2}ll, aNotioe of Parties was issued.2 On November 2,
2011, the Commission issued a procedtual schedule proposed and agreed to by the parties.
Order No. 32388. In accordance with the schedule, the utilities filed their individual direct
testimonies on January 21,2012.
On March 12,2012 (prior to the filing of direct testimony by Commission Staff and
Intervenors), Idatro Power filed a Motion for Temporary Stay of Its Obligation to Enter into New
Power Purchase Agreements with Qualiffing Facilities. Idaho Power argued that its prefiled
testimony established prima facie proof that Idatro Power's cunent avoided cost rates were not
accurate; and that without adequate interim relief from its obligation to purchase, Idaho Power
2 Several parties were also granted intervenor status after the deadline for intervention had passed.
oRDERNO. 32697 4
customers were likely to suffer substantial harm. The Company asserted that the balance of
harms favored granting interim relief and that good cause existed to grant irnmediate relief on an
interim basis. Idaho Power filed affidavits in support of its Motion.
On March 14,2012, Rocky Mountain Power filed a Request to Join and Response to
Idatro Power's Motion. The Idatro Conservation League, Snake River Alliance, Exergy, and J.R.
Simplot Company each filed responses opposing Idaho Power's Motion and asked that the
request for a stay be dismissed in its entirety. In order to give all parties an adequate opportunity
to respond to the assertions made by Idatro Power, but in consideration of the expedited nature of
Idaho Power's request, the Commission convened an oral argument on March?l,}0lz. Order
No.32495.
On March 22,2012, the Commission issued Order No. 32498 denying Idatro Power's
Motion for a Temporary Stay of its mandatory purchase obligation. However, the Commission
found that the avoided cost rate methodologies "as utilized and applied by ldatro Power, do not
currently produce rates that reflect ldaho Power's avoided costs and are notjust and reasonable,
nor in the public interest." Order No. 32498 at 2. Therefore, the Commission ordered that,
effective March 21,2012, and continuing until the Commission issues its final Order in Phase
III, "contracts for all projects over 100 kW entered into by Idaho Power and presented to this
Commission for approval will be individually evaluated with regard to all terms contained
therein." .Id.
Thereafter, direct testimony was filed by Commission Staff and numerous
intervenors. On July 6, 2012, rebuttal testimony was simultaneously filed by all parties and
subsequent legal briefs were also submitted. A tluee-day technical hearing convened on August
7, 2012. The following parties appeared by and through their respective counsel or
representative:
Avista Corporation
ldaho Power Company
PacifiCorp dba Rocky Mountain Power
Commission Staff
Michael G. Andrea, Esq.
Donovan Walker, Esq.
Jason Williams, Esq.
Daniel Solander, Esq.
Kristine Sasser, Esq.
5ORDER NO. 32697
Northwest and lntermountain Power
Producers Coalition (NIPPC); Clearwater
Paper Corp; J.R. Simplot Co.; Exergy
Development Group of ldaho, LLC; Grand
View Solar II; Board of County
Commissioners of Adams County
Dynamis Energy, LLC;
Renewable Energy Coalition
Intermountain V/ind, LLC; Idatro
Windfarms, LLC; Renewable Northwest
Project; Ridgeline Energy, LLC
North Side Canal Company; Twin Falls
Canal Company; Big Wood Canal
Company; American Falls Reservoir
District No. 2
Idaho Conservation League
Snake River Alliance
Idaho Wind Partners I, LLC
Mountain Air Projects, LLC
Interconnect Solar Development
Blue Ribbon Energy
Birch Power Company
Energy Integrity Project
Peter J. Richardson, Esq.
Gregory M. Adams, Esq.
Ronald L. Williams, Esq
Dean J. Miller, Esq.
Tom Arkoosh, Esq
Benjarnin J. Otto, Esq.
Ken Miller
Deborah E. Nelson, Esq.
Michael J. Uda, Esq.
Pro hac vice
Bill Piske
Aaron Jepson, Esq.
Ted Sorenson
Tauna Christensen
Following the technical hearing, settlement discussions were held at the directive of
the Commission. Order No. 32617. A partial settlement was negotiated and submitted to the
Commission for consideration. On October 16,2012, the Commission issued a Notice of Partial
Settlement and Request for Comment. Order No. 32665. Parties and the public were given until
October 25, 2012, to submit comments regarding the terms of the Settlement Stipulation.
Requests for intervenor funding were submitted by Big Wood Canal and American Falls
Reservoir; ICL; and North Side and Twin Falls Canal Companies.
6oRDERNO. 32697
By this Order, and as set out in greater detail below, the Commission modifies
published (SAR) and negotiated (IRP) avoided cost rate methodologies. The Commission
further establishes and adopts numerous contract terms for power pruchase agreements entered
into between regulated utilities and QFs consistent with PLJRPA and FERC regulations.
D. PaRPA andAvoided Cost Rates
Congress enacted PURPA in 1978 in response to a national energy crisis. *Its
purpose was to lessen the country's dependence on foreign oil and to encourage the promotion
and development of renewable energy technologies as altematives to fossil fuels." Order No.
32580 at 3, citing FERC v. Mississippt, 456 U.S. 742, 745-46 (1982). To encourage the
development of renewable facilities, PURPA requires that electric utilities purchase the power
produced by designated qualifring facilities (QFs). o'This mandatory purchase requirement is
often referred to as the 'must purchase' provision of PURPA ." Id., 16 U.S.C. $ 824a-3(b); I 8
C.F.R. g 292.303(a).3
Under the must purchase provision, the rate a utility must buy the power produced by
the QF is generally referred to as the "avoided cost" rate. "The avoided cost rate represents the
'incremental cost' to the purchasing utility of power which, but for the purchase of power from
the QF, such utility would either generate itself or purchase from another source." Order No.
32580 at3 citing Rosebud Enterprises v. Idaho PUC,128 Idatro 624,917 P.zd 781 (1996); l8
C.F.R. $ 292,101(bX6). The ldatro Supreme Court has held that the Commission has the
authority to implement PURPA and set the avoided cost rates. Rosebud, 128 Idatro at 612,917
P.2d at 769; A.W. Brown v. Idalo Power Company, l2l Idatro 812, 814, 828 P.2d 841, 843
(1992). In other words, PLJRPA requires that utilities buy the power output from QFs under a
federal rate mechanism (i.e., avoided costs) that is determined and irnplemented by state utility
commissions.
DISPUTED ISSUES
A. Sunogate Avoided Resource (SAR) Methodologt
PURPA and its implementing regulations require that published/standard avoided
cost rates be established and made available to QFs with a design capacity of 100 kW or less. 18
C.F.R. $ 292.30a(c). This Commission has utilized the SAR Methodology for computing
published avoided cost rates since the State began implementing PURPA. The SAR
3 There are exceptions to the must purchase provision but they are not applicable in this case.
70RDER NO. 32697
Methodology estimates a utility's avoided costs to be applied to QF generation by calculating the
cost of a surrogate avoided resource - currently the surrogate used is a natural gas-fired
combined-cycle combustion turbine (CCCT). Modifications to the methodology have occuned
over time. Input variables and price assumptions have been updated and modified in order to
ensure that the published avoided cost rates are an accurate reflection of a utility's avoided cost.
A QF's eligibility to published rates has ranged from the minimum requirement of a project
producing 100 kW or less to projects as large as l0 MW obtaining a published rate conffact.
Currently, for Avista and Rocky Mountain Power, published avoided cost rates are
available for wind and solar projects producing 100 kW or less. All other resource types in
Avista and Rocky Mountain Power's service territories must generate l0 alvlW or less to be
eligible for published rates. As of March2l,2012, all QFs contacting with Idaho Power for the
sale and purchase of energy under PURPA, regardless of resotrce type, must generate 100 kW or
less to be eligible for published rates. Order No. 32498. All QF projects generating more energy
than what is permitted for a published avoided cost rate contract are eligible under the IRP
Methodology to avoided cost rates based on the specific characteristics of each project.
l. Utilities. Avista and Rocky Mountain Power urge the Commission to maintain the
100 kW published rate eligibility ttreshold for wind and solar resources. These utilities reason
that using the SAR Methodology for small projects provides a sirnple and tansparent means of
pricing and negotiation that minimizes tansaction costs and allows small QFs to build projects.
Tr. at 187. Conversely, the utilities argue that, as the size and capacity of a project grows, the
appropriateness of the SAR Methodology diminishes. Rocky Mountain Power explains that this
is because a small project does not materially impact a utility's load and resource plan. Id. at
189. The valuation of energy from a larger project must take into consideration the utility's need
for the energy at the times when the resource is able to produce it because of the substantial
impact that a large project has on a utility's load and resource balance.
Avista and Rocky Mountain Power further contend that resources other than wind and
solar with a nameplate capacity of l0 MW or less be eligible for published avoided cost rates.
These utilities argue that a l0 aMW threshold, as is currently used, can be manipulated by
"creative developers" to obtain eligibility to published rate contracts - as evidenced by
disaggregation. Id. at 9l-92. The utilities maintain that limiting published rates to smaller
projects with a nameplate capacity of l0 MW or less would limit arbinage opportunities without
8oRDER NO. 32697
compromising the intent of PURPA. Id. ln addition, Avista supports annual updates of the fuel
price forecast utilized within the SAR model using the DOE EIA Annual Energy Outlook. /d. at
92.
Avista also supports separating energy and capacity payments and only paying a QF
for capacity when the energy is needed to serve a utility's load. Avista argues that making
capacrty payments to a QF when the energy is not needed is a violation of the avoided cost
principle that the utility only pay what costs it avoids by purchasing the QF generation instead of
producing the energy itself. Tr. at 59. Avista reasons that if a QF cannot be relied upon to
generate energy during the utility's peak load hours, then the utility will be forced to build or
otherwise procure a resource that can be utilized to serve custorners during those peak load
hours. Id. ?t 75. Thus, a utility's capacity needs are not avoided by purchase of such QF
generation. Resources must still be built to meet the utility's capacity needs. If capacity needs
are not being met by the QF resource then, Avista argues, the QF should not be compensated
with capacity payments.
Avista supports use of load and resource balances as reported in each utility's IRP in
order to determine when the utility becomes capacrty deficient. Id. rt 68. Capacity payments
would be included in payment of avoided costs in the year in which a utility's load and resource
balance shows that the utility is capacity deficient. Avista also suggests that load changes
between IRP filings (i.e., a new load forecast, new contact obligations, deliveries incurred since
the publication of the IRP), should be considered when determining a utility's capacity needs.
Id. Rocky Mountain Power proposes that capacity payments be included in avoided costs
coincident with the timing of its next deferrable resource. Id. at207.
Idatro Power maintains that the IRP Methodology should be used to set both
published and negotiated avoided cost rates. Id. at 483. Idatro Power argues that the SAR
Methodology does not correctly model the actual PUPJA resource because the SAR utilizes a
CCCT in its calculation and assumes a very high annual capacity factor. Idatro Power further
states that the SAR does not properly value the energy at the tirnes it is delivered to the utility.
Idatro Power contends that different types of generating resources have different operating
characteristics that offer different value to the utility and should be considered when setting an
avoided cost rate. Finally, Idaho Power asserts that the current published rates are not updated
on a regularly scheduled basis and, therefore, do not take into account changes in resources as
9ORDER NO. 32697
they are added to a utility's portfolio. For these reasons, Idatro Power does not support continued
used of the SAR Methodology in establishing published avoided cost rates.
Idaho Power recommends that the published rates be derived from the IRP
Methodology based on resource tpe and updated every two years as each IRP is compiled and
presented for Commission review. Idatro Power states that this is a more accurate method for
calculating avoided cost rates because it allows the utility to assign pricing within smaller time
frames which provides a better estimate of the actual value of the energy being delivered. Tr. at
484. Idaho Power continues to maintain that published rates be available to only projects
producing 100 kW or less. Idaho Power states that, because the published rates would be
updated only every two years, making published rates available to only truly small QF projects
reduces the risk to the utility's customers that they would be paying too much for the energy
produced.
Idatro Power maintains that an annual update of fuel price forecasts, through use of
the federal Energy Information Administration (EIA) Annual Energy Outlook, is an
improvement over the method currently used, but the utility suggests that the Commission go a
step further to also adopt the EIA's short-term forecast. Idatro Power contends that the EIA
annual forecast can become rapidly outdated in a quickly shifting natural gas market. Id at 493.
Idaho Power supports payment of a capacity component at the tirne in which each utility's IRP
shows a capacity deficiency. Idatro Power maintains that this treafinent is consistent with the
utility's requirement that it show resources are'1rsed and useful" in order to seek recovery from
customers. Idatro Power also argues that it "is an appropriate way to account for the ability of a
QF to come on-line at any time irrespective of a utility's need." td. at 513.
2. Commission Staff. Commission Staff maintains that the current SAR
Methodology, with some modifications, should continue to be used to set the published avoided
cost rates for PURPA contracts. Staff contends that eligibility to published rates be set at 100
kW for wind and solar to address the unique characteristics of these resources that allows them to
disaggregate and receive higher, less accurate avoided cost rates for their energy. Staff argues
that, for resoruces other than wind and solar, a l0 aMW threshold has been utilized successfully
for many years and should be maintained.
Staff proposes that the Commission update the fuel price forecast used in the SAR
model annually using the EIA Annual Energy Outlook instead of the current process utilizing
oRDER NO. 32697 l0
updates issued by the Northwest Power and Conservation Cormcil. Statrcontends that updating
fuel prices on a regularly scheduled, annual basis will produce a more accurate SAR calculation.
Staff firther argues that the SAR model should be modified to account for a utility's surplus
energy periods in order to produce more accurate avoided cost rates. Staff proposes that the
SAR model identiff when a utility is deficient in energy, in capacity, or both. Tr. at 1061. If a
utility is not deficient in energy when a QF delivers then the QF's energy payment should be
reduced by the cost of transmission and losses.
Staff also proposes that capacity payments vary based on resource type. By allowing
capacity payments to difler based on resource type, QF development would be encouraged or
disconraged based on when the energy is deliverable to the utility. Id. at 1062. QFs that provide
generation during peak hours (when the utility is most in need to serve its customers) would be
compensated based on their ability to deliver energy when it is most needed. Under this method
ofvaluing capacity, canal drop hydro rates are considerably higher than other resources because
canal drop projects provide capaclty during peak summer hours and their capacity payment is
spread over relatively few total hours. Id at 1064. Wind projects receive the lowest rates
because of wind's low on-peak capacity factor. Id. at 1065.
Staff maintains that, by using a QF's nameplate capacity in the SAR calculation,
capacity payments can be determined based on a project's ability to incrementally contribute to a
utility's capacity deficiency. Tr. at 1067-68. Through use of this method, a QF would be paid
earlier, but at an incremental rate, for its capacity contribution to the utility. This method also
recognizes that there are times when capacity provided in only one season does, in fact, tanslate
into capacity avoided by the utility. Id. at 1068. Under Staffs approach, capacity deficiency
would be identified based on load and resource balances found in each utility's IRP plan.
3. Intervenors. Norttrside Canal Company, Twin Falls Canal Company and
Renewable Energy Coalition ('the Canal Companies") filed joint testimony in this proceeding.
The Canal Companies propose that all projects with a nameplate capacity of l0 MW or less be
eligible for published avoided cost rate contracts. The Canal Cornpanies maintain that a 100 kW
thneshold for eligibility to published rates for all resotrce t)?es would force virtually every
project to be negotiated through use of the IRP Methodology which could ultimately impact a
project's viability. Tr. at 843-44. Based on this reasoning, the Canal Companies contend that a
l0 MW nameplate eligibility cap for published avoided cost rates would reasonably allow
ORDER NO. 32697 lr
smaller QF projects to develop without the administrative and transactional complications of
negotiations through the IRP Methodology. Id. The Canal Companies further maintain that a t0
MW nameplate eligibility threshold for published rates is consistent with this Commission's past
practice.
The Canal Companies argue ttrat positions advocating a 100 kW eligibility cap really
amount to a pricing issue under the SAR Methodology that can be fixed by modifring the
manner in which the SAR prices are determined. Tr. at 845. Consequently, the Canal
Companies oppose the changes to avoided cost calculations proposed by Idatro Power. The
Canal Companies maintain that, as long as consistent assumptions are used under both
methodologies, the SAR and IRP methodologies should result in similar avoided cost
calculations. Id. at 852. They believe that either method is appropriate, when applied
consistently, and would result in reasonable avoided cost prices. Id. at853.
The Canal Companies also support annual updates, using the EIA Annual Energy
Outlook, for the fuel price forecast used in the SAR model. Id. at 886. The Canal Companies
further support Staffs proposal regarding use of a QF's nameplate capacity in the SAR
calculation in order to derive capacity payments that can be determined based on a project's
ability to incrementally contribute to a utility's capacity deficiency. Id. at 890. They "find
StafPs revised model a simple, transparent and straightforward approach to determine capacity
need, allocation and picing." Id.
Clearwater Paper, Exergy Development Group, and J.R, Simplot ("C/E/S') filed joint
testimony in this proceeding. C/E/S maintains that the SAR Methodology "has been a
successful, tansparent and effective method for estimating a utility's avoided cost rates." Tr. at
926-27. These companies support the continued use of the SAR Methodology for calculating
published avoided cost rates. In addition, C/E/S contends that all projects producing l0 aN,IW or
less should be eligible to published avoided cost rates regardless of the QF resource. Id. at957.
C/E/S maintains that a CCCT is more appropriate than a SCCT in setting a proxy
under the SAR Methodology. The companies axgue that combined-cycle units are the "resource
of choice" for utilities adding base load plants and, therefore, a CCCT remains the reasonable
choice in calculating values with the SAR Methodology. C/E/S also agrees with use of the EIA
Annual Energy Outlook for annual updates of the fuel price forecast used in the SAR model.
They agree that annual updates to the fuel price forecast provide predictability for all parties and
oRDERNO. 32697 t2
parity in the timing of potential rate increases and decreases. Id. at94l. C/E/S further oontends
that QF projects should be eligible for capacity payments through the entire term of their
contracts with no consideration of when a utility becomes capacity deficient. Tr. at 958. C/HS
argues that *denial of capacity payments dtring a period of clairned surplus does not put a QF
facility and a company owned generating plant on an equal footing." Id. at936.
Finally, C/E/S maintains that IRP submissions by the utilities "are becoming
increasingly relied upon for a wide number of important regulatory issues." Id. at939. For this
reason, C/E/S argues that IRPs should be subject to greater scrutiny and an adjudicated hearing
process, with ultimate approval by the Commission before the IRP conclusions are utilized for
the calculation of the avoided cost calculation rates.
Commission Findings
l. The Eligibilitv Cap for Published Rates. Wind and solar are intermittent energy
resouroes with unique characteristics. A 100 MW wind farm or solar project can be broken up
into 10 aJ\,IW pieces in order to obtain multiple published rate contracts, i.e., disaggregation.
When a 100 MW wind or solar project is disaggregated, we hnd the SAR Methodology no
longer produces a rate that accurately reflects the value of the energy to the utility. A 100 MW
project is not even eligible under PURPA nor is a utility bound to purchase power from a 100
MW facility under PURPA's "must purChase" provision. l8 C.F.R. $292.20a@). Therefore, to
prevent large projects from disaggregating in order to not only become eligible under PURPA
but also obtain published avoided rates, and based on the unique eharacteristics of wind and solar
resources to disaggregate, we find that the eligibility cap for published avoided cost rate
contracts for wind and solar projects shall be set at 100 kW or less. Congress intended to allow
PURPA cogeneration and small renewable projects to produce and sell power without the burden
of being regulated as an electric utility. Congress did not intend for multi-national corporations
to fund large wind farms for the benefit of their shareholders and the detriment of the utilities'
ratepayers. l8 C.F.R. $ 292.30a(a). lndeed, PURPA ffansactions are intended to hold ratepayers
harmless. This finding is just and reasonable and consistent with PURPA and FERC regulations.
A QF project producing no more than l0 aN/tW meets the definition of a small project
that does not materially impact a utility's load and resource balance as long as it is, in fact, a
single small QF project and not a large project disaggregated to obtain a higher avoided cost rate.
The l0 aI{W eligibility cap for published rate avoided costs for resources other than wind and
oRDER NO. 32697 13
I
solar has proven to be beneficial by allowing for small projects to be developed without unduly
or inappropriately burdening ratepayers. This Commission's use of a l0 aMW eligibility cap for
published ratn contracts has encouraged PURPA projects, promoted renewable energy
development in Idaho and, when used as it was intended, kept ratepayers indifferent. Utilizing a
l0 MW nameplate eligibility cap for published avoided cost rate contracts, as proposed by
Avista and Rocky Mountain Power, is a more restrictive approach and would limit the
availability of published avoided cost rates to only very small projects. This Commission is
confident that, with other changes to the avoided cost methodologies incorporated in this Order,
changing eligibility from l0 aMW for resources other than wind and solar is tmnecessary at this
time. We find that a l0 aMW eligibility cap for access to published avoided cost rates for
resources other than wind and solar is appropriate to continue to encourage renewable
development while maintaining ratepayer indifference. Maintaining a l0 aJ\,IW eligibility cap is
also consistent with our long history of encouraging PURPA projects and renewable energy
generation in Idaho.
We acknowledge Idaho Power's efforts to devise an alternative wholly different than
the SAR method currently used to obtain published avoided cost rates. However, we are not
prepared to abandon the SAR method entirely. As is evident from this Commission's history
with PURPA, avoided cost methodologies, inputs and calculations need to be reviewed and
refreshed periodically. The genesis of this case in November 2010 came from ldaho Power
being overwhelmed with requests by QFs for published avoided cost rate contracts. The vast
majority of those projects were large wind farms that were disaggregating in order to take
advantage of the then l0 aMW published rates. Under PURPA's must purchase obligation,
Idatro Power was forced to accept hundreds of megawatts of electricity at rates intended for
small projects producing l0 aMW or less. These large projects had the potential to drastically
affect the utility's load and resource balance and raise customer rates contrary to the mandate in
PURPA that they be held harmless. The valuation of energy from ttrese large projects must take
into consideration the QF's ability to generate energy at a time when the utility most needs the
energy to serve its load. This valuation can be accurately accomplished through application of
the IRP Methodology. We find that, by maintaining an eligibility cap of 100 kW or less for wind
and solar projects, Idatro Power's concerns regarding disaggregation are mitigated.
oRDERNO. 32697 t4
2. Separate Capacity and Energy Rates. A QF that provides generation during peak
hours when the utility is most in need of power to serve its custorners should be compensated
based on the QF's ability to deliver during peak horus. This structure comports with the purpose
and intent of PURPA that a utility pay a QF the costs it avoids by not having to build or procure
alternative energy, 18 C.F.R. 292.304(b)(2). Payments for both energy and capacity must be
part of this consideration. Although the current SAR model merges energy and capacity
payments into a single avoided cost rate, this Commission has previously approved separate
energy and capacity payments as consistent with the intent and objectives of PURPA. PUPJA
requires that the utility purchase the energy produced by a QF. Paying for a resource's ability to
provide the utility with capacity that the utility needs to reliably serve its customers encourages
development of resources that truly allow the utility to avoid the costs of building new
generation.
The utilities, Commission Stafi and several intervenors support the use of a separate
capacity payment to appropriately value the power being produced and delivered by a QF. We
find that implementation of a separate resource-specific capacity factor is an appropriate way to
value when a QF is able to generate and deliver energy to a utility. The value of all renewable
resources is not equal. If a QF is primarily allowing a utility to avoid energy generation during
non-peak hours, but not providing capacity during peak hours, then the utility is not avoiding the
cost of building new plant. Generation will ultimately have to be built to provide the capacity
necessary to reliably serve customers during peak load hours. Consequently, we find it
reasonable to assign a value to a QF resource's ability to provide such capacity. A QF resouce
with a high capacity factor is not only providing the utility with energy, but also capacity that
will allow the utility to avoid having to constnrct new generation to serve its customers during
peak load hours.
lntervenors to this case have selectively used the tenn "equal footing" to refer to the
way utilities are fieated versus the way QFs are treated. Intervenors suggest that denial of
capacity payments does not put a QF on "equal footing" with a utility. To the contrary, a
consideration of utility need and potential surplus energy does treat a QF much like a utility-
owned resource. A utility cannot be compensated by its customers for energy produced from a
generating facility until the utility establishes the need for such new generation. Idaho Code $$
oRDERNO. 32697 l5
6l-526, 6l-528, and 6l-541 . See also Case No. U-1006-265, Order No. 20610; Case No. IPC-E-
12-14, Order No. 32585; and Case No. PAC-E-I l-12, Order No. 32432.
Moreover, "equal footing" is not a legal standard required by PURPA nor applied by
this Commission. The legal standard for an appropriate determination of avoided cost rates is
clearly defined by PURPA. Rates for purchases from a QF shall "(i) be just and reasonable to
the electric consumer of the electric utility and in the public interest; and (ii) not discriminate
against qualiffing cogeneration and small power production facilities." l8 C.F.R. $
29230a@)(l). 'Nothing in this subpart requires any electric utility to pay more than the avoided
costs for ptuchases." Id. at $ 292.304(aX2). Avoided costs are those costs which a public utility
would otherwise incur for electric power, whether that power was purchased from another source
or generated by the utility itself. 18 C.F.R. $ 292.101OX6). PURPA allows QFs to obtain a rate
equivalent to the utility's avoided cost, a rate that holds utility customers harmless - not a rate
that puts QFs on "equal footing" with the utility. PURPA requires public utilities to purchase
generation from QFs without regard for whether the utility needs the energy. If a QF resource
provides energy but not capacity, then the utility is not avoiding a portion of costs that will be
required to build generation that provides capacity. For this reason, we find it reasonable,
appropriate and in the public interest to compensate QFs separately based on a calculation of not
only the energy they produce, but the capacity that they can provide to the purchasing utility.
We find that utilizing a QF's nameplate capacity in the SAR calculation is a
reasonable approach that provides payment to QFs for capacity based on a project's ability to
incrementally contribute to a utility's capacity deficiency. We further find it appropriate to
identifr each utility's capacity deficiency based on load and resource balances found in each
utility's IRP.
3. Line Loss. We decline proposals to discount QF energy payments for
tansmission and line loss when a utility is energy surplus. These costs are difftcult to quantiS
and may not exist in all cases. Therefore, we find that, without more certainty, it would be
inappropriate to discount QF energy payments for such costs.
4. Annual SAR Updates. We firther find that, in order to remain flexible and
responsive to the fluctuations in gas prices, it is appropriate to annually update the SAR model
with the most recent gas forecasts provided by EIA's Annual Energy Outlook. Based on the
oRDERNO. 32697 l6
timing of the release of EIA's annual report, and as proposed by Dr. Reading, we find it
appropriate to update rates with EIA's most recent gas forecasts on June I of each year.4
5. SAR Type. We further find it reasonable to continue to utilize a combined-cycle
combustion turbine (CCCT) sturogate as the basis for all calculations in the SAR model. The
SAR Methodology is intended to represent a surrogate base load natural gas resource. Simple-
cycle combustion turbines (SCCT) are primarily utilized for rneeting a utility's peak loads;
CCCTs provide base load energy. The proposals of some of the parties to use an SCCT for
calculating capacity value and a CCCT to compute energy value would create a very awkward
and not representative surrogate resource. Consequently, we decline to utilize a SCCT.
B, Integrated Resource Plan (If,.P) Methodologt
The IRP Methodology had its inception in 1995 (Case No. IPC-E-95-9) but has
seldom been utilized - even by large QF projects - because the avoided cost rate produced
through use of the IRP Methodology for certain types of resources has not, historicallyn been as
favorable as the published avoided cost rates. Consequently, large wind QF projects were being
broken into smaller pieces in order to meet the eligibility cap requirernent for access to published
avoided cost rate confiacts, i.e., disaggregation. See PAC-E-10-01 tlrough 10-05; IPC-E-10-51
through 10-55; IPC-E-10-56 through 10-58; IPC-E-10-59 and 10-60; and IPC-E-10-61 and l0-
62. When this case was initiated by the utilities in November 2010, only two IRP-based rate QF
power purchase agreements had been presented and approved by this Commission. Therefore,
the IRP Methodology has not had the benefit of adjustments over time to ensure that the
calculation produces an accurate representation of the utility's avoided cost. The rates produced
pursuant to the IRP Methodology were not called into question until eligibility to published rate
contacts was restricted.
The IRP Methodology takes into account many different variables and produces a
result based on each individual utility's need for energy. More specifically, the IRP method
assesses the value of each QF project in terms of its capability to deliver resources in relation to
the timing and magnitude of the utility's need of such resotrces.
L Utilities. Avista proposes that, under the IRP Methodology, the QF only receive
capacity payments after the utility becomes capacity deficient. Avista maintains that, when the
a Calculations for resources under the SAR Methodology - utilizing EIA's most recent Annual Energy Outlook - are
attached.
oRDERNO. 32697 l7
utility is in surplus, it does not avoid any capacity by purchasing output from the QF. Because
the utility does not need the capacity, the capacity value of QF power during surplus periods
should be zero. Tr. at 80. In addition, Avista argues that a QF's energy payments should be
discounted during times of utility surplus to account for the costs of transmitting surplus power
and selling it in the market. "[T]ransmission has value to customers as it can be resold by
Avista's transmission group to third parties. Reserving transmission for the purpose of moving
QF power to market would reduce those tansmission revenues." /d.
Rocky Mountain Power maintains that the IRP Methodology, "as established in IPC-
E-95-09, is an appropriate method to assess the value of a QF project in terms of its capability to
deliver its resoruce when the Company is in need of such a resource, and is reflective of the
value of the QF to the Company and its customers." Tr. at 188. Rocky Mountain Power argues
that, with a 100 kW eligibility cap in place for wind and solar resources, the previously adopted
SAR and IRP methodologies continue to provide an accurate means of calculating avoided cost
prices for QFs.
Rocky Mountain Power proposes that modeling inputs for the tRP Methodology be
updated contemporaneously at the time of each pricing request in order to ensure the most upto-
date modeling assumptions. Rocky Mountain Power asserts that its IRP process already
accounts for the incremental need and cost of capacity on its system. lts capacity payments are
determined based on the timing of the next deferrable resource in its IRP preferred portfolio. /d.
at 199.
Idaho Power maintains that the IRP Methodology should be used for setting both
published and negotiated avoided cost rates. Tr. al 477. Idaho Power contends that the IRP
Methodology is appropriate to use for all PURPA contracts because it sets a more accurate value
on the energy that a QF delivers to the utility based on the time that the energy is delivered.
Idaho Power argues that the tRP Methodology is flexible and can be updated more frequently as
conditions and assumptions change. Id. at 484. The Company explains that the IRP model can
be updated as each incremental resource is added to a utility's generation portfolio. /d
Idatro Power explains that a resource that is able to deliver energy during heavy load
hours when the utility is most in need of the energy would receive a higher overall price than a
resource that is primarily able to deliver energy during light load hours when the utility is already
surplus and least in need of the energy to serve its customers. As it is cunently applied, Idatro
oRDER NO. 32697 t8
Power's IRP Methodology does not include an avoided cost for capacrty until the first month that
its load and resource balance shows a peak-hour deficit based on existing and committed
resources as identified in its IRP. /d. at 474.
2. Commission Staff. Staff maintains that the IRP Methodology can produce more
accurate avoided cost rates with a few modifications. Staff argues that the IRP rates should not
inslude any value for QF capacity in years when the utility has surplus capacity. Tr. at 1079.
"The proper mechanism for accounting for utility need is not to relieve utilities of their
obligation to purchase, but instead to establish prices for capacity and energy that properly
recognize the utilities' need, or lack of need, for capacity and energy. By not paying for capacity
during surplus periods, utilities would be paying what arnounts to a more accurate reflection of a
true avoided cost." Tr. at 1090. Statr further maintains that energy rates be reduced by the cost
of tansmission and losses during surplus periods. /d. at 1085. Staffnotes that, as it is presently
applied, each utility's IRP model accounts for whether the utility is in need of capacity. "In the
methods used by each utility, none assign capacity value to QFs in years when the utility is in a
surplus condition." Id. at 1091.
Finally, Staffproposes that a simple-cycle combustion turbine (SCCT) be used as the
basis for computing capacity value under the IRP Methodology for all resource types. Staff
argues that "the propq resource to use as the basis for computing capacity value is the lowest
cost resource that could be added to provide capacity equivalent to what would otherwise be
provided by the QF." Id. at 1093. Because Staff proposes to compute energy and capacity
separately, using a SCCT is most appropriate because it represents the lowest cost, nearly
capacity-only resonrce. ^Id.
In order to produce a more accurate avoided cosl rate, Staff recommended that
utilities be permitted to update fuel price forecasts and load forecasts annually - between IRP
filings. Staff further recommended that long-term contract commitments (including QF/
conEacts) be incorporated once a contact has been signed by the QF and submitted to the utility
for signature. Id. at 1099. "PURPA contracts that are terminated, expire, or that have approved
modifications of their online dates should also be immediately considered in the load resource
balance." Id. at 1100.
3. Intervenors. The Canal Companies support use of the IRP Methodology as long as
consistent assumptions are used in both the SAR and IRP methods. Tr. at 852. The Canal
oRDER NO. 32697 t9
Companies admit that while "the integrated resource method rnay not be as transparent as the
surrogate resource method, it can do a better job of taking into account a utility's needs by
incorporating all the expected loads and resources over the contrasting planninghoizan." Id. at
852-53. They support two updates to the model between IRP filings: annual updates for natural
gas prices and updates for new, executed QF agreements, /d. at 859-60.
The Canal Companies maintain that it is reasonable for a utility to include only the
cost of energy in its avoided cost payment to new QFs until the utility shows a need for capacity.
Tr. at 867. However, they argue that existing QFs entering into conhact extensions or renewals
should be paid full capacity value for the entire term of an extension or renewal. "These
resources have not caused the projected short-term surplus and should not be penalized in the
form of reduced capacity value payments in a subsequent follow-on PPA." Id. at 869. The
Canal Companies further maintain that utilizing a SCCT to determine a QF's capacity value is
appropriate for Idatro Power.5 Id. at866.
C/E/S only supports use of the IRP Methodology after "each utility's IRP is fully
considered and approved through the hearing process." Id. at957. CIEIS proposes that changes
to variable inputs only be allowed with each approved tRP - with the exception of natural gas
prices which should be updated annually. Id. at 958. C/E/S further proposes that capacity
payments be included for the full term of the contract with no consideration of utility surplus or
deficit.
Commlssion Findings
The IRP Methodology recognizes the individual generation characteristics of each
project by assessing when the QF is capable of delivering its resources against when the utility is
most in need of such resources. We find that the resultant pricing is reflective of the value of the
QF energy being delivered to the utility. We are not convinced, nor has sufficient evidence been
presented, that the utilities' use of different models to derive lRP-based rates (i.e., AURORA vs.
GRID) produces substantially different rates. To the confiary, the evidence shows that energy
rates calculated by the utilities for different resources are substantially similar between the
utilities. Therefore, we find that the IRP models used by each individual utiliry produce
reasonable avoided cost rates consistent with PUPJA and FERC regulations.
5 The Canal Companies are not recommending changes to Avista's or Rocky Mountain Power's avoided capacity
resource. Tr. at 867
oRDERNO. 32697 20
Idatro Power proposed revisions to the IRP Methodology that focus on identiffing the
incremental costs that its system would incur, i.e., a single-run simulation, rather than its current
methodology that is primarily predicated on making surplus sales at the future market prices
developed within the AURORA model, i.e., a two-run simulation. In order to do this, Idatro
Power proposes to use the AURORA model to determine the highest displaceable incremental
cost being incuned during each hour of the QF's proposed contract term. The Company claims
that its proposed modified methodology better aligns with the definition of avoided cost from
federal regulations, and results in a much better estimation of the costs the utility is capable of
avoiding.
The Commission finds tdatro Power's proposed modifications to ttre IRP
Methodology reasonable. We agree that the Company's revisions properly focus the
determination of avoided costs on incremental costs, not solely on the value of potential market
sales. The result, we find, is a more accurate avoided cost. Moreover, we find that the modified
methodology comports with the definition of avoided cost contained in FERC regulations.
Therefore, we direct Idaho Power, Avista and Rocky Mountain Power to utilize displaceable
incremental costs in calculating avoided cost rates under the tRP Methodology.
l. Capacity Deficiency. In computing avoided cost rates under the IRP
Methodology, each of the three utilities already employs a two-step approach in which energy
and capacity values are computed separately. [n calculating a QF's ability to contribute to a
utility's need for capacity, we find it reasonable for the utilities to only begin payments for
capacity at such time that the utility becomes capacrty deficient, If a utility is capacity surplus,
then capacity is not being avoided by the purchase of QF power. By including a capacity
payment only when the utility becomes capacity deficient, the utilities are paying rates that are a
more accurate reflection of a true avoided cost for the QF power. However, we find merit in the
argument made by the Canal Companies that contract extensions and/or renewals present an
exception to the capacity deficit rule that we adopt today. [t is logical that, if a QF project is
being paid for capacity at the end of the contract term and the parties are seeking
renewaUextension of the conffact, the renewaUextension would include immediate payment of
capacity. An existing QF's capacity would have already been included in the utility's load and
resource balance and could not be considered surplus power. Therefore, we find it reasonable to
allow QFs entering into confiact extensions or renewals to be paid capacity for the full term of
oRDER NO. 32697 2t
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the extension or renewal. Consistent with our findings under the SAR Methodology, we decline
proposals to discount QF energy payments for transmission and line loss when a utility is energy
surplus. At this time, it would be inappropriate to discount QF energy payments for such costs.
We firther find that a simple-cycle combustion turbine (SCCT) is the most
appropriate basis for computing capacity value for all resource types. SCCT's are added to a
utility's resource portfolio to satisfr capacity needs. Because energy and capacity are being
calculated separately, it is reasonable to use a SCCT because it represents the lowest cost, nearly
capacity only resource.
2, Updates. We find that, in order to maintain the most accurate and up-to-date
reflection of a utility's true avoided cost, utilities must update fuel price forecasts and load
forecasts annually - between IRP filings. For the sake of consistency, these annual updates
should occur simultaneously with SAR updates - on June I of each year. In addition, it is
appropriate to consider long-term contract commitnents because of the potential effect that such
commitnents have on a utility's load and resource balance. We find it reasonable to include
long-term contract considerations in an IRP Methodology calculation at such time as the QF and
utility have entered into a signed contact for the sale and purchase of QF power. We further
find it appropriate to consider PURPA confracts that have terminated or expired in each utility's
load and resource balance. We find it reasonable that all other variables and assumptions utilized
within the IRP Methodology remain fixed between IRP filings (every two years).
C. The IRP Planning Process
The IRP Methodology utilizes inputs determined through the utilities' IRP planning
process. Each utility submits an Integrated Resource Plan every two years that details what the
utility anticipates its resource needs will be over the next 20 years. A utility's IRP is a flexible
document meant to assess the needs of the utility so it can safely and reliably serve its customers.
When it became apparent that the IRP Methodology would be utilized for a growing
number of QF projects, the tRP planning process came under attack by opponents of the IRP
Methodology. They axgue that the IRP planning process is not a collaborative effort and factors
used within the IRP Methodology can be manipulated by the utility compiling the Plan. The
utilities maintain that the IRP planning process is independently conducted without regard to the
impact that particular determinations will have on the IRP Methodology.
oRDER NO. 32697 22
Commission Findings
At the outset it is important to note that IRPs submitted by each utility are not
"approved" by this Commission. An IRP assesses a utility's long-term energy needs. However,
it is ariomatic that a utility's energy needs change over time based on customer growth,
availability and cost of resources, environmental considerations and requirements, and other
factors. It would not be reasonable, nor to the benefit of customers, to hold a utility to a fixed
20-year projection of its anticipated resource needs. Approval of IRPs by this Commission
might imply that we agree with all of the utility's assessments regarding how it will respond to
growth over the next 20 years and that we intend to hold the utility to its projections and plans.
Such an approach would run counter to the Commission's position that a utility's long-term plan
should remain just that - a plan that is flexible and responsive to its customerso needs oVer time.
Hence, the requirement of submitting a 2}-year plan to this Commission for review every two
years.
The IRP process is a beneficial and worthwhile endeavor by the utilities to
objectively and critically evaluate their growing needs for power into the funre. We decline to
assert more control and regulation over a process that functions well for its intended pu{pose,
i.e., assessment of the utility's long-term needs. However, we acknowledge that some
determinations made within the IRP process have an impact on calculations under the SAR and
IRP methodologies. Specifically, the IRP process determines when the utility will experience a
need for new capacity.
In an effort to address the concems of QF developers who maintain that a utility
could manipulate variables within the tRP planning process in a way that would negatively
impact the pricing of capacity paid to a QF, we find it reasonable and fair to subject each utility's
determination of capacity deficiency to further scrutiny. Therefore, when a utility submits its
lntegrated Resource Plan to the Commission, a case shall be initiated to determine the capacity
deficiency to be utilized in the SAR Methodology. The capacity deficiency determined through
the IRP planning process will be the starting point, and will be presumed to be correct subject to
the outcome of the proceeding.
D. Contract Length
Over the years, this Commission has approved QF contracts of varying lengths. The
current standard contract length of 20 years was approved by this Commission in2002 when we
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found that a 20-yeu contract would better coincide with the amortization period or planned
resource life of the renewable/cogeneration resources being constructed and ensures a revenue
steam sufficient to facilitate the financing of QF projects. See Order No. 29029.
1. Utilities. Idaho Power proposed that the Commission adopt a ma:rimum contact
lenglh of five years. Id. at 487. Idaho Power maintains that a 20-year fixed-rate contract
unfairly shifts market price risk from the QF developer entirely onto the utility's ratepayers.
2. Commission Staff. Staff supports ldatro Power's proposed five-year contract
length for IRP-based conEacts. Staff reasoned that long-term contacts have historically been
used by this Commission to encourage and boost the development of PURPA projects. Tr. at
1105. However, utilities are not currently in need of the power produced by PURPA QFs and,
with present economic conditions, utilities' customers are already struggling to pay their bills.
Id. Staff argues that it is not this Commission's responsibility to ensure that contract length is
long enough for the QF to be able to obtain financing. Further, Staff maintains that it is good
public policy for the Commission to utilize tools, such as limiting ma:cimum contract length, in
order to control the pace of PURPA development. .Id.
3. lntervenors. The Canal Companies oppose the implementation of five-year
contacts. The Canal Companies characterize five-year contracts as unfair, inequitable, and
insufficient for cost recovery. Id. at 845. They maintain that the contract term should more
closely align with the usable life of the resource, Id. C/E/S axgues that the cunent 20-year
contract length should be maintained. Id. at 958. C/E/S urges the Commission to reject ldaho
Power's five-year proposal as contrary to the intent of FERC and detrimental to QF
development. Id. at969.
Commission Findings
We find that a 2}-year contract length, along with other factors, has been benelicial in
encouraging PURPA development in ldaho. We continue to believe that 2O-year contacts better
coincide with the useful life of the renewable/cogeneration resources. While it is not this
Commission's responsibility to ensure a conhact length that allows a QF to obtain financing, we
find that reducing maximum contract length to five years would unduly hinder PURPA
development. That is not the Commission's objective. We believe that, by utilizing other tools
to ensure an accurate and up-to-date avoided cost valuation, we can continue to encourage the
types of projects that were envisioned by PURPA while maintaining the transparency for
oRDER NO. 32697 24
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ratepayers as PURPA requires. Therefore, we find that a maximum contact length of 20 years is
appropriate. The parties to a power prxchase agreement are free to negotiate a shorter contract if
that would be most suitable for the project. As in the past, this Commission will consider
contracts of more than 20 years on a case-by-case basis.
E. S ecurity Deposit/Liquidated Damages
l. Utilities. Avista and ldatro Power uge the Commission to continue allowing
utilities to require security deposits in the amount of $45 per kW of nameplate capacity. Avista's
witness Clint Kalish testified that adequate delay security is "one of two key protections a utility
must have with any [PURPA] developer" to ensure that developer performs under an executed
PPA. Tr. at 84. The security deposit provides an incentive to the QF developer to bring the
project onJine. If a PURPA developer is not able to meet the commercial operation date
specified in its PPA, then "the utility ends up at the last moment having to procure other
resources, potentially at higher costs. In the absence of meaningful liquidated damages, the QF
developer has a free option to either honor its confiacfual commitrnent . . ., or simply cease
development where market conditions have changd." Id. at 84-85.
Mr. Kalich explained that the second key protection for utilities is the need for
"meaningful termination rights if the QF fails to achieve commercial operation within the
timeframe established in the PURPA contract." Id. at85. He recommended that each PURPA
contract have a standard termination clause which enables the utility to terminate the PPA 180
days after a developer's project has failed to achieve to achieve commercial operation as
scheduled in the PPA. He concluded by recommending that the developer be required to post the
$45 per kW "liquidated damages deposit at the time that the legally enforceable obligation arises
- i.e., when the . . . QF developer executes and retums the tendered contract obligating the utility
to pnrchase" the output from the QF. /d. at 86.
Idaho Power also supported a requirement that PURPA developers post delay damage
security in the amount of $45 per kW of nameplate capacity. Idaho Power witness Mark Stokes
testified that the Commission has addressed the issue of security on numerous occasions when it
has been called upon to approve various PPAs. Mr. Stokes argued that the difference between
acquiring replacement power and the cost of power in a PPA is not the only measure of damage
suffered by a utility when a QF does not bring its facility on-line as scheduled. He noted that
there are system operations and planning problems that arise when a QF fails to bring its
ORDER NO. 32697 25
facilities on-line as scheduled. Tr. at 536. If a QF is allowed to default under the PPA by not
bringing its project on-line as scheduled, "then customers are left in a financially disadvantaged
position and uncompensated for the price lock and option they extend to the QF project." /d.
In its prehearing legal briefl Idaho Power asserted that when a QF resource fails to
come on-line as scheduled
Idaho Power must replace this energy by making a market purchase, assuming
tansmission capacity is available to get the energy to Idaho Power's system.
Because the transaction is done closer to real time, market prices can be
higher than they would have been had Idaho Power been able to execute the
transaction earlier in time. There is also the possibility that market prices will
be lower than the QF contract, which typically the current situation if Idaho
Power is able to buy energy from the Mid-C market. If transmission capacity
is not available from the Pacific Northwest, the energy must be bought from
the east side of [our] system where market liquidity is an issue and prices are
almost always higher.
Brief at 29. Thus, damages may be difficult to quantiry with precision, but are nevertheless
"very real to the utility and its customers." Id. at 31. Consequently, Idatro Power asked the
Commission to continue allowing utilities to collect delay liquidated damage security.
2. Commission Staff. Staff witness Rick Sterling testified that it was reasonable for
utilities to require a security deposit for liquidated damages. Although he stated the Commission
has never specified in any of its Orders the timing of when such a security deposit should be due,
he found merit in Avista's proposal that the deposit be due when a legally enforceable obligation
arises. Tr. at I 1 I l. "It seems fair that if a QF can unilaterally impose a legally enforceable
obligation on a utility, the QF should contemporaneously incur a corresponding obligation to
perform backed by a posting of required security for liquidated damages." Id. at llll-12.
Although he recommended continued use of the liquidated damages provision, he also
acknowledged on cross-examination that he was not necessarily opposed to using an "actual
damages type of an approach if it could be done practically and fairly," Tr. at I178.
3. [ntervenors. C/E/S witness Dr. Don Reading testified that rather than basing
liquidated damages on a $45 per kW amount, liquidated damages should be based on an actual
estimate of the likely damages that the utility would incur if the QF is not operational as
scheduled in the contract. In the event of a QF developer's default, the "intent should be to keep
the utility and its customer[s] whole in the event of a default." Tr. at 960, In calculating delay
ORDER NO. 32697 26
damages, Dr. Reading reconrmended three factors in setting liquidated damages. First, in the
event of a QF default, the estimate of damages should be calculated as the difference between the
rates in the PPA "and the actual cost for replacement power during the period the QF's delay
default forces the utility to secure replacement power." Tr. at 961. The replacement price would
include the cost at the relevant market hub plus the necessary transmission and administrative
costs to secure that replacement power. Id. Secon{ although he recognized that PURPA
contacts typically have 20-year terms, he suggested that paying damages should be limited to a
period of tirne o'for the utility to make altemative long-term arrangements to secure that amount
of power." .Id Third, he recommended that if a security deposit is required, that such deposit
not be required until "after the PPA is signed and approved by the Commission." Tr. al962.
The Canal Companies and Renewable Energy Coalition sponsored the testimony of
Donald Schoenbeck. He recommended that when QF developers execute a PPA, the QF could
post either "a frxed $/kW amount or an amount based upon the difference between the contract
revenue payments and forward power prices for a period of three years starting at the expected
commercial operation date." Tr. at 881. Using this forward mark-to-market option, Mr.
Schoenbeck suggested that the deposit be adjusted every calendar quarter'to ensure adequate
security has been posted by the QF throughout the licensing and construction period." Id. at882.
With these adjustments, he indicated that his clients would accept the inclusion of liquidated
damage provisions in all PPAs. /d.
E(l). The Partial Settlement
After the close of the technical hearing on August 9,2012, the Commission scheduled
a sefflement conference to allow the parties to informally discuss standard PPA terms related to
delay security and liquidated damages. Order No. 32617. The participating parties met in
settlement conferences on August 23 and September 7, 2012. On October 2, 2012, a "Partial
Settlement Stipulation" was filed on behalf of 13 of the 25 parties that participated in the
settlement conference.6 On October 16, 2012, the Commission issued a Notice of Partial
Settlement and invited the parties and other interested persons to submit written comments
regarding the partial settlement no later than October 25,2012. Supporting comments were filed
by Avista, Staff and one public witness. tdatro Power and C/E/S hled opposing comments.
6 The sigring parties included: Rocky Mountain Power; Staff; Renewable Energy Coalition; Dynamis;North Side
Canal; Twin Falls Canal; Birch Power, ICL; SRA; Idaho Wind Partners; Ridgeline; Big Wood Canal; and American
Falls Reservoir District.
ORDER NO. 32697 27
The signing parties agreed that existing PPAs that have been approved by the
Commission shall not be affected by the settlement and that all new PPAs after the date of the
Partial Settlement Stipulation conform to the terms contained in the settlement. Settlement at !f![
9, 12. They also agreed that the settlement represents a compromise of the parties' position.
They further assert that ttre settlement o'is reasonable and in the public interest. They urged the
Commission to adopt the Settlement Stipulation without condition or modification." Order No.
32665 at l-2. The specific terms of the settlement are set out below:
l. Calculation of the Security Depo$it. The parties agree that a security deposit or
performance bond ("the Security Deposit") will be required for each new PURPA agreement
(PPA) entered into after the date upon which the Commission adopts and approves this
Settlement Stipulation. The purpose of the Security Deposit is to provide security for: (l) Delay
Damages during the Cure Period if the QF is not in commercial operation by the Scheduled
Commercial Operation Date set out in the PPA; and (2) Termination Damages if the QF cannot
cure a failure to achieve commercial operation and a party seeks termination of the PPA. The
Security Deposit shall be set at $45 per kilowatt (kW) of nameplate capacity for each new PPA.
The cash or other liquid Security Deposit will be forwarded to the utility no later than thirty (30)
days after the Commission issues its find Order approving the PPA.
2, Refund of Security Deposit. If the QF has achieved commercial operation in
accordance with the Scheduled Commercial Operation Date set out in the PPA, the utility will
promptly refund or rebate the Security Deposit to the QF,
3. Failure to Achieve Commercial Operation - Delay Damages. In the event the QF
fails to achieve commercial operation by the Scheduled Commercial Operation Date contained in
the PPA, Delay Damages shall be calculated based upon the difference between market rates at
the time the QF fails to achieve its Scheduled Commercial Operation Date and the avoided cost
rates contained in the PPA during the Cure Period. Delay Damages, if any, during the Cure
Period will be drawn from the Security Deposit held by the utility. If the Security Deposit is
insufficient to defray all of the Delay Damages, then the QF will promptly pay the outstanding
Delay Damages. tf the QF achieves commercial operation during the cure period, any remaining
Security Deposit beyond the amount of any Delay Damages shallbe refunded to the QF.
4. Cure Period. The defaulting party shall have one hundred twenty (120) days from
the Scheduled Operation Date to cure its default.
ORDER NO. 32697 28
5. Failure to Cure. In the event the QF fails to achieve commercial operation within
the Cure Period, then the non-defaulting party may, at its option, collect its Delay Damages as
calculated in Paragraph No. 3 above, terminate the Agreement, and calculate its Termination
Damages, if any. If the QF fails to achieve commercial operation within the cure period and the
non-defaulting party elects to terminate the Agreement, the Security Deposit may be used to: (a)
first pay the Delay Damages arising during the cure period, if any; and (b) second pay
Termination Damages, if any, arising after the Crue Period for the remaining term of the
Agreement.
6. Termination Damages. The party claiming that the PPA is in default and seeking
termination of the Agreement shall communicate its notice of default and claim for any
Termination Damages to the other party within a reasonable time. The other party shall respond
within fifteen (15) days. In the event of a dispute regarding the calculation of Termination
Damages, either party may resort to a court of competent jurisdiction.
7. Undisputed Dflmaees and Refimds. The utility may draw any undisputed Delay
Damages or Termination Damages from the Security Deposit. [n the event that the Security
Deposit is insufficient to pay the undisputed damages, such undisputed damages will be paid
promptly by the defaulting party. If the Security Deposit exceeds the total amount claimed as
Delay Damages or Termination Damages, the utility shall promptly refund any portion of the
deposit that is in excess of the claimed Delay Damages or Termination Damages.
8. Security Deposit for Existing OF Projects. The parties agree that a Security
Deposit shall not be required in situations where the parties are entering into a new PPA for an
existing QF project already in commercial operation so long as the new PPA is between the same
parties and there are no material changes or modifications to the existing QF project.
E(2). Cottutten8 on the Pafiial Settlement
l. Avista. Although Avista did not sign the partial settlement, it supports the terms
of the settlement. Comments at 3. Consistent with the partial settlement, Avista recommends
that PPAs require "at a minimum, that QFs post a security equal to $45 per kilowatt based on
installed capacity. In the event the QF failed to achieve commercial operation by the scheduled
operation date, damages would be calculated based upon the difference between the market price
of replacement power and the PPA price during a reasonable cure period. . . ." Id, at2-3, Avista
proposes that if the QF fails to achieve commercial operation by the end of the cure period, then
oRDERNO. 32697 29
the "QF would forfeit its security [deposit] as liquidated damages and the utility could terminate
the PPA." Id. at3. In particular, Avista supports adoption of standard terms such as: (l) posting
a security deposit of $45 per kW based on nameplate capacity; (2) a uniform cure period; and (3)
calculating delayed damages incurred by the utility during the cure period based upon the
difference between the PPA and market rates. Adopting the standard PPA terms will enhance
the PPA process "by resolving issues OP"* the utilities and QF developer[s7." Id.
2. Commission Staff. Staff also supports the partial settlement and urges the
Commission to adopt it without material condition or modification. Staff Comments at 6. Staff
notes that security deposits have been included in nearly all PURPA agreements signed since
2009 and that the $45 per kW deposit amount for nameplate capacity has been included in
contracts since January 2010. Id. at 3. Staffstates that the security deposit "helps ensure that the
QF will perform and that funds will be available to cover damages should they arise. tl]f
commercial operation is achieved per [the terms o{l the PPA, the deposit is to be returned to the
QF." Id. at 2. Staff explains that the security deposit can be used to either pay delay damages
during the standardized 120-day cure period if the QF is not commercial operation, or
termination damages if the QF cannot achieve commercial operation during the cure period and a
party seeks termination of the PPA. Id. Staff also observes that under the terms of the
settlement, the security deposit is to be forwarded to the utility no later than 30 days after the
Commission issues its final Order approving the PPA.
Staff asserts that the sectrity deposit is essential to adequately protect the utility and
its ratepayers from default by a QF. The $45 per kW is a reasonable deposit arnount that would
likely cover most, if not all delay and/or termination damages. Id. at3. Staffalso recommends
approval of the standardized term that requires the prompt refund of the security deposit to the
QF if it achieves commercial operation in accordance with the PPA. If "there is a delay and a
cure within the [20-day] cure period, the undisputed portion of the deposit will be retumed to
the QF." Id. lnother words, the security deposit is only maintained for as long as necessary. /d
Staff recognizes that determination of the exact amount of delay damages has
frequently led to disputes between a QF and a utility. "The partial settlement will help to
alleviate disputes by speciffing [that] . . . delay damages shall be calculated based upon the
difference between market rates at the time the QF fails to achieve its scheduled commercial
operation date and the avoided cost rates coniained in the PPA during the cure period." Id. at 3-
ORDER NO. 32697 30
4, Basing delay damages on the difference between the market rates and the contact rates
"fairly assesses the amount of the damages and holds the QF responsible for the full amount of
actual damages without imposing a penalty." Id. at 4. Staff also supports the settlement because
if the security deposit is insuffrcient to defray the delay damages, the QF will promptly pay the
outstanding delay damages. Conversely, if the QF achieves corrmercial operation during the
cure period, then any undisputed security deposit beyond the amount of any delay damages shall
be retunded to the QF. /d.
Staff observes that if the PPA is terminated because the QF fails to achieve its
commercial operation, then damages may extend beyond the cure period. Per the settlement,
then deposits may be used to: (a) first pay delay damages arising during the cure period, if any;
and (b) second pay termination damages, if any, arising after the cure period for the remaining
term of the PPA. Settlement at ![ 5. In the event the parties are unable to agree to termination
damages, if any, then any party may bring suit in a court of competent jurisdiction. Because
termination damages 'oare exceedingly difficult to quantift in advance, and because they depend
on the circumstances of each individual case, Staff believes it is appropriate to leave
determination of the [termination] damages to negotiation[s] between the parties or to a court if
there is a dispute." Comments at 4.
Finally, StaIf notes that calculating delay damages based on actual damages
eliminates an axgument that the previous liquidated damages (now [the] security deposit) were
punitive and unreasonable." Id. at 5. Based on its review of the partial settlement, Staff
determined that its terms are just and reasonable and in the public interest. Consequently, Staff
recommends that the Commission approve and adopt the partial settlement. Id. at6.
3. Opposing Comments. tdatro Power indicates that there was "little to no value in
entering into some kind of compromise of its position[s] that it has set forth . . in this
proceeding" without complete agreement from all the QF parties. Comments at l. It trges the
Commission to continue the current requirements of requiring QFs post delay damage security
calculated at $45 per kW of nameplate capacity. Id. at3,5. The utility rugues that the damages
provisions of the partial settlement do not "adequately compensate customers for the risks
assumed by customers and the damages incurred by a QF breach." Id. at 2. Idaho Power
continues to argue that a QF may choose or not choose to bring its project into commercial
operation. Thus, "a QF has the ability to eliminate its own downside [risk], to the direct and
ORDER NO. 32697 3l
substantial harm and detriment of Idaho Power's customers, and take advantage of the upside" if
prices axe more favorable to the QF. /d. at 5.
C/E/S filed joint comments opposing the partial settlement. They disclose that they
did not sign the partial settlement "b@ause it simply codifies the status quo. The only tnre
settlement issue that was resolved was the unremarkable and obvious concession that existing
projects will not be required to post a delayed security deposit." Joint Comments at 1. C/E/S
reiterates its position at the hearing by attaching Dr. Reading's testimony as comments.
Commission Findings
Based on our review of the underlying testimony, the partial settlement, and the
comments filed in response to the settlement, we find that the partial settlement represents a fair,
just and reasonable resolution to the issue of liquidated damages. Contrary to the assertion made
by C/VS, the partial settlement does not simply codifu the status quo. In our view, the
settlement represents a reasoned approach to the issues of risks and damages in the event a QF
fails to perform under the terms of its PPA. We find that the requirement that a security deposit
be posted 30 days after the Commission approves the PPA is reasonable. We further find it
reasonable to base delay damages on the actual difference between the PPA rates and the market
rates. This is similar to the recommendation offered by Mr. Schoenbeck and is in agreement
with Dr. Reading's testimony that delay damages should be based on damages measuring the
"difference between the rate . . . in the QF contract and the actual cost for replacement power. . .
." Tr. at 961.
As we previously observed in Order No. 31034, posting adequate security "acts not
only as an incentive for PURPA project owners to complete their projects on time, but it can also
mitigate any additional costs which might arise when a utility is forced to purchase substitute
power on the open market." Order No. 3 1034 at 3; Exh. 519. However, we also noted that such
security "'should not be punitive' and 'should constitute a fair and reasonable offset of a
regulated utility's estimated increase in power supply costs attributable to the PURPA supplier's
failwe to meet its contractually scheduled operation date.' Order No. 30608." Id. at4.
Although C/EIS argued that the $45 per kW amount was unreasonable, we are not
persuaded for several reasions. First, as indicated in the partiat settlement, a broad array of
parties agreed that $45 per kW is a reasonable amount for the security deposit. Second, a survey
conducted by Avista regarding the $45 kW amount showed that the utilities charged a
ORDER NO. 32697 32
comparable arnount "and actually substantially higher in some cases." Tr. at 164; Exh. 519,
Order No. 31034 at 3 (in a survey of l0 utilities only I required "less than $25 per kW, while the
other 9 utilities required security of at least $50 per kW."). Third, the Commission has
previously found that an increase in the delay security amount to $45 was "reasonable and
necessary." Exh. 519, Order No. 31034 at 3. Fourth, it is reasonable to set a uniform amount so
that all parties to a PPA know how the secr.rity deposit is to be calculated and can calculate the
amount of the deposit before executing the contract. Finally, the $45 per kW deposit is balanced
with the fact that the deposit is returned if the QF meets its scheduled operation date or becomes
operational during the cure period and the undisputed amount is returned to the QF.
As set out in the partial settlement that we adopt, the security deposit is to be used as
a source of actual damages for both delay damages (the inability of the QF to bring its facility
on-line during the 120-day cure period) and also as a source of termination damages in the event
the PPA is terminated. If there is a dispute among the parties regarding the calculation of
termination damages, then either party may take their dispute to a court of competent
jurisdiction. Of course, in the event the QF comes onJine as scheduled, then "the utility will
promptly refund the Security Deposit to the QF" developer. Partial Settlement at tf 2.
Consequently, we find that the standard terms proposed in the partial settlement are
fair, just and reasonable, and in the public interest. Moreover, we find that the $45 per kW of
installed capacity is a reasonable amount to post as a security deposiUperformance bond. Thus,
we approve and adopt the partial settlement for all new PPAs entered into after the date of this
Order.
F. Curtoilment
Idaho Power proposed that the Commission approve a new taritr - Schedule 74
(Curtailment). Schedule 74 would allow Idatro Power, during low loading periods, "to meet its
energy needs by using its own lowest cost, base load resources instead of dispatching less
efficient, higher cost resources to accommodate PURPA generators on the Company's system."
Tr. at 615.
l. Utilities. Idatro Power argues that its proposed tariff is consistent with PURPA
and FERC rules. Id. The Company contends that 18 C.F.R. g 292.304(f) allows a utility to
curtail higher cost QF energy if the utility would have to dispatch less effrcient, higher cost units
to meet system load. Id. The Company maintains that intermittent PURPA generation
0RDER NO. 32697 33
frequently provides energy at night and during the spring and fall months. These times coincide
with ldatro Power's low load periods. Id, at 617. During these low loading periods, Idaho Power
generates and/or must accept more energy than its customers need and must sell excess power
back into the market - sometimes at a loss.
Idatro Power explains that the addition of large amounts of intermittent generation on
the system, coupled with the fact that intermittent generation often generates when the
Company's system load is at a low level, "forces the Company to use the flexibility of the hydro
system that is normally used to meet load swings and to meet system balancing needs . . . of the
wind generators. Thus, the Company is forced to use base load generation resources to integrate
the intermittent QF generation which comes at an additional cost to customers." Tr. at 610.
Proposed Schedule 74 would allow lda]ro Power to curtail its QF generation if, during low load
situations, Idaho Power would otherwise be forced to utilize less efficient, higher cost units to
meet impending load following a low loading period.
2, Commission Staff. Staff supports the approval of Idatro Power's proposed
Schedule 74. Staffmaintains that existing Schedule 72 gives Idatro Power the authority to curtail
and the proposed Schedule 74 outlines the policies and procedures for curtailment. Id. at lll3.
Staff states that Schedule 74 would allow Idatro Power to curtail for system efficiency and
economics under limited circumstances - reasons not allowed under Schedule 72. Id. Staff
argues that Idaho Power's proposed Schedule 74 is consistent with PURPA and FERC
regulations.
3. lntervenors. The Canal Companies oppose Idaho Power's proposed Schedule 74.
Tr. at 874. The Canal Companies argue that Idaho Power's proposal unilaterally modifies
existing contracts. The Companies maintain that existing Idatro Power PPAs do not contain
language to allow for operational or economic curtailment. Thus, implementing Schedule 74
would unilaterally change existing contracts that were mutually negotiated by the parties. .Id at
876.
The Canal Companies further argue that Idaho Power presents a misleading picture of
FERC's rulings regarding operational curtailment rights. The Canal Companies assert that, "[b]y
employing production simulation models such as AURORA, the economic dispatch of the
system, including during light load hours, has already been taken into account in deriving the
avoided cost prices." Id. at 878. Therefore, the Canal Companies maintain that the utility has
oRDER NO. 32697 34
already accounted for light load periods and should not be permitted to also curtail a QFs
production.
Finally, the Canal Companies state that Langley Gulch is mischaracterized by Idaho
Power as a must-run base load resource. Tr. at 879. They argue that Langley Gulch's ramp rate
does not qualiry it as a must-run base load resource. They further maintain that ldaho Power has
not shown that FERC's low load scenario exists on Idatro Power's system. Id. The Canal
Companies suggest other options for light-load conditions such as selling powff to sunounding
service tenitories in order to avoid curtailment. The Canal Companies characterize Idaho
Power's proposed Schedule 74 as a "poorly disguised effort to impose economic curtailment on
QF deliveries." Id.
C/E/S also opposes ldaho Power's proposed Schedule 74. C/E/S maintains that
Schedule 74 amounts to economic curtailment not permitted by FERC's regulations. Tr. at97l.
C/E/S further asserts that Idaho Power already possesses the authority to curtail for operational
concerns under its existing Schedule 72. CIEIS maintains that ldatro Power's proposal primarily
takes issue with the bwden of intermittent resources, i.e., wind. C/E/S argues that the ldaho
Commission has already approved and implemented a wind integration charge in order to
address the intermittency of the resource and integration challenges that wind presents. Id. al
972. C/E/S argues that ldaho Power has not adequately demonstrated that its system
configuration is similar to that oontemplated by FERC within 18 C.F,R. $ 292.304(0. Id. at975.
Idatro Wind Parfrrers maintains that curtailment under Section 304(0 does not apply
to pre-determined, fixed price contracts. Id. at 815. Idaho Wind Panners argues that fixed price
contracts already take into account "the anticipated average or composite avoided costs for the
life of the contract, including the potential for negative avoided costs." Id. Therefore, Idaho
Wind Partners opposes the application of ldatro Power's proposed Schedule 74 to existing, ftxed
price contracts.
Commission Findings
First, this Commission has thoroughly reviewed 18 C.F.R. g 292.304(fl and its
subsequent interpretations. We find that Section 292.304(f) clearly allows for curtailment of QF
power under specific circumstances when base load resources would be forced to cut back to a
point where they might not be able to increase their output rapidly enough to meet subsequent
system demand. 45 Fed.Reg. 12214 at 12227 (February 25, 1989) (FERC Order No. 69).
ORDER NO. 32697 35
During certain low load conditions, a utility is permitted to curtail QF power so that base load
resources do not fall below a must-run level.
We further find that, while each power purchase agreement (PPA) that we have
reviewed contains a general reference to 18 C.F.R. S 292.304(f1, curtailment under this section
was not reasonably contemplated when the parties entered into their agreements. The apparent
need for such authority to curtail under these circumstances has only presented itself within the
last several years in ldatro - and, as evidenced by the testimony, seems to be a problem only on
Idaho Power's system.
We acknowledge that Idaho Power has had to accept what it considers a glut of QF
power. This Commission, through these proceedings, is attempting to provide Idaho Power and
the other Commission-regulated utilities with the tools necessary to manage QF power without
harming ratepayers. However, we find that Idatro Power has not provided suffrcient information
or persuaded us about its must-run, resources, the frequency of such conditions, and the
tansparency of its proposed schedule fur us to approve Schedule 74.
It became apparent at he4rjng that ldatro Power's proposed curtailment tariff lacks
suffrcient definition and is void of soiire provisions altogether. As proposed, Schedule 74 does
not provide for a penalty to ldatro Powgr or compensation to a QF if the QF is curtailed without
proper notice. Tr. at 670. The proposed tariff does not address consequences and/or
compensation to a QF if curtailment by the utility would cause the QF not to meet its firming
provisions required by contract (i.e. 85% mechanical availability guarantee or 90Yo threshold in a
90/l l0 contract). /d. As proposed, the tariff has no limit on the number of hous or days that
could be declared must-run periods. Id. a|694. As written, Schedule 74 does not provide for
notice to the Commission or a QF that the utility has declared a must-run period or its expected
duration. Id. a|696. In addition, proposed Schedule 74 does not provide for an opportunity for
the Commission or a QF to contest the utility's declaration of a must-run period. /d. Finally, it
is unclear whether Schedule 74 would operate to curtail Idaho Power's own PURPA resowces.
Id. at 677.
We find that, as proposed, Idatro Power's Schedule 74 is too vague and adoption of
such a tariff is not adequately supported by the evidence provided in this proceeding. If the
Company believes that the over-supply of QF power presents operational problems during light-
load periods then it should address this issue when it negotiates new PPAs.
0RDERNO. 32697 36
I
:l
G. Ownership of Renewable Energt CertiJicates (REC{
We next turn to the dispute regarding renewable energy credits (RECs). Typically
RECs (also known as environmental attributes, green tags, or renewable trading certificates)
represent the environmental attributes associated with I MWh of electicity generated from an
eligible renewable energy source. Order No. 32580 at 4. The utilities and Staff generally assert
that RECs should belong to the utility. Conversely, the PURPA or QF developers argue that
RECs should belong to them. Before providing the position of the parties in greater detail, it is
helpful to review the history, legal background, and the interplay between RECs and PURPA. In
Jrme 2012, the Commission addressed the history and interplay between RECs and PURPA. See
Order No. 32580.7
l. Backsround. A renewable portfolio standard (RPS) tJrpically requires electric
utilities to generate or purchase a certain percentage of their annual generation (their "portfolio")
from designated renewable energy sources or meet their RPS obligation by the purchase of
unbundled RECs. Since about 1995, about 25 States and the District of Columbia have created
mandatory RPS programs. There is no federal RPS standard. Order No. 32580 at 3, citing
Steven Ferrey, et al. "Fire and Ice: World Renewable Energy and Carbon Control Mechanisms
Confront Constitutional Barriers," 20 Duke Enfil.L. & Pol'y F. 125 at 146 (2010) (hereinafter
"Ferrey"). The purpose of adopting RPS programs is to improve air and water quality, reduce
greenhouse emissions, broaden fuel diversity, enhance energy security, and hedge against the
price volatility of fossil fuels. Order No. 32580 ctting American Ref-Fuel Company,l05 FERC
61,004 at'lf 4 (Oct. l, 2003) rehr'g. denied,l0T FERC 61,016 (April 15, 2004), dismissed sub
nom. for lack of jurisdiction, Xcel Energt Services v. FERC,407 F.3d 1242 (D.C.Cir. 2005).
RECs did not exist and were not contemplated when PURPA was enacted in 1978. American
Ref-Fuel, 105 FERC at fl 4; Order No. 29480 at 3. Indeed, PURPA and RPS programs were
created for different reasons.
"About half of the states that have adopted RPS programs allow utilities to use
[RECs] to meet their RPS requirements." Order No. 32580 at 4 cittng Fetey at 145. As the
Second Circuit explained in Wheelabrator Lisbon v. Connecticut Dept. Public Utility Control,
7 Several parties in this case have cited to Order No. 32580 in their legal briefs or testimony addressing RECs.
Parties addressing Order No. 32580 include : Idaho Power, C/E/S, ICL, Idaho Wind Partners, and Staff.
ORDER NO. 32697 37
RECs are otradable certifrcates . . . that correspond to a certain amount of
renewable energy generated by a third party." American Ref-Fuel,105 FERC
at 1[ 61,005. Generally speaking, RECs are inventions of state nroperty law
whereby the renewable enerey attributes are "unbuodled" from the energy
itself and sold separately. The credits can be purchased by companies and
individuals to offset use of energy generated from taditional fossil fuel
resources or . to satisfu cer0ain requirements that [utilities] purchase a
certain percentage of their energy from renewable resources.
531 F.3d 183, 186 (2d Cir. 2008) (emphasis uddro; Order No. 32580 at 4. FERC has declared
that RECs "exist outside the confines of PURPA. PURPA thus does not address the ownership
of RECs. . . . States, in creating RECs, have the power to detennine who owns the RECs in the
initial instance, and how they may be sold or traded; it is not an issue controlled by PURPA."
Order No. 32580 at 5 quoting Amertcan Ref-Fuel,l05 FERC at\23; Order No. 29480; Idaho
Wind Partners, 136 FERC 61,174 at n.l0 (Sept 15,20ll) ("the sale and trading of RECs are for
the states to decide"). Because "RECs are state-created, different states can fieat RECs
differently." American Ref-Fuel,l07 FERC 61,016 atn.4.
The parties in this case agree that the Idatro Legislature has not implemented an RPS
program nor has it enacted any statute which addresses the ownership of RECs. Moreover, this
Commission has noted on several occasions, the *State of [datro has not created a REC program,
has not established a trading market for [RECs] nor does it require a renewable resource
portfolio standard." Order No. 32580 at 9 citing Order Nos. 29480, 29577, 29630. With this
background, we now turn to the arguments of the parties.
2. Utilities. Rocky Mountain believes that RECs should belong to the utility
whenever the QF sells energy to the utility under PURPA. Tr. at 222. Company witness Paul
Clements explains but for PURPA's must purchase provision, utilities would not be required to
purchase the renewable energy.
Without these [renewable or efficiency] characteristics, the [QF] would not be
able to require the utility to purchase its energy at all. In other words, it is
onlv bv virtue of the existence of the Environmental Attributes that facilities
are deemed OFs and utilities become oblieated to purchase their power. In the
cille of eligible renewable energy resource QFs, these Environmental
Attributes are the essence of the requirements to pwchase the output, and is
therefore part of what the utility is buying with the payment of avoided costs.
If Rocky Mountain Power does not get the QF Environmental Aftribute, it is
not receiving the very characteristic that enabled the facility to achieve its QF
oRDER NO. 32697 38
status, and which thereby triggers the utility's obligation to purchase the
output from the facility.
Tr. at 223-24 (emphasis added). If ownership of the RECs is not assigned to the utility, then
"Rocky Mountain Power and its customers would in effect be paying twice for that attribute . . .
." Tr. at223.
Mr. Clements maintains that the subsequent unbundling between the PURPA power
and the RECs associated with that very same power does not justiff separate compensation. Tr.
at224. As originally envisioned by PURPA, a purchasing utility is not buying'fundifferentiated
energy from the Grid; it is bulng energy that . . . the utility is required by law to purchase.' Tr.
at225. The subsequent creation of RECs with their associated market value should not deprive
utilities of the attibutes subsumed in the renewable power they are required to purchase under
PURPA. He recommended that any power purchase from a QF should assign the associated
environmental atEibutes to the purchasing utility.
In its brief, Avista first argues that the Commission has jurisdiction to determine the
ownership of RECs. Avista insists that FERC has expressly disclairned jurisdiction over RECs
and has held that the states "have the power to determine who owns the RECs in the initial
instance, and how they may be sold or traded." American Ref-Fuel,105 FERC 61,004 al\23.
Avista asserts that the Public Utilities Laws (61-501, 6l-503, 6l-507, etc.) give the Commission
subject matter jurisdiction over the determination of RECs. More specifically, Avista maintains
that a QF may be considered a "public utility" as defined by Idaho Code $ 6l-129. Although it
recognized that PURPA prohibits states from regulating QFs in the same manner as other public
utilities, Avista nevertheless argues that federal law "does not prohibit all regulation of QFs by
states." Avista Brief at 4, n.15 citing l8 C.F.R. $ 292.602(c)(2); Independent Power Producers
of New York, 80 FERC 61,125 (1997)(affrrming the requirement that QFs must comply with
certain state monitoring requirements was a legitimate exercise of the state's authority). Avista
also states that the avoided cost rate cannot be adjusted to compensate for RECs. Id. at6.
Avista asserts that other state commissions have addressed the ownership of RECs.
Brief at 5 citing In Re the Riley Energt Corp.,2004 WL 3160409 (Conn. DPUC 2004). In
particular, Avista insists that the State Commissions of Connecticut, Nevada, New Jersey, North
Dakota, Oregon, Pennsylvania, Utah, and Colorado have all deterrnined that REC ownership
should be vested in the utility. Id. at 5, a,16.
oRDERNO. 32697 39
Idatro Power asserts in its brief that it is "well established that the question of REC
ownership is properly decided by the states. PLJRPA does not govem the question [of RECs]."
Brief at 69, citing American Ref-Fuel, 105 FERC at t[ 23, rehr'g denied, 107 FERC 61,016
(2004), appeal dtsmissed sub nom., Xcel Energt Servtces v. FERC,407 F.3d 1242 (D.C. Cir.
2005); Weelabrator Lisbon v. Connecticut Dept. of Util. Control,53l F.3d 183, 190 (2d Cir.
2008); IPUC Order No. 32580. The Company furttrer argues that the Commission has the
subject matter jurisdiction to decide the REC issue. Brief at 73-79. Like Avista, Idatro Power
maintains that the Commission's organic statutes ($$ 61-502, 6I-503, 6l-506, 6l-507 and
others) grant the Commission broad powers to regulate the terms and conditions of PURPA
contracts. Id. at77-78.
Idatro Power points to decisions of other state commission (Connecticut, New Jersey,
Maine, Pennsylvanig Wyoming) that do not have REC or RPS statutes. Id. at 80. The utility
argues these other state cases represent a compelling argument why RECs should belong to the
purchasing utility. "Simply put, in the absence of an ldatro RPS [or REC] statute, there is no
reason to conclude that a QF selling to an Idatro utility has any right or ability to unbundle
energy and environmental attributes." Id. at86.
Idatro Power also mentions a November 201I order issued by the Wyoming Public
Service Commission. In Order No. 12750, the Wyoming Commission found that Rocky
Mountain Power's argument that the utility should retain the RECs was persuasive. Relying on
Mr. Clements testimony, the Wyoming Commission found that Rocky Mountain
should continue to retain the RECs since they represent tangible value for the
ratepayer, and they should not be routinely severed frorn the underlying green
power generated. The Commission had in the past rnade it clear that REC
revenues are a key component to mitigate, to an extent, the effects on
customers of the ongoing series of rate increases filed RMP. The Commission
is not inclined to approve the transfer of RECs to other entities and reiterates
its position that RECs should stay with the utility.
Idaho Power Brief at 86-87 , citing Wyoming Order No. 12750 at ![ 63 (Nov. 4,2011).
3. Commission Staff. Staff also insists that the Commission has the subject matter
jurisdiction to decide the REC issue. [n particular, Staff notes that the Legislature has delegated
authority to the Commission'to deal broadly with existing and future rates, rate schedules and
contracts affecting rates." Washtngton Water Power Co. v. Kootenai Environmental Alltance,99
Idalro 875, 880, 951 P.2d 122,127 (1979); Staff Brief at 4. Staff rnaintains that the Commission
ORDER NO. 32697 40
has the authority to decide the REC issue because the ownership of RECs and their value are
inextricably tied to power rates and contracts affecting rates. Id. Staff observed that the costs
associated with QF oontacts are directly recovered from ratepayers. Id, al4.
Staff also asserts that but for the must purchase requirement of PURPA, the QF and
the associated REC, would not exist. Echoing a point raised by Rocky Mountain, Staff states in
its brief that if a
QF resticts the renewable attibutes prior to conveying the energy to a utility,
then the bases for which the QF initially received its [qualiffingJ status and
gained its authority to sell no longer exists. Said another way, if the utility is
being compelled to ptrchase based on the energy being [classified as]
renewable, then the renewable status should remain with the energy purchased
by the utility. Moreover, an environmental attibute is an intaneible
characteristic of the energy generated by a renewable energv facilit!,, not a
characteristic of the facility itself.
Brief at 4 (emphasis added).
Staff notes that one of the purposes of PURPA was to reduce the country's
dependence on fossil fuels by encouraging renewable technologies and cogeneration. However,
one of the key underpinnings of PURPA was to make "ratepayers indiflerent as to whether the
utility used more traditional sources of power or the newly-encouraged [QF] altematives." .ld. at
5 quoting Southern Cal Edison, San Diego Gas & Electric, Tl FERC 61,269,62,080 (1995).
Staff insists that Congress did not intend to create an environment in which renewable energy
producers thrive to the detriment of the utility's ratepayers.
In balancing the competing REC arguments, Staff recognizes the differences in
assigning RECs under the IRP and SAR methodologies. More specifically, "because the SAR is
a [natural] gas-fired resource that does not produce RECs," [such] "RECs would be a unique
attribute of the power provided by the QF." Tr. at 1122-23. Conversely, under the IRP
Methodology, a utility's 2O-year resoruce portfolio contains some renewable resources. In this
latter case, the utility would presumably be entitled to RECs. /d.
4. lntervenors. Although Renewable Northwest (R].fW) recognizes that RECs are "a
creature of state law and exist outside of PURPA," it argues that assigning RECs to the utility
would nevertheless violate PURPA by: (l) discriminating against QFs; (2) discouraging future
QF development; and (3) represent a windfall to utilities. Brief at 5, l-4. RNW argues that
unbundled RECs are not part of the avoided cost methodology. Id. at 5-6. It also suggests that
ORDER NO. 32697 4l
neither the SAR nor the IRP methodologies used to calculate avoided costs in ldatro include
compensation for RECs in any fashion. Id. at7. Providing the RECs to utilities would mean that
utilities would receive energy, capacity and RECs, but only pay for the energy and capacity. Id.
at 9. Such a finding would run afoul of PURPA's anti-discrimination provision and undermine
PURPA's objective to encourage renewable generation. .Id.
The Canal Companies note that FERC recognizes that RECs, like the thermal output
from cogeneration QFs, may be sold separately (i.e., unbundled) from the capacity and energy
output of QFs. Brief at 9. FERC has emphatically stated that avoided cost rates are not intended
to compensate the QF for more than capacity and energy. Id. at 10, More recently, FERC
affirmed its holding in American Ref-Fuel that'the sale and nading of RECs are for the state to
determine, and that this is not an issue that PURPA controls." Idaho Wind Partners,136 FERC
61,174 at fl l0 (Sept 15, 201 l).
The Canal Companies and C/E/S both maintain that prior Order Nos. 29480 and
29577 of this Commission (in Case Nos. IPC-E-04-02 and IPC-E-04-16, respectively) declared
that RECs do not belong to the utilities. Canal Brief at l0-ll; C/E/S Brief at 29-30.
Consequently, C/E/S argues that these Orders may be interpreted to hold that *Idaho QFs are the
default owners of [RECs]," Brief at 30. Finally, if the Commission does assign RECs to
utilities, then utilities must compensate the QFs for the 'taking" of RECs. "QFs' intsrest in the
transferable [and unbundledJ RECs of QFs is a compensable property interest." Canal Brief at
16. Taking of a QF's REC property without just compensation would violate both the U.S. and
Idaho Constitutions. /d.; C/E/S Brief at 32.
The Idaho Conservation League (ICL) maintains that the Commission has no
authority to resolve REC ownership. Brief at 3. ICL notes that the Commission in its prior REC
Order No. 32580 explained that "RECs are inventions of strate property law whereby the
renewable energy attributes are'unbundled' from the energy itself and sold separately." Id. at3-
4, citing Order No. 32580 at 4. Absent a specific Idaho statute that addresses RECs, ICL
maintains that the legal status of RECs depends upon "traditional notions of common law, which
in Idaho vests those rights in the owner who expends the time and effort to create the property."
Id. at4 citing King v. Chamberlain,Z}ldatro 504, 118 P. 1099 (l9l l). 'oBecause QF developers
expend their own time and resources to create an independent property right in RECs, . . . QF
developers inherently own RECs under Idaho law." Brief at 4.
ORDER NO. 32697 42
Dynamis and Renewable Energy Coalition (RE) also argue that the Commission has
no authority to determine the ownership of RECs. Relying upon the Kootenai Environmental
Alliance case, they assert there is no statute that gives the Commission the authority to adjudicate
the ownership of RECs. REC ownership does not fall into those subject mafier areas that the
Commission taditionally regulates, nor does it require the application of the Commission's
technical expertise. Brief at 34, cittng Kootenai, gg ldatro 875, 882, 591 P.2d 122,129 (1979).
They also note that the 2012 Legislature did not pass Senate Bill No. 1364 which, if enacted into
law, would have recognized that RECs associated with QF power sales are "atEibutes of the
power purchased by the utility." Brief at 6; Exh. No. 802. Although, no legislative hearings
were held on the bill, they infer that the printing of this bill reinforces the view that the
Commission does not have authority to adjudicate RECs. /d.
Conmission Findings
l. Jurisdiction. We turn first to the issue of subject matter jurisdiction. DynamislRE
and ICL af,gue that the Commission does not have jurisdiction to decide the REC issue. First,
ICL argues that because there is no REC statute, the Commission cannot decide the matter.
Second, they argue that the Legislature "has considered but ultimately rejected two attempts at
addressing the ownership of RECs." ICL Brief at 2; see a/so Dynamis/RE Brief at 5-6; Exh.
802, 803. Dynamis/RE argue that the failure of the Legislature to pass a REC statute should be
construed as the Commission lacking authority to decide the REC issue. Conversely, Avista,
Idatro Power and Staff argue that the Commission does have the requisite subject matter
jurisdiction to decide the REC ownership dispute.
At the outset, we recognize t}r;t the Commission is a creature of statute and our
jurisdiction is dependent upon our statutory authority. The Cornmission exercises limited
jurisdiction based upon the authority given by the Legislature. Washington Water Power v.
Kootenai Environmental Alliance, 99 ldatro 875, 879,591 P.2d 122, 126 (1979). Our Supreme
Court has noted that the Commission may determine whether we have jurisdiction over specific
issues. Id. However, o'once jurisdiction is clear, the Commission is allowed all power that is
either expressly granted by statute or which may be fairly implied" to effectuate its purpose.
Idaho State Homebuilders v. Washington l(ater Power,l07 Idaho 415,418, 690 P.2d 350, 353
(1984); Id. We do not agree with ICL and Dynamis/RE that the Commission does not have
authority to determine the REC question for several reasons.
oRDER NO. 32697 43
First, it is well settled that the Commission has been granted authority to review OF
contacts and resolve disputes between OFs and electric utilities. A. W. Brown v. Idaho Power,
121 Idalro 812, 816, 828 P.2d 841, 845 (1992'l; Empire Lumber Co. v. Washington Water Power,
114 Idaho 191,755 P.2d 1229 (1988); Afion Energt v. Idaho Power Company 107 ldaho 781,
693 P.2d 427 (1984); Idaho Code S 6l-612. The disposition of RECs is now a term that is found
in most, if not dl, PURPA contracts. Since 1980, the Commission's PURPA procedures have
required that all QF contracts be submitted to the Commission for its approval. Order No.
15746,38 P.U.R. 4n 352 (ldatro 1980); Order No. 29632, 2004 V/L 2724113 (Idaho PUC); see
Rosebud Enterprises v. Idaho PUC,l28 Idaho 609,620,917 P.2d766,778 (1996). Likewise,
Idaho Code $ 6l-502 authorizes the Commission to review contracts with utilities that affect
utility rates and charges. Moreover, Idaho Code S 6l-503 provides that the Commission shall
have the power to investigate the contracts of any public utility.
Second, in A.W. Brown, our Supreme Court rejected the QF's argument that the
Commission has no jurisdiction ooto litigate the common law contract issues between [the QF]
and ldaho Power. . . ;' l2l Idatro at 819, 828 P.2d at 848. The Court rejected that argument and
found "that the Commission 'has jurisdiction to hear complaints against utilities alleging
violation of any provision of law. . . ."' Id. ln Empire Lumber, the Court found that the
Commission has been "granted authority by the Idatro statutes to, and is the appropriate forum to
resolve" PURPA contract issues. I 14 Idatro at 192,755 P.zd at 1230. In this proceeding, the
parties have argued about the ownership of RECs in standard PURPA contracts and this dispute
is ripe for decision.
Third, we find that the disposition of RECs directly affects rates. As noted above, the
sale of RECs directly offsets the rates that utilities must pay QFs for power. The cost of
purchasing QF power is initially recovered in the annual Power Cost Adjustnent (PCA)
mechanisms for Idatro Power and Avista, and in the Energy Cost Adjustment Mechanism
(ECAM) for Rocky Mountain. Tr. at392,1107. Upon the utility's next general rate case filing,
QF costs become part of base rates. The sale of RECs by wilities is recorded in the PCA/ECAM
mechanisms of the utilities. Tr. at 573, 1192, ll93-94. Thus, the disposition of RECs directly
affects utility rates. And, as our Supreme Court noted in Kootenai,Idaho Code $$ 6l-502 and
6l-503 embody "the legislative grant of authority to the Commission to deal broadly with
existing and future rates, rate schedules and contracts affecting rates." 99 ldaho at 880, 591 P.2d
ORDER NO. 32697 44
at 127. Consequently, we find that the Commission has subject matter jurisdiction to decide the
REC issue.
Finally, we find Dynamis/RE's argument that the Commission lacks authority to
decide the REC issue based on the introduction of a REC bill (SB 1364) in the last legislative
session to be unpersuasive. Dynamis/RE acknowledges there were no hearings on the bill. Brief
at 6. The fact that legislation was introduced but no hearings were held, no committee votes
were taken, and the Legislature as a whole did not vote on the bill is accorded little weight. See
Casey v. Com'er of Labor & Ind., 167 A.zd 900 (N.J.Super. 196l). As any observer of the
legislative process recognizes, many more bills are introduced than enacted, and it is not unusual
for bills in ldaho to be "printed" (i.e., assigned a bill number), and receive no further legislative
consideration.s
2. RECs. We now turn to the merits of the REC issue. Despite the disagreement
among the parties regarding RECs, there are several facts which are not in dispute. First, all the
parties agree that PURPA does not contol RECs - RECs are controlled by the state. RECs exist
outside the confines of PURPA. Second, there is no Idatro law that implements a renewable
portfolio standard (RPS) program or addresses the ownership of RECs. Order No. 32580, 29480
at 9. Third, the parties agree that ldatro's avoided cost rates do not compensate QFs for RECs.
Moreover, this Commission has previously found, avoided cost rates "are not intended to
compensate the QF for [RECs]." Order No. 32580 atB quottng Morgantown Energt Associates,
I 39 FERC 6l ,066 at \ 47 (April 24, 2012). See also California PUC, 133 FERC 6l ,059 at fl 3 I
n.62 (Oct. 21,2010).
As we noted in Order No. 32580, RECs resemble intangible assets. But for the "must
purchase" provision of PURPA, RECs would not exist or be created for a PURPA project. RECs
are non-physical assets which exist only in connection with something else, i.e., the purchase of
E DynamiVRE's reliance on two other Idaho Supreme Court cases is also misplaced. Brief at 3-5. In Alpert v. Boise
lYater Corp., ll8 Idaho 136,795 P.2d 298 (1990) the issue before the Court was the validity of franchise
agreements between utilities and certain cities under ldaho Code $$ 50-329 and 50-329A. Here RECs are an
integral part of PURPA conracts. The Court has observed many times that it is well settled that the Commission
has been ganted authority to review QF contracts and resolve disputes betueen QFs and electric utilities. ln Ada
County Higlrway Distict v. Idaho PUC, l5l Idaho 2, 253 P.3d 675 (2011), Dynamis/RE asserts that the
Commission in that case argued that it had "siatutory authority to order relocation of utility facilities owned by third-
pa*y beneficiaries." Brief at 5. That was neither the position of the Commission nor do third parties "own" utility
facilities.
oRDER NO. 32697 45
QF power under PURPA.e Order No. 32580 at 10, citingBlack's Law Dictionary at 808 (6th ed.
1990). There is no REC without the QF generating power.
Having considered the positions advanced by the parties, we find that it is reasonable
to apportion RECs based upon the SAR or IRP methodologies applicable to each QF project.
The avoided cost rate paid to a QF under the SAR Methodology is based on a gas-fired surrogate
resource. If the utility were not "avoiding" the cost by acceping the QF energy, it would build a
gas resowce. Gas resources do not produce RECs. Because the SAR Methodology is based
upon a gas-fired surrogate and such a resource produces no RECs, we find that it is reasonable
and appropriate to assign the RECs for SAR-based QFs to the QFs. Conversely, IRP rates are
derived from the utility's actual resource portfolio. The tRP Methodology considers a utility's
resource stack that contains both renewable and non-renewable resources. The rates arc based
on the actual generation characteristics of the renewable resource. Renewabls resources,
whether utility or QF owned, produce RECs. In this case, absent an agreement between the
parties to do otherwise, we find it reasonable to equally apportion RECs befween ttre utility and
the QF. Tr. at ll22-23. Because both the utility and the QF are contactually and inextricably
joined in the production, sale and purchase of QF power, we frnd that it is reasonable to
apportion the unbundled REC assets in this manner. Under the IRP Methodology, we find that
splitting RECs either 50%-50% each year over the life of the PPA, or equally in terms of years
over the length of the contract, is reasonable. Indeed, several recent Orders have approved the
splitting of RECs in this manner. ,See Order Nos. 32419 (Cedar Creek), 32451 (Riverside),
32384 (Interconnect Solar), 32294 (Clark Canyon), and32l25 (Rockland).
Assigning RECs to both the QFs and utilities (including their ratepayers) reasonably
allocates the benefits and burdens from these unbundled REC assets. Typically unbundled RECs
produced in ldatro are sold to produce revenue. From the utility's perspective, selling RECs
produces revenue which directly offsets the utility's (and ratepayers) costs of purchasing power
from QFs. Tr. at 573,1192,1193-94; see Order No. 32002. Thus, another tangible ratemaking
element to RECs,
We funher find that assigning RECs to the QFs under the SAR Methodology and
splitting RECs under the IRP Methodology is also in the public interest. From the QF's
perspective, revenues from the sale of RECs continue to provide a revenue stream to QF
e We recognize that RECs may exist in non-PURPA renewable projects. OrderNo. 32580 at n.5.
oRDERNO. 32697 46
developers to encourage the development of renewable generation. This promotes the
underlying purpose of PURPA and specifically recognizes that the SAR Methodology is based
on a natural gas-fired surrogate. E.9., Rosebud,l2S Idaho at 627,917 P.zd at784. Splitting
RECs under the IRP Methodology for wind/solar QFs larger than 100 kW and other QFs larger
than l0 MW also mitigates those arguments that assigning RECs to either the QF or the utility in
their entirety represents a revenue windfall to the recipient. Under the tRP Methodology, both
the QF and the utility (including its ratepayers) share the benefits of selling RECs. Finally,
because the ownership of RECs is apportioned as set out above, there is no taking of the
intangible asset resulting from the QF-utility relationship. As ttre Connecticut Supreme Corut
found in a similar case, the "[PUC's] decision [to award RECs to the utility] could not constitute
an urconstitutional taking under the State's Constitution because no property owned by the [QF]
has been taken." Wheelabrator Lisbonv. Dept. of Public Util. Co*o\,283 Conn. 672,700,931
A.2d 159, 177 (2007);Weelabrator Lisbon,526 F.Supp.2d295,307 (D.Conn. 2006), affmed,
531 F.3d 183 (2d Cir. 2008).
We are also not persuaded by the Canal Companies' and C/E/S's argument that two
prior Commission Orders (Nos. 2948A and29577) assigned RECs to the QF. As we found in our
Order No. 32580, the Commission in OrderNo. 29480 did not reach the issue of REC ownership
in Case No. IPC-E-04-02. We dismissed tdatro Power's petition for a "right of first refusal"
because the petition did not "present an actual or judiciable controversy in Idatro and is not ripe
for a declaratory judgment by this Commission." Order No. 29480. In the second Order relied
upon by the Canal Companies and C/E/S (No. 29577), Idaho Power waived any claim to
ownership associated with a PPA between Simplot and Idatro Power (Case No. IPC-E-O4-16). In
Order No. 32580, we stated "Given the agreement between the parties, the Commission did not
address the REC ownership issue." Order No. 32580 at ll citing Order No. 29577.
In summary, we find that the Commission has subject matter jurisdiction to decide the
REC issues for the reasons set out above. We further find that it is fair and reasonable to
apportion RECs equally between the QF and the utility when using IRP Methodology, and assign
all RECs to the QF when using SAR Methodology.
H. Confracthg Procedures and Rules
Proposals were made by multiple parties regarding Commission approval of
contracting procedures and rules. The parties supported terms for contract milestones, timing of
ORDERNO, 32697 47
pricing, conditions for delivery of power, and other various informational requirements. We find
that such procedures and rules would be beneficial to bottr the utilities and the QFs. We find that
a fair and consistent set of rules for the utilities and QFs would reduce confusion and provide
more certainty regarding the expectations of all contracting parties. We are optimistic that such
rules might also reduce the number of complaints filed with this Commission because of disputes
regarding contact terms. We direct the parties to participate in workshops with one another to
begin to form a structure for fair and reasonable contracting procedures and rules. We expect the
parties to submit to this Commission no later than December 13, 2013, aproposal for approval of
such terms.
INTERVENOR FTJNDING
On August 14,2012, the ldatro Conservation League filed a request for intervenor
funding in the amount of $8,100. The Canal Companies (Twin Falls Canal Company, North
Side Canal Company, Big Wood Canal Company, and American Falls Reservoir District No. 2)
filed a request for $55,445 in intervenor funds on August 21,2012. Both applications were
timely.
lntervenor funding is available pursuant to ldaho Code $ 6l-617A and Commission
Rules of Procedure 161 through 165. Section 6l-617A(t) declares that it is "the policy of
[Idaho] to encotrage participation at all stages of all proceedings before this commission so that
all affected customers receive full and fair representation in those proceedings." The statutory
cap for intervenor funding that can be awarded in any one case is $40,000. Idaho Code $ 6l-
617A(2). Accordingly, the Commission may order any regulated utility with intastate annual
revenues exceeding $3.5 million to pay all or a portion of the costs of one or more parties for
legal fees, witress fees and reproduction costs not to exceed a total for all intervening parties
combined of $40,000.
Rule 162 of the Commission's Rules of Procedure provides the form and content
requirements for a Petition for Intervenor Funding. The petition must contain: (l) an itemized
list of expenses broken down into categories; (2) a statement of the intervenor's proposed finding
or recommendation; (3) a statement showing that the costs the intervenor wishes to recover are
reasonable; (4) a statement explaining why the costs constitute a significant financial hardship
for the intervenor; (5) a statement showing how the interyenor's proposed finding or
recommendation differed materially from the testimony and exhibits of the Commission Staff;
oRDER NO. 32697 48
(6) a statement showing how the intervenor's recommendation or position addressed issues of
concem to the general body of utility users or customers; and (7) a statement showing the class
of customer on whose behalf the intervenor appeared.
l. Idatro Conservation League (lCL). ICL is a non-profit organization supported
through charitable donations of members and foundations. ICL provided an itemized list of
expenses totaling $8,187.50. The organization "rounded down for ease of accounting" and
requests $8,100 in intervenor funding for attomey's fees incurred by participating in the case,
reviewing the testimony, and representing ICL at the hearing. Petition at 2.
In its Petition, ICL states that it reviewed the case, opposed Idatro Power's Motion for
a Temporary Stay, filed direct testimony, and actively participated in the evidentiary hearing.
ICL further maintains that its position differed materially from that of Staffregarding ownership
of renewable energy credits. ICL argued in briefing and at hearing that RECs are an independent
property interest owned by the project developer. ICL also submitted testimony to rebut ldatro
Power regarding its legal obligations on dams ptrsuant to the Clean Water Act. Id at4.
ICL maintains that, as a non-pnofit organization, its charitable contributions are
inherently unstable. As such, the availability of intervenor funding is essential for ICL to
participate in proceedings in front of the Commission. Id. ICL states that they have no
pecuniary interest in the outcome, "rather we dedicated our time and resources to represent the
interests of our 20,000 supporters around the state who have a strong interest in a robust clean
energy industry in [daho." .Id.
ICL asserts that it addressed issues of concem for customers of all tluee utilities. "All
customers, regardless of class, share a stong interest in ensuring tdatro utilities acquire power
pursuant to rules that are fair, accurate, and conform to applicable laws." Id. Therefore, the
organization suggests that the Commission allocate the responsibility for any intervenor funding
award equally between the three utilities. Id. at l. tCL maintains that both its hourly rate and
hours expended are reasonable based on the complexity of this case. Petition at 2. ICL further
states that its rates are "in line with the current range for other intervening parties." /d.
2. The Canal Companies. The Canal Companies provided an itemized list of partial
expenses incurred during this proceeding. The Canal Companies assert that they seek an
intervenor funding award only based on $55,445 in fees associated with retaining the expert
oRDER NO. 32697 49
consulting services of lv[r. Don Schoenbeck. Petition at 3. They do not request an award for the
recovery of fees associated with legal coursel. Id. atZ.
In its Petition, the Canal Companies state that through the testimony of its witnesses,
cross-examination of utility witnesses and in closing arguments, they advocated for 2O-year
contract length, l0 MW nameplate eligibility for published rates, and two-run simulations for
IRP-based modeling. The Canal Companies also advocated an altemative for capacity payments
and maintained that actual damages for breach of contact by a QF be determined through a
"mark to market" approach. The Companies opposed Idatro Power's proposed ctrtailment tariff
and advocated for QF ownership of RECs. The Canal Companies maintain that their various
positions were materially different from Staffs.
The Canal Companies state that their members/owners are ratepayers of Idaho Power.
Id. at 3. The Companies state that their funding for participation in this case is gained through a
membership assessment fee. Id. The Canal Companies maintain that they addressed issues of
concern for Idaho Power customerc and in the public interest. "All customers, regardless of
class, share a strong interest in ensuring tdatro utilities acquire power pursuant to rules that are
fair, and accurate, and conform to applicable laws. . . . In addition, the involvement of [datro's
canal system in the production of inexpensive renewable energy provides a multiplier effect into
the local economy, . , ." Id. at 5. The Canal Companies maintain that the customer classes they
represent are residential and small commercial customers of ldaho Power and Rocky Mountain
Power, "as well as QFs falling within the purview of Section 210 of PURPA allowing for sale
and purchase of energy from investor-owned utilities." /d
Commission Findings
The Commission has reviewed the Petitions for Intervenor Funding filed by ICL and
the Canal Companies. We find that ICL contributed to discussions, debate and testimony and
presented important perspectives that materially contibuted to the Commission's decision-
making in this case. Specifically, ICL presented testimony and cross-examination regarding
Idaho Power's dams and must-run requirements that prompted rneaningful discussion regarding
the breadth of Idatro Power's proposed curtailment tariff.
The Commission finds that ICL's participation contibuted to our deliberations in this
matter and presented positions different from that of Staff and other utility and intervenor
witnesses. We further find that $8,100 is a reasonable amount in costs and fees based on ICL's
ORDER NO. 32697 50
level of participation at all phases of this proceeding and that these costs would otherwise
amount to a financial hardship for the organization. Therefore, we find that it is just and
reasonable to grant ICL intervenor funding in the amount of $8,[00. Pursuant to ldqho Code $
6l-617A(3), the amount awarded to ICL shall be recovered from Avista, Idaho Power and Rocky
Mountain Power based on a proportional share of the total number of Idatro customers served by
each utility.
We find that the Canal Companies participation also connibuted to the positions
advanced by the parties to this case. Mr. Schoenbeck's testimony advanced a reasonable
approach on several issues that otherwise divided the utilities and the QFs. However, in
considering the reasonableness of the request for intervenor funding made by the Canal
Companies, the Commission is required to consider whether the payment of the amount
requested by the intervenors would constitute a "significant financial hardship." Idaho Code $
6l-617A(2)O); IDApA 31.01 .01.162.04. The Canal Companies made no mention of whether
and to what extent their participation and commensurate expenses would amount to a significant
financial hardship for their members. We find that a showing of financial hardship is critical for
an award of intervenor funds. Therefore, we deny any award of intervenor funding to the Canal
Companies based on their failure to comply with the requirements of ldsho Code $ 6l-617A(2).
ULTIMATE FINDINGS AND CONCLUSIONS
The Commission has jurisdiction over this matter pursuant to the authority and power
granted it under Title 6l of the Idaho Code and the Public Utility Regulatory Policies Act of
1978 (PURPA). The Commission has authority under PURPA and its implementing regulations
to set avoided costs, to establish standard published avoided cost rates, to order electric utilities
to enter into fixed-term obligations for the purchase of energy from QFs, and to implement
FERC regulations. The Commission is also empowered to resolve complaints between QFs and
utilities and approve QF contracts.
Under PURPA, utilities are required to purchase QF generation at a rate equal to the
utility's avoided cost. 18 C.F.R. $ 292.304(b)(2). "Avoided costs" are the incremental costs to
the electric utility of power which, but for the purchase from the QF, such utility would generate
itself or purchase from another source. l8 C.F.R. $ 292.101(bX6). PURPA and FERC
regulations direct not only that rates for purchases shall not discriminate against QFs, but also
ORDER NO. 32697 5l
that avoided cost rates be just and reasonable to the utility's ratepayers and in the public interest.
l8 c.F.R. $ 292.30a(aXl).
Although FERC promulgated the general scheme and rules, it left the actual
irnplementation of PURPA to the state regulatory authorities. Rosebud Enterprises, Inc. v. Idaho
Public Utilities Commtssion,l2S ldaho 609, 614,917 P.zd766,771 (1996). FERC regulations
grant the states latitude in implementing the regulation of sales and purchases between QFs and
electric utilities. See Federal Energt Regulatory Commtssion v. Mississ@i,456U.S.742,102
s.ct. 2126, 72 L.Ed.2d 532 (1982).
As we have stated previously in this docket and other PURPA related matters, this
Commission has a long history of encouraging PURPA development. With the changes adopted
herein, we believe that PURPA development can continue to thrive in a way that holds
ratepayers harmless. QF projects will be compensated according to their ability to provide a
utility with needed energy and capacity at a rate that reflects the costs that the utility avoids by
puchasing QF generation. Our findings regarding calculation of avoided costs, eligibility to
published rates, RECs and performance security, terms and conditions within contracts, and
length of contracts are entirely consistent with PUFJA and FERC regulations.
ORDER
IT IS HEREBY ORDERED that published avoided cost rates are available for wind
and solar projects producing up to 100 kW. Published rates for all other resources are available
for projects producing up to l0 alvtw.
IT IS FURTHER ORDERED that qualifring facilities not receive compensation for
capacity rmtil the utility is capacity deficient.
IT IS FURTHER ORDERED that natural gas prices utilized in the SAR
Methodology be updated annually, on June I of each year, with the most recent natural gas
forecasts provided by EIA's Annual Energy Outlook.
IT IS FURTHER ORDERED that fuel price forecasts and load forecasts utilized in
the IRP Methodology be updated annually, on June I of each year. In addition, long-term
contracts shall be considered in IRP Methodology calculations at such time as the utility and QF
have entered into a signed contract for the sale and purchase of QF power.
IT IS FURTHER ORDERED that a utility's detennination of capacity deficiency
through its IRP planning process shall be subject to additional scrutiny for use within the SAR
oRDER NO. 32697 52
Methodology. We continue the remainder of the IRP planning prosess as it is currently
constituted.
IT IS FURTHER ORDERED that we adopt and approve the Partial Settlement
Stipulation regarding security deposits, delay damages, refunds, and termination damages in its
entirety.
IT IS FURTHER ORDERED that RECs for SAR based projects will be owned by
the QF. RECs produced by projects utilizing the IRP Methodology will be equally apportioned
between the utility and QF in the manner of their choosing.
IT IS FURTHER ORDERED that Idaho Power's proposed Schedule 74 is not
approved.
IT IS FURTHER ORDERED that additional pricing calculations, contract
provisions, terms and conditions shall comply with the findings of this Commission as set out in
greater detail in the body of this Order.
IT IS FURTHER ORDERED that [CL's Petition for Intervenor Funding is granted in
the amount of $8,100. The utilities are directed to remit this amount to ICL within 28 days from
the date of this Order and as more specifically described herein. IDAPA 31.01.01.165.02.
IT IS FURTHER ORDERED that the Canal Companies Petition for lntervenor
Funding is denied.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See ldaho Code $ 6l-626.
ORDER NO. 32697 53
DONE by Order of the ldaho Public Utilities Commission at Boise, Idatro tns l8 rh
day of December 2012.
PAUL
MACK A.
H. SMITH,
ATTEST:
O:GNR-E- I l -03_ks_dh_Final Order
oRDERNO. 32697 54
/L^tu. n-fl
Jd& D. Jewell/ I
CUmmission SYcretary
IDAHO POWER COMPANY
AVOIDED COST RATES FORwlND PROJECTS
December 13,2012
$/MVvtt
Ellgibility for these rates ls limited to wlnd and solar proiects 100 kW or smaller, and to non-wlnd and non-
solar prdects smaller than 10 aMW.
CONTRACT
LENGTH
ON.LINE YEAR
CONTRACT NON-LEVELIZED
1
2
3
4
5
o
7
II
10
11
12
13
14
15
16
17
18
19
20
22.U
21.E9
22.65
23.66
24.41
26.32
27.83
29.11
30.18
31.27
32.36
33.42
34.39
35.2E
36.1 2
36.95
37.74
36.48
39.1S
39.89
21.73
22.99
24.29
25.13
27.39
29.08
30.47
31.61
32.75
33.92
35.03
36.04
36.97
37.84
38.71
39.53
40.30
41.05
41.77
42.47
24.35
25.72
26.45
29.1 1
30.93
32.38
33.52
34.69
35.8E
37.02
38.06
39.01
3S.90
40.79
41.63
42.42
43.19
43.93
44.65
45.35
27.21
27.63
30.97
32.93
u.40
35.52
36.68
37.90
39.07
40.1 3
4'1.0E
41.99
42.89
43.75
44.56
45.34
46.1 1
46.85
47.37
48.30
28.09
33.0E
35.16
36.58
37.61
38.75
39.97
41.15
42.21
43.16
44.08
44.99
45.87
46.59
47.49
4E.27
49.03
49.77
50.52
51.29
38.4E
39.'t 3
39.88
40.49
4'.t.43
42.55
43.67
44.68
45.60
46.48
47.38
48.25
49.06
4S.86
50.65
51.42
52.17
52.94
53.73
54.48
2012
20't3
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2432
2033
203/
2035
2036
2037
22.O4
21.73
24.35
27.2'l
28.09
38.48
39.84
41.56
42.64
46-00
49.71
52.58
54.52
56.1 I
58.48
61.63
64.00
66.03
68.69
71.49
74.37
77.18
81.63
86.29
E8.46
92.22
Not6: The rates shown in this leble have been computed using the U.S. Energy lnfurmation Administralion (ElAls Annual Energy
Outlook2012releasedJune25,2012. S6e"AnnualEnergyOutlook2012,AllTables,EnergyPricesbySectorandSource,Mountain,
Reference case" at htlp://www.eia. gov/oiaf/aeoltablebrowser/.
ATTACHMENT A
0RDER NO. 32697
CASE NO. GNR.E-1I-03
IDAHO POWER COiIPANY
AVOIDED GOST RATES FOR SO1AR PROJECTS
D,ecember 13,2012
$'MllJtr
Ellglbltlty for these rates ls llmltod to wlnd and solar prolects 100 kW or smaller, and to non-wind and non-
solar prolecb smaller than 10 aMW.
ON.LINE YEAR
LENGTH CONTRACT NON.LEVELIZED
2012
1
2
3
4
5
5
7II
10
1'l
12
13
14
15
16
17
18
19
20
18.70
18.52
20,93
27.47
31.58
36.26
39.78
42.60
44.89
46.97
48.90
50.66
52.24
53.66
54.98
56.2s
57.40
58.49
59.52
60.50
18.32
2.19
30.88
35.48
40.68
44.36
47.21
49.48
51.53
53.43
55.1 7
56.73
5E.1 3
59.42
60.66
61.E2
62.90
63.93
6rt-91
65.E5
26.37
37.94
42.16
47.45
50.91
53.50
55.50
57.v
59.09
60.71
62.16
5:t.46
64.68
65.65
66.96
68.00
68.99
69.94
70.86
71.74
50.46
51.04
55.66
58.35
60.32
61.84
63.33
64.83
66.25
67.53
68.70
69.E1
70.90
71.%
72.9',!
73.86
74.78
75.56
76.52
77.39
51.66
58.58
61..lt}
63.31
64.70
66.1 3
67.60
69.01
70.n
71.U
72.il
73.64
74.6E
75.67
76.62
77.55
78.46
79.U
80.23
El.13
66.06
66.91
67.85
68.65
69.T1
71.O7
72.3?
73.55
74.63
75.68
74.74
77.76
7E.73
79.68
80.61
8't.52
82.41
83.32
u.24
85.'t l
2012
2013
2014
2015
2016
2017
2018
20't9
2020
2021
20n
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
20u
203s
2036
2037
18.70
18.32
26.37
50.46
5 t.66
66.06
67.83
69.96
71.46
75.24
79.36
82.67
85.06
E7.1 6
89.91
93.53
96.37
98.86
102.01
105.30
108.67
I 11.99
116.94
122.12
124.82
129.1 1
Note: The rates shown in this table hav6 b€en computed using th€ U.S. Enorgy lnformetion Administmtion (ElA)'s Annual Enorgy
Outlook2O12releasedJune25,2012. S€€"AnnualEnergyOu[ook20l2,AllTables,EnergyPricssbySectorandSourcs,Mountain,
Reference case" at http://www.€ia.gov/oiafra€o/lablebrowser/.
IDAHO POWER COMPANY
AVOIDED COST RATES FOR HYDRO PROJEGTS
December 13,2012
UMvvh
Eligibility for these rates is limited to wand and solar prciects 100 kW or smaller, and to non-wind and non-
solar projects smaller than l0 aMW.
CONTRACT
LENGTH
ON.LINE YEAR
CONTRACT NON.LEVELIZED
1
2
3
4
5
6
7
8I
10
11
12
13
14
15
16
17
18
19
20
23.s1
23.18
24.52
27.42
29.33
31.84
33.79
35.42
36.77
38.08
39.37
40.59
41.70
42.72
43.68
44.62
45.50
46.33
47.'t3
47.89
23.03
25.1 I
29.A2
31.16
33.99
36.07
s7.75
39.12
40.46
41.78
43.03
44.17
45.20
46.1E
47.13
4E.04
48.88
49.70
50.49
51.25
27.53
32.39
u.32
37.3 1
39.35
40.96
42.23
43.51
4.AO
46.03
47.15
4E.17
49.14
50.09
50.9S)
51.84
52.66
53-45
*.22
54.97
37.64
3E.1 4
41.12
42.93
44.U
45.43
116.60
47.83
49.02
50.r0
51.09
52.03
s2.97
53.85
54.71
55.53
56_33
57.1 1
57.86
58.63
3E.6E
43.07
45.00
46.37
47.39
48.55
49.E0
51.0 1
52.11
53.1 I
54.06
55.02
55.94
56.80
57.64
fi.47
59.27
60.05
60.84
61.65
2012
2013
2014
20r5
2016
2017
201A
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2ou
2035
2036
2037
23.31
23.O3
27,53
37.64
38.68
47.83
49.33
51.19
52.4'l
55.91
59.77
62.78
44.87
66.68
69.1 3
72.44
74.97
77 15
79.98
82.95
86.00
88.98
93,59
96.43
100.78
1U.72
Note: The rates shown in this table have b€en computed using lhe U.S. Enargy lnformstion Administation (ElA)'s Annual Energy
Outlook2012releasedJun625,2012. S€e''AnnualEnergyOutlook2012,AllTaues,EnergyPricesbySec*orandSourcs,Mountain,
Referenc€ case" at http:/fu/ww.eia. gov/oiaf/aeo/tabl6brows6r/.
47.E3
48.55
49.36
50.03
51.03
52.22
53.39
54.47
55.44
56.37
57.33
fi.25
59.12
59.97
60.80
61.62
62.42
63.24
64.07
64.86
IDAHO POWERCOMPANY
AVOIDED COST RATES FOR CANAL DROP HYDRO PROJECTS
December 13,20'12
$lMWtr
Eligibility for these rates E llmlted to wlnd and solar protects 100 kW or smaller, and to non-wind and non-
solar prorects smaller than 10 aitlW.
CONTRACT
LENGTH
ON-LINE YEAR
CONTRACT NON.LEVELIZED
3 2017
1
2
3
4
5
6
7I
9
10
11
12
13
14
15
16
17
18
't9
20
23.31
23.1E
24.52
35.38
42.14
47.93
s2.28
55.73
5E.54
61.05
63.34
45.42
67.28
68.95
70.49
71.94
73.29
74.55
75.74
76.87
23.03
25.19
40.06
47.85
54.13
5E.58
62.00
64.72
67.1 3
69.35
71.37
73.1 6
74.78
76.27
77.68
79.01
80.24
81.40
82.51
83.57
27.53
49.66
57.51
63.56
67.52
70.48
72.77
74.E6
76.83
78.63
80.25
81.71
83.07
84.38
85.62
8.77
87.86
88.94
89.96
s0.94
73.60
74.36
77.58
79.U
81.2E
82.61
84.01
85.46
86.E7
8E.1 7
89.:t6
90.51
91.65
92.74
93.77
94.78
95.75
96.71
97.63
98.58
75.17
79.82
E1.99
8:!.61
84.88
86.27
E7.75
89.19
90.52
91.73
92.90
94.06
95.18
96.24
97.28
9E.28
99.27
100.22
101.19
102.16
E4.E5
E5.6s
86.90
87.82
89.07
$.49
91.90
93.21
94.40
95.56
96.73
97.E6
98.94
99.99
101.02
102.02
103.00
'r04.00
105.01
105.96
2012
2013
2014
2015
2016
201"t
2018
2019
20m
2021
2022
2023
2024
2025
2026
2021
2028
2029
2030
20s1
2032
2033
20u
2035
2036
2037
23.31
23.03
27.53
73.60
75.17
84.85
86.89
89.30
91.08
95.1 4
99.57
1 03.1 7
r 05.85
108.26
111.32
115.25
11E.40
121.22
124.69
128.32
r32.03
135.68
140.99
146.52
149.56
1il.23
Note: A "canal dmp hydro projecf is dafined as a gensretion facility rvhic} produces the majority of its generation during the inigation
season and is located on a man-made waterway that conveys wstsr primarily intend€d tor irigalion or that primarily conveys inigation
relum flows.
Note: The rates shown in this table hav€ be6n computed using the U.S. Energy lnbrmation Adminkttation (ElA)'s Annual Energy
Outlook 2012 releasEd June 25, 2012. See "furnual Energy Oullook 2012, All Tables, Enorgy Prices by Seclor and Source, Mountain,
Rebrsnce case" at hth://www.eia. gov/oiaf/aec/tablebroivser/.
l
I
ii
I
ll
ii
ii
1lI
:
l
i
!
I
i!
i
IDAHO POWERCOMPANY
AVOIDED COST RATES FOR OTHER PROJECTS
December 13.2012
$'l',lVfi
Eliglbility for these rates as llmited to wlnd and solar prciects 100 kW or smaller, and to non-wind and non-
solar projects smaller then 10 ailW.
ON.LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
I
2
J
4
5
6
7
8
9
10
1',|
12
13
14
15
16
17
18
19
20
26.49
26.38
25.98
32.43
35.89
38.99
41.37
43.34
2t4.96
46.50
47.99
49.38
50.64
51.80
52.88
53.92
54.91
55.83
56.71
57.56
26.26
27.26
u.74
38.75
42.14
4.6'.1
46.59
4E.20
49.73
51.2.
52.61
53.88
55.03
56.t,|
57.16
58.15
59.09
59.98
60.E4
61.07
28.33
39.50
43.60
46.95
49.23
5'1.02
52.44
53.84
55.24
56.57
57.78
58.88
59.93
60.95
61.92
62.E4
63.72
64.58
65.40
66.20
51.58
52.1 I
54.20
55.56
56.72
57.6E
58.77
59.96
61.13
62.21
63.20
64.16
65.12
66.04
66.91
67.76
6E.60
69.41
70.20
7't.00
52.85
55.67
57.11
58.28
59.22
60.33
61.58
62.E0
63.92
64.95
65.93
66.93
67.89
68.79
69.68
70.u
71.39
72.21
73.U
73.E9
5E.72
59.51
60.40
61.15
62.22
63.47
64.72
65.E6
66.90
67.90
68.92
69.90
70.83
71.74
72.63
73.50
74.%
75.23
76.1 1
76.95
2012
2013
2014
2015
2015
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2o31
2032
2033
203/.
2035
2036
2037
26.49
26.26
28.33
51.58
52.E5
58.72
60.38
62.40
63.78
67.45
71.48
74.66
76.92
78.91
81.54
E5.03
E7.75
90.12
93.13
96.29
99.54
102.71
107.53
112.57
1 1 5.13
I 19.2E
Note: "Other projecls" refers to projects other lhan wind, solar, hydro, and canal drop hydro projec'ts. These "Other proiects" may
include (but ar6 not limited to): cogeneration, biomass, biogas, landfill gas, or g€othermal projects.
Note: The rates shown in this table have baen computed using the U.S. Energy lnformation Administration (ElA)'s Annual Energy
Oullook 201 2 reloased June 25, 2012. See "Annual Energy Outlook 201 2, All Tables, Energy Pricss by Secior and SourcE, Mountain,
Rebrence case" at http:/lr,vi,vw. eia. gov/oiaf/aeo/tablebrowser/.
AVISTA
AVOIDED COST RATES FOR wlND PROJECTS
December 13,2012
$/Mt/ltr
Ellglblllty for these rates ls llmlted to wlnd and solar prcJects 100 kW or smaller, and to non-wlnd and non-
solar proiects smaller than t0 aMW.
CONTRACT
LENGTH
ON.LINE YEAR
CONTRACT NON.LEVELIZED
I
2
3
4
5
6
8
I
10
11
12
13
't4
15
16
17
18
19
20
21.31
21.15
21.O1
21.57
22.U
22.47
22.90
23.35
24.86
26.29
27.66
28.93
30-08
31.12
32.08
33.02
33.E9
u.71
35.48
36.22
20.98
20.45
21.67
22.26
22.77
23.25
23.75
25.49
27.10
28.63
30.03
31.28
32.40
33.43
34.43
s5.36
36.23
37.05
37.U
38.59
20.71
22.06
2..77
?3.31
23.83
24.36
26.38
28.19
29.E8
31.41
32.76
33.96
35.06
36.11
37.10
38.01
38.88
39.70
40.50
41.25
23.53
23.93
24.U
24.78
25.29
27.63
29.66
31.51
33.16
34.60
35.86
37.O2
38.1 2
39.15
40.1 0
41.00
41.86
42.69
43.48
44.26
24.36
24.79
25.27
25.82
2E.67
31.00
33.07
u.87
36.41
37.74
38.96
40.12
41.19
42.18
43.11
4.O1
4.87
45.69
46.51
47.12
25.25
25.78
2G.40
29.9E
32.69
34.9E
36.93
38.55
39.94
4't.19
12.38
43.49
44.50
45.46
46.38
47.26
48.'r1
48.96
49.81
50.61
2012
2013
2014
20t5
2016
2017
2018
2019
2020
2021
20?,.
20zi
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
20u
2035
2036
2037
21.31
20.96
20.71
23.53
24.%
25.25
26.35
27.79
42.69
46.04
49.76
52.62
54.56
56.22
5E.52
61.68
64.05
66.07
68.74
71.il
74.42
77.24
E1.08
86.34
88.51
92.27
Note: The rates shown in this tablo have been computed using the U.S. Energy lnfomation Administration (ElA)'s Annual Energy
Outlook 2012 r€leasod Juno 25, 2012. See "Annual En€rgy Ouuook 2012, Al Tables, Energy Prices by Soctor and Source, Mountain,
Reference case' at http:/
^
r,'r r.eia.govroiaf/aeo/tablebmws€r/.
ATTACHMENT B
oRDER NO. 32697
CASE NO. GNR.E.II.O3
AVISTA
AVOIDED COST RATES FOR SOLAR PROJECTS
December 18,2012
uMvlltl
Eliglbility for these rates is limited to wlnd and solar prolects 100 kW or smaller, and to non-wind and non-
solar proJects smaller than l0 aMW.
CONTRACT
LENGTH
ON.LINE YEAR
CONTRACT
YEAR
NON-LEVELIZED
1
2
3
4
5
6
7I
9
10
11
12
13
14
15
16
17
18
19
20
17.49
17.29
17.12
17.64
18.08
18.47
1 8.87
19.29
23.40
26.92
30.00
31.23
32.35
33.36
34.30
35.22
36.08
35.88
37.64
38.37
17.08
16.91
't7.70
18.25
18.72
19.17
'19.64
24.45
28.46
31.91
33.21
34.38
35.43
36.41
37.36
38.25
39.08
39.87
40.63
41.36
16.73
't8.05
18.72
19.23
19.70
20.20
25.90
30.48
34.34
35.67
36.87
37.93
38.93
39.90
40.81
41.65
42.46
43.24
43.99
44.71
19.48
19.E4
20.20
20.61
21.08
27.91
33.17
37.47
38.78
39.94
40.98
41.96
42.92
43.82
44.66
45.41
46.26
47.O1
47.74
4E.48
n.23
20.61
21.05
21.57
30.05
36.1 9
40.99
12.21
43.29
44.27
45.19
46.12
46.99
47.82
48.61
49.39
50.14
50.87
51.62
52.37
21.U
2't.52
22.10
33.ffi
40.24
45.56
46.51
47.39
44.21
49.01
49.84
50.65
51.41
52.17
52.91
53.64
54.36
55.10
55.85
56.56
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
20u
2035
2036
2037
17.49
17.06
16.73
19.48
20.23
21.04
n.05
23.40
71.88
75.67
79.81
54.14
56.11
57.79
60.1 1
63.29
65.69
67.73
70.42
73.25
76.1 6
7E.99
83.46
88.15
90.35
94.'13
Note: The rates shown in this table have been computed using th€ U.S. Energy lnformation Administralion (ElA)'s Annual Eneqy
Outlook 2012 released JunB 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case" at http:/www.eia.gov/oiaf/aso/tablebrows€r/.
AVISTA
AVOIDED COST RATES FOR HYDRO PROJECTS
December 13,2012
UMVIfi
Eligibility for these rates is limlted to wind and solar projects 100 kW or smaller, and to non-wlnd and non-
solar proiects smaller than 10 aMW.
ON.LINE YEAR
LENGTH CONTRACT NON.LS/ELIZED
1
2
3
4
5
6
7II
10
'l 1
12
13
14
15
16
17
18
19
20
?2.76
22.62
22.49
23.06
23.55
23.99
24.43
24.90
27.06
29.01
30.82
33.1 5
35.21
37.02
38.66
40.19
41.59
42.87
44.06
45.1 E
22.46
22.34
23.1 8
23.79
24.30
24.80
25.31
27.83
30.04
32.05
34.65
36.90
38.88
40.65
42.29
43.79
45 15
46.42
47.61
48.72
22.22
2s.59
24.31
24.E7
25.39
25.94
28.88
31.38
33.62
36.51
38.98
41.12
43.O2
u.77
46.36
47.81
49.1 5
50.39
51.56
52.66
25.08
25.49
25.91
26.37
26.69
30.34
33.'t8
35.64
38.85
41.54
43.U
45.E6
47.71
49.39
50.90
52.30
53.60
54.52
55.96
57.06
25.93
26.36
26.87
27.44
3'1.6E
34.96
37.71
4't.30
u.24
46.70
48.86
50.80
52.56
54.13
55.58
56.93
58.20
59.3E
60.53
61.65
26.86
27.40
28.03
33.44
37.25
40.30
44.30
47.49
50.1 I
52.36
54.38
56.1 9
57.81
59.30
60.68
61.97
63.18
64.36
65.51
66.58
20't2
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
m27
2028
2029
2030
2031
2032
2033
20u
2035
2036
2037
22.76
22.46
22.22
25.08
25.93
26.85
27.99
29.46
52.5S
56.08
59.94
76.60
7E.E9
80.91
83.57
87.09
89.83
92.23
95.28
s8.47
10'1.75
1(N.96
109.E,|
114.88
1'.17.48
121.66
Note: The rates shown in this table hav€ bsen computod using lh€ U.S. Energy lnformation Administration (ElA)'s Annual Energy
Outlook 2012 reloas€d June 25, 2012. See "Annual Enorgy Outlook 2012, All Tables, Energy Pries by Ssc-tor and Sourcs, Mountain,
Reference case" at http://www.eia.gov/oiaf/a€oltablebrowsar/.
AVISTA
AVOIDED COST RATES FOR CANAL DROP HYDRO PROJECTS
December 13, 2012
$/n v\,tr
Eligibility for these rates ls limited to wlnd and solar prolects 100 kW or smaller, and to non-wlnd and non-
solar proiects smaller than 10 aMW.
CONTRACT
LENGTH
ON.LINE YEAR
CONTRACT NON.LEVELIZED
1
2
3
4
5
5
7
8
9
10
11
12
13
14
't5
16
17
18
19
20
22.76
22.62
22.45
23.06
23.55
23.99
24.43
24.90
30.13
34.55
3E.38
38.94
39.49
40.o2
40.55
41.11
4 t.65
42.18
12.70
43.22
22.46n.u
23.1 8
23.79
24.30
24.80
25.31
3',t.u
36.48
40.n
41.27
41.77
42.27
42.78
43.32
43.86
44.39
44.91
45.43
45.95
22.22
23.59
24.31
24.87
25.39
25.94
33_19
38.97
43.77
44.14
/U,55
44.97
45.43
45.93
46.45
46.95
47.46
47.98
48.49
49.01
25.08
25.49
25.91
24.37
26.89
35.61
42.25
47.59
47.73
47.96
4E.25
48.59
45.O2
49.48
49.94
50.41
50.90
5't.40
51.91
52.44
25.93
26.38
26.87
27.44
38.29
46.02
52.00
51.75
51.71
51.79
51.98
52.29
52.66
53.05
53.47
53.93
54-40
54.88
55.40
55.96
26.86
27.40
28.03
42.06
5t.13
57.74
56.81
56.29
56.02
55.96
56.08
5€.31
56.59
56.92
57.31
57.73
58.1 7
5E.67
59.21
59.73
2012
20't3
2014
2015
201 6
2017
20't8
2019
2020
2021
2022
2023
2024
2025
202G
2027
2028
2029
2030
2031
2032
2033
203,1
2035
2036
2037
22.76
22.46
22.22
25.08
25.93
26.66
27.99
29.44
91.77
95.84
100.28
49.31
51.21
52.E2
55.07
58.17
60.50
62.46
65.07
67.E3
70.65
73.41
77.40
82.40
u.52
8E.22
Note: A "canal drop hydro projed" is defined as a gpnoration facility which prcducos lh6 majority of it8 goneration during th6 inigation
season and is located on a man-mad€ waterway that conveys w8ter primarily int€nd€d for inigation or that primarily convoys inigation
retum flor/s.
Note: Ths rates shown in this tabl€ have been computed using the U.S. Energy lnformation Administration (ElA)'s Annual En€rgy
Outlook2012releasedJune25,2012. See"AnnualEnergyOutlook20l2,AllTables,EnorgyPricssbySecdorandSourc€,Mounlain,
Reference cas€" at http://www.eia. gov/oiaf/aeo/tauebrowser/.
AVISTA
AVOIDED COST RATES FOR OTHER PROJECTS
December 13,2012
UMWh
Eligibility for these rateg is limited to wind and solar prolects 100 kW or emaller, and to non-wind and non-
solar proiects smaller than t0 aifrY.
ON.LINE YEAR
LENGTH CONTRACT NON.LEVELIZED
20't4 2015
I
2
3
4
5
6
7
8I
10
11
12
13
14
15
16
17
18
19
20
26.39
26.28
26.19
26.79
27.31
27.79
28.26
28.75
31.52
33.96
36.17
38.1 5
39.90
41.46
42.E9
44.23
4s.46
46.60
47.67
48.6E
26.16
26.08
26.95
27.59
28.'14
28.67
29.22
32.43
35.20
37.66
39.84
41.75
43.43
44.96
46.38
47.70
4E.90
50.03
5't.09
52.10
25.99
27.40
28.15
28.75
29.31
29.69
3:i.66
36.E0
39.54
41.93
43.99
45.79
47.41
€.91
50.30
51.56
52.74
53.86
54.91
55.90
28.92
29.37
29.83
30.32
30.88
35.35
38.92
41.95
4.54
46.74
48.63
50.33
51.90
53.34
54.65
55.87
57.O2
5E.1 1
59.r3
60.14
29.68
30.34
30.87
31.48
36.98
41.12
44.50
47.31
49.65
51.64
53.41
55.(x
56.52
57.E7
59.1 3
60.3't
61.43
62.4E
63.52
64.53
30.66
31.44
32.11
39.15
43.9E
47.72
50.73
53.1 7
55.21
57.01
58.66
60.r6
61.52
62.79
63.99
65.1 2
66.19
67.25
68.29
69.26
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
20?2.
2023
2024
2025
2026
2027
2024
2029
2030
2031
2032
2033
2034
2035
20fi
2037
26.39
26.16
25.99
2E.92
29.86
30.86
32.O7
33.62
64.11
67.78
71.81
74.99
77.26
79.25
81.89
E5.39
88.'t'l
90.48
93.50
96.67
99.92
103.10
107.92
112.97
1 15,54
1 19.69
Note: "Oth€r projects" refers to projects other than wind, solar, hydro, and canal drop hydro p,oj€cts. These "Other projects' may
include (but are not limitod to): cogeneration, biomass, biogas, landfill gas, or geothormal projects.
Not6: The rates shorm in this tabl6 have be€n computed using the U.S. Energy lnbmation AdminBlration (ElA)'s Annual Energy
Outlook 2012 released Juns 25, 2012. Se€ 'Annual Eneryy Outlook 2012, Al Tablas, Enetgy Pric63 by Sgctor and Source, Mountain,
Rebr€nco cas€" at http:/r\iu^/w.eia. govroiaf/a€dtablebrowser/.
PACIFICORP
AVOIDED COST RATES FOR WND PROJECTS
December 1t,2012
s/n wh
Ellglbility for these rates ls limlted to wlnd and solar proiects 100 kW or smaller, and to non-wind and non-
solar projects-smaller than l0 aMW.
CONTRACT
LENGTH
ON.LINE YEAR
CONTRACT
YEAR
NON.LEVELIZED
1
2
3
4
5
6
7II
10
11
12
13
14
15
16
17
18
19
20
18.62
18.45
19. 15
20.12
20.83
21.43
23.48
25.1 I
26.57
27.91
29.22
30.45
31.56
32.58
33.53
34.46
35.33
36.1 5
36.94
37.69
18.25
19.45
20.70
21.50
22.13
24.U
26.44
27.96
29.40
30.60
32.10
33.28
u.34
35.34
36.31
37.22
38.07
3E.89
39.67
40.43
20.74
22.O7
22.76
23.30
26.11
2E.21
29.E2
31.33
32.80
34.16
35.38
36.48
37.50
38.49
39.43
40.31
41.15
41.96
42.74
43.49
23.51
23.89
24.29
27.73
30.08
3't.78
33.37
34.90
36.31
37.56
38.68
39.72
40.74
41.70
42.59
43.45
4.28
45.08
45.86
46.64
24.31
24.73
29.35
32.06
33.E5
35.50
37.09
36.54
39.8r
40.94
41.99
43.02
43.99
44.90
45.78
46.62
47.44
44.24
49.04
49.E6
25.18
32.20
35.06
36.73
38.30
39.E5
41.27
42.51
43.60
4.62
45.64
46.60
47.50
46.3E
49.23
50.05
50.E6
51.68
52.51
53.30
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2028
2027
2028
2025
2030
2031
2032
2033
20u
2035
2036
2037
18.62
18.25
20..74
23.51
24.31
25.1 8
39.78
41.49
42.58
45.93
49.64
52.51
il.45
56.10
58.40
61.56
63.93
6s.95
58.61
71.41
74.29
77.10
8't.54
86.20
88.38
92.13
Note: The rates shown in this lable have been computed using th6 U.S. Energy lnfurmation Administralion (ElA)'s Annual Energy
Outlook2012rEleasedJune25,2012. See"Annual EnergyOutlook20l2,All Tables,EnergyPricesbySEctorBndSourcs,Mountain,
Ref€renc€ case" at htlp://www.eia. gov/oiaf/aeo/tablebrowser/.
ATTACHMENT C
ORDER NO. 32697
CASE NO. GNR.E.Il.O3
PACIFICORP
AVOIDED COST RATES FOR SOLAR PROJECTS
December 13,m12
$/[nt fi
Ellgibillty for these rates is limited to wind and solar prolects 100 kW or smaller, and to non-wind and non-
solar prolects smaller than 10 alrlw.
CONTRACT
LENGTH
ON.LINE YEAR
CONTRACT NON.LEVELIZED
1
2
3
4
5
b
7II
10
11
12
't3
14
15
16
17
18
19
20
13.E5
13.62
22.25
27.22
30.38
32.63
36.51
39.59
42.O9
44.33
46.39
48.27
49.95
51.46
52.85
il.17
55.40
56.54
57.62
58.65
13.38
26.96
32.41
35.37
37.U
41.40
44.53
47.00
49.20
51.24
53.09
54.74
56.21
57.57
58.87
60.09
61.21
62.28
63.30
64.28
41.62
43.08
43.90
44.56
48.42
51.26
53.45
55.43
57.30
59.00
60.52
61.89
6ii.16
64.38
65.54
66.61
67.64
68.62
69.57
70.48
44.66
45.18
46.71
50.47
53.68
56.01
58.09
60.02
61.78
53.34
&1.73
56.02
67.26
68.43
69.53
70.57
71.58
72.55
73.48
74.42
45.74
46.30
52.7e
56.40
58.85
60.99
62.97
64.76
66.33
67.71
69.O0
70.26
71.44
72.U
73.60
74.62
75.60
76.56
77.51
78.4f
46.90
56.64
60.53
62.81
64.81
66.70
68.41
69.90
71.23
72.47
73.69
74.U
75.93
76.97
77.99
78.97
79.93
80.90
81.87
82.75
2012
2013
2014
2015
20'16
2017
2018
20't9
2020
2021
2022
2023
2424
2025
20%
2027
202A
2029
2030
2031
2032
2033
20u
2035
2036
2037
13.85
13.36
41.62
/14.66
45.74
46.90
67.1 6
69.28
70.77
74.54
78.67
E1.95
u.32
86.42
89.16
92.77
95.60
98.08
101.21
1M.49
107.86
I 1 1.16
1 16. 't0
121.27
123.96
128.23
Note: The rates shorvn in this table hav6 ba€n computed using the U.S. Energy lnformation Adminislration (ElA)'s Annual Energy
Outlook 2012 roleased June 25, 2012. S€€ "Annual Energy Oullook 2012, All Tabl8s, En€tgy Prices by Sector and Source, Mountain,
Reference case" at htlp:/rwww. eia. gov/oiaf/aeo/tablebrorvser/.
PACIFICORP
AVOIDED COST RATES FOR HYDRO PROJECTS
December 13,2012
$/Mr /h
Eligibllity for these lates is limited to wind and solar prolects 100 kW or smaller, and to non-wlnd and non-
solar projects smaller than t0 aMW.
CONTRACT
LENGTH
ON.LINE YEAR
CONTRACT NON.LEVELIZED
RATES201
I
2
3
4
5
6
7II
10
11
12
13
14
15
16
17
18
19
20
20.44
20.28
23.70
26.06
27.83
28.82
31.09
32.95
34.49
3s.95
37.37
38.69
39.90
40.99
42.02
43.01
43.95
44.83
45.68
46.48
20.1 0
25.53
28.24
29.80
30.92
33.39
35.36
36.93
38.43
39.89
41.25
42.48
43.59
44.63
45.65
46.61
47.50
48.36
49,19
49.99
31.39
32.E0
33.57
34.1E
fi.72
36.6s
40.16
41.62
43.05
44.39
45.61
46.70
47.73
48.74
49.70
50.60
51.46
52.29
53.1 0
53.88
u.32
34.79
35.26
38.32
40.47
42.06
43.58
45.08
46.47
47.72
48.85
49.90
50.94
51.92
52.U
53.72
54.5E
55.41
56.22
57.03
35.29
35.79
39.88
42.33
44.00
45.58
47.14
48.59
49.87
51.01
52.08
.53.1 4
54.14
55.08
55.99
56.87
57.72
58.55
59.39
60.23
36.33
42.45
45.06
46.63
4E.16
49.71
51 .14
52.40
53.52
54.58
55.64
56.64
57.58
58.49
59.3E
60.25
61.09
61.95
62.83
63.65
2012
2013
2014
201s
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
20.44
N.10
31.39
34.32
35.29
36.33
49.06
50.91
52.13
5s.63
59.48
62.49
u.57
66.38
66.83
72.13
74.66
76.84
79.66
82.62
65.67
88.64
93.25
98.08
100.44
104.36
Note: The rates shown in this table have b€sn computed using the U.S. Enorgy lnformation Administration (ElA)'s Annual En€rgy
Outlook2012relsasedJune25,2012. Seo"AnnualEn€rgyOutlook2012,AllTables,EnergyPricosbySectorandSource,Mountain,
Reference case" at htlp:/ A,ww.eia.gov/oiaf/aoo/tabl€bro,rrs€r/.
PACIFICORP
AVOIDED COST RATES FOR CANAL DROP HYDRO PROJECTS
Decembsr 13,2012
MIl tr
Ellglbility for these rates ls llmlted to wlnd and solar prclects {00 kW or smaller, and to non-wlnd and non-
solar prolects smaller than l0 aMtU.
ON.LINE YEAR
LENGTH CONTRACT
YEAR
NON.LEVELIZED
1
2
3
4
5
6
8
I
10
11
12
13
14
't5
16
17
18
19
20
20.44
20.?a
34.39
42.1E
47.09
50.57
il.52
57.69
60.27
52.61
64.76
66.72
6E.49
70.09
71.56
72.97
74.2A
75.50
76.66
77.76
20.10
42.20
50.62
55.14
58.1't
61.89
64.84
67.20
69.35
7r.36
73.20
74.86
76.36
77.76
79.09
80.35
61.53
82.65
83.72
64.75
66.07
67.72
66.73
69.5E
72.U
?4.51
76.24
77.91
79.56
81.1 1
82.52
E3.E2
85_04
86.24
87.38
88.46
89.50
90.50
91.47
92.41
69.50
70.22
70.94
74.24
76.62
78.44
80.1 I
81.90
83.51
u.97
86.30
E7.56
6E.79
89.96
91.07
92.14
93.1 7
s4.1 8
95.1 5
96.1 2
70.99
71.74
76.07
78.77
60.68
82.49
u.28
85.95
87.45
EE.EO
90.09
91.35
e2.55
93.66
94.78
95.E5
96.88
97,EE
9E.89
99.90
72.55
78.92
E1.78
83.60
85.37
87.15
88.82
90.3'l
91.6s
92.33
9.20
95.41
96.55
97.66
9E.75
99.80
100.83
't01.86
102.91
103.90
2012
201 3
2014
2015
2016
2017
2015
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
?o32
2033
20u
2035
2036
20s7
20.44
20.10
66.07
59.50
70.99
72.55
85.81
88.20
E9.96
94.01
9E.43
102.00
10/..e7
107.06
110.11
114.O2
il7.16
119.96
123.41
127.02
't30.71
134.35
139.63
145.14
148.18
152.E1
Nole: A "canal drop hydro projed" is deltned as a generation facility wttkth producas the majority of ils generation during the inigation
season and is located on a man-made wataruay that conveys uater primadly intended for inigation or thal primarily conveys inigation
retum f,ows.
Note: The rates sho\fln in this table have been computed using the U.S. Energy lnfurmauon Administration (ElA)'s Annual Energy
Outlook 2012 releas€d June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Enorgy Prices by Sec{or and Sourca, Mountain,
Referonce case" at http:/ rvww.eia.gov/oief/aeo/tablebrowser/.
PACIFICORP
AVOIDED COST RATES FOR OTHER PROJECTS
December 13,2012
$nlllA'tr
Eliglbillty for these rates ls llmlted to wlnd and solar projects 100 kW or emaller, and to non-wind and non-
solar projects smaller than 10 aMlltl.
CONTRACT
LENGTH
ON-LINE YEAR
CONTRACT NON.LEVELIZED
'|
2
3
4
5
b
7
I
9
10
11
'12
13
14
15
't6
17
1E
19
20
24.97
24.85
31.46
35.46
38.06
39.96
42.19
44.04
45.58
47.06
4E.49
49.E5
5 t.08
52.21
53.27
54.30
55.27
56.19
57.O7
57.92
24.73
35.1 0
39.53
42.01
43.71
45.91
47.71
49.17
50.59
52.00
53.33
54.54
55.65
56.70
57.72
58.69
59.61
60.49
61.34
62.1 6
46.31
47.83
48.7'.|
49.44
51.22
52.67
53.86
55.09
56.36
57.58
58.71
59.75
60.74
61.72
62.66
63.54
64.40
65.24
65.06
66.84
49.48
50.06
50.66
52.70
54.27
55.49
fi.77
58.1 I
59.39
60.56
61.63
62.65
63.67
64.64
65.56
68.45
67.31
68.16
68.98
69,E1
50.70
51.32
53.95
55.71
57.00
58.35
59.76
61.1 1
62.33
63.rt4
64.49
65.55
66.55
67.50
68.43
69.33
70.21
71.06
71.92
72.80
51.99
55.78
57.66
58.90
60.27
61.72
63.1 1
64.36
55.48
66.55
67.63
68.66
69.63
70,58
71.50
72.41
73.29
74.19
75. t0
75.96
2012
2013
2014
201 5
2016
2017
201 8
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
20s4
2035
2036
2037
24.97
24.73
46.31
49.4E
50.70
51.99
59.86
61.88
63.26
66.92
70.94
74.11
76.37
78,34
80,97
84.45
87.1 6
89.52
92.53
95.68
98.92
102.08
106.89
111.92
114.48
118.61
Not6: "Other poects" refers to projec'ts othor than wind, solar, hydro, and canal drop hydro projeds. Thes€ "Other projects" may
include (but are not limitod to): cogeneration, biomass, biogas, landfill gas, or geothermal ptoioc{s.
Note: The rates shown in this table have been comput€d using the U.S. Energy lnformation Administration (ElA)'s Annual Energy
Outlook2012releasedJune25,20l2. See"Annual EngrgyOutlook2012,All Tabl6s,EnorgyPricesbySectorandSource,Mountain,
Rafer€nce case" at http:/,r^r v.eia.gov/oiaf/a€o/tabl6browser/.
Exhibit 4
Idaho Public Utilities Commission
Order No. 32176
Office ofthc Sectetary
Service Date
Febnrary 7,2011
BEFORE THE IDAHO PI]BLIC UTILITIES COMMISSION
IN TIIE MATTER O['THE JOINT
PETITION OF IDAHO POWER COMPANY,
AVISTA CORPORATION, AIYD
PACIT'ICORP DBA ROCKY MOIINTAIN
POWER TO ADDRESS AVOIDED COST
ISSTIES AI\[D TO ADJUST TIIE PUBLISIIEI)
CASE NO. GNR-8.10-04
ORDER NO. 32176
On November 5, 2010, Idaho Power Company, Avista Corporation, and PacifiCorp
dba Rocky Mountain Power filed a Joint Petition requesting that the Commission initiate an
investigation to address various avoided cost issues related to the Commission's implementation
of the Public Utility Regulatory Policies Act of 1978 (PLJRPA). PURPA was intended to
encourage the development of renewable energy technologies as alternatives to the use of fossil
fuels and the constnrction of new generating facilities by electric utilities. Section 210 of
PIIRPA generally requires electic utilities to ptrchase power produced by qualifring facilities
(QFs) at "avoided cosf' rates set by the Commission. *Avoided costs" are those costs which a
public utility would otherwise incur for electric lx)wer, whether that power was purchased from
another source or generated by the utility itself. 18 C.F.R. $ 292.101OX6).
While the investigation is rmderway, the Fetitioners also moved the Corrunission to
"lower the published avoided cost rate eligibility cap from l0 aI,IW to 100 kW [to] be effective
immediately. . . ." Petition at 7. Pursuant to PURPA regulations issued by the Federal Energy
Regulatory Commission (FERC), this Commission must publish avoided cost rates for small QFs
with a design capacity of 100 kW or less. However, the Commission has the discretion to set the
published avoided cost rate at a higher capacity amormt - commonly referred to as the
"eligibility cap." 18 C.F.R. $ 29X04(c)(l) and (2). When this case was initiated, the eligibility
cap for the published avoided cost rate was set at l0 aIvIW. Order No. 3M88. The avoided cost
rates for purchases from QFs larger than the eligibility cap (10 aIvIW) must be individually
negotiated by the QF and the public utility. In a negotiated contact, the utility's avoided cost is
the starting point for rate negotiations.
As set out in greater detail below, the Commission grants in part and denies in part
the Petitioners' Motion to reduce the eligibilrty cap. The Commission temporarily reduces the
)
)
)
)
)
)
)
IoRDERNO.32176
AVOIDED COST RATE ELIGIBILITY CAP.
eligibility cap for published avoided cost rates from t0 aMW to 100 kW for wind and solar QFs
only.
BACKGROI,JND
A. The loint Petition
The Petition states that Idaho Power cunently has more than 208 MW of wind
generation and an additional 264 MW of Commission-approved QF wind contracts (many of
which are scheduled to be online by December 31, 2010). The Petition asserts that Idaho Power
could have 1,100 MW of wind-powered generation on its system in the near term that would
exceed the minimum loads experienced on Idaho Power's system this year. "Cumulatively, this
amount of generation would exceed any other single source of generation - hydro, coal, nafural
gas, or renewables - that exists on Idaho Power's system." Id. at 4.
Rocky Mountain asserts that it is in a similar situation. The Petition declares that in
2005, Rocky Mountain had a single 20 MW wind QF contract and less than 50 MW of wind QF
requests in ldaho. "As of today, [Rocky Mountain] has 64 MW of wind QF contracts executed;
however, none have achieved commercial operation, and another 358 MW of standard wind QF
contracts are proposed." Rocky Mountain maintains that the majority of these proposed standard
wind QF contracts are configured to interconnect with the utility's Goshen substation "where
integration of the QF resource as a Network Resource for serving load could be impacted by
transmission constraints across Path C if the wind power is exported to RMP's northem Utah
load." Id. at 4.
The Petition states that many current QF projects are "large, utility-scale wind farms
that are broken up into l0 aMW increments in order to qualifr for the published [avoided cost]
rates." Id. at 5. The Petition maintains that the typical wind developer is no longer
"unsophisticated" about the QF process and small projects (0.5-1.5 MW) "are no longer the
nom." Id. The Petitioners assert that it is "commonplace" for wind developers seeking QF
contracts with Idaho Power and Rocky Mountain to aggregate o'six or more 'projects' totaling
100 to 150 MW of nameplate rating, and the multiple projects to all share interconnection
facilities to one common utility delivery point." Id.
B. Procedural History
After the filing of the Joint Petition, the Commission received several Petitions to
Intervene. The following parties requested, and were granted, intervenor status: Cedar Creek
2oRDERNO. 32176
Wind, LLC; Exergy Development Group of tdatro; Grandview Solar II; Idaho Windfarms,LLC;
Interconnect Solar Development, LLC; the Northwest and Intermountain Power Producers
Coalition (NIPPC); Renewable Energy Coalition (Coalition);' lntennountain Wind, LLC; J.R.
Simplot Company; Board of Commissioners of Adams County (Adams County); Birch Power
Company; Dynamis Energy, LLC; North Side and Twin Falls Canal Companies (Canal
Companies); and Blue Ribbon Energy, LLC.
In addition to the Petitions to Intervene, the Commission also received four answers
to the Joint Petition. Answers were filed by NIPPC, the Coalition, Simplot, and the Milk
Producers of ldaho.z The answers raise both procedural and substantive objections to the
Petitioners' request to lower the eligibility cap for the published avoided cost rate to 100 kW
nameplate capacity. The Milk Producers, Simplot and the Coalition also argue in their answers
that the lowering of the eligibility cap should not apply to non-wind QFs. Simplot asserts that
the Joint Petition does not refer to any "problems associated with biomass, cogeneration, solar,
small hydro, waste-to-energy projects or any other type of PURPA eligible QF resource. These
other types of [QF] resources have very different generating characteristics from wind and
should therefore not be caught in the overly broad sweep of the Joint Motion." Simplot Answer
at 3.
C. The Commission's Notice of Petition
On December 3,2010, the Commission issued an Order and Notice of Joint Petition.
After reviewing the Joint Petition and the answers, the Commission declined the Motion to
immediately reduce the eligibility cap. Instead, the Commission determined that it would
expeditiously consider the Petitioners' request to reduce the eligibility cap through the use of
Modified Procedure (written comments) and oral arguments. The Notice established an
intervention deadline of December 17,2010; set deadlines for initial comments and reply
comments of December 22,2010, and January 19, 2011, respectively; and scheduled an oral
argument for January 27 ,201I . Order No. 32131 .
The Commission specifically requested comment and argument regarding: (l) the
advisability of reducing the published avoided cost eligibility cap; (2) if the eligibility cap is
I The Coalition is an Oregon-based consortium of existing base load hydroelectric and biomass QFs located in the
Northwest.
'The Milk Producers did not file a Petition to Intervene and its "Answer" was a "letter in opposition," The Milk
Producers letter, therefore, will been treated as a comment.
3ORDERNO. 32176
reduced, the appropriateness of exempting non-wind QF projects from the reduced eligibility
cap; and (3) the consequences of dividing larger wind projects into l0 aIvIW projects to utilize
the published rate.3 The Commission also determined that its decision regarding the Joint
Petitioners' Motion to reduce the published avoided cost eligibilrty cap would become effective
on December 14, 2010.
PROCEDT'RAL AI\ID SUBSTAI\ITIYE MOTIONS
Before and at the January 27,2011 oral argument, several parties made various
motions. The motions are addressed in greater detail below.
A. MotiontoStrike
With its reply comments filed on January 19,2011, Rocky Morurtain Power prefiled
the direct testimony of Bruce Griswold. On January 21,2011, NIPPC filed a Motion to Strike
Griswold's testimony. NIPPC renewed its Motion to Strike at oral argument. Given NIPPC's
Motion, Rocky Mountain Power withdrew Mr. Griswold's testimony. Tr. at 11.
B. Motionfor a Technical Hearing
In their initid comments and reply comments, bottr NIPPC and Adams County
requested that the Commission conduct a technical hearing in order to allow the parties to
present witnesses. Several times during oral argument NIPPC and Adams County referenced the
need for a technical hearing, but did not renewtheir Motion.
The Commission finds that tlrc parties' positions have been adequately presented
through initial comments, reply comments and oral af,gument, and that a technical hearing is not
necessary to resolve the question of whether the eligibility cap should be rcduced. We also find
that conducting a technical hearing would unnecessarily delay the decision making process.
Consequenfly, the Commission denies the parties' requests for a tecbnical hearing. We find that
the comments and oral argument provide sufficient information to resolve the policy question of
temporarily reducing the eligibility cap.
C. Request to Take Afficial Notice
At oral argtrment, NIPPC distributed a document entitled "Request for Official
Notice" and asked the Commission to take official notice of a host of documents listed in the
"Requesf including approximately 14 PUC Orders, several FERC orders, and the "Filings,
3 The Co-mission intends to consider the other avoided cost issues identified by the Petitioners and other interested
parties in subsequent proceedings.
4oRDER NO. 32176
Testimony, Exhibits and Orders" in24 different PUC dockets. In addition, NIPPC orally asked
that the Commission take official notice of "th,ree documents related to coal costs that support
our comments": a settlement agreement of the Environmental Protection Agency; an Oregon
State Senate Natural Resources Committee report on greenhouse gas emissions; and
MidAmerican Holdings Company's comments from a coal combustion residual rulemaking. Tr.
at 7'8. The Commission acknowledged official notice of its own notices and orders. Id. at9.
Pursuant to our Procedure Rule 263.01, the Commission may take official notice at
hearing and in its Orders of:
a. ( I ) Its own orders, notices, rules, certificates and permits, and (2) those of
any other regulatory agency, state or federal;
b. (l) matters of common knowledge, (2) technical, financial, or scientific
facts established and published in accepted authorities or in the
Commission's specialized knowledge, and (3) matters judicially
noticeable;and
c. Data contained in periodic reports of regulated utilities filed with the
Commission or federal regulatory agencies.
However, "[u]nless otherwise agreed to by the parties and approved by the presiding officer,
parties tequesting the Commission to take off,cial notice of documents must submit those
documents to the Commission in the manner prescribed for documents in Rule 262." Rule
263.02 (emphasis added). Although NIPPC presented the Commission with a list of citations to
documents, it did not actually provide copies of the requested documents to the Commission or
to the parties. NIPPC also advised the Commission that all of its requested documents met the
parameters of Rule 263.01. Tr. at 10. However, Rule 263.01 pertains to matters that the
Commission may officially note. Parties requesting official notice must comply with Rule
263.02 and provide copies of the documents for which it seeks official notice. The purpose of
providing copies to parties is to afford the parties an opportunity to review, and if necessary,
contest the offered material. Id. Moreover, the majority of the "f,rlings, testimonies and
exhibits" from the 24 PUC dockets are not documents or information subject to official notice
per Rule 263. Notwithstanding the Commission's acknowledgement of taking official notice of
its own notices and orders, the Commission denies NIPPC's request to take official notice of the
remainder of its listed documents, including the three additional documents regarding coal costs.
5oRDERNO.32176
D. Motion to Dismiss
During oral argument, Blue Ribbon Energy asked the Commission to dismiss the
utilities' Joint Petition. Blue Ribbon articulated three bases upon which the Commission should
dismiss the Petition: (l) the utilities' failed to flrle the Petition in good faith; (2) the utilities have
not presented a basis upon which relief can be granted; and (3) the utilities' Joint Petition
constitutes an effort by the utilities to terminate their obligations to enter into PURPA contracts.
Tr. at 74. The utilities responded that their Joint Petition was made in good faith and based on
verifiable evidence that large QF projects are receiving an avoided cost rate in excess of the
utility's true avoided cost. Id. at 82. Rocky Mountain Power specifically pointed out that the
costs of QF contracts are borne by ratepayers and that the utilities were acting in the ratepayers'
interest. Id. at83.
The Commission denied Blue Ribbon's request for dismissal of the Petition. The
Commission stated that the utilities' Petition was based on the Commission's authority to set the
eligibility cap for QF projects . Id. at 87. We reject Blue Ribbon's argument that a reduction in
the eligibility cap relieves utilities of their obligation to purchase QF power. Tr. at 76-77,81.
Finally, Blue Ribbon's argument regarding the 80 MW maximum size of a QF is not relevant to
the cap size of the standard published rate. Cf, l8 C.F.R. $$ 292.204(a) and 29230a@).
COMMENTS AND ORAL ARGUMENT
Comments and arguments were presented by developers of QF facilities, Staff, each
of the Petitioners, and other interested persons. Idaho Power, Avista, and Rocky Mountain
Power all propose lowering the threshold for PURPA published avoided cost rates from l0 aI\rIW
to 100 kW for all QF resources. The utilities argue that the number of QFs currently requesting
contracts under the published l0 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. Specifically, the utilities cite large wind QFs as the source of their
current predicament.
Idaho Power stated that '"the current application of the [published rate] methodology,
including the l0 average megawatt cap, has several problems associated with it that have
potentially huge ramifications or implications for our customers. ." Tr. at 13. Avista
maintained that reducing the eligibility cap to 100 kW "is the most practical, simplest, most
easily implemented and enforced solution to the issues" that the utilities are facing. Id. at3l.
6ORDER NO. 32 176
When addressing the disaggregation issue raised by the Petition, Rocky Morurtain
Power argued that a disaggregated wind project "looks a lot like a large wind QF project. Except
for additional [elecfric] meters, the differences are almost purely legal." Id. at 33. Rocky
Mountain Power explained that "the large QFs have an option andthis option is valuable and that
value comes at the expense of ratepayers." Id. at 36. The Petitioners also maintain that it is
important that any change in the eligibility cap be applied equatly for all three utilities in order to
prevent a utility not granted a reduction fiom disproportionately attracting a greater number of
QF project proposals.
Without exception, the Intervenors oppose reduction of the published avoided cost
rate eligibilrty cap. The Intervenors generally contend that lowering the threshold is an
imposition on legally permissible QF projects that cannot absorb the costs of negotiating with a
utility and the increased difficulty of obtaining financing created by the uncertainty of the
payments they will receive under PURPA contracts negotiated through use of the Integrated
Resource Plan (IRP) Methodology.
Dynamis, Adams County, Birch Power,Interconnect Solar, the Canal Companies, the
Coalition and Commission Staff urge the Commission to nanowly apply any reduction in
eligibility cap to the resource identified by the utilities as causing the immediate problem: wind
QFs. lnterconnect Solar distingurshes its resource from wind by argurng that "[s]olar power is
not 'intermitteut' and instead has a firm nattue to its production that directly matches a utility's
need for exrergy and capacity duing heavy load hours." Interconnect Solar Comments at 2.
Even lntermountain Win4 a selGprofessed family operation, maintains that "[a]n overly broad
eligibility reduction would harm projects that are legitimately entitled access to PURPA
published avoided cost rates and would adversely affect the development of renewable energy in
Idaho." Intermountain Wind Comments at 5. Interurountain Wind also argues that, *[w]hether
PLTRPA published rates should be available to commercial scale projects may be fairly
debatable. Whether those rates should be available to parties such as lntermountain is not.'o .Id.
at 4.
NIPPC maintains that a reduction in the published avoided cost rate eligibility cap is
not warranted for any resource because the utilities have not demonstated that the published
avoided cost rate is too high. NIPPC furtlrer argues that, although the utilities have identified
large wind projects as the immediate source of the problem, the utilities do not claim that they
7ORDER NO. 32176
would be unable to integrate the amount of wind currently in the queue. NIPPC and Adams
County claim that disaggregation "is irrelevant and a non-issue, because ifthe avoided cost rates
ate accurately set, the rates for an IRP methodology avoided cost project would be essentially the
same {N the rates for a non-lRP methodology avoided cost project." Tr. a|49. They go on to
assert that "[n]o developer is going to go in for the IRP methodology knowing that it sets the
avoided cost rate under actual avoided cost rates if they're able to take advantage of the tue
avoided cost rate. . . ." Id. at 51.
NIPPC and lntermountain Wind also oppose the Comrnission's decision to implement
a December 14, 2010, effective date. Intermountain Wind argues that the Commission'odoes not
have authority to look back in time and rearrange legal rights that existed on a certain day in the
past." Intermountain Wind Reply at 4. NIPPC contends that a December 14 effective date
"violates the filed rate doctrine and the prohibition against retroactive ratemaking." NIPPC
Comments at 8.
Commission Staff asserts that, although large wind projects are not inherently
undesirable, the disaggregation of multiple, affiliated QFs seeking to qualift for published rate
contracts raises concems. Staff contends that "considering each 10 aMW QF individually for
purposes of eligibility for [published] avoided cost rates creates an artificial mismatch between
the method used to establish a project's avoided cost rates and the collective size of the project."
Staff Comments at 4. Staff emphasizes that, "[w]hen large QFs are added to a utility's
renewable portfolio, but the QFs disaggregate in order to qualifu for the published rate, the
avoided cost paid to the QF becomes inaccurate, because under the published rate methodology,
there's no mechanism to reflect the utility's reduced avoided cost." Tr. at 88. Staff furttrer
maintains that obligating utilities to accept generation that they do not need unnecessarily
increases the rates paid by the utilities' customers. Staff Comments at 5. Staff insists that the
problem described by the utilities is real and requires immediate attention,
DISCUSSION AND FINDINGS
The Idaho Public Utilities Commission has jurisdiction over this matter pursuant to
the authority and power granted it under Title 6l of the Idaho Code and the Public Utility
Regulatory Policies Act of 1978 (PURPA). The Commission has authority under PURPA and its
implementing regulations of FERC to set avoided costs, to establish standard published avoided
8ORDERNO.32176
cost rates, to order electric utilities to enter into fixed-term obligations for the purchase of energy
from QFs, and to implement FERC regulations.
Based upon the record, the Commission frnds that a convincing case has been made
to temporarily reduce the eligibility cap for published avoided cost rates from l0 aMW to 100
kW for wind and solar only while the Commission funher investigates the implications of
disaggregated QF projects.a We maintain the eligibility cap at l0 aMW for QF projects other
than wind and solar (including but not limited to biomass, small hydro, cogeneration,
geothermal, and waste-to-energy). The Petitioners have not convinced us that lowering the
eligibility cap for these other QF technologies is necessary or in the public interest.
Wind and solar resources present unique characteristics that differentiate them from
other PURPA QFs. Wind and solar generation, integration, capacity and ability to disaggregate
provide a basis for distinguishing the eligibility cap for wind and solar from other resources.
Furthermore, these intermittent resources must be "firmed" by ancillary services to asstre system
reliability. Temporarily reducing the eligibility cap for wind and solar while we continue our
investigation, will still allow wind and solar projects larger than 100 kW to negotiate avoided
cost rates using the IRP Methodology.
Lowering the cap to 100 kW does not change the published avoided cost rates
established in Order No. 31025 (March 16, 2010). The published rate for wind and solar QFs
will still be available for projects 100 kW or smaller and as we have stated previously, will be
the starting point for negotiating an avoided cost rate for larger wind and solar QF projects.
At a minimum, FERC regulations require that standard or published rates be set for
purchases from QFs with a design capacity of 100 kW or less. These regulations also grant the
Commission the discretion to set the published rate eligibility cap at a higher level. l8 C.F.R. $
292.304(c). Whether it is a published rate or a rate for a larger QF, FERC requires that the
avoided cost rates for all QF purchases be just and reasonable to utility customers and in the
public interest; and not discriminate against qualifuing cogeneration and small power production
facilities. l8 C.F.R. $ 292.30a(aXl). In establishing a published rate, the Commission may
differentiate among QFs using various technologies on the basis of supply characteristics of the
different technologies; the availability of capacity and energy during daily and seasonal peak;
n Other avoided cost issues identified in the Joint Petition, including utilization and/or modification of the IRP
Methodology, will be considered after a determination regarding disaggregation.
9ORDER NO. 32176
dispatchability; reliability; and other factors. l8 C.F.R. $ 292.30a(c)(3); In re Califurnia PUC,
Order Granting Clarification and Dismissing Rehearing,l33 FERC u 61,059 (October 21,2010)
at fl 23. Contrary 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.
This Commission established a clear and reasoned distinction between small and
large QFs in 1995 when it adopted the use of the IRP methodology for larger QFs. Order Nos.
25882,25883, 25884. The Commission explained that requiring larger QF projects 'to prove
their viability by market standards ensures that utilities will not be required to acquire resources
priced higher than would result from a least cost planning [RFP] process. Ratepayers will not be
disadvantaged and QFs will be treated fairly and consistently with the requirements and goals of
PURPA." Id. at 6. The purpose, then and now, 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 - not encourage or discourage QF resotrces.
We note that parties have challenged the accuracy of the tRP Methodology. We
believe that the tRP Methodology appropriately assesses when the QF is capable of delivering its
resources against when the utility is most in need of such resources. The resultant pricing is
reflective of the value of QF energy to the utility. Unfortunately, the IRP Methodology is being
under-utilized because our Orders do not currently prevent QF developers from breaking up what
is truly a single, large project into several small QF projects in orderto avail themselves of wtrat
may sometimes be more favorable, published avoided cost rates.
Based on the foregoing, the Commission temporarily reduces the eligibility cap for
published avoided cost rates from l0 aMW to 100 kW for wind and solar resources only,
effective December 14, 2010. Arguments that the Commission is without authority to implement
its eligibility cap reduction on December 14 are unpersuasive for several reasons. First, the filed
rate doctrine and rule against retroactive ratemaking do not extend "to cases in which [parties]
are on adequate notice that resolution of some specific issue may cause a later adjustment to the
rate being collected at the time of service." Natural Gas Clearinghouse v. FERC,965 F.2d
1066, 1075 (D.C.Cir.1992). "The goals of equity and predictability are not undermined when the
Commission warns all parties involved that a change in rates is only tentative and might be
disallowed." OXY USA, lnc. v. FERC,64 F.3d 679, 699 (D.C.Cir.l995). The Commission
provided notice on December 3, 2010, that its decision regarding the published avoided cost rate
oRDER NO. 32176 l0
eligibility cap would become effective December 14,2010. One need look no furttrer than the
abundance of firm energy sales agreements filed with the Commission within that time frame to
realize that the parties took the Commission's notice of its effective date seriously.
Consequently, adequate notice was provided to all parties that the eligibility cap was subject to
change.
Second, as previously mentioned, the published avoided cost rates established in
Order No. 31025 have not changed. What has temporarily changed is the availability of
published rates to wind and solar QFs. Wind and solar projects larger than 100 kW are still
entitled to PURPA contracts and avoided cost rates that reflect the unique characteristics of their
resource.
This Commission is supponive of all small power producers contemplated by
PURPA, including wind and solar, and it is not the Commission's intent to push small wind and
solar QF projects out of the market. With this goal in mind, the Commission is initiating
additional proceedings to investigate and deterrrine in a finite timefiame requirements by which
wind and solar QFs can obtain a published avoided cost rate without allowing large QFs to
obtain a rate that is not an accurate reflection of a utility's avoided cost for such projects. It is
just and reasonable and in compliance with the intent and mandate of PURPA that large QF
projects avail themselves of economies of scale. Such an approach will assist the Commission in
fulfilling its obligations under PURPA.
The Commission directs the parties to meet informally wittrin l0 days of the issuance
of this Order to establish an expedited schedule, including dates for discovery, prefiled direct
testimony and rebuttal that will accommodate a technical hearing during the week of May 9,
2011. Specifically, the Commission solicits information and investigation of a published
avoided cost rate eligibility cap structure thal (1) allows small wind and solar QFs to avail
themselves of published rates for projects producing l0 alvlW or less; and (2) prevents large QFs
from disaggregating in order to obtain a published avoided cost rate that exceeds a utility's
avoided cost.
ORDER
IT IS HEREBY ORDERED that the Petitioners' Motion to reduce the eligibility cap
for published avoided cost rates is granted in part and denied in part. The Commission
temporarily reduces the eligibility cap for published avoided cost rates from 10 aI{W to 100 kW
ORDER NO. 32176 l1
for wind and solar QFs only, effective December 14, 2010. The Petitioners' Motion to reduce
the published eligibility cap for other QFs is denied.
IT IS FLJRTHER ORDERED tlnt NIPPC's request for the Commission to take
official notice of our Notices and Orders is granted and the request regarding the other
documents is denied as set out above.
IT IS FURTIIER ORDERED that the parties meet informally within l0 days of the
issuance of this Order to establish a schedule consistent with a technical hearing to occur during
the week of May 9,2011. The Commission directs the parties to address disaggregation, as more
fully described above.
THIS IS A FINAL ORDER. tuiy person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7)
days after any pemon has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See ldaho Code $ 6l-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 7n
day ofFebnrary 2011.
Mc&,a
MARSHA H. SMITH, COMMISSIONER
ATTEST:
MACK A.
fu*n rL*a!@C6mmission Secretary
O:GNR-E- I 0-04_ks_Final
oRDER NO. 32176 t2
Exhibit 5
Idaho Power Company
Petition for Declaratory Ruling Before
The Idaho Public Utilities Commission
Case No. IPC-E-17-01
tEffio@ili rl I !VrD
iilil i:f !l ?l Pl.I h: Sti
'r; i l'^. i,t.-'i.;..,- i,ri!,i$Sirli'i
An IDACORP Companv
DONOVAN E. WALKER
Lead Gounsel
dwalker@i da hooower.com
February 27,2017
VIA HAND DELIVERY
Diane Hanian, Secretary
ldaho Public Utilities Commission
472 West Washington Street
Boise, ldaho 83702
Case No. IPC-E-17-01
Franklin Energy Storage One through Four, LLC, and Black Mesa Energy,
LLC - ldaho Power Company's Petition for Declaratory Order
Dear Ms. Hanian
Enclosed for filing in the above matter please find an original and seven (7)
copies of ldaho Power Company's Petition for Declaratory Order.
Very yours,
E. Walker
DEW:csb
Enclosures
1221 W. ldaho St. (83702)
PO- Box 70
Boise, lO 81707
Re
DONOVAN E. WALKER (lSB No. 5921)
ldaho Power Company
1221 West ldaho Street (83702')
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
dwalker@ ida hopowefeqm
Attorney for ldaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
- . -i:,\/:r'l
'! --- r i -1 {-':..t 1.. r: :,. ; . ':. i i ll 'l";v
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION FOR
DECLARATORY ORDER REGARD! NG
PROPER CONTRACT TERMS,
CONDITIONS, AND AVOIDED COST
PRICING FOR BATTERY STORAGE
FACILITIES.
CASE NO. IPC-E-17-01
PETITION FOR DECLARATORY
ORDER
)
)
)
)
)
)
)
)
ldaho Power Company ("ldaho Power" or "Comp?f,y"), pursuant to RP 101,
hereby petitions the Idaho Public Utilities Commission ("IPUC" or "Commission") to
issue an order determining the proper contract terms, conditions, and avoided cost
pricing to be included in the Public Utility Regulatory Policies Act of 1978 ('PURPA')
contracts requested by several battery storage facilities.l
' On January 26, 2017, ldaho Power received four separate Schedule 73 applications from
proposed baftery storage projects requesting published avoided cost rate indicative pricing and 2O-year
contracts from: Franklin Energy Storage One, LLC (32 MW); Franklin Energy Storage Two, LLC (32
MW); Franklin Energy Storage Three, LLC (32 MW); and Franklin Energy Storage Four, LLC (32 MW).
See Aftachments 1-4. All proposed Franklin Energy Storage projects were submitted by the same
developer. On February 13, 2017, ldaho Power received another Schedule 73 application from a
separate proposed battery storage project from another developer: Black Mesa Energy, LLC (20 MW).
See Attachment 5. These five proposed projects are hereafter referred to collectively as "Proposed
Baftery Storage Facilities."
PETITION FOR DECLARATORY ORDER - 1
I
I
I
ldaho Power, a vertically integrated public utility electric service provider
regulated in the state of ldaho by the IPUC, is the petitioner in this mafter. PURPA
requires ldaho Power, as a public utility, to purchase generation from cogeneration and
small power production facilities that are certified as PURPA qualiffing facilities ("QFs"
or "QF") at avoided cost rates determined by the IPUC. The Proposed Battery Storage
Facilities claim they are entitled to published avoided cost rates with a 2O-year contract
term. Attachments 1-5, 6. ldaho Power asserts that the Proposed Battery Storage
Facilities be subject to the same 100 kilowatt ("kW") published rate eligibility cap
applicable to wind and solar generation.
ldaho Power seeks a declaratory ruling from the Commission that proposed
battery storage facilities over 100 kW are eligible for negotiated avoided cost rates
determined by the incremental cost lntegrated Resource Plan ("lRP") methodology and
a maximum contract term of two years-and that battery storage facilities up to a
maximum nameplate capacity of 100 kW are entitled to published avoided cost rates
and a 2O-year maximum contract term.
ln support of this Petition, ldaho Power states as follows:
I. BACKGROUND AND FACTS
After separate Iengthy and contested proceedings, the Commission determined
as part of its implementation of PURPA for the state of ldaho: (1) the published, or
standard, avoided cost rate eligibility cap for wind and solar QFs is set at 100 kW,
consistent with 18 C.F.R. 292.304(c), Order No. 32262; and (2) the maximum contract
term for proposed QF projects that are larger than the published rate eligibility cap is
two years. Order No. 33357. The published rate eligibility cap for all other generation
PETITION FOR DECLARATORY ORDER.2
types remains at the previously established 10 average megawatts ("aMW") on a
monthly basis and all proposed projects that are eligible for published rates have the
previously established maximum contract term of 20 years available to them. The
Commission also previously directed that published avoided cost rates be distinguished
by resource type. Order No. 32697, p. 15; Order No. 32802, pp. 5-8. Negotiated
avoided cost rates, for projects that exceed the published rate eligibility cap, are based
upon the incremental cost IRP methodology, which compares the specific generation
profile of the proposed project to the displaceable resources used to serve load in the
Company's resource stack to arrive at an avoided cost.
Over an approximate two week period in late January/early February 2O17,ldaho
Power received five applications seeking PURPA energy sales agreements for a total of
148 megawatts ("MW") of proposed battery storage QFs. See Attachments 1-5. ldaho
Power has attached hereto, and incorporates herein by this reference, as Aftachments 1
through 5, the Proposed Battery Storage Facilities' five separate Schedule 73
applications requesting published avoided cost pricing and Z0-year contracts, the
Federa! Energy Regulatory Commission ("FERC") Form 556 QF self-certifications, and
the projects' generation/output profiles submitted by each project to ldaho Power. Also
attached hereto, and incorporated herein by this reference are: Attachment 6, ldaho
Power's February 9 and 27,2017, responses to the Proposed Battery Storage Facilities;
Attachment 7, February 10, 2017, response from Franklin Energy Storage One through
Four; as well as Attachment 8, maps depicting the location and layout of the Proposed
Battery Storage Facilities.
PETITION FOR DECLARATORY ORDER - 3
Each Proposed Battery Storage Facility submitted a FERC Form 556 self-
certification of QF status to ldaho Power, purporting to be a QF independent of its
generation source. Aftachments 1-5. As part of the required Schedule 73 applications,
each Proposed Battery Facility also submitted a generation output profile, on an hourly
basis, for all 8,760 hours in a year. ld. Each generation profile is nearly identical, and
generally matches the shape, timing, and output of a solar generation profile. ld. The
four proposed Franklin Energy Storage projects are Iocated at the same site and were
submifted from a single developer-the same developer that had previously submitted
Schedule 73 applications and requests for energy sales agreements for the four
proposed 20 MW Jackpot Solar facilities which were the subject of the Commission's
final Order No.33667 in Case No. IPC-E-16-21. Attachments 14,8. The fifth
proposed battery storage facility, Black Mesa LLC, was submitted by a different
developer at a different location, but with nearly identical information provided in both
the Schedule 73 application and Form 556 self-certification. Attachments 5, 8. Each
Proposed Battery Storage Facility in its individual Schedule 73 application requests
published avoided cost rates, Rate Option 4, Non-Levelized Non-Fueled Rates, and a
20-year contract. Attachments 1 -5.
ldaho Power responded to the four proposed Franklin Energy Storage facilities
within Schedule 73's required 1O-business day response time with a letter dated
February 9,2017. Attachment 6. ldaho Power notified legal counsel for the four
proposed Franklin Energy Storage facilities that the applications were not complete,
identified several deficiencies in the Schedule 73 applications, and stated that "it does
not appear that your proposed projects qualify for Rate Option 4 - Non-Levelized Non-
PETITION FOR DECLARATORY ORDER - 4
Fueled Rates and a twenty (20) year contract term." /d. The proposed Franklin Energy
Storage facilities responded by letter dated February 10, 2017, purporting to address
deficiencies in its applications and demanding that ldaho Power proffer 20-year,
published avoided cost rates for its proposed battery storage projects. Attachment 7,
attached hereto and incorporated herein by this reference. By letters dated February
27, 2017, ldaho Power responded to all five Proposed Battery Storage Facilities that it
does not agree that they are eligible for published rates and 20-year contracts, and
notified them of this case filing. Attachment 6.
il. DtscusstoN
A. The Commission has Jurisdiction to lssue a Declaratorv Order in the Case.
The Commission has jurisdiction to issue declaratory orders under Title 61 of
ldaho Code and the ldaho Uniform Declaratory Judgments Act of 1933. See Order No.
33667, pp. 5-6, Case No. IPC-E-16-21.
A declaratory judgment "must clariff and settle the legal
relations at issue, and afford leave from uncertainty and
controversy which gave rise to the proceeding." Hanis v.
Cassia County, 106 ldaho 513, 517, 681 P.2d 988 (1984)
(citing Sweeney v. Am. Nat'l 8k.,62 ldaho 544, 115 P.zd
109 (1941)). For a declaratory judgment to be rendered,
there must be "an actual or justiciable controversy" that is
"real and substantial," and "definite and concrete, touching
the legal relations of parties having adverse legal interests."
ld. at 516 (quoting Aetna Life lns. Co. v. Haworth,300 U.S.
277,240-41 (1937)).
ld. The Commission has further recognized its role when considering a petition for
declaratory ruling as follows:
Declaratory rulings are appropriate regarding the
applicability of any statutory provision or of any rule or order
of this Commission. See IDAPA 31.01.01.101; Uniform
Declaratory Judgment Act, ldaha Code 10-1201 ef seg. A
declaratory ruling contemplates the resolution of prospective
PETITION FOR DECLARATORY ORDER. S
problems. The rights sought to be protected by a
declaratory judgment may invoke either remedial or
preventive relief; it may relate to a right that is only yet in
dispute or a status undisturbed but threatened or
endangered; but in either event it must involve actual and
existing facts. ldaho Supreme Court in Hanis v. Cassra
County,106 ldaho 513, 516-517,618 P.2d 988 (1984).
Order No. 29480, p. 16. Additionally, the Commission may clarify any order on its own
motion. RP 325.
ldaho Power does not agree with the Proposed Battery Storage Facilities' claims
as to their QF status independent of a cognizable associated generation resource, and
this Petition is without prejudice to ldaho Power's position before FERC on the validity
of the self-certifications. However, QF status is within the exclusive jurisdiction and
properly before FERC, not this Commission, for determination. ldaho Power does not
seek from this Commission a determination as to QF status with regard to the Proposed
Battery Storage Facilities. ldaho Power seeks a determination from the Commission as
to the proper avoided cost rates, as well as the proper contractualterms and conditions
applicable to the Proposed Battery Storage Facilities Schedule 73 requests for PURPA
pricing and contracts. Although not conceding any argument and advocacy to the
contrary at FERC, for purposes of the determination as to the rate eligibility and contract
term length for the Proposed Battery Storage Facilities as requested in this Petition,
ldaho Power does not dispute that the facilities are self-certified QFs without respect to
the validity of those self-certifications. The legal controversy or question for the
Commission is, under the facts presented by the requests of the Proposed Battery
Storage Facilities, whether they are entitled to published avoided cost rates and 2O-year
contract terms-or are instead entitled to the negotiated rate and contracting
PETITION FOR DECLARATORY ORDER - 6
I
procedures and two-year contract terms. This is a deterrnination that is within the
exclusive jurisdiction of this Commission. The status of and applicability of the
Commission's implementation of PURPA with regard to proposed battery storage
facilities was not considered and/or addressed in the Cornmission's determinations as
to published rate eligibility cap, differentiation of applicable avoided cost rates to
different generation technologies, or its determinations regarding other contractual
terms and conditions, such as contract term.
ldaho Power has now received, in a little over two weeks' time, multiple requests
for a total of 148 MW from proposed battery storage facilities and disagrees with the
Proposed Battery Storage Facilities as to the proper application of the Commission's
implementation of PURPA with regard to published avoided cost rate eligibility and the
maximum contract term applicable to such projects. There is a real and substantial
controversy as to the proper application of this Commission's implementation of PURPA
with regard to specific requests and actual and existing facts, applicable to the
Proposed Battery Storage Facilities. lt is appropriate for the Commission to issue a
declaratory order in this case.
B. Batterv Storaoe Facilities should be Subiect to the {00 kW Published Rate
EliEibilitv Cap.
With regard to the five applications seeking PURPA energy sales agreements,
the generation source that energizes all of the Proposed Battery Storage Facilities is
solar generation. Attachments 1-5. The output profile submitted for each of the
Proposed Battery Storage Facilities matches the shape and timing of the generation
profile of a solar generator. ld. None of the Proposed Battery Storage Facilities
propose to operate in a manner that would realize the potential benefits of energy
PETITION FOR DECLARATORY ORDER - 7
storage facilities-they simply propose to operate with substantially the same
generation profile as a solar generator. The potential benefits and possible promise of
economically viable, utility-scale energy storage facilities is in the unique operational
characteristics to, for example: provide ancillary grid services such as reserve capacity,
surge capacity, load-balancing, or voltage support; firming of variable generation; or
time-shifting generation to match load. However, to realize these benefits, it would be
necessary for operational control and dispatchability of the facility to be with the utility
charged with serving load. When operated as proposed by the Proposed Battery
Storage Facilities, it appears to be structured in a way that passes through as many kW
hours as possible in order to maximize revenue under the must-purchase provision of
PURPA. Furthermore, any of the potential benefits of utility-scale battery storage
facilities cannot be recognized when the Proposed Battery Storage Facilities are
configured in such a manner as to come under published rates, priced at the avoided
cost of a natural gas combustion turbine, and standard contract terms and conditions. lt
would only be through the project-specific avoided cost determinations of the
incremental cost IRP methodology and the negotiated rate and contract process
required of proposed projects that exceed the published rate eligibility cap where it may
be possible to determine the value of the Proposed Battery Storage Facilities.
Furthermore, from ldaho Power's perspective, the Proposed Battery Storage
Facilities' Schedule 73 applications appear to be vehicles used to circumvent the
Commission's rules and requirements in its implementation of PURPA for the state of
ldaho. The four proposed Franklin Energy Storage facilities are all located adjacent to,
and in the same vicinity as the previously proposed four, 20 MW each, Jackpot Solar
PETITION FOR DECLARATORY ORDER - 8
facilities. See Case No. IPC-E-16-21. The four proposed Jackpot Solar facilities have
the same developer, Robert Paul, and the same legal counsel, Peter Richardson, as the
four proposed Franklin Energy Storage facilities. The proposed Black Mesa storage
facility submitted almost identical documents as the four proposed Franklin Energy
Storage facilities, and the developers of all five proposed projects had some level of
involvement with the Grand View Solar project, an 80 MW PURPA solar QF under
contract with ldaho Power. As was made clear by the Commission in the previously
referred to Jackpot Solar case, Case No. IPC-E-16-21, solar QFs are subject to a 100
kW published rate eligibility cap, and for any projects that exceed the published rate
eligibility cap, the maximum contract term is limited to two years. Pricing for such
facilities is determined at the start of each two-year contract term. Order No. 33667.
The non-generator Proposed Battery Storage Facilities have proposed to classiff
themselves without regard to the solar generation that will energize their batteries, and
further proposed to disaggregate into 10 aMW increments, which would avoid
application of the 100 kW published rate cap and associated two-year contract term
limitation for projects over the cap. First, the Commission should recognize that the
Proposed Battery Storage Facilities are acting as nothing more than a pass through of
the solar generation, in what appears to be a blatant attempt to manipulate the 100 kW
published rate eligibility cap and two-year contract limitation for solar generators.
Secondly, the four proposed Franklin Energy Storage facilities are all immediately
adjacent to each other within the same one-mile section of land. Attachment 8. The
projects purport to be in compliance with disaggregation rules by claiming separate
ownership, but this appears to be an attempt to get 128 MW of capacity split up into four
PETITION FOR DECLARATORY ORDER.9
separate 10 aMW increments, with the goal of qualifying for published rates and 20-year
contracts.
This was the practice that the Commission determined to prevent when it first
implemented a temporary reduction to a 100 kW published rate eligibility cap for wind
and solar projects, Order No. 32176, and then made that 100 kW published rate cap
permanent for wind and solar QFs. Order No. 32262. See Case Nos. GNR-E-10-04,
GNR-E-1 1-01.
Based upon the record, the Commission finds that a
convincing case has been made to temporarily reduce the
eligibility cap for published avoided cost rates from 10 aMW
to 100 kW for wind and solar onlv while the Commission
further investigates the implications of disaggregated QF
projects. . . .
Wind and solar resources present unique characteristics that
differentiate them from other PURPA QFs. Wind and solar
generation, integration, capacity and ability to disaggregate
provide a basis for distinguishing the eligibility cap for wind
and solar from other resources. . . .
At a minimum, FERC regulations require that standard or
published rates be set for purchases from QFs with a design
capacity of 100 kW or less. These regulations also grant the
Commission the discretion to set the published rate eligibility
cap at a higher level. 18 C.F.R. $ 292.30a(c). Whether it is
a published rate or a rate for a larger QF, FERC requires
that the avoided cost rates for all QF purchases be just and
reasonable to utility customers and in the public interest; and
not discriminate against qualifying cogeneration and small
power production facilities. 18 C.F.R. S 292.304(aX1). ln
establishing a published rate, the Cornmission may
differentiate among QFs using various technologies on the
basis of supply characteristics of the different technologies;
the availability of capacity and energy during daily and
seasonal peaks; dispatchability; reliability; and other factors.
18 c.F.R. S 2e2.304 (cX3) .
This Commission established a clear and reasoned
distinction between small and large QFs in 1995 when it
PETITION FOR DECLARATORY ORDER. 1O
adopted the use of the IRP methodology for larger QFs.
Order Nos. 25882, 25883, 25884. The Commission
explained that requiring larger QF projects "to prove their
viability by market standards ensures that utilities will not be
required to acquire resources priced higher than would result
from a least cost planning [RFP] process. Ratepayers wil!
not be disadvantaged and QFs will be treated fairly and
consistently with the requirements and goals of PURPA." ld.
at 6. The purpose, then and now, 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 - not encourage or discourage
QF resources.
Order No. 32176, pp. 9-10 (citations omitted, emphasis in original). ln extending the
100 kW published rate eligibility cap from temporary to permanent for wind and solar
QFs, the Commission stated:
Based upon the record in this case and after careful
consideration of the positions presented, the Commission
finds it appropriate to maintain the 100 kW eligibility cap for
published avoided costs rate for wind and solar QFs. We
find that any attempt to implement criteria in an effort to
prevent disaggregation would be met by attempts to
circumvent such criteria. The economic incentive for the
projects is obvious. QF developers are working within the
current structure provided by this Commission. However, we
emphasize that PURPA and our published rate structure
were never intended to promote large scale wind and solar
development to the detriment of utility customers. Avoided
cost rates are to be just and reasonable to the utility's
ratepayers. 18 C.F.R. S 292.30a(a)(1). PURPA entitles QFs
to a rate equivalent to the utility's avoided cost, a rate that
holds utility customers harmless - not a rate at which a
project may be viable. 18 C.F.R. S 292.304(a)(2). lf we
allow the current trend to continue, customers rnay be forced
to pay for resources at an inflated rate and, potentially,
before the energy is actually needed by the utility to serve its
customers. This is clearly not in the public interest.
PURPA and the implementing regulations require only that
the published/standard avoided cost rates be established
and made available to QFs with a design capacity of 100 kW
or less. 18 C.F.R. S 292.304(c). . . . Wind and solar projects
PETITION FOR DECLARATORY ORDER.11
larger than 100 kW continue to be entitled to PURPA
contracts at avoided cost rates calculated using the IRP
Methodology. Furthermore, a 100 kW threshold for wind and
solar QFs provides a certainty to the parties in negotiations
that disaggregation criteria would not. While we recognize
the impact that this decision will have on small wind and
solar projects, it would be erroneous, and illegal pursuant to
PURPA, for this Commission to allow large projects to obtain
a rate that is not an accurate reflection of the utility's avoided
cost for the purchase of the QF generation.
Order No. 32262, p. I (citations omitted).
Once again, the Commission is faced with a rush of proposed PURPA projects
that appear to be configuring themselves in such a manner as to circumvent the
Commission's rules implementing PURPA to the direct detriment of ldaho Power
customers, which is contrary to PURPA. The Proposed Battery Storage Facilities share
the modular, and easily disaggregated, nature of wind and solar generation referenced
by the Commission in its orders limiting those resource types to 100 kW for published
rate eligibility. The 148 MW of Proposed Battery Storage Facilities' requests for energy
sales agreements also came in a large amount of proposed MWs in a very short time,
again similar to the previous wind and solar development. ln its order reducing the
maximum contract term for proposed projects that exceed the published rate eligibility
cap, the Commission stated:
Based upon our record, we find that 2O-year contracts
exacerbate overestimations to a point that avoided cost rates
over the long-term period are unreasonable and inconsistent
with the public interest. We find shorter contracts
reasonable and consistent with federal and state law for
multiple reasons. First, shorter contracts have the potential
to benefit both the QF and the ratepayer. By adjusting
avoided cost rates more frequently, avoided costs become a
truer reflection of the actual costs avoided by the utility and
allow QFs and ratepayer to benefit from norrnal fluctuations
in the market.
PETITION FOR DECLARATORY ORDER - 12
Second, shorter contract lengths do not ultimately prevent a
QF from selling energy to a utility over the course of 20
years - or longer. PUPRA's "must purchase" provision
requires the utility to continue to purchase the QF's
power. . . . A shorter contract length merely functions as a
reset for calculation of the avoided costs in order to maintain
a more accurate reflection of the actual costs avoided by the
utility over the long term. . . .
This Order shortens the length of lRP-based PURPA
contract in order to maintain a more accurate avoided
cost. . . . This Order strikes a balance between just and
reasonable rates for ratepayers, the public interest and
interests of QFs, as is mandated by PURPA and FERC
regulations.
Order No. 33357, p. 23, 32 (emphasis in original). lt is appropriate and within the
exclusive authority of the Commission to act in the public interest to protect customers
from this manipulation of the rules and extend the 100 kW published rate eligibility cap
to battery storage projects.
ilt. coNclusloN
ldaho Power respectfully requests that the Commission issue a declaratory
order, without prejudice to ldaho Power's position on the validity of the underlying self-
certifications, finding that, under the facts presented, the Proposed Battery Storage
Facilities are subject to the same 100 kW published avoided cost rate eligibility cap
applicable to wind and solar facilities. More specifically, ldaho Power seeks a
declaratory ruling from the Commission that the proper authorized avoided cost rate for
battery storage facilities, such as those proposed by Franklin Energy Storage One
through Four and Black Mesa Energy, as projects that exceed 100 kW nameplate
capacity, is the incremental cost IRP methodology with a maximum contract term of two
PETITION FOR DECLARATORY ORDER - 13
years-and that battery storage facilities, up to a maximum nameplate capacity of 100
kW, are eligible for published avoided cost rates and a Zo-year maximum contract term.
Respectfully submitted this 27th day of February 2017.
DONOVAN E. WALKER
Attorney for ldaho Power Company
PETITION FOR DECLARATORY ORDER - 14
Exhibit 6
Idaho Public Utilities Commission
Order No. 33785
Office ofthe Secretary
Service Date
July 13, 2017
BEFORE THE IDAHO PUBLIC UTILITIES COMVIISSION
IN TIIE MATTER OF'THE PETITION OF
IDAHO POWER COMPANY FORA
DECLARATORY ORDER REGARDING
PROPER CONTRACT TERMS,
CONDITIONS, AND AVOIDED COST
PRICING FOR BATTERY STORAGE
FACILITIES
CASE NO. IPC.E.I7-OI
ORDER NO. 33785
On February 27,2017,Idatro Power Company filed a Petition asking the Commission
to issue a Declaratory Order regarding proper contract terms, conditions, and avoided cost
pricing for five battery storage facilities requesting contracts under the Public Utility Regulatory
Policies Act of 1978 (PURPA). The Commission issued a Notice of Petition and Notice of
Modified Procedure setting deadlines for comments from the battery storage facilities, affected
utilities, Staff, and any interested persons. Order No. 33729. The Commission also granted a
joint Petition to lntervene by Siena Club and Idaho Conservation League (ICL). Order No.
33743.
The Commission received comments from the battery storage facilities - Franklin
Energy, LLC and Black Mesa, LLC - followed by comments from Commission Staff, Avista
Corporation, Sierra Clubfldaho Conservation League (ICL), and ldaho Power. Each of the
parties, except Black Mesa, also filed reply comments. See Order No. 33765 (ganting Franklin
Energy's unopposed Motion to extend deadline for reply comments). With this Order, the
Commission grants IPC's request for a Declaratory Order.
BACKGROTIND: PUBLIC UTILITY REGULATORY POLICIES ACT
PURPA was passed as part of the National Energy Act of 1978. The Act's goals
include the encouragement of electric energy conservation, efficient use of resources by electic
utilities, and equitable retail rates for electric consumers, as well as the improvement of electic
service reliability. 16 U.S.C. $ 2601 (Findings). Under the Ac! the Federal Energy Regulatory
Commission (FERC) prescribes "broad, generally applicable rules" for PURPA's
implementation. Portland General Electric Co. v. FERC,854 F.3d 692, (D.C. Cir. 2017); 16
U.S.C, $ 824a-3(a), (b). The Act also "requires state public-utility commissions to implement
FERC's rules at the local level." Portland General Electric,854 F.3d 692; 16 U.S.C. $ 824a-
3(f1. State commissions "rnay comply with the statutory requirernents by issuing regulations, by
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IORDERNO. 33785
resolving disputes on a case-by-case basis, or by taking any other action reasonably designed to
give effect to FERC's rules." FERC v. Mississippi, 456 U.S. 742, 751 (1982). State
commissions have "discretion in determining the marlner in which the nrles will be
implemented." Idaho Power Company v. Idaho Pub. Wil. Comm., 155 Idaho 780,782,316 P.3d
1278,1280 (2013).
PURPA requires electric utilities, unless otherwise exempted, to purchase electric
energy from QFs. 16 U.S.C. $ 824a-3; see also l8 C.F.R. $ 292.101 (defining QFs),292.303(a).
In Idaho, the purchase rate for a utility's contact to purchase QF energy under PURPA must be
approved by this Commission. Idaho Power,155 Idaho at789,316 P.3d at1287.
Under PURPA, the purchase rate for PURPA contracts shall not exceed the
"incremental" or "avoided cost" to the utility, defined as the cost of energy which, but for the
purchase from [the QF], such utility would generate or purchase from another source. 16 U.S.C.
$ 82aa-3(d); 18 C.F.R. 5 292.101(6) (defining avoided costs). However, FERC rules require
establishment of "standard rates for purchases from [QFs] with a design capacity of 100
kilowatts or less," and allow "standard rates for purchases from [QFs] with a design capacity of
more than 100 kilowatts." l8 C.F.R. S 292.304(c)(1), (2). FERC rules provide that standard
rates "[m]ay differentiate among [QFs] using various technologies on the basis of the supply
characteristics of the different technologies." 18 C.F.R. $ 292.304(cx3xii).
This Commission has established two methods of calculating avoided cost, depending
on the size of the QF project: (1) the surrogate avoided resource (SAR) methodology, and (2)
the integrated resor:rce plan (IRP) methodology. See Order No. 32697 at 7-8. The Commission
uses the SAR methodology to establish standard or "published" avoided cost rates. Id.
Currently, the eligibilrty cap for wind and solar QFs to access published avoided cost rates is set
at 100 kilowatts GVD. QF projects other than wind and solar are subject to a published rate
eligibility cap of 10 average megawatts (aMW). Order Nos. 32262 al1,32697 at7-8.
PURPA and FERC's implementing regulations do not dictate a requisite term length
for contracts under PURPA. See Afion Energt, Inc. v. Idaho Power,107 Idaho 781, 785-86, 693
P,2d 427,43L-32 (1984); Idaho Power,155 Idaho at782,316 P.3d at 1280, Consequently, state
jurisdictions have identified varying minimum contract terms. Since PURPA was first
implemented in ldaho, this Commission has periodically modified the marimr.un length for
PURPA contracts. See Order No. 29029. In 2015, this Commission reduced the term for
2oRDERNO. 33785
individually-negotiated PURPA contracts (those not subject to published rates) in ldaho from 20
years to 2 years. Order Nos. 33357,33419. The contract term for published rate contracts
remains at 20 years. See Order No. 33253 (clariffing that the proceedings concerned the
contract term for QFs exceeding the published rate eligibility cap).
IDAHO POWER'S PETITION
Idaho Power stated it received requests for PURPA contracts from five battery
storage facilities (self-certified as QFs)r asserting they are entitled to published avoided cost
rates and Z}-year terms. Petition at 2. The five facilities are Franklin Energy Storage One, Two,
Three, and Four, LLCs and Black Mesa, LLC,Z and the contracts request 148 MW of total
combined energy storage. Id. at 4,7. Idaho Power informed Franklin and Black Mesa that it did
not believe any of the storage facilities are eligible for published rates and 2O-year contracts. 1d
Idatro Power acknowledged that "QF status is within the exclusive jurisdiction [ofl
and properly before FERC"; thus for purposes of its Petition, tle Company did not challenge the
QF status of Franklin and Black Mesa. Id. at 6. Idaho Power asserted the Commission has
jurisdiction to issue a Declaratory Order. Id. at 5. Thus, the Company requested a Declaratory
Order that the Franklin and Black Mesa QFs and other battery storage facilities "are subject to
the same 100 kW published avoided cost rate eligibility cap applicable to wind and solar
facilities." Id. at 13. The Company also requested a ruling that "the proper authorized avoided
cost rate for battery storage facilities . . , that exceed 100 kW nameplate capacity, is [a rate based
on] the incremental cost IRP methodology with a maximum contract term of two yearc." Id. at
t3-14.
Idaho Power noted that "the generation source that energizes all of the Proposed
Battery Storage Facilities is solar generation," and "the output profile submitted for each of the ,
. . Facilities matches the shape and timing of the generation profile of a solar generator." Id. at 7
(citing Attachments 1-5). According to the Company, the potential benefits of an economically
I Petition at 4. Fraoklin and Black Mesa submitted a FERC Form 556 for each of the proposed projects, self-
certiffing that the projects are QFs under l8 C.F.R. $ 292.207(a). See Attachments l-5 to Petition.
2 The Black Mesa QF is owned by Redwood Energy, LLC, which submitted comments on behalf of Black Mesa as
its corporate owner. However, "Black Mesa Energy, LLC' submitted its Schedule 73 PLTRPA contact request form
to Idaho Power on its own behalf. Attachment 5 to Petition, at 4.
3oRDERNO. 33785
viabte utility-scale energy storage faciliql cannot be recognized if QFs "are configured in such a
manner as to come under published rates," or stnrctured to "pass[ ] through as many kW hours as
possible...to maximize revenue," as proposed by Franklin and Black Mesa. Id at8.
The Company believes that Franklin and Black Mesa are using their QFs to
"circumvent the Commission's rules and requirements in its implementation of PURPA for the
state of Idaho." Id. The Company asserted the Franklin and Black Mesa QFs are "nothing more
than a pass through of the solar generation [that will energize their batteries], in what appears to
be a blatant attempt to manipulate the 100 kW published rate eligibilrty cap and two-year
contact limitation for solar generators." Id. at 9. The Company argued it is appropriate and
necessary for the Commission to grant its requested declaratory relief "extend[ing] the 100 kW
published rate eligibility cap to battery storage projects . . . to protect customers from this
manipulation of the rules." Id. at 13.
COMMENTS
A. Franhlin Energt
Franklin opposed Idaho Power's Petition. Fra*lin asserted there is no "legal
controversy" because the Commission's Orders and policy rulings af,e "clear [and] unequivocal"
in supporting Franklin's entitlement to published avoided cost rates for up to 20 years. Franklin
Comments at l-2, L1-12. Franklin quoted Commission Order No. 32697, which provides, "We
find that a l0 aMW eligibility cap for access to published avoided cost rates for resources other
than wind and solar is approoriate to continue to encourage renewable development while
maintaining ratepayer indifference." Id. at 7 (quoting Order No. 32697 at 14 (emphasis by
Franklin)). Also, Franklin quoted the Commission's decision to "maintain the eligibility cap at
10 aMW for QF projects other than wind and solar (rncludine but not limited to biomass, small
hydro, cogeneration, geothermal, and waste-to-energy)." Id. atl0 (quoting Order No. 32697 at 9
(emphasis by Franklin)).
Franklin argued that, because Commission Order No, 32697 is clear, there "are no
adverse legal interests," and Idatro Power's request must be construed as a request to reconsider
or revise Order No. 32697. Id. at2,4, For such relief Franklin contended, it and any potentially
affected parties must receive notice and the opportunity to present evidence and cross-examine
3 The Company states that the potential benefits of economically viable, utility-scale energy storage facilities include
"provid[ing] ancillary grid services such as reserve capacity, surge capacity, load-balancing, or voltage support;
firming [ ] variable generation; or time-shifting generation to match load." Petition at 8.
4oRDERNO. 33785
witnesses. Id. at3-4. Franklin also argued that the Commission's decision in such a proceeding
must be prospective only, and thus not apply to its legally enforceable contacts with Idatro
Power for the four proposed battery storage QFs. Id. at 4-5.
In addition, Franklin challenged - and asked the Commission to disregard - a number
of factual assertions in Idatro Power's Petition. Franklin contended that, contary to the
Company's claims, the Franklin QFs (l) "contemplated" energy sources in addition to solar; (2)
have offered to be dispatchable; and (3) will have the ability -'to varying degrees" - to provide
ancillary grid services, flrming of variable generation, and time-shifting generation to match
load. Id. at 14. Further, Franklin disputed that its QFs will merely "pass through" solar power,
arguing that they would instead "utilize renewable energy as input into the battery storage system
. . . [that would then be] used to provide a non-intermittent, dispatchable product." Id. at 15.
Finally, Franklin asserted that it has complied with all the requirements of the
Company's Tariff Schedule 73, which outlines PURPA contacting procedures, and that as such
it has established LEOs and is entitled to published rates and 20-year contracts. Id. at 17.
B. Redwood Energfor Black Mesa
Redwood Energy, LLC, which owns the Black Mesa QF, submitted brief comments
on Black Mesa's behalf, asserting that it qualifies for published rates "because it is a QF twithl
output of less than 10 taMwl but is not a wind or solar QF that would be restricted to 100 kW."
Redwood Comments. Redwood contended that the Black Mesa QF "has fimdamentally different
characteristics than a wind or solar project without energy storage." /d. According to Redwood,
battery storage "makes output both more predictable and more coincident with system load, thus
[resulting in] a higher Net Qualiffing Capacity." Id. Redwood asserted that "[e]nergy storage
will reduce Idaho Power's requirements for Resource Flexibility, thus avoiding a cost that would
be bome but for" the Black Mesa QF project. Id. Redwood furlher asserted, 'oThis is a
dispatchable system that will offer ancillary grid services such as voltage support, load shifting,
reserve capacity, load-balancing, [and] firrning of variable generation or time-shifting to match
load." Id.
C. Staff
Staffbelieves there is a legal dispute that can be properly addressed by a Declaratory
Order, namely the terms of PURPA contracts between Idaho Power and the battery storage QFs.
5oRDERNO. 33785
Staff maintained that Franklin's and Black Mesa's position that they are clearly
entitled to published avoided cost rates under the language of Order Nos. 32262 and 32176 is an
o'overly simplistic analysis." Staff Comments at 7. Staff asserted that "the energy source of a
battery system is not an electro-chemical reaction." Id. at 8. Rather, "a battery storage facility
can be a QF only if its energy source complies wift PURPA and PURPA regulations," consistent
with FERC's analysis in Luz Development and Finance Corporatiorz, 51 FERC P 61,078 (1990),
a FERC order cited in Franklin's comments. .Id.
Staff thus reasoned "it is appropriate to look to the Franklin and Black Mesa QFs'
energy sources in determining their eligibility for published ratss;' Id. Staff highlighted that
Franklin's and Black Mesa's requests for PURPA contacts identified solar as the energy sounoe,
although they have "contemplated" other sources. Id. at 8-9 (citing Franklin Comnents at 14
and arguing that "mere contemplation of an alternate source is insufficient to obligate a utility to
purchase power from a battery storage QF with rates and contract terms based on that
hypothetical source"). Staffthus argued that Franklin and Black Mesa are subject to the 100 kW
published avoided cost rate eligibility cap. Id. at 9. Staff asserted that Franklin and Black Mesa
- as cturently configured - exceed that cap, and are thus eligible for two-year terms and
negotiated avoided cost rates under the IRP methodology. .Id.
Staff argued that Franklin and Black Mesa were interpreting isolated parts of
Commission orders, but ignoring the intent of the orders gleaned by reading them in their
entirety and in context. Staff Comments at 9-10, quoting Hayes v. Ctty of Plummer, 159 Idaho
168, 170, 357 P.3d 1276, 1278 (2015) (other citation omiued) (statutory "provisions should not
be read in isolatiorU but must be interpreted in the context of the entire document").
Staffasserted, o'A battery storage QF that would not exist except for its erergy source
should not be able to evade an eligibility cap that would otherwise be applied to its energy
source." Staff Comments at I l. "Here, Franklin and Black Mesa- battery storage QFs currently
intending to use solar as their energy sourrce - should not be exempt from this Commission's
eligibility cap which was intended to prevent disaggregation of large solar projects." .Id. Staff
argued Franklin's and Black Mesa's interpretation that they are eligible for published rates under
Order No.32262 is contary to the Commission's intent - ignored by Franklin and Black Mesa,
but expressed throughout Order No.32262 - to prevent disaggregatior. Id. at 9-11.
6oRDERNO. 33785
Finally, Staff disputed Franklin's contention that it established a LEO. Id. at9. T\e
Idaho Supreme Court affrrmed this Commission's deterrnination that a LEO "requires a showing
that there would have been a contract but for the actions of the utility." Idaho Power,155 Idaho
at 787. Given the urdisputed facts that Franklin and Black Mesa proposed to configure their
QFs with solar energy sources, Staff determined there was no indication that Idatro Power
impeded formation of PURPA contracts. StaffComments at 9.
Given the broader implications of issues raised in the case, Staff recommended that
the Commission initiate a general investigation into the appropriate contract terms for battery
storage QFs, StaffComments at 11.
D. Avista
Avista Corporation supported Idaho Power's Petition, Avista asserted that battery
storage facilities "should be classified, and treated, in the same mamer as the facilities that
provide the primary energy source for such battery storage facilities." Avista Comments at 5, 3-
4 (discussing Luz,5l FERC P 61,078). In other words, battery storage facilities using wind or
solar facilities as their primary energy source should be treated as wind or solar QFs. Id. Avista
proposed that if the Commission rejects the proposal to treat battery storage facilities in the same
manner as their primary energy source, then the Commission should "initiate a generic
proceeding to determine the appropriate treatment of such facilities." Id. at 5. Finally, Avista
recommended that the Commission put a "moratorium on energy storage QFs with nameplate
capacities above 100 kW to protect utility customers during [a genericJ proceeding." Avista
Comments at 5-6.
E. Sterra Club and ICL
Sierra Club and ICL opposed Idatro Power's Petition, arguing that the Company is
asking to modiff prior Commission Order Nos. 32262 and, 33357, and that a petition for
declaratory order is therefore not the appropriate process. Siera Club/ICL Comments at l-2.
Sierra Club and ICL asserted that the Commission's 'oinherent, derivative" authority under the
ldaho Uniform Judgments Act "must yield to" the statutory process for "rescinding, altering or
amending prior orders" under Idaho Code $ 61.-624, because otherwise the procedures set forth
in ldaho Code $ 6l-624 "become superfluous." Sierra Club/ICL Comments at 3.
The bulk of Sierra Club and ICL's comments challenged the validity of Order No.
33357, the final Order from consolidated proceedings onpetitions by Idaho electric utilities to
7ORDERNO. 3378s
shorten PURPA contract lengths for projects with IRP-based avoided cost rates. Sierra Club/ICL
Comments at 4-19. Sierra Club and ICL raised several arguments why Order No. 33357 is
invalid, and concluded that 'othe Commission cannot extend [an Order that] exceeded the
Commission's jurisdiction." Id. at 19. Sierra Club and ICL recommended that the Commission
"revisit Order No. 33357 for wind and solar projects." .Id
Siera Club and ICL asserted, to the extent the Commission considers whether to limit
the length of contracts for battery storage facilities, "it must hold a hearing and make findings
that the contract term allows reasonable opportunity for QFs to attact financing for viable
projects." Id. atZ.
REPLY COMMENTS
A. Idaho Power
On reply, Idaho Power stated that the proposed battery storage facilities have not
established a LEO. Idaho Power Reply at7-9. The Company detailed communications between
Idatro Power and the battery storage QFs demonstrating the Company's efflorts and actions prior
to filing its Petition here, and attached supporting records. Id. (Attachments l-2).
Idaho Power further asserted a generic case was not needed. Idatro Power Reply at 5-
6. However, the Company indicated it "is not necessarily opposed to such proceedings." Id.
B. Franklin and Black Mesa
In its reply, Franklin asserted that Staffis simply ignoring the 'oclear and unequivocal
ruling by this Commission that all QFs other than solar and wind are entitled to twenty-year
contracts." Franklin Reply at 8. Franklin noted that, "in Luz,FERC was not'evaluating battery
storage facilities' for the purpose of determining their eligibility for published rates and twenty-
year confract terms." Franklin's Reply at 2 (emphasis by Franklin). Franklin highlighted that
FERC's conclusion n Luz was that "energy storage facilities such as the proposedLw battery
system are a renewable source for purposes of QF certification." Id. (quoting Luz at 10).
Franklin argued that Idatro Power, Staff and Avista "conveniently ignore the distinct legal status
FERC has declared as to energy storage QFs." Id. at3-4.
Franklin took no position on StafFs recommendation to open a generic case, except to
assert that "such new generic dockets will only have prospective effect." Franklin Reply at 11.
8ORDER NO. 3378s
C. Staff
Staffdisageed with Sierra Club and [CL's argument that the petition be construed as
a request to modi$ the Commission's Orders. Staff Reply at 3. Staffnoted that the Company's
request is consisten with Order No.32262, and consistent with Inz. Id. "Thus there is no
reason - as Sierra CIub and ICL contend - for ldaho Power to seek modification of Order No,
32262." Id. Staff further noted that the Company's Petition seeks to apply Order No. 33357
without modification. Id. at4.
Staffdisputed the argument by Siena Club and ICL challengrng the validity of Order
No. 33357. Staff argued that their challenges exceed the scope of Idaho Power's Petition, and
are barred by ldaho Code $ 6L-625, which precludes collateral attack on a final order of the
Commission. Staff Reply at 4-5.
As to Avista's recommended moratorium on energy storage QFs larger than 100 kW,
Staff recommended instead that the Commission allow such QFs to enter PURPA contracts, but
that the Commission temporarily set a 100 kW threshold for battery storage facilities to be
eligible for published avoided cost rates, pending the outcome of a generic proceeding. Staff
Reply at 2. Staff stated this "would ensure that ldaho Power complies with its obligation to
purchase under PURPA while also protecting ratepayers by ensuring accurate avoided cost
rates." Id. at2-3.
D. Sierra Club and ICL
In their reply, Sierra Club and ICL argued that Stafferred in asserting that the issue of
contract length is in the discretion of state commissions based on FERC's silence about contact
length in its implementing regulations. Sierra Club/ICL Reply at2-4. Sierra Club and ICL also
again addressed, as they did in their opening comments, the issue of contract length as it relates
to QFs' financial viability. Id. at4-6.
COMI\ISSION FII\IDINGS A}tD DECISION
This Commission has jrxisdiction over ldaho Power, an electric utility, pursuant to
the authority and power granted it under Title 6l of the Idaho Code and PURPA. Idaho Code $$
6I-129,61-501; 16 U.S.C. $ 82aa-3(f). The Commission has authority under PURPA and
FERC's implementing regulations to set avoided costs, order electic utilities to enter into fixed-
term obligations for the purchase of energy from QFs, and implement FERC rules. See supra
Background.
9oRDERNO. 3378s
Also, the Commission has jurisdiction to issue declaratory orders under Title 61 of
the Idaho Code and the Idaho Uniforrn Declaratory Judements Act of 1933, Idaho Code $$ l0-
l20l et seq. See Utah Power & Light v. Idaho Pub. Util. Comm'n, ll2Idaho 10, 12, 730 P,zd
930,932 (1986) (PUC had jurisdiction to determine which regulated electrical utility had the
right to be the sole supplier of electricity to electic customer under the Uniform Declaratory
Judgments Ac|. A declaratory judgment "must clariff and settle the legal relations at issue, and
afford leave from uncertainty and controversy which gave rise to the proceeding," Hatis v.
Cassia County, 106 Idaho 513, 517, 681 P.2d 988 (1984) (citing &tteeney v. Am. Nat'l Bk, 62
Idaho 544,1,15 P.2d 109 (1941). For a declaratory judgment to be rendered, there must be "an
actual or justiciable controversy" that is "real and substantial," and "definite and concrete,
touching the legal relations of parties having adverse legal interests." /d. at 516 (quoting Aetna
Life Ins. Co. v. Haworth,300 U.S. 227,240-41(1937)).
Under the applicable statutes and case precedent, and in light of the circumstances
here, we have jurisdiction to issue a declaratory order. Idaho Power disagrees with Franklin and
Black Mesa as to which avoided cost rate and eligibility cap should apply to the two battery
storage developers for purposes of forming PURPA contacts. Both sides contend their
respective interpretations of applicable law should govem their contracts. We thus find the
Cornpany, Franklin and Black Mesa have adverse legal interests about which there is 'oan actual
or justiciable controversy" that is "real and substantial," and "definite and concrete," that we
have jnrisdiction to clarify and resolve. See Harris,106 Idaho at 516 (quoting Aetna Life Ins.,
300 U.S. at 240-41). We reject Sierra Club's and ICL's argument that the Company is actually
seeking modification of the Commission's prior Orders. Sierra Club/ICL Comments at 1-2. We
further find Siena Club/[CL's challenge to the validity of Order No. 33357 to be an
impermissible collateral attack, pursuant to ldaho Code $ 6l-625.
We are unaware of any reference in PURPA or FERC's implementing regulations
that identifies battery storage as a renewable resource eligible for QF status and the benefits
provided by the Act. Indeed, FERC acknowledged that "[n]either the statute nor the final nrle
refers specifically to energy storage systems." Luz at 61,171. Consequently, our ruling on the
narrow declaratory issue before us should not be read to presume that this Commission deems
battery storage to be a legitimate qualifying facility eligible for the benefits of PURPA and
ORDERNO. 33785 10
subject to the Act's irnplementing regulations under FERC. The battery storage facilities' QF
status is a matter within FERC's jurisdiction and is not at issue in this case.
Although FERC goes on n Luz to summarily include battery storage as a renewable
resource for purposes of QF certification, it does so with specific parameters. FERC
distinguishes battery storage from energy sources that generate electric energy and provide the
battery with its resource. FERC states that ". in order for a storage facility to be a QF the
primary energy source for generation of this energy must be one of those contemplated by the
statute for conventional small power production facilities. . . ." Id. "Section 3(17XA) of the
FPA defines a srnall power production facility as one which 'produces electric energy solely by
the use, as a primary energy source, of biomass, waste, renewable resources, geothermal
resources or any combination thereof."' Id,, citing 16 U.S.C. $ 796(17)(AXi) (1988). "Primary
energy source is defined as the fuel or fuels used for the generation of electric energy. . . ." Id.,
citing 16 U.S.C. $ 796(17XBXi) (1988).
Luz attempted to convince FERC that a battery storage facility independently meets
the definition of a primary energy source because it generates energy when an electo-chemical
reaction discharges the stored power from the battery. Id. at 61,169. Lr;z further argued that the
time shifting capability of energy storage "can only make sense and be implemented if energy
storage facilities like the proposed battery system are allowed to operate as QFs and to use
electric energy without an inquiry as to the source of energy used to generate that electricity."
Id. at 6l)7A. FERC rejected this position. "Contrary to Luz's assertion, the primary energy
source of the battery system is not the electro-chemical reaction. Rather, it is the electric energy
which is utilized to initiate that reaction, for without that energy, the storage facility could not
store or produce the electric energy which is to be delivered at some later time. Since this energy
is the primary energy source of the facility, it is necessary to look to the source of this energy as
the ultimate primary energy source of the facility." Id. at6l,l7l.
FERC confirmed that energy storage facilities are not renewable resources/small
power production facilities per se. Id. Electric input is required to produce electric output from
a storage facility. Id. at 61,172. For this reason, in order to qualiff as a PURPA resource, the
primary energy source behind the battery storage must be considered. We must, then, look to
Franklin's and Black Mesa's primary energy sorrces in order to deterrrine their eligibility under
PURPA. The primary energy source for Franklin and Black Mesa is solar generation.
oRDERNO. 33785 1l
Moreover, the energy generation output profiles for the battery storage facilities are a direct
reflection of the solar generation that operates as the primary energy source for the battery
storage facilities. Petition at 7, Attachments l-5.
Accordingly, we find it appropriate to base Franklin's and Black Mesa's eligibility
under PURPA on its primary energy source - solar. Solar resources larger than 100 kW are
entitled to negotiate two-year PURPA contracts through the use of Idaho's IRP methodology.
Franklin's argument that this Commission's prior decisions clearly and unequivocally allow it
entitlement to published rates ignores FERC's pronouncement that energy storage facilities are
notper se renewable resources/small power production facilities rmder PURPA.
Franklin firther maintains ttrat it has established a legally enforceable obligation
(LEO) requiring Idatro Power to purchase its energy. Franklin Comments at 17. However,
Franklin has failed to prove that ldaho Power impeded Franklin's ability to enter into PURPA
contracts. See ldaho Power,155 Idaho at787. To the conhary, Idatro Power notified the battery
storage facilities tlat the utility did not believe the projects were entifled to 20-year, published
rate contacts and requested the projects "supplement your Applications with additional
inforrnation that verifies eligibility for the requested rates and terms, or modiff your
Applications to request rates and terms that your proposed projects may qualiff for." Petition,
Attachment 6.
*FERC has given each state the authority to decide when a LEO arises in that state."
Idaho Power,155 ldatro at787, quoting Power Resource Group, Inc. v. Public Utility Comm'n
of Texas, 422 F.3d 231, 239 (5th Cir. 2005). The facts and evidence in this case reveal that the
parties were in active negotiations which resulted in ldaho Power's Petition for a declaratory
ruling. We decline to interpret a reasonable dispute between the parties regarding contract terms
and conditions as intransigence or a failure to negotiate on the part of the utility. Therefore, we
find that no action (or inaction) of the utility has triggered the creation of a legally enforceable
obligation.
Finally, based on the above findings regarding the characteristics of battery storage
and the compulsory consideration of its underlying primary energy source, we find a generic
investigation unnecessary. We grant Idaho Power's Petition for a declaratory ruling to address
and resolve the legal dispute between Idaho Power and Franklin Energy/Black Mesa arising out
of contract negotiations between the two panies. We find that, as storage facilities with design
oRDERNO. 33785 t2
capacities that will exceed 100 kW each and with solar as their primary energy source, the
projects are eligible for two-year, negotiated (IRP methodology) contracts,
ORDER
IT IS HEREBY ORDERED that tdaho Power's Petition for declaratory relief is
granted as set forth above.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See ldaho Code $ 6l-626.
DONE by Order of the Idatro Public Utilities Commission at Boise, Idatro this / "
&
day ofJuly 2017.
SIONER
ERIC A}IDERSON, COMMISSIONER
ATTEST:
Diane M. Hanian
Commission Secretary
O:IPC-E- l7-01_djh3
ORDER NO. 33785 13