20130506reconsideration_order_no_32802.pdf

Office of the Secretary
Service Date
May 6, 2013
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S )
REVIEW OF PURPA QF CONTRACT ) CASE NO. GNR-E-11-03
PROVISIONS INCLUDING THE )
SURROGATE AVOIDED RESOURCE (SAR) )
AND INTEGRATED RESOURCE PLANNING )
(IRP) METHODOLOGIES FOR ) ORDER NO. 32802
CALCULATING AVOIDED COST RATES. )
)
On December 18, 2012, the Commission issued final Order No. 32697 determining
various issues related to avoided cost rate methodologies and other considerations regarding
Public Utility Regulatory Policies Act (PURPA) contracts. On January 8, 2013, Idaho Power
Company, Renewable Northwest Project, Renewable Energy Coalition, Idaho Conservation
League and J.R. Simplot/Clearwater Paper filed timely requests for reconsideration/clarification.
Commission Staff and Idaho Wind Partners filed timely answers to the petitions.
Idaho Power filed what it captioned as a "Response and Cross-Petition" within the time allowed
for answers. On January 22, 2013, Mountain Air Projects filed an untimely answer to the
petitions. On January 23, 2013, the Canal Companies filed what was captioned as a "Reply" to
Idaho Power's Response and Cross-Petition.
RECONSIDERATION
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 Idaho 875, 879, 591 P.2d 122, 126 (1979). The Commission may
grant reconsideration by reviewing the existing record, by written briefs, or by evidentiary
hearing. IDAPA 31.01.01.332.
On February 5, 2013, the Commission issued Order No. 32737 partially granting and
partially denying reconsideration/clarification. The Commission granted reconsideration on the
issues related to ownership of renewable energy credits (RECs). The Commission chose to
reconsider the REC issues based on the existing record. We also granted reconsideration of the
SAR methodology issues surrounding the definition of canal drop hydro and proper capacity
ORDER NO. 32802 1
factors for hydro and "other" projects. Discovery, comments and reply were permitted on the
canal drop hydro and capacity factor issues.
The Commission took the opportunity to clarify that, in its final Order No. 32697; it
did not implicitly or explicitly authorize contract extensions or renewals for existing contracts
that do not contain such provisions. Order No. 32737 at 5. The Commission explained that
"when an existing QF under a current contract desires to continue to sell energy to the same
utility after expiration of the current contract, and the parties enter into a new contract for the
sale and purchase of energy, the QF is entitled to be paid capacity for the full term of the new
agreement." Id. The Commission also directed Staff to provide published rate tables for
replacement contracts upon request by any interested party.
The Commission clarified its determination of capacity deficiency. We stated that,
"the SAR model recognizes not only the timing of when the first deficit occurs, but also the
magnitude of the deficit. . . . As the utility's deficit grows, increasing amounts of the QF's
capacity are given credit until the year when the utility's deficit exceeds the QF's capacity, when
full value for the QF's capacity is given." Id. at 8.
The Commission further granted clarification on the issue of annual updates to the
utilities' gas and load forecasts. In acknowledgement that the final EIA gas forecast might be
released after June 1 in any given year, the Commission clarified that the annual update of the
ETA gas forecast utilized within the SAR methodology should occur "on June 1 or within 30
days of the final release of the ETA Annual Energy Outlook, whichever is later." Id. at 7. The
Commission also directed the utilities to collaborate and propose a suitable date for all three
utilities to update their gas and load forecasts used in their IRP methodologies.
The Commission denied Idaho Power's request to clarify the Commission's findings
regarding curtailment and the application of 18 C.F.R. § 292.304(f). The Commission further
denied reconsideration of its findings regarding use of incremental costs in determining avoided
costs under the IRP Methodology. Id. at 8.
By this Order, we address the narrow issues of annual updates to gas and load
forecasts, canal drop hydro concerns, resource specific capacity factors, and REC ownership
which were granted reconsideration by Order No. 32737.
ORDER NO. 32802 2
UPDATES TO GAS AND LOAD FORECASTS
In the Commission's final Order, we determined that the natural gas price forecast
used in the SAR model and the fuel and load forecasts used in the IRP Methodology should be
updated every June 1 utilizing data from the ETA's Annual Energy Outlook. Order No. 32697
at 52. Idaho Power requested clarification of the Commission's determination regarding fuel and
load forecast updates in two respects. First, Idaho Power proposed that the Commission consider
updating the SAR model "immediately upon release of the specifically designated EIA natural
gas price forecast" instead of waiting until June 1 in order to avoid "gamesmanship." Petition at
8. Second, Idaho Power stated that the Company does not update its fuel and load forecasts
utilized in the IRP Methodology until October of each year. Consequently, Idaho Power
requested that annual updates to the fuel and load forecasts utilized in its IRP Methodology be
set for a different date.
The Commission determined that a single date for annual updates to both the SAR
and IRP methodologies was not required. "However, to avoid confusion, ensure consistency,
and alleviate gamesmanship, we find it necessary for all three utilities to update their annual
SAR gas forecast on the same date, and to also update their annual IRP forecasts on a uniform
date." Order No. 32737 at 6. The Commission clarified that "the annual update of the EIA gas
forecast should occur on June 1 or within 30 days of the final release of the ETA Annual Energy
Outlook, whichever is later." Id. at 7 (emphasis in original).
The Commission also directed the three utilities to collaborate and propose a suitable
date for all three utilities to update their gas and load forecasts used in their IRP methodologies.
The utilities filed notice with the Commission on March 5, 2013, that they consulted and agreed
that each utility should update the natural gas and load forecasts used in each utility's respective
IRP avoided cost methodology annually on October 15.
Commission Findings: The Commission finds that the utilities' joint
recommendation to update natural gas and load forecasts for each utility's IRP Methodology on
October 15 of each year is reasonable. Therefore, updates to each utility's natural gas price
forecast used in the SAR methodology shall be based on the EIA gas forecast and shall occur
annually on June 1 or within 30 days of the final release of the ETA Annual Energy Outlook,
whichever is later. Further, updates to gas and load forecasts used in the IRP methodologies
shall occur annually on October 15.
ORDER NO. 32802 3
CANAL DROP HYDRO PROJECTS
The Commission's final Order No. 32697, Attachment A defines "canal drop hydro"
as "a generation facility which produces a majority of its generation during the irrigation season
and is located on a man-made waterway that conveys water primarily intended for irrigation or
that primarily conveys irrigation return flows." The Renewable Energy Coalition requested
clarification of this definition and suggested an alternative classification. Because the definition
of canal drop hydro was not fully explored at hearing, the Commission allowed discovery,
comments and reply on the issue.
The Renewable Energy Coalition proposed that canal drop hydro projects be
redefined as "irrigation related hydro projects" and include any generation facility "which
produces a majority of its generation during the irrigation season and conveys or impounds water
primarily intended for irrigation." Petition for Clarification at 4. The Coalition explained that its
definition justified a higher avoided cost rate based on the correlation between the generation
delivered and the utility's system peak, and not the physical features of the water delivery
system. Comments at 1.
Idaho Power proposed that the Commission adopt changes to the definition of canal
drop hydro that would base the definition on a hydro project's ability to deliver energy during
peak summer load. Comments at 2. Idaho Power proposed the following definition:
A "canal drop hydro project" is defined as a generation facility which
produces 55% of its generation during the months of June, July, and August
and is located on a man-made waterway that conveys water primarily intended
for irrigation or that primarily conveys irrigation return flows.
Alternatively, Idaho Power recommended that, if the Commission wished to retain the entire
irrigation season as part of the definition, the definition be modified as follows:
A "canal drop hydro project" is defined as a generation facility which
produces 96% of its generation during the months of April through October
and is located on a man-made waterway that conveys water primarily intended
for irrigation or that primarily conveys irrigation return flows.
Idaho Power also proposed that the provisions for implementation and compliance
with the definition and qualification for the higher canal drop hydro rate be contained in the firm
energy sales agreements between the utility and QFs. Comments at 7. Idaho Power
recommended that compliance be verified each year at year-end to ensure that the project's
ORDER NO. 32802 4
generation is eligible to receive the higher avoided cost rate. If the project failed to deliver its
energy during the proper time period, its rate would be changed to reflect the "hydro" published
avoided cost rate structure. Any overpayment received by the project based on the "canal drop
hydro" rates could be trued-up through energy payments made the following year.
Staff recommended replacing the term "canal drop hydro" with the term "seasonal
hydro." Staff asserted that the location of the hydro project and use of the water is less important
than whether the project reliably generates energy during the times when capacity is most
valuable to the utility. Comments at 3. Staff proposed to define a seasonal hydro project as one
that, over the last ten years, generated at least 90% of its average annual generation during the
months of April through October. New hydro projects would be required to demonstrate
compliance with the definition in the first year of operation with retroactive adjustment of rates if
the project fails to comply. Comments at 3.
Commission Findings: After a thorough review of the underlying record in this
case, the petitions for reconsideration, and comments and replies on reconsideration, the
Commission adopts new terminology to classify hydro projects within the SAR methodology
that better identifies the type of resource and timing of generation. We find that identifying the
formerly classified "canal drop hydro" projects as "seasonal hydro" projects better describes the
timing of the generation and the justification for higher avoided cost rates. We further find that a
modification of the definition of what classifies as a "seasonal hydro" project is necessary.
We find that the appropriate and reasonable definition of a "seasonal hydro" project
is a hydro generation facility that produces at least 55% of its annual generation during the
months of June, July, and August. We agree with the proposition that the higher avoided cost
rates available to these types of resources are based on the project's ability to deliver generation
when the utility is most in need of energy. We find that the modified definition recognizes a
utility's peak power consumption months and rewards projects that are able to deliver power
during peak times when the utility would otherwise have to utilize an alternative resource to
meet customer demand. Conversely, these projects do not produce energy that the utility is
compelled to purchase during non-peak months. We find that requiring a QF to produce 55% of
its generation during June, July and August when the utility is most in need of energy is a
reasonable threshold to satisfy entitlement to higher avoided cost rates.
ORDER NO. 32802 5
In order to ensure compliance with the requirement that 55% of a project's
generation must be produced during the months of June, July and August, we find it just and
reasonable for the utility to audit and verify the generation of a seasonal hydro project each year
at year-end. If a project fails to deliver at least 55% of its energy during the proper time period,
its rate will be changed to reflect the non-seasonal hydro published avoided cost rate structure.
Any overpayment received by a project based on a mischaracterization as a seasonal hydro
project should be trued-up through energy payments made to the project during the subsequent
year.
These changes to resource type and eligibility only impact new and renewing
projects. Current projects continue under their existing Agreements. As with any other change
in eligibility or rates, new contracts and replacement contracts are subject to the eligibility
criteria and rates in effect at the time that legal obligations are incurred.
RESOURCE SPECIFIC CAPACITY FACTORS
Idaho Power proposed the use of a different resource specific capacity factor for
canal drop hydro projects that, it claims, is based upon actual data from projects on Idaho
Power's system. Consequently, Idaho Power recommended use of a 67.1% capacity factor for
canal drop hydro projects. Idaho Power further proposed a 92% capacity factor for projects
falling within the "other" category based on the Northwest Power and Conservation Council's
forced outage data. Comments at 8. Idaho Power argues that a 100% capacity factor for any
resource is simply unreasonable. Id.
The Canal Companies support use of a 100% on-peak capacity factor for avoided
cost calculations of canal drop hydro projects. The Canal Companies argue that, because canal
drop hydro projects contribute capacity during the utility's summer peak season when the utility
would otherwise have to purchase energy from another source to meet its load, such projects
should be compensated for 100% of the capacity that a canal drop hydro project provides. The
Canal Companies maintain that their position is supported by the testimony and exhibits of
Commission Staff submitted in the underlying case. Comments at 2, n. 1. The Canal Companies
consider Idaho Power's capacity calculations for canal drop hydro projects to be flawed. The
Canal Companies maintain that Idaho Power's calculations are based on inaccurate and
imprecise data. The Coalition concurs with and adopts the position of the Canal Companies
regarding resource specific capacity factors.
ORDER NO. 32802 6
Commission Staff considered 20 years of Idaho Power data in order to identify the
day and hour of Idaho Power's summer and winter peak. Comments at 5. After a detailed
analysis of the approach used by Idaho Power to arrive at resource specific capacity factors and
the compilation of its own research and discovery material, Staff calculated an annual capacity
factor for seasonal hydro projects (aka canal drop hydro) at 32%. Staff further recommended
that non-seasonal hydro projects be assigned an annual capacity factor of 50% and "other"
projects be assigned an annual capacity factor of 89%.
On reply, Idaho Power concurred with Staffs analysis concerning the timing of
summer peak hours. Reply at 4. Idaho Power further stated that it believes "that Staffs analysis
addressed any deficiencies identified by other parties." Reply at 4. Idaho Power found Staff's
recommended peak hour and annual capacity factors reasonable given Idaho Power's proposed
definitional change for seasonal hydro projects. Reply at 5.
The Canal Companies acknowledged the "sound analysis undertaken by Staff' but
disagreed with Staffs recommended on-peak capacity value. Reply at 4. Specifically, the Canal
Companies disagreed with Staffs implicit assumption that the "avoided resource can and does
provide on-peak capacity 100% of the time." Reply at 3. The Canal Companies also disputed
Staffs use of a 901h percentile capacity (or exceedence) factor. Reply at 5.
Commission Findings: Based not only on the detailed analysis performed with
historical data, but also the acknowledgement of Idaho Power and the Canal Companies that
Staff's recommendations were based on a "sound analysis" that produced "reasonable" results,
the Commission finds that Staff's approach provides a fair, just and reasonable basis for
computing both peak hour and annual capacity factors. The Commission further finds that it is
just and reasonable to use a 901h percentile capacity factor in peak hour capacity factor
calculations. If a QF is to be awarded payment for providing capacity, then the utility must be
assured that the planned-on capacity will be available the vast majority of the time. Using a 90th
percentile capacity factor minimizes the risk that planned-on capacity is not available.
The Commission also finds merit in the Canal Companies assertion "that the avoided
resource cannot provide 100% on-peak deliveries 100% of the time." Reply at 3. Consequently,
the Commission finds that a 92% capacity factor for the SAR, which contemplates an 8% forced
outage rate for baseload resources (as identified in the Northwest Power and Conservation
Council's 6th Power Plan), is just and reasonable.
ORDER NO. 32802 7
Utilizing (1) a 92% capacity factor for the avoided resource and (2) the updated
definition of a seasonal hydro project results in the following annual and peak hour capacity
factors:1
The change in capacity factors for seasonal hydro, non-seasonal hydro and "other" projects has
no impact on these factors for wind and solar projects.
To be clear, these changes only impact new and renewing projects. Current projects
continue under their existing agreements. As with any other change in eligibility or rates, new
contracts and replacement contracts are subject to the eligibility criteria and rates in effect at the
time that legal obligations are incurred.
OWNERSHIP OF RENEWABLE ENERGY CREDITS (RECs)
RECs (also known as environmental attributes, green tags, or renewable trading
certificates) typically represent the environmental attributes associated with one megawatt-hour
(MWh) of electricity generated from an eligible renewable energy facility. RECs may be created
at renewable generating facilities operated by utilities, exempt wholesale generators (EWGs),
non-PURPA generators, or PURPA qualifying facilities ("QFs"). Order No. 32697 at 37. The
Commission's investigation in this case focused on REC transactions between QFs and Idaho
public utilities. Before addressing the issues on reconsideration, it is helpful to briefly review the
relevant regulatory landscape and the relationship between PURPA, renewable portfolio
standards ("RPS"), and RECs.
A. Background
1. PURPA. Congress passed PURPA in 1978 in response to a national energy crisis.
Its purpose was to lessen the country's dependence on foreign oil; encourage the development of
renewable energy technologies; and control consumer costs. FERC v. Mississippi, 456 U.S. 472,
1 Avoided cost rate tables for seasonal hydro, non-seasonal hydro and "other" based on these factors are attached.
ORDER NO. 32802 8
745, 46, 102 S.Ct. 2126, 2130 (1982). To encourage the development of renewable generating
facilities, Section 210 of PURPA requires electric utilities to purchase the power produced by co-
generators or small power producers that are determined to be eligible qualifying facilities (QFs)
under PURPA. 16 U.S.C. § 824a-3(b); 18 C.F.R. § 292.303(a). This mandatory purchase
requirement is often referred to as the "must purchase" provision of PURPA. FERC v.
Mississippi, 456 U.S. at 751, 102 S.Ct. at 2133; Order Nos. 32697 at 7, 32580 at 3.
2. Renewable Portfolio Standards (RPSs). A RPS typically requires an electric
utility to generate or purchase a certain percentage of its annual electric generation (its
"portfolio") from designated energy resources, or alternatively, meet its RPS obligation by the
purchase of unbundled RECs from renewable sources. Alliance to Protect Nantucket Sound v.
Dept. of Public Utilities, 959 N.E.2d 413, 419 n.7 (Mass. 2011); Order No. 32002. The creation
of RPS programs by the states occurred well after PURPA was enacted in 1978; RPS programs
have generally been adopted since about 1995. Steven Ferrey, et al. "Fire and Ice: World
Renewable Energy and Carbon Control Mechanisms Confront Constitutional Barriers," 20 Duke
Env'lL. & Policy F. 125, (Winter 2010 (hereinafter "Ferrey")). In other words, RECs did not
exist and were not contemplated when PURPA was enacted in 1978. Order No. 32697 at 37
citing American Ref-Fuel Co., 105 FERC 61,005 at 14 (2003) rehr 'g denied, 107 FERC 61,016
(2004) dismissed sub nom. for lack ofjurisdiction, Xcel Energy Services v. FERC, 407 F.3d 1242
(D.C.Cir. 2005); Order No. 29480 at 3. As FERC noted in American Ref-Fuel, adoption of RPSs
"are premised on promoting policy goals such as improved air and water quality, reduction of
greenhouse gas emissions, broader fuel diversity, enhanced energy security, and hedging against
the price volatility of fossil fuels." Order No. 32580 at 4 citing American Ref-Fuel Co., 105
FERC 61,005 at ¶ 4; see also Order No. 32697 at 37. Thus, PURPA and RPS programs were
created for different reasons. Order No. 32697 at 37.
As the Commission noted in its final Order No. 32697:
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 citing Ferrey
at 145. As the Second Circuit explained in Wheelabrator Lisbon v.
Connecticut Dept. Public Utility Control,
RECs are 'tradable certificates. . . that correspond to a certain amount
of renewable energy generated by a third party.' American Ref-Fuel,
105 FERC at ¶ 61,005. Generally speaking, RECs are inventions of
state property law whereby the renewable energy attributes are
ORDER NO. 32802 9
"unbundled" from the energy itself and sold separately. The credits
can be purchased by companies and individuals to offset use of energy
generated from traditional fossil fuel resources or. . . to satisfy certain
requirements that [utilities] purchase a certain percentage of their
energy from renewable resources.
531 F.3d 183, 186 (2d Cir. 2008) (emphasis added); 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 determine 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 American Ref-Fuel, 105 FERC [61,004] at ¶ 23;
Order No. 29480; Idaho Wind Partners, 136 FERC 61,174 at n.10 (Sept. 15,
2011) ("the sale and trading of RECs are for the states to decide"). Because
"RECs are state-created, different states can treat RECs differently."
American Ref-Fuel, 107 FERC 61,016 at n.4. (Emphasis added.)
Order No. 32697 at 37-3 8 (emphasis as indicated).
In its prior final Order, the Commission noted that the parties agreed the Idaho
Legislature has not implemented a RPS program nor has it enacted any statute addressing the
ownership or allocation of RECs. The Commission observed that it has stated on several
previous occasions that the "State of Idaho 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. 32697 at 38 citing Order Nos. 32580 at 9, 32480, 29577, 29630.
B. Prior Order No. 32697
1. Jurisdiction. In its prior Order, the Commission first took up the issue of whether
it has subject matter jurisdiction over RECs. Although the Commission recognized it is a
creature of statute and normally its jurisdiction is dependent upon statutory authority "once
jurisdiction is clear, the Commission is allowed all power that is either expressly granted by the
statute[s] or which may be fairly implied" to carry out its responsibilities. Idaho State
Homebuilders v. Washington Water Power Co., 107 Idaho 415, 418, 690 P.2d 350, 353 (1984).
The Commission found that it has jurisdiction to decide the REC issue for three primary reasons.
Id. at 43-45.
First, the Commission noted it was well settled that it has been granted authority to
review QF contracts and resolve disputes between QFs and electric utilities. Order No. 32697
citing A. W. Brown v. Idaho Power Co., 121 Idaho 812, 816, 828 P.2d 814, 845 (1992); Empire
Lumber Co. v. Washington Water Power Co., 114 Idaho 191, 755 P.2d 1229 (1988); Afton
ORDER NO. 32802 10
Energy v. Idaho Power Co. ("Afton I/Ill"), 107 Idaho 781, 693 P.2d 427 (1984); Idaho Code §
61-612. The Commission found that the "disposition of RECs is now a term that is found in
most, if not all, PURPA contracts." Order No. 32697 at 44. The Commission further declared
that since 1980, it has required that all PURPA contracts be submitted to the Commission for its
approval. Id. citing Order No. 15746, 38 P.U.R. 4th 352 (Idaho 1980); Order No. 29632 at 7;
Rosebud I, 128 Idaho at 620, 917 P.2d at 778; Rosebud II, 128 Idaho at 628, 917 P.2d at 785.
Likewise, Idaho Code §§ 61-502 and 61-503 authorizes the Commission to review and
investigate contracts with utilities that affect utility rates and charges. Order No. 32697 at 44.
Second, the Commission recognized in A. W. Brown, that the Idaho Supreme Court
rejected the QF's argument that the Commission has no jurisdiction "to litigate the common law
contract issues between [the QF] and Idaho Power. . . ." Order No. 32697 at 44 citing 121 Idaho
at 819, 828 P.2d at 848. In rejecting the QF's argument, the Court held that "the Commission
'has jurisdiction to hear complaints against utilities alleging violation of any provision of law.
." Id. The Commission also noted that the Court in Empire Lumber, declared the Commission
is "granted authority by the Idaho statutes to, and is the appropriate forum to resolve" PURPA
contract issues. Order No. 32697 at 44 citing 114 Idaho at 192, 755 P.2d at 1230.
Finally, the Commission found that it had authority to decide the REC issue because
RECs directly affect utility rates and the disposition of RECs is a common term contained in
most if not all PURPA agreements. Order No. 32697 at 44. The Commission observed that
utilities recover the cost of purchasing QF power initially through the annual Power Cost
Adjustment (PCA) mechanisms for Idaho Power and Avista, and in the Energy Cost Adjustment
Mechanism (ECAM) for Rocky Mountain. Id. citing Tr. at 392, 1107. The Commission found
that the revenue from the sale of RECs directly offsets the avoided cost rates that utilities must
pay QFs for power in PCA rates and base rates. Id. As the Supreme Court noted in Washington
Water Power Co. v. Kootenai Environmental Alliance, 99 Idaho 875, 880, 591 P.2d 122, 127
(1979), Idaho Code §§ 61-502 and 61-503 embody "the legislative grant of authority to the
Commission to deal broadly with existing and future rates, rate schedules and contracts affecting
rates." Order No. 32607 at 44.
2. Disposition of RECs. Despite the disagreement among the parties regarding the
disposition of RECs, the Commission noted there were several issues which were not in dispute.
First, all the parties agree that PURPA does not control RECs - RECs are controlled by the
ORDER NO. 32802 11
states. In other words, RECs exist outside the confines of PURPA. Id. at 45. Second, the
Commission found there was agreement among the parties that no Idaho law implements a
renewable portfolio standard (RPS) program or addresses the disposition of RECs. Id. citing
Order Nos. 32580, 29480 at 9. Finally, the Commission stated that the parties agree that Idaho's
avoided cost rates do not compensate QFs for RECs. Id. citing Order No. 32580 at 3 quoting
Morgantown Energy Associates, 139 FERC 61,066 at 147 (2012); see also California PUG, 133
FERC 61,059 at ¶ 31 n.62 (2010).
The Commission went on to describe RECs as intangible assets. "But for the 'must
purchase' provision of PURPA, RECs would not exist or be created for a PURPA project." Id. at
45. RECs are not tangible and do not "exist" until the renewable QF project produces a MW of
power. "RECs are non-physical assets which exist only in connection with something else, i.e.,
the purchase of renewable power under PURPA." Order No. 32580 at 10 citing Black's Law
Dictionary at 808 (6 0' ed. 1990). There is no REC without the generation of renewable power.
Order No. 32697 at 45-46 (footnote omitted).
Absent an agreement between the parties in a PURPA contract to do otherwise, the
Commission found it was reasonable to equally apportion RECs between the utility and QF when
the contract is based upon rates derived through the IRP Methodology. Id. at 46.2 "Because both
the utility and QF are contractually and inextricably joined in the production, sale and purchase
of QF power, we find that it is reasonable to apportion the unbundled RECs by 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." Id. The Commission observed that equally splitting RECs between the utility
and the QF has been approved in several recent Orders. Id. citing Order Nos. 32419, 32451,
32384, 32294, and 32125.
The Commission also found that dividing REC ownership equally between the utility
and the QF is in the public interest. Equally dividing RECs under the IRP Methodology provides
an additional revenue stream to QF developers, thereby encouraging the development of
renewable generation. "This promotes the underlying purpose of PURPA." Id. at 47 citing
Rosebud II, 128 Idaho at 627, 917 P.2d at 784. On the other hand, a utility's sale of RECs
produces revenue which directly offsets the cost of purchasing PURPA power from the QF and
For PTJRPA contracts using the surrogate avoided resource (SAR) methodology based on a natural gas-fired
generating resource, the Commission allocated the RECs to the QF because a natural gas resource produces no
RECs. Order No. 32697 at 46.
ORDER NO. 32802 12
provides a tangible benefit to ratepayers. Id. at 46 citing Tr. at 573, 1192, 1193-94; Order No.
32002. In other words, both the QF and the utility (including its ratepayers) share the benefits of
REC ownership. Id. at 47.
C. Reconsideration Issues
1. Jurisdiction. In its Petition for Reconsideration, the Idaho Conservation League
(ICL) renews its argument that the Commission does not have subject matter jurisdiction to
decide the REC issue. ICL generally presents two arguments. First, ICL asserts that Order No.
32697 oversteps the Commission's jurisdiction by presuming that RECs have been "dedicated to
public use." ICL Petition at 1-2. Relying on the early case of Idaho PUC v. Natatorium, 36
Idaho 287, 215 P. 533 (1922), ICL maintains that only QFs that "include RECs in [their PURPA]
contracts are making an unequivocal dedication of [REC5] to public use." Id. at 2. Conversely,
QFs that do not include RECs in their contracts are not dedicating RECs to public use, or in other
words, not subjecting RECs to the Commission's jurisdiction. Id.
Second, although the Commission recognizes that RECs are subject to state law, ICL
asserts the Commission did not determine who owns RECs in the first instance. ICL generally
argues that RECs "are an asset created through the efforts of QF developers," and the QF's
"property interest [in RECs] arise[s] spontaneously" and vests in the QF. Id. ICL notes that the
Court in a 1911 case held that a person who collects rain and snow melt on his property has
created a private property right in such water and the water is "not subject to the dedication to
public use of water." Id. citing King v. Chamberlin, 20 Idaho 504, 118 P. 1099 (1911). The
Commission should not presume that RECs are dedicated to public use and subject to the
Commission's jurisdiction.
Idaho Power filed a timely answer asserting that the Commission "clearly has subject
matter jurisdiction to make determinations regarding the ownership of RECs in the PPAs.
Answer and Cross-Petition at 17. Idaho Power argued that its previous legal brief confirms that
State Commissions, the U.S. Court of Appeals for the Second Circuit, and the Appellate Courts
of Connecticut, New Jersey, Pennsylvania, and West Virginia "all agree that ownership of RECs
is decided by States even in the context of a PURPA power sales [Agreement]." Id.
Commission Findings: After reviewing the underlying record, the previously filed
legal briefs, and the points raised in ICL's reconsideration Petition, we affirm our initial decision
made in Order No. 32697 that the Commission has subject matter jurisdiction to decide the REC
ORDER NO. 32802 13
dispute in PURPA contracts. In addition to those reasons set out in our prior Order, the
Commission finds that there are several other points supporting our jurisdiction.
At the outset, we find that our authority over PURPA contracts does not arise solely
from State statutes. In the context of a PURPA contract, the Idaho Supreme Court has declared
that PURPA imposes "requirement on state regulatory authorities in excess of their duties under
state law." Afton I/Ill, 107 Idaho at 785, 693 P.2d at 431 (emphasis added). The Court declared
that the United States Supreme Court in FERC v. Mississippi "stated that through PURPA the
federal government attempted to use state regulatory machinery to advance federal goals. The
Court held as constitutional the requirements of Section 210 which 'has the States enforce
standards promulgated by FERC.' Thus, it is clear that PURPA was intended to confer upon
state regulatory commissions responsibilities not conferred under state law." Id. quoting FERC
v. Mississippi, 456 U.S. at 759, 102 S.Ct. at 2137 (emphasis added).
In Empire Lumber, the Idaho Supreme Court observed that the Commission's
PURPA responsibilities can be accomplished in a manner subsumed or consistent with its
statutory authority over public utilities. The "Commission is the agency authorized . . . to
supervise and regulate electric utilities, and has ratemaking authority over such utilities. The
Commission as part of its statutory duties determines reasonable rates and investigates and
reviews contracts. The Commission also has jurisdiction to hear complaints against utilities
alleging violation of any provision of law or of any order . . . of the Commission." Empire
Lumber, 114 Idaho at 192, 755 P.2d at 1230 (internal citations omitted and emphasis added)
citing Idaho Code §§ 61-129, 61-501, 61-502, 61-503, 61-612. As the United States Supreme
Court held in FERC v. Mississippi, the state utility commission "can satisfy [PURPA] § 210's
requirements simply by opening its doors to [PURPA] claimants. . . . Congress determined that
the federal rights granted by PURPA can appropriately be enforced through state adjudicatory
machinery," i.e., the Idaho Commission. 456 U.S. at 760, 102 S.Ct. at 2137; Afton I/Ill, 107
Idaho at 789, 693 P.2d at 435. Although RECs are not controlled by PURPA, the disposition of
RECs is addressed in PURPA contracts with other necessary terms and conditions. See Empire
Lumber, 114 Idaho at 192, 755 P.2d at 1230.
We find ICL's reliance upon the Natatorium case and whether QFs have dedicated
RECs "to public use" to be misplaced for two primary reasons. First, ICL infers that if PURPA
agreements do not contain references to RECs, then RECs are not dedicated to "the public use."
ORDER NO. 32802 14
However, as the Commission previously found, most if not all PURPA contracts do address
RECs. Order No. 32697 at 44. Second, in Idaho PUC v. Natatorium, the issue was whether the
Natatorium Company was a public utility subject to the Commission's regulatory jurisdiction
under Idaho Code §§ 61-125, 61-129. The Court in Natatorium examined whether the company
devoted its physical assets to the "public use" and supplied water to customers. In this case we
are not examining whether a QF is operating as a public utility. More specifically, the sale of
RECs by itself does not make the QF a utility. Idaho Code § 61-129. In fact, PURPA exempts
QFs from most but not all state utility regulation. 16 U.S.C. § 824a-3(b), (e); 18 C.F.R. §
292.602(c)(1)(i, ii); Rosebud I, 128 Idaho 614, 917 P.2d at 771; Afton I/Ill, 107 Idaho at 787-88,
693 P.2d at 433-34. What is at issue here is the appropriate disposition of RECs. Consequently,
we find the test for determining whether a company is a public utility is not applicable or
controlling over the issue of REC ownership.3
We also find ICL's reliance on King v. Chamberlin, 20 Idaho at 504, 118 P. at 1099
is misplaced. ICL Petition at 2. In King, the Court ruled that a person who collects rain and
snow melt on his property holds the resulting water as private property. ICL argues that, like
captured water, "RECs are an asset created through the efforts of QF developers. . . ." Id
However, King too is distinguishable for several reasons. First, a person who collects water from
rain and snow on his property has tangible property, i.e., the water. Here, RECs are intangible
property. As we found in our prior final Order, but for the "must purchase" requirement of
PURPA, the generation of renewable power and the resulting RECs would not exist or be
created. RECs are non-physical assets which exist only in connection with something else, i.e.,
the generation of renewable power. Order No. 32697 at 45-46 citing Order No. 32580 at 10;
Black's Law Dictionary at 808 (6 t"ed. 1990). With PURPA contracts, there is the added
compulsion of the utility's "must purchase" obligation. When a QF utilizes PURPA to compel a
utility to purchase its renewable power, the RECs would not be created but for the "must
purchase" requirement imposed on the utility.
Second, a person capturing snow or rain for his own use is not a water utility
corporation. Idaho Code §§ 61-125, 61-129. Third, the disposition of RECs is now a common
The facts of Natatorium are also distinguishable. The case was decided on stipulated facts. The parties stipulated
that "Surplus hot water has never been offered for sale to any person [and] the said natural hot water was strictly a
private and not a public use. . . ." Stoehr v. Natatorium, 34 Idaho 217, 220, 200 P. 132, 133 (1921); Idaho PUG v.
Natatorium, 36 Idaho at 334,211 P. at 547 (Duim,J., dissenting).
ORDER NO. 32802 15
provision in Idaho PURPA contracts. Besides having jurisdiction over contracts that affect
utility rates under Idaho Code §§ 61-502 and 61-503, the Commission has jurisdiction to
approve PURPA contracts, including any REC provisions contained in the agreements. A. W.
Brown, 121 Idaho at 816, 828 P.2d at 846; Empire Lumber, 114 Idaho at 192, 755 P.2d at 1229.
Finally, our Supreme Court also recognized that the Commission may resolve
disputes between QFs and electric utilities. Order No. 32697 at 44 and cases noted therein.
There can be no disagreement that the parties here dispute the appropriate disposition and
ownership of RECs as part of this generic PURPA investigation. Given these reasons, we
conclude we have jurisdiction to decide the REC issue. Having found jurisdiction, we now turn
to the ownership of RECs.
2. Ownership of RECs. ICL, Renewable Northwest Project (RNP), and
Simplot/Clearwater Paper all seek reconsideration regarding the Commission's decision that
RECs under the IRP methodology belong equally to both the QF developer and the utility. ICL
asserted that the Commission's decision to apportion RECs equally between the QF and the
utility is not adequately explained nor supported by substantial and competent evidence. ICL
Petition at 3. Although ICL conceded the utilities have renewable resources in their generation
portfolio, this fact does not support allocating a portion of RECs to utilities. Id
ICL agreed with the Commission's decision that RECs should belong to the QF
under the SAR Methodology. Likewise, Simplot/Clearwater does not request reconsideration of
the Commission's decision that QFs retain RECs in contracts with SAR-based rates. Petition at
4 n.2. RNP also does not challenge the Commission's REC decision for SAR-based QF
contracts. RNP at 2-3.
Simplot/Clearwater challenged the Commission's determination that the RECs
belong equally to the utility and the QF when rates are derived through the IRP Methodology.
They argued that the Commission's decision violates PURPA by: (1) assuming QFs are
compensated for RECs in the avoided cost rates; (2) discriminating against QFs versus non-QFs;
and (3) discriminating against large QFs by denying them their full avoided cost. Petition at 11.
For its part, RNP argued that Idaho common law vests ownership of RECs with the QF. Petition
at 3. RNP also insisted that the Commission has not laid out a rational basis for evenly dividing
RECs between the utility and the QF. Id. at 3-4. Finally, RNP asserted that the Order
ORDER NO. 32802 16
unreasonably discriminates against wind and solar QFs based upon generating technology with
no discernible rationale. Id
Idaho Power filed a timely answer to the three Petitions for Reconsideration and
submitted a Cross-Petition for Reconsideration. Idaho Power urged the Commission to deny
reconsideration on the REC issues. Idaho Power invited the Commission to review its arguments
and citations to authority in the REC portion of its legal brief. Answer at 19; see IPC Legal Brief
at 79-97. Just as ICL, RNP and Simplot/Clearwater asserted that the QFs are owners of RECs,
Idaho Power advocated in its Cross-Petition "that the utilit[ies] be determined the owners of
RECs in the initial instance." Id.
In Order No. 32737, the Commission granted reconsideration on the issue of RECs.
The Commission found that further evidence is not necessary because the primary issues are
questions of law. Order No. 32737 at 2; Rule 332. Consequently, the Commission did not seek
further legal briefing because the REC issue "has already been the subject of extensive legal
briefing by the parties in this case." Id. at 2-3. In addition, the reconsideration parties do not
raise new legal issues for us to consider. Consequently, the Commission declared that it would
reconsider its REC decision based upon the existing record and previously filed legal arguments.
Commission Findings: We begin our reconsideration of the REC issue by
reiterating that ownership of RECs is determined by the States. RECs exist outside the confines
of PURPA. States have the power to determine who owns the RECs in the initial instance.
Order No. 32697 at 37-38, 47; American Ref-Fuel, 105 FERC 61,004; Wheelabrator Lisbon v.
Connecticut Dept. of Pub. Util. Control, 532 F.3d 183, 186 (2d Cir. 2008); Wheelabrator Lisbon
v. Connecticut Dept. of Pub. Util. Control, 526 F.Supp.2d, 295, 305 (Conn. 2006); In Re
Ownership of Renewable Energy Certificates, 913 A.2d 825, 830-31 (App.N.J. 2007);
Wheelabrator Lisbon v. Dept. of Pub. Util. Control, 931 A.2d 159, 173-74 (Conn. 2007); Idaho
Wind Partners, 136 FERC 61,174 at n.10 (2011). Moreover, "RECs are separate commodities..
and [are] not part of the avoided cost calculation." California PUC, 133 FERC 61,059 at ¶ 31
n.62 (2010); Order Nos. 32580 at 8, 32697 at 45.
The Idaho Supreme Court has recognized that PURPA contracts represent a "special
type of contract." Afton I/Ill, 107 Idaho at 793, 693 P.2d at 439; Afton Energy v. Idaho Power
Co. ("Afton V"), 114 Idaho 852, 854, 761 P.2d 1204, 1206 (1988). In our view, what makes
them a "special type of contract" is the fact that federal law compels utilities to purchase power
ORDER NO. 32802 17
without arms-length bargaining and without regard to whether the utility needs the power.
Wheelabrator Lisbon v. Dept. of Public Util. Control, 921 A.2d 159, 174 (Conn. 2007).
The Idaho Supreme Court has declared that "Freedom of contract is a fundamental
concept underlying the law of contract and is an essential element of the free enterprise system."
Morrison v. Northwest Nazarene University, 152 Idaho 660, 661, 273 P.3d 1253, 1254 (2012)
quoting Rawlings v. Layne & Bowles Pump Co., 93 Idaho 496, 499, 465 P.2d 107, 110 (1970);
Order No. 32580 at 10. However, the utility as a party to a PURPA contract is not wholly free to
bargain because PURPA compels utilities to purchase the power output produced by QFs.
PURPA compels the utility to purchase power whether it needs the power to serve load or not.
Even if QF power replaces power the utility would otherwise generate, ratepayers are ultimately
paying for both the capital assets of the utility's baseload generating plant in rates and the QF
power. While PURPA compels the underlying purchase of eligible renewable power, the RECs
are intangible assets which arise only because of their association with the generation of
renewable power under the "must purchase" provision. In other words, but for the must
purchase provision of PURPA there is no requirement to purchase - no PPA - and RECs would
not exist or be created. Order No. 32580 at 10.
The question of REC ownership hinges upon which party has a property interest in
RECs. Whether a party has a compensable property interest in RECs presents "a question of law
based upon factual underpinnings." See Mohien v. United States, 74 F.Cl. 656, 660 (2006)
quoting Walcek v. United States, 303 F.3d 1349, 1354 (Fed.Cir.) citing Wyatt v. United States,
271 F.3d 1090, 1096 (Fed.Cir. 2001), cert denied sub nom. E. Minerals Intl v. United States,
535 U.S. 1077, 122 S.Ct. 1960 (2002).
The Supreme Court of Connecticut's Wheelabrator Lisbon v. Dept. of Pub. Util.
Control decision is instructive in analyzing the ownership issues surrounding RECs. In that case,
the Court affirmed the state regulatory commission's decision that the ownership of RECs under
existing PURPA agreements that do not mention RECs vests with the utility. The Connecticut
Supreme Court addressed several factors in its analysis. First, it noted that PURPA's must
purchase provision compels utilities to purchase power that it would not otherwise be obligated
to purchase but for PURPA. Wheelabrator, 931 A.2d at 174. Second, the RECs are
"inexplicably tied to the [QF's] production of electricity." Id In other words, but for the
PURPA requirement that utilities purchase the power generated by QFs, RECs would not be
ORDER NO. 32802 18
created nor would they be contemplated within the context of a PURPA contract. Moreover, the
disposition of RECs has become a standard provision in PURPA contracts. Third, PURPA
requires that the utility must purchase the power without any demonstration that the utility needs
the power. Id. at 175. Finally, providing all the RECs to the QF would result in a windfall to
them. Id. at 174-75.
The Court went on to declare that
the term [REC] "unbundling" itself implies that the renewable attribute of the
energy generated by renewable energy resources is an inherent attribute of the
energy, and, therefore, the creation and state recognition of the certificates did
not result in an entirely new commodity but in the splitting of a pre-existing
commodity, i.e., "electricity," that the utility had contracted to purchase. It
was reasonable, therefore, for the [state regulatory agency] to conclude that
the word "electricity," as used in [the state statute] and the 1991 agreement
meant renewable energy. In other words, the term "electricity" necessarily
included the renewable attribute that later was "unbundled" from the energy
and represented by the certificates. Accordingly, we conclude that the
Department reasonably determined that the certificates were owned by the
utility.
Wheelabrator, 931 A.2d at 176 (footnote omitted). See also Order No. 32697 at 38-39 citing Tr.
at 223-25.
On the other hand, we recognize that QFs must first generate the power before a REC
is created. QFs must build their facilities and interconnect with the utility purchasing the
generated power under the PURPA contract. Second, providing all the RECs to the utility would
result in a windfall to the utility. Wheelabrator, 931 A.2d at 175 n.24. We have also noted that
the secondary source of REC income for QFs further encourages the development of renewable
resources consistent with the goals of PURPA and intent of this Commission.
We find these utility and QF property interest factors applicable in considering the
ownership of RECs. We find that Idaho common law does not vest RECs exclusively in either
the QF or the utility. We find especially important the fact that PURPA compels the purchase
and that utilities must purchase QF power whether needed or not. These facts are balanced
against the QF's investment in the renewable facility and the Congressional goal of promoting
renewables. Although the Connecticut Court and other courts have concluded that RECs belong
to the utility, we affirm our previous decision that RECs under the IRP methodology should be
equally divided between the QF and the utility. After considering the factual underpinnings of
ORDER NO. 32802 19
how RECs are created as set out above, we find that it is just, reasonable and in the public
interest that the ownership (i.e., the property interest) of RECs should be vested equally in both
the utility and the QF. We conclude that RECs under the IRP methodology should be equally
shared by the parties while still allowing for some contractual flexibility.
Based upon the factual underpinnings above, we find there is substantial and
competent evidence that the QFs do not have an exclusive cognizable property interest in RECs.
See also Ruckeishaus v. Monsanto Co., 467 U.S. 986, 1001, 104 S.Ct. 2862, 2871 (1984)
("Property interests . . . are not created by the Constitution. Rather they are created and their
dimensions are defined by existing rules or understandings that stem from an independent source
such as state law.").
3. Substantial and Competent Evidence. The three parties challenging our REC
decision allege there is not substantial and competent evidence supporting the Commission's
decision that the ownership of RECs under the IRP methodology resides equally in both the
utility and QF. We disagree for several reasons.
Commission Findings: First, we note there is compelling authority from other states
that RECs belong to the utility in their entirety. While we do not find that RECs belong entirely
to utilities, several states have adopted this position -just like other states that have adopted RPS
and REC programs. As the appellate court in New Jersey noted, nine states have ruled that
RECs "are the property of the purchasing utility rather than the producer" in contracts that do not
reference RECs or in PURPA contracts that were entered into before the concept of RECs arose.
In Re Ownership of Renewable Energy Certificates, 913 A.2d 825, 828 (N.J.App. 2007) citing
Edward A. Holt et al., "Who Owns Renewable Energy Certificates? An Exploration of Policy
Options and Practice," at 14 (2006). Tr. at 222-25; Wyoming Order No. 12750 at ¶ 63; Ferrey
at 145-46. Second, allocating RECs equally to both parties mitigates arguments that RECs
apportioned to either party in their entirety results in a windfall. As we have noted in this and
past Orders, RECs provide an incentive and encouragement for the development of QF facilities
and also help to offset the expense of renewables when retained by the utility for the benefit of
ratepayers - all of which are recognized as goals of PURPA. Rosebud II, 128 Idaho at 627, 917
P.2d at 784; Order No. 32697 at 47.
Published by the Ernest Orlando Lawrence Berkley National Laboratory, available at:
eetd.lbl.gov/ealemp/reports/599965.pdf.
ORDER NO. 32802 20
Third, we found in final Order No. 32697 that IRP-based rates are derived from the
utility's actual resource portfolio which contains both renewable and non-renewable generating
resources. Order No. 32697 at 46. Thus, IRP rates reflect the actual generation characteristics of
the utility's generating resources, including renewable resources. According to the 2012 Idaho
Energy Plan adopted by the Idaho Legislature on March 6, 2012, Avista's resource mix is
reported to be 54% renewable (biomass and hydro); Idaho Power's resource mix is reported to be
54.6% renewable (hydro, wind, geothermal and biomass); and PacifiCorp non-carbon emitting
resources are reported to be approximately 24% of its portfolio. Energy Plan at 29-30; HCR 34
(2012).5 In addition, as "a stand-alone utility, PacifiCorp is second only to Mid-America Energy
Company in ownership of wind generation. . . . At year-end 2010, PacifiCorp had more than
1,000 megawatts of owned wind generation capacity and long-term purchase agreements for
more than 600 megawatts from wind projects owned by others." Id. at 29-31. Moreover, the
Energy Plan reports that Idaho dams produce "in an average year approximately half of Idaho's
2010 electricity consumption." § 2.3.2 at p. 42 (emphasis added). More importantly, we have
found based upon the property interest facts set out above, that it is reasonable and just to vest
REC ownership equally between the QF and the utility. The resource mix in the IRP
methodology further supports our decision that RECs belong equally to utilities and QFs.
Consequently, we find that there is substantial and competent evidence supporting the
Commission's decision to split RECs equally between utilities and QFs under the IRP
methodology.
4. Technology Distinction. RNP and to some extent Simplot/Clearwater argued that
vesting RECs equally between the QF and the utility "unreasonably penalizes wind and solar
resources as compared to other technologies." RNP at 3. Because the eligibility cap for wind
and solar is set at 100 kW, RNP argues that the Order in effect "assigns RECs from QFs sized
100 kW to 10 aMW to utilities only for wind and solar technologies." Id. at 4.
Commission Findings: RNP's argument misses the mark. First, our prior Order
does not "assign RECs from [wind and solar] QFs sized 100 kW to 10 MW to utilities." Id. In
fact, RECs for wind and solar QFs larger than 100 kW are equally divided between the utility
ICL asked us to take official notice of Idaho Power's IRP. ICL Petition at 4 n. 1. Without relying on the IRP for
this Order, we noted that Idaho Power's 2011 IRP shows its 2010 supply-side resources were 48.4% hydro, 3.1%
wind, .5% biomass, .5% waste, and 46.5% fossil fuel. Fig. 1.3. Under the projected 2030 fuel mix, fossil fuel
resources are estimated to reduce to approximately 35% while hydro and other renewables increase to more than
63% (with the inclusion of .5% nuclear power). Fig. 1.4, Case No. IPC-E-ll-11.
ORDER NO. 32802 21
and the QF. Second, it appears the RNP's real argument is that the eligibility cap for the
published avoided cost rates for wind and solar projects is set at 100 kW. That decision was
made in an earlier case (GNR-E-11-01). In that case, the Commission found that it was
appropriate to set the eligibility cap for the published SAR-based avoided cost rates at 100 kW
for wind and solar QFs. Order No. 32697 at 3-4 citing Order No. 32262.
As we have noted in past Orders, PURPA and its implementing regulations require
that the published/standard avoided cost rates be established and made available to QFs with
design capacity of 100 kW or less. 18 C.F.R. § 292.304(c). Moreover, in establishing the
eligibility criteria for a published avoided cost rate, the Commission may differentiate among
QFs using various technologies. 18 C.F.R. § 292.304(c)(3). Order No. 32262 at 1. Over the
years, the eligibility for standard rates has ranged from the minimum requirement of 100 kW or
less to projects as large as 10 MW. Id. at 8. In Phase II of our generic PURPA investigation, we
set the eligibility cap for wind and solar QF projects at 100 kW. Id. at 8-9. No party (including
RNP) sought reconsideration of the Commission's eligibility cap Order No. 32262 (Case No.
GNR-E-11-01). Thus, wind and solar projects larger than 100 kW are entitled to PURPA
contracts at avoided cost rates calculated using the IRP methodology. Order No. 32262 at 8.
Third, as we stated in Order No. 32580, FERC regulations provide that the
calculation of avoided costs may differentiate among QFs "using various technologies on the
basis of the supply characteristics of the different technologies." Order No. 32580 at 8 quoting
18 C.F.R. § 292.304(c)(3)(ii). In Order No. 32176, we distinguished wind and solar from other
QF resources such as hydro, biomass, cogeneration, geothermal and water-to-energy. We found
in Phase I and affirmed in Phase II of this generic PURPA investigation that:
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 assure system reliability.
Order Nos. 3176 at 9; 32212 at 15-16; 32262 (affirming the 100 kW eligibility cap for wind and
solar). "Wind and solar projects larger than 100 kW continue to be entitled to PURPA contracts
at avoided cost rates calculated using the IRP Methodology." Order No. 32262 at 8. Moreover,
ORDER NO. 32802 22
the disposition of RECs is not dependent on the type of renewable resource. The disposition of
RECs relies on the methodology used in calculating a QF's avoided cost.
Finally, as set out above we find that REC ownership vests in both the QF and the
utility. The Commission has the authority to differentiate rates based on specific characteristics
of different technologies. The States (this Commission) further retain the authority to assign
ownership of RECs. This Commission assigns REC ownership based on the generating resource
used to calculate the rate. SAR rates, now based on a natural gas resource, assign RECs to the
QF because an equivalent facility constructed by the utility would not generate RECs. Projects
subject to the IRP rate methodology enjoy rates based on the actual renewable project being
constructed whether constructed by the QF or the utility. Therefore, we find it equitable to split
the RECs under these circumstances. Consequently, the Order does not unreasonably
discriminate among generating technologies. Again, RECs are based on the acquired property
right based upon the factors outlined above.
5. Taking. Simplot/Clearwater argue that the vesting of RECs equally in both the
utility and the QF means that "QFs must cede half of their RECs for no additional payments."
Petition at 16. They also insist that vesting REC ownership equally between the QF and the
utility constitutes a taking of property without just compensation in violation of both the U.S.
and Idaho Constitutions. Id. at 19. They characterize the allocation of RECs to utilities as a
"gift" of 50% of the RECs, or a taking without just compensation. Id at 20.
Commission Findings: Simplot/Clearwater's argument mischaracterized the
Commission's Order No. 32697 and is off the mark. The Commission is not requiring QFs to
give half their RECs to the utility. The Commission is finding that the utility and the QF, based
upon the rationale set out above, equally share a property right in the RECs based on the
renewable characteristics and how the avoided cost rate for such projects is derived.
Consequently, we have not taken or impaired a QF's ability to sell its property interest in half the
RECs. Order No. 32697 at 47. "As the Connecticut Supreme Court found in a similar case, the
PUC's 'decision [to vest RECs in the utility] could not constitute an unconstitutional taking
under the State's Constitution because no property owned by the [QF] has been taken." Id.
quoting Wheelabrator, 931 A.2d at 177; Wheelabrator Lisbon, 526 F.Supp.2d at 307 (D.Conn.
2006) affirmed, 531 F.3d 183 (2d Cir. 2008). In other words, the QFs do not possesses a
ORDER NO. 32802 23
cognizable property interest in all of the RECs - only their half of the RECs. Thus, no taking has
occurred.
Simplot/Clearwater point to the power purchase agreement regarding the Neal Hot
Springs geothermal facility as an example of discrimination between a non-QF and a QF
generator. However, this comparison is not appropriate as it compares dissimilar projects. As
they acknowledge, the Neal geothermal facility is not a PURPA project. Order No. 31087 at 2.
Consequently, the parties were at liberty to bargain and negotiate the various terms of their
agreement including whether there would even be a contract. Moreover, our Order No. 32697
regarding the disposition of RECs is not inconsistent with PURPA because: (1) PURPA does not
apply to the disposition of RECs; and (2) there is no assumption that IRP-based avoided cost
rates compensate QFs for RECs. Indeed, we have been steadfast and clear in stating that avoided
cost rates do not compensate QFs for RECs.
Another important point to remember is that this Order and the prior final Order No.
32697 do not affect any existing PURPA contracts. In addition, we further recognize that the
parties have flexibility in negotiating the allocation of RECs. Parties may negotiate disposition
of REC ownership. Order No. 32697 at 46.
6. Dormant Commerce Clause. Simplot/Clearwater also argued that the
Commission's Order No. 32697 "directs the utilities to take title to an interstate commodity
created by other states' RPS laws - RECs." Petition at 24. They further characterize the Order
as unlawfully requiring "RECs to be processed in-state and then resold out-of-state by the
Commission's chosen proprietors." Id. at 25.
Commission Findings: The Commerce Clause of the United States Constitution
gives Congress the power to regulate commerce among the States. Art. I, § 8, Cl. 3. "The
United States Supreme Court has consistently held that the Commerce Clause includes a 'further,
negative command, known as the dormant Commerce Clause." Alliance to Protect Nantucket,
959 N.E.2d 413, 421 n.12 (2011) (citations omitted). The dormant Commerce Clause has been
interpreted to prohibit "different treatment of in-state and out-of-state economic interests that
benefits the former and burdens the latter, as opposed to state law that regulates evenhandedly
with only incidental effects on interstate commerce." Id. (internal punctuation and citations
omitted). The crucial inquiry is whether the Commission's REC decision is basically a
protectionist measure or can it fairly be viewed as a decision directed to legitimate state
ORDER NO. 32802 24
concerns, with only incidental effects on interstate commerce. McBurney v. Young, - U.S. -,
S.Ct. -, 2013 WL 1788080, Slip Op. (April 29, 2013) citing Philadelphia v. New Jersey, 437
U.S. 617, 624, 98 S.Ct. 2531 (1978).
Contrary to Simplot/Clearwater's assertion, there is no different treatment between
in-state and out-of-state economic interests - the ownership of RECs is for States to determine
and our REC decision evenhandedly applies both to in-state utilities and QFs, and to out-of-state
QFs selling to Idaho utilities.6 Wheelabrator, 531 F.3d at 186; American Ref-Fuel, 105 FERC
61,004 at ¶ 23; Idaho Wind Partners, 136 FERC 61,174 at ¶ n.10. Our REC decision is not
protectionist and is directed to a legitimate state interest - deciding REC ownership. In addition,
Simplot/Clearwater has not adequately shown that vesting ownership of RECs under Idaho law
equally to the QF and the utility has burdened interstate commerce. Utilities and QFs may sell
their RECs to in-state or out-of-state entities. Moreover, out-of-state utilities may be subject to
entirely different REC or RPS standards, unlike Idaho that has neither. Based on the foregoing,
we find no dormant Commerce Clause violation.
"Insofar as RECs are state-created, different states can treat RECs differently."
American Ref-Fuel, 107 FERC 61,016 at n.4. When a QF project derives its avoided cost rate
based on the resource's renewable characteristics, the resource avoided by the utility is presumed
to be a like resource - renewable. But for the "must purchase" obligation imposed by PURPA,
the utility would be generating the energy - and creating RECs - with its own like resources.
Under such circumstances, it is just and reasonable to equally apportion ownership of RECs
between the QF and the utility.
CONCLUSION
The Idaho Public Utilities Commission has jurisdiction over electric utilities and the
issues raised in this matter pursuant to the authority and power granted it under Title 61 of the
Idaho Code and the Public Utility Regulatory Policies Act of 1978 (PURPA). The Commission
has authority under PURPA and the implementing regulations of the Federal Energy Regulatory
Commission (FERC) to set avoided costs, to order electric utilities to enter into fixed-term
obligations for the purchase of energy from qualified facilities (QFs) and to implement FERC
rules. It is well-settled that the Commission has the authority to review contracts and resolve
disputes between QFs and electric utilities. Thus, REC ownership - having been delegated to the
6 Idaho QFs selling to out-of-state utilities is beyond the scope of our jurisdiction.
ORDER NO. 32802 25
states and inextricably linked to PURPA generation - is a matter appropriately resolved by this
Commission.
The Commission has reviewed the underlying record, including the petitions,
responses, comments, and replies filed on reconsideration by the parties in this case. Based on
the record, we find that the foregoing findings and conclusions are just and reasonable. We
further find that the conclusions are supported by substantial and competent evidence.
IT IS HEREBY ORDERED that gas and load forecasts used' in IRP methodologies
shall occur annually on October 15.
IT IS FURTHER ORDERED that new or renewing "canal drop hydro" projects be
designated as "seasonal hydro" projects. A "seasonal hydro" project shall be defined as a hydro
generating facility that produces at least 55% of its annual generation during the months of June,
July and August.
IT IS FURTHER ORDERED that capacity factors for "seasonal hydro," "non-
seasonal hydro," and "other" projects utilizing the SAR methodology be modified as more
particularly described herein.
IT IS FURTHER ORDERED that RECs produced by projects utilizing the IRP
Methodology be apportioned equally between the utility and the QF.
THIS IS A FINAL ORDER ON RECONSIDERATION. Any party aggrieved by this
Order or other final or interlocutory Orders previously issued in this Case No, GNR-E-11-03
may appeal to the Supreme Court of Idaho pursuant to the Public Utilities Law and the Idaho
Appellate Rules. See Idaho Code § 61-627.
ORDER NO. 32802 26
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 1 ph
day of May 2013.
PAUL KJELTANDtR,'P1UESIDENT
MACK A. REDFORD, CbMMISSIONER
1~ '/ a)~'
MARSHA H. SMITH, COMMISSIONER
ATTEST:
Jh D. J'ewelyj
Commission Secretary
O:GNR-E-1 1-03ks8FinaI Reconsideration
ORDER NO. 32802 27
AVISTA
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
May 6, 2013
$IMWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 30.25 33.34 34.38 35.49 2012 30.53
2 30.45 30.30 31.73 33.84 34.91 36.12 2013 30.35
3 30.39 31.24 32.54 34.34 35.49 36.84 2014 30.25
4 31.04 31.93 33.19 34.89 36.15 43.93 2015 33.34
5 31.60 32.53 33.80 35.49 41.70 48.80 2016 34.38
6 32.12 33.10 34.43 40.00 45.88 52.58 2017 35.49
7 32.64 33.70 38.25 43.62 49.29 55.61 2018 36.81
8 33.18 36.95 41.43 46.68 52.14 58.09 2019 38.48
9 35.98 39.76 44.21 49.30 54.52 60.16 2020 69.05
10 38.46 42.26 46.62 51.54 56.54 61.99 2021 72.79
11 40.70 44.47 48.72 53.46 58.33 63.67 2022 76.90
12 42.71 46.41 50.54 55.19 59.99 65.20 2023 80.16
13 44.50 48.12 52.19 56.79 61.50 66.59 2024 82.50
14 46.09 49.67 53.73 58.25 62.87 67.88 2025 84.57
15 47.54 51.13 55.14 59.59 64.16 69.10 2026 87.28
16 48.91 52.47 56.43 60.84 65.36 70.26 2027 90.86
17 50.17 53.70 57.63 62.01 66.50 71.35 2028 93.66
18 51.33 54.85 58.77 63.12 67.58 72.43 2029 96.12
19 52.42 55.93 59.84 64.16 68.64 73.50 2030 99.22
20 53.45 56.96 60.85 65.19 69.67 74.49 2031 102.47
2032 105.80
2033 109.07
2034 113.98
2035 119.12
2036 121.78
2037
I I
126.02
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy Outlook
2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case" at http://www.eia.gov/oiaf/aeo/tablebrowser/.
Attachment
Order No. 32802
Case No. GNR-E-1 1-03
A VISTA
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
May 6, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 30.25 33.34 34.38 35.49 2012 30.53
2 30.45 30.30 31.73 33.84 34.91 36.12 2013 30.35
3 30.39 31.24 32.54 34.34 35.49 36.84 2014 30.25
4 31.04 31.93 33.19 34.89 36.15 48.31 2015 33.34
5 31.60 32.53 33.80 35.49 45.05 55.83 2016 34.38
6 32.12 33.10 34.43 42.67 51.49 61.41 2017 35.49
7 32.64 33.70 40.43 48.21 56.54 65.77 2018 36.81
8 33.18 38.78 45.27 52.74 60.63 69.25 2019 38.48
9 37.54 43.02 49.35 56.51 63.99 72.12 2020 88.92
10 41.27 46.68 52.82 59.68 66.81 74.60 2021 92.95
11 44.54 49.84 55.78 62.37 69.27 76.83 2022 97.35
12 47.41 52.58 58.33 64.75 71.49 78.82 2023 100.91
13 49.93 54.97 60.61 66.91 73.49 80.62 2024 103.55
14 52.15 57.12 62.68 68.86 75.28 82.27 2025 105.93
15 54.16 59.08 64.56 70.62 76.94 83.80 2026 108.96
16 56.01 60.87 66.27 72.24 78.47 85.24 2027 112.85
17 57.70 62.51 67.84 73.75 79.91 86.59 2028 115.97
18 59.24 64.02 69.31 75.16 81.26 87.90 2029 118.75
19 60.68 65.42 70.68 76.48 82.56 89.17 2030 122.19
20 62.01 66.74 71.96 77.75 83.82 90.35 2031 125.77
2032 129.45
2033 133.06
2034 138.33
2035 143.82
2036 146.84
I
2037 151.45
I
Note: A "seasonal hydro project" is defined as a generation facility which produces at least 55% of its annual generation during the months
of June, July, and August. Order 32802
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy Outlook
2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case" at http://www.eia.gov/oiaf/aeo/tablebrowser/.
A VISTA
AVOIDED COST RATES FOR OTHER PROJECTS
May 6, 2013
$IMWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
-•
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 30.25 33.34 34.38 35.49 2012 30.53
2 30.45 30.30 31.73 33.84 34.91 36.12 2013 30.35
3 30.39 31.24 32.54 34.34 35.49 36.84 2014 30.25
4 31.04 31.93 33.19 34.89 36.15 42.24 2015 33.34
5 31.60 32.53 33.80 35.49 40.40 46.07 2016 34.38
6 32.12 33.10 34.43 38.97 43.70 49.15 2017 35.49
7 32.64 33.70 37.40 41.84 46.49 51.68 2018 36.81
8 33.18 36.24 39.94 44.34 48.85 53.77 2019 38.48
9 35.38 38.49 42.21 46.51 50.85 55.54 2020 61.36
10 37.37 40.54 44.22 48.38 52.56 57.11 2021 64.99
11 39.22 42.39 45.98 50.01 54.09 58.58 2022 68.98
12 40.90 44.02 47.53 51.49 55.54 59.93 2023 72.12
13 42.40 45.47 48.94 52.87 56.86 61.16 2024 74.35
14 43.74 46.79 50.26 54.15 58.07 62.32 2025 76.30
15 44.98 48.05 51.49 55.32 59.21 63.41 2026 78.89
16 46.16 49.21 52.62 56.42 60.29 64.46 2027 82.34
17 47.25 50.29 53.68 57.46 61.31 65.46 2028 85.02
18 48.27 51.30 54.69 58.46 62.28 66.45 2029 87.35
19 49.23 52.26 55.64 59.40 63.25 67.43 2030 90.32
20 50.14 53.17 56.55 60.32 64.20 68.34 2031 93.45
2032 96.65
2033 99.78
2034 104.56
2035 109.55
2036 112.07
I I
2037
I
116.17
Note: "Other projects" refers to projects other than wind, solar, non-seasonal hydro, and seasonal hydro projects. These "Other projects"
may include (but are not limited to): cogeneration, biomass, biogas, landfill gas, or geothermal projects.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)s Annual Energy Outlook
2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case" at http://www.eia.gov/oiaf/aeo/tablebrowser/.
IDAHO POWER COMPANY
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
May 6, 2013
$IMWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
CONTRA7ON-LEVELIZED LENGTH
RATES (YEARS) 2012 2013 2014 2015 2016 2017 YEAR
1 30.53 30.35 34.36 60.45 61.88 63.39 2012 30.53
2 30.44 32.28 46.89 61.14 62.60 64.22 2013 30.35
3 31.65 40.94 51.50 61.83 63.38 65.14 2014 34.36
4 38.02 45.58 54.13 62.56 64.22 65.92 2015 60.45
5 42.08 48.60 56.00 63.34 64.98 67.02 2016 61.88
6 44.97 50.84 57.52 64.07 65.98 68.30 2017 63.39
7 47.21 52.67 58.76 65.00 67.16 69.58 2018 65.11
8 49.08 54.16 60.03 66.07 68.33 70.75 2019 67.20
9 50.64 55.61 61.34 67.16 69.43 71.81 2020 68.66
10 52.13 57.04 62.60 68.18 70.43 72.84 2021 72.40
11 53.58 58.39 63.76 69.13 71.41 73.89 2022 76.50
12 54.94 59.63 64.82 70.05 72.40 74.90 2023 79.75
13 56.19 60.75 65.84 70.99 73.36 75.85 2024 82.09
14 57.33 61.82 66.84 71.90 74.27 76.79 2025 84.15
15 58.40 62.86 67.80 72.76 75.16 77.70 2026 86.86
16 59.44 63.84 68.70 73.61 76.03 78.60 2027 90.43
17 60.43 64.77 69.58 74.43 76.89 79.48 2028 93.23
18 61.35 65.66 70.43 75.24 77.72 80.37 2029 95.68
19 62.24 66.52 71.26 76.03 78.57 81.28 2030 98.77
20 63.09 67.36 72.06 76.84 79.42 82.13 2031 102.02
2032 105.34
2033 108.61
2034 113.51
2035 118.64
2036 121.29
I
-
2037
I
125.53
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)s Annual Energy Outlook
2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case' at http://www.eia.gov/oiaf/aeo/tablebrowser/.
IDAHO POWER COMPANY
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
May 6, 2013
$IMWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 35.98 78.68 80.38 82.16 2012 30.53
2 30.44 33.06 56.49 79.50 81.23 83.12 2013 30.35
3 32.15 47.09 63.84 80.32 82.13 84.17 2014 35.98
4 42.45 54.46 67.89 81.17 83.11 85.07 2015 78.68
5 48.89 59.16 70.65 82.08 83.98 86.30 2016 80.38
6 53.40 62.55 72.81 82.92 85.11 87.71 2017 82.16
7 56.83 65.22 74.53 83.96 86.40 89.10 2018 84.16
8 59.61 67.38 76.19 85.15 87.69 90.39 2019 86.53
9 61.88 69.36 77.82 86.35 88.90 91.57 2020 88.27
10 63.96 71.23 79.35 87.48 90.02 92.71 2021 92.29
11 65.91 72.95 80.75 88.53 91.10 93.87 2022 96.68
12 67.70 74.51 82.03 89.56 92.20 94.98 2023 100.23
13 69.32 75.92 83.23 90.60 93.26 96.04 2024 102.87
14 70.78 77.24 84.41 91.61 94.27 97.08 2025 105.23
15 72.14 78.51 85.53 92.56 95.25 98.09 2026 108.25
16 73.44 79.70 86.59 93.50 96.22 99.08 2027 112.13
17 74.66 80.82 87.60 94.42 97.17 100.05 2028 115.25
18 75.80 81.89 88.58 95.32 98.09 101.04 2029 118.02
19 76.88 82.91 89.53 96.20 99.02 102.03 2030 121.44
20 77.91 83.89 90.45 97.08 99.96 102.97 2031 125.02
2032 128.68
2033 132.29
2034 137.54
2035 143.02
2036 146.03
I I
2037
I
150.63
Note: A "seasonal hydro project" is defined as a generation facility which produces at least 55% of its annual generation during the months
of June, July, and August. Order 32802
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy Outlook
2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case' at http://www.eia.gov/oiaf/aeo/tablebrowser/.
IDAHO POWER COMPANY
AVOIDED COST RATES FOR OTHER PROJECTS
May 6, 2013
$IMWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 32.38 53.39 54.72 56.12 2012
-
30.53
2 30.44 31.33 42.47 54.03 55.39 56.90 2013 30.35
3 31.04 38.11 46.23 54.67 56.11 57.77 2014 32.38
4 35.99 41.78 48.42 55.35 56.91 58.50 2015 53.39
5 39.17 44.22 50.00 56.09 57.62 59.55 2016 54.72
6 41.47 46.05 51.32 56.77 58.58 60.79 2017 56.12
7 43.28 47.58 52.41 57.65 59.70 62.02 2018 57.74
8 44.82 48.84 53.56 58.68 60.84 63.14 2019 59.72
9 46.11 50.10 54.76 59.73 61.89 64.16 2020 61.07
10 47.38 51.37 55.93 60.71 62.85 65.15 2021 64.70
11 48.65 52.59 57.01 61.62 63.79 66.15 2022 68.68
12 49.86 53.71 58.00 62.50 64.74 67.12 2023 71.82
13 50.97 54.73 58.94 63.40 65.66 68.04 2024 74.05
14 51.99 55.70 59.88 64.27 66.53 68.93 2025 75.99
15 52.95 56.66 60.78 65.09 67.38 69.81 2026 78.58
16 53.90 57.57 61.64 65.90 68.22 70.67 2027 82.03
17 54.80 58.43 62.46 66.69 69.03 71.51 2028 84.70
18 55.64 59.26 63.27 67.47 69.83 72.37 2029 87.02
19 56.46 60.06 64.05 68.23 70.65 73.24 2030 89.99
20 57.24 60.83 64.81 69.00 71.47 74.06 2031 93.11
2032 96.31
2033 99.44
2034 104.21
2035 109.20
2036 111.71
I I
2037 115.81
Note: "Other projects' refers to projects other than wind, solar, non-seasonal hydro, and seasonal hydro projects. These "Other projects"
may include (but are not limited to): cogeneration, biomass, biogas, landfill gas, or geothermal projects.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy Outlook
2012 released June 25, 2012. See 'Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case" at http://www.eia.gov/oiaf/aeo/tablebrowser/.
PACIFICORP
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
May 6, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 56.39 59.86 61.28 62.78 2012 30.53
2 30.44 42.87 58.06 60.54 62.00 63.61 2013 30.35
3 38.44 48.11 59.05 61.23 62.77 64.52 2014 56.39
4 43.19 51.03 59.88 61.96 63.62 65.30 2015 59.86
5 46.28 53.03 60.67 62.75 64.37 66.40 2016 61.28
6 48.53 54.60 61.47 63.47 65.38 67.69 2017 62.78
7 50.32 55.94 62.21 64.40 66.55 68.97 2018 64.50
8 51.85 57.08 63.11 65.48 67.73 70.14 2019 66.58
9 53.15 58.26 64.13 66.57 68.83 71.21 2020 68.03
10 54.43 59.47 65.16 67.59 69.84 72.25 2021 71.76
11 55.72 60.65 66.14 68.55 70.82 73.30 2022 75.85
12 56.95 61.75 67.06 69.48 71.82 74.31 2023 79.09
13 58.09 62.76 67.95 70.42 72.79 75.27 2024 81.42
14 59.14 63.73 68.85 71.34 7170 76.22 2025 83.48
15 60.14 64.69 69.72 72.21 74.60 77.14 2026 86.18
16 61.12 65.61 70.55 73.06 75.48 78.05 2027 89.74
17 62.05 66.48 71.37 73.90 76.35 78.93 2028 92.52
18 62.93 67.32 72.17 74.72 77.19 79.84 2029 94.96
19 63.78 68.14 72.95 75.52 78.05 80.76 2030 98.05
20 64.60 68.94 73.72 76.34 78.92 81.63 2031 101.28
2032 104.60
2033 107.85
2034 112.75
2035 117.86
2036 120.50
2037 124.73
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)s Annual Energy Outlook
2012 released June 25, 2012. See Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case" at http://www.eia.gov/oiaf/aeo/tablebrowser/.
PACIFICORP
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
May 6, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT
I
ON-LINE YEAR
-
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 73.97 77.70 79.38 81.15 2012 30.53
2 30.44 51.32 75.76 78.51 80.23 82.10 2013 30.35
3 43.85 59.45 76.88 79.32 81.12 83.14 2014 73.97
4 51.37 63.87 77.82 80.17 82.09 84.05 2015 77.70
5 56.14 66.82 78.73 81.07 82.97 85.27 2016 79.38
6 59.55 69.04 79.65 81.91 84.09 86.68 2017 81.15
7 62.20 70.89 80.50 82.95 85.38 88.07 2018 83.13
8 64.39 72.42 81.51 84.14 86.67 89.36 2019 85.49
9 66.22 73.93 82.64 85.35 87.88 90.54 2020 87.21
10 67.95 75.43 83.78 86.48 89.00 91.69 2021 91.22
11 69.61 76.85 84.86 87.54 90.09 92.85 2022 95.60
12 71.17 78.17 85.87 88.57 91.19 93.97 2023 99.13
13 72.59 79.37 86.86 89.61 92.26 95.03 2024 101.75
14 73.89 80.52 87.86 90.63 93.28 96.07 2025 104.10
15 75.12 81.64 88.83 91.59 94.27 97.10 2026 107.10
16 76.30 82.72 89.75 92.54 95.24 98.10 2027 110.97
17 77.42 83.73 90.66 93.47 96.20 99.08 2028 114.07
18 78.48 84.70 91.54 94.37 97.13 100.07 2029 116.82
19 79.49 85.65 92.41 95.26 98.08 101.08 2030 120.23
20 80.46 86.56 93.26 96.16 99.03 102.03 2031 123.79
2032 127.44
2033 131.02
2034 136.26
2035 141.72
2036 144.71
I
2037
I
149.29
Note: A 'seasonal hydro project' is defined as a generation facility which produces at least 55% of its annual generation during the months
of June, July, and August. Order 32802
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy Outlook
2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case" at http://www.eia.gov/oiaf/aeo/tablebrowser/.
PACIFICORP
AVOIDED COST RATES FOR OTHER PROJECTS
May 6, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
V
CONTRACT
__
WA
ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 49.56 52.95 54.27 55.67 2012 30.53
2 30.44 39.60 51.20 53.59 54.95 56.45 2013 30.35
3 36.34 43.71 52.15 54.23 55.67 57.32 2014 49.58
4 40.03 46.06 52.93 54.91 56.47 58.05 2015 52.95
5 42.46 47.70 53.67 55.65 57.17 59.10 2016 54.27
6 44.26 49.00 54.43 56.33 58.13 60.34 2017 55.67
7 45.72 50.15 55.13 57.21 59.26 61.57 2018 57.29
8 46.99 51.14 55.98 58.25 60.40 62.70 2019 59.26
9 48.08 52.19 56.96 59.30 61.45 63.73 2020 60.60
10 49.20 53.29 57.96 60.28 62.42 64.72 2021 64.22
11 50.34 54.38 58.89 61.20 63.36 65.73 2022 68.20
12 51.45 55.39 59.77 62.09 64.32 66.70 2023 71.34
13 52.48 56.33 60.62 62.99 65.25 67.62 2024 73.55
14 53.43 57.23 61.49 63.87 66.12 68.53 2025 75.49
15 54.34 58.12 62.32 64.70 66.99 69.41 2026 78.07
16 55.24 58.98 63.12 65.52 67.83 70.28 2027 81.51
17 56.10 59.80 63.90 66.32 68.66 71.13 2028 84.18
18 56.91 60.59 64.67 67.11 69.47 72.00 2029 86.50
19 57.70 61.37 65.42 67.88 70.29 72.89 2030 89.46
20 58.46 62.12 66.15 68.66 71.13 73.72 2031 92.57
2032 95.76
2033 98.88
2034 103.64
2035 108.62
2036 111.13
2037 115.22
Note: "Other projects" refers to projects other than wind, solar, non-seasonal hydro, and seasonal hydro projects. These 'Other projects'
may include (but are not limited to): cogeneration, biomass, biogas, landfill gas, or geothermal projects.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)s Annual Energy Outlook
2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain, Reference
case" at http://www.eia.gov/oiaf/aeo/tablebrowser/.