20120720Legal Brief.pdf

HO
POWER
An IDACORP Company
202 JUL 20 ..P14 4:5I
DONOVAN E. WALKER
Lead Counsel
dwaIkeridahopower.com JTLT ES COMMtSSiON
July 20, 2012
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
Boise, Idaho 83702
Re: Case No. GNR-E-11-03
PURPA SAR and IRP Methodologies - Legal Brief of Idaho Power Company
Dear Ms. Jewell:
Enclosed for filing in the above matter are an original and seven (7) copies of the
Legal Brief of Idaho Power Company.
Very yours,
onovan E. Walker
DEW:csb
Enclosures
1221 W. Idaho St. (83702)
P.O. Box 70
Boise, ID 83707
DONOVAN E. WALKER (ISB No. 5921)
JASON B. WILLIAMS (ISB No. 8718)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
dwaIkercidahopower.com
iwiIIiams(idahopower.com
RECEIVED
212JuL20 PM :5f
rj)J:.
UT1L1gES COMj:
Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE
SURROGATE AVOIDED RESOURCE
(SAR) AND INTEGRATED RESOURCE
PLANNING (IRP) METHODOLOGIES FOR
CALCULATING PUBLISHED AVOIDED
COST RATES.
CASE NO. GNR-E-11-03
LEGAL BRIEF OF IDAHO POWER
COMPANY
LEGAL BRIEF OF IDAHO POWER COMPANY - Cover Page
I. INTRODUCTION 2
A. PROCEDURAL HISTORY 2
B. PURPA REQUIRES CUSTOMER INDIFFERENCE 5
C. CURRENT IDAHO IMPLEMENTATION OF PURPA HARMS CUSTOMERS 7
D. IDAHO POWER'S RECOMMENDATIONS 8
1.Authorize Idaho Power to use a revised IRP avoided cost 8
methodology for all QFs
2.Authorize Idaho Power to limit the term of PURPA contracts to five 9
years
3. Authorize Idaho Power to adopt its proposed Schedule 73, which 10
establishes an express process and timeline for the negotiation of
PURPA contracts without published rates
4. Authorize Idaho Power to adopt its proposed Schedule 74, which 11
establishes a process for curtailment of QF output consistent with
FERC rule 304(f)
S. Establish that utility purchasers of QF output own the RECs associated 11
with that output
II. ARGUMENT 12
A. THE COMMISSION SHOULD AUTHORIZE IDAHO POWER TO USE THE 12
HOURLY INCREMENTAL COST METHODOLOGY FOR ALL QFS
1. Statutory and regulatory definition of avoided cost 12
a."Avoided Cost" defined ("Rule 101(b)(6)") 12
b.FERC's Four Factors Affecting Avoided Cost ("Rule 304(e)") 12
c.PURPA does not permit avoided cost rates to subsidize QF 15
development.
2. The Hourly Incremental Cost Methodology 17
3. The Hourly Incremental Cost Methodology Closely Adheres to the 18
Definition of Avoided Cost Established by FERC and PURPA
4. Proposed Changed to the Avoided Cost Model Inputs 20
a. Change Proxy Resource from a CCT to a SCCT for the Avoided Cost 20
of Capacity
b. Source of Natural Gas Price Forecast for AURORA Simulations 20
c. Frequency of Refreshing Inputs to the Model 21
S. Use of the SAR Methodology Should be Eliminated for Idaho Power 21
6. The Hourly Incremental Cost Methodology can Accommodate the Four 22
FERC Factors in Rule 304(e)
7. The Intervenors' objections to Idaho Power's proposed methodology 23
are unpersuasive
8. The Commission Should Maintain its Presently Required Delay 27
Damages and Delay Damage Security in QF Contracts
B. THE COMMISSION SHOULD LIMIT THE TERM OF PURPA QF 32
CONTRACTS TO FIVE YEARS
1.The Commission has authority to set a five-year term for fixed price 32
contracts.
2.A Shorter Contract Term Protects Customers by Implementing More 35
Accurate Avoided Cost Rates
3. A Shorter Contract Term Properly places Investment Risks on the QF 37
and its Investors, and not on Utility Customers
C. THE COMMISSION SHOULD APPROVE IDAHO POWER'S TARIFF 39
SCHEDULE 73- FORMAL CONTRACTING PROCEDURE
1. Schedule 73 will benefit QFs, utilities, and the Commission by 41
lowering transaction costs and reducing disputes.
2. Participants agree that a Commission-authorized negotiation process 42
and procedure would be beneficial.
3. No materially significant objections to Schedule 73 have been raised. 43
4. Schedule 73 is ripe for Commission approval. 45
D. THE COMMISSION SHOULD APPROVE IDAHO POWER'S TARIFF 45
SCHEDULE 74- OPERATIONAL DISPATCH
1. FERC Rule 304(f) remains a viable exception to the must-buy 46
obligation.
2. Rule 304(f) is not limited to "real-time" contracts. 47
3.Rule 304(f) applies to existing, fixed-price, contracts. 52
4.Idaho Power's proposal to implement Rule 304(f) with Schedule 74 is 54
not novel.
5.Idaho Power's proposed Schedule 74 comports with PURPA. 57
E. THE COMMISSION SHOULD DETERMINE THAT UTILITY PURCHASERS 66
OF QF GENERATION OWN RENEWABLE ENERGY CREDITS
ASSOCIATED WITH THAT GENERATION
1.States have the authority to decide the ownership of RECs. 69
2.The Commission has the subject-matter jurisdiction to decide 73
ownership of RECs from PURPA sales even in the absence of an Idaho
RPS statute.
3.The Idaho Commission should hold that utilities own all 79
environmental attributes or RECs associated with QF energy sold to
the utilities under the PURPA must-buy obligation.
4.Awarding RECs to the utility does not make a Constitutional taking or 88
conflict with American Ref-FueL
5.The Commission should use its inherent authority to recognize that, in 92
the absence of a state RPS and REC program ownership of RECs
associated with Idaho QFs belong to the utilities.
6.In the alternative, the Commission should authorize the utilities to 95
include a "reservation of rights" provision in each QF power purchase
agreement clarifying that ownership of RECs is currently
undetermined but will follow any determinations ultimately made by
Idaho statute or regulation.
III. Conclusion 98
DONOVAN E. WALKER (ISB No. 5921)
JASON B. WILLIAMS (ISB No. 8718)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
dwaIkeridahopower.com
iwilliams(idahopower.com
Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE
SURROGATE AVOIDED RESOURCE
(SAR) AND INTEGRATED RESOURCE
PLANNING (IRP) METHODOLOGIES FOR
CALCULATING PUBLISHED AVOIDED
COST RATES.
CASE NO. GNR-E-11-03
LEGAL BRIEF OF IDAHO POWER
COMPANY
Pursuant to the schedule set forth in Idaho Public Utilities Commission
("Commission") Order No. 32388, Idaho Power Company ("Idaho Power') hereby
respectfully submits this legal brief in support of Idaho Power's recommendations to the
Commission in the above-captioned matter.
LEGAL BRIEF OF IDAHO POWER COMPANY -1
I. INTRODUCTION
A. PROCEDURAL HISTORY
On November 5, 2010, Idaho Power, Avista, and Rocky Mountain Power filed a
joint petition in Case No. GNR-E-10-04 requesting that the Commission investigate
issues related to avoided cost rates and the State of Idaho's implementation of the
Public Utility Regulatory Policies Act of 1978 ("PURPA"). In the joint petition, the utilities
expressed concern with the volume of intermittent qualifying facility ("QF") generation
under PURPA contract or seeking PURPA contracts. Joint Petition at 3-4. Idaho Power
noted that at the present rate of growth the volume of QF generation forced on Idaho
Power through PURPA contracts could exceed Idaho Power's minimum load in the near
term. Id. at 4. The utilities noted that large QF projects are disaggregating to
inappropriately take advantage of more favorable published avoided cost rates intended
for small projects. Id. at 5-6. The utilities also noted that the rapid expansion of
intermittent QF generation is creating significant system reliability, integration, and
operational impacts that are inadequately addressed under Idaho's current
implementation of PURPA and result in direct and substantial harm to customers. Id. at
4-5.
In comments filed on December 22, 2010, in Case No. GNR-E-10-04, Idaho
Power provided additional discussion regarding its concerns with the current avoided
cost methodologies and related PURPA implementation issues. Idaho Power noted that
the current method of calculating avoided cost rates in Idaho is leading to results that
are inaccurate and inflated. Comments of Idaho Power at 17-19, Case No. GNR-E-10-
04 (Dec. 22, 2010). Idaho Power noted that power purchased under such contracts is
LEGAL BRIEF OF IDAHO POWER COMPANY -2
purchased at rates significantly exceeding those required by PURPA to the substantial
harm of utility ratepayers and the public interest. Id. at 19 ("It is difficult to see how the
customers are held neutral, or indifferent, with a requirement to enter into FESAs, at
above-market prices, for power that is not needed on the system and also withholds the
value that could be derived from the RECs."). In sum, the utilities urged the
Commission to investigate its avoided cost rates and related PURPA implementation
issues and to make changes as necessary to remedy the situation and to protect the
public interest. Joint Petition at 1, 8. By way of interim relief to reduce the impact of
these problems, the utilities asked the Commission to immediately reduce the eligibility
cap for published avoided cost rates from 10 aMW to 100 kW. Id at 2, 8.
On December 3, 2010, the Commission declined to immediately lower the
eligibility cap; instead the Commission issued notice of a modified procedure to serve as
Phase I of the Commission's investigation. Order No. 32131. The modified procedure
involved written comment and oral argument on the question of whether to lower the
eligibility cap as an interim protective measure. The Commission indicated that any
decision to lower the eligibility cap would become effective December 14, 2010. Id. at
9. On February 7, 2001, the Commission issued Order No. 32176 in which it
determined to temporarily lower the eligibility criteria from 10 aMW to 100 kW for all
wind and solar QFs effective December 14, 2010. The order also directed the parties to
meet to establish a proposed schedule for Phase II of the investigation.
On February 25, 2011, the Commission issued Order No. 32195 in which it
established a schedule for Phase II of its investigation, designated as Case No. GNR-E-
11-01. The purpose of Phase II was to determine a long-term solution to the problem of
LEGAL BRIEF OF IDAHO POWER COMPANY -3
large projects that disaggregate into small projects and take inappropriate advantage of
published avoided cost rates. After a technical hearing and other modified procedure,
the Commission issued Order No. 32262 on June 8, 2011, in which it decided to
address disaggregation by making permanent the 100 kW cap on eligibility to published
avoided cost rates for wind and solar Us.
Order No. 32262 also directed the parties to meet to establish an issue list and a
schedule for Phase Ill of the Commission's investigation into avoided cost rates and
related PURPA issues. The Commission stated that it was initiating "additional
proceedings to allow the parties to investigate and analyze both the SAR Methodology
and the IRP Methodology" and that the Commission encouraged "a full examination of
the application of the IRP Methodology and [is] open to considering alternatives to the
current methodologies." Order No. 32262 at 8-9. In its Notice of Review for Phase Ill—
designated Case No. GNR-E-1 1-03—the Commission further described the scope of
the instant case:
[T]he Commission seeks information regarding the
appropriateness of both the SAR and the IRP-based avoided
cost methodologies. Specifically, the calculation of avoided
cost rates for both published and negotiated contracts, is
being re-examined. . . . [T]he Commission anticipates that
the scope of this inquiry will also include (but is not limited
to) considerations regarding the dispatchability of varying
resources, curtailment options, integration costs, renewable
energy credits, delay security and liquidated damages,
timing and schedule of negotiations, and contract
milestones.
Order No. 32352 at 4.
In Order No. 32288 dated November 2, 2011, the Commission established a
Phase Ill schedule including the filing of direct and rebuttal testimony in January, May
LEGAL BRIEF OF IDAHO POWER COMPANY -4
and June of 2012, the filing of all legal briefs by July 20, 2012, and a technical hearing
to occur August 7 to August 9, 2012.
On March 12, 2012, Idaho Power filed a Motion for a Temporary Stay of its
Obligation to Enter into New Power Purchase Agreements with Qualifying Facilities
during the pendency of this proceeding. The Commission, in denying Idaho Power's
request for a stay, entered findings, "that the methodologies previously approved by this
Commission, as utilized and applied by Idaho Power, do not currently produce rates that
reflect Idaho Power's avoided costs and are not just and reasonable, nor in the public
interest." Order No. 32498, p. 2. The Commission ordered that all QF contracts with
Idaho Power for projects over 100 kW be presented to the Commission for individual
evaluation with regard to all terms contained therein. Id.
Parties in this docket have previously filed direct and rebuttal testimony. Idaho
Power now respectfully submits this legal brief in compliance with the Commission's
scheduling order.
B. PURPA REQUIRES CUSTOMER INDIFFERENCE
Congress passed PURPA to encourage the development of renewable energy
technology as an alternative to fossil fuel technology and as an alternative to utility
owned generation. Under Section 210 of PURPA, a public utility must generally
purchase all output from a QF at the utilities "avoided cost" rate. "Avoided cost" is the
cost that the utility would have paid for the capacity and energy obtained from the QF if
the utility had purchased the capacity and energy from another source or generated the
power itself. 18 C.F.R. § 292.101(b)(6); see also Order No. 32176 at 1.
LEGAL BRIEF OF IDAHO POWER COMPANY -5
The avoided cost rate paid by a utility for QF output must be just and reasonable
to the ratepayers of the utility, in the public interest, and must not discriminate against
QFs. 16 U.S.C. § 824a-3(b). In determining the avoided cost rate, "the utility must take
into account all alternative sources including third-party suppliers and does not have to
buy power it does not need." New PURPA Section 210(m) Regulations Applicable to
Small Power Production and Cogeneration Facilities, 114 FERC 161,043 at P9 (2006)
(citing Southern California Edison Company and San Diego Gas & Electric Company,
70 FERC 61,215 at 61,677-78, reconsideration denied, 71 FERC 161,269 at 62,078
(1995)).
Congress directed the Federal Energy Regulatory Commission ("FERC") to
promulgate regulations to implement PURPA. 16 U.S.C. § 824a-3(a)-(b); Connecticut
Light and Power Co., 70 FERC 161,012, 61,023 (1995). FERC's regulations delegate
to the States the responsibility to establish avoided cost rates. Connecticut Light and
Power Co., 70 FERC ¶ 61,012, 61,024. In setting PURPA avoided cost rates, States
may not require utilities to pay more than their avoided cost. Id. at 61,029-030; So. Cal.
Edison v. Pub. Util. Comm., 101 Cal. App. 4th 384, 398-99, 124 Cal. Rptr. 2d 281
(2002). In general, the avoided cost rates paid for QF output are fully recoverable from
a utility's ratepayers. It is a fundamental premise of PURPA implementation that
ratepayers should remain indifferent to, and unharmed by, avoided cost rates. 16
U.S.C. § 824a-3(b); 18 CFR § 292.304(a)(2); Indep. Energy Producers Assn v.
Val.Pub.Utils. Comm'n, 36 F.3d 848, 858 (9th Cir. 1994). The Commission has
recognized the need for this important principle in its implementation of PURPA in the
state of Idaho. See e.g., Order No. 32262 at 8 ("PURPA entitles Us to a rate
LEGAL BRIEF OF IDAHO POWER COMPANY -6
equivalent to the utility's avoided cost, a rate that holds utility customers harmless—not
a rate at which a project may be viable.").
C. CURRENT IDAHO IMPLEMENTATION OF PURPA HARMS CUSTOMERS
Idaho Power has identified several problems with the current implementation of
PURPA that result in unnecessarily inflated avoided cost rates that exceed the
requirements of PURPA and that have lead to a flood of over-priced PURPA contracts.
Idaho Power's direct testimony in this matter establishes that, as of the time of
filing direct testimony in this matter, it currently had 119 Commission-approved QF
power purchase agreements that represent a nameplate capacity of 989 MW and a
contractual obligation of more than $3.6 billion. Idaho Power Direct Test. M. Stokes at
Ex. Nos. 1, 2 (Jan. 31, 2012). The large increase in QF projects on-line and under
contract since 2004 increased the power supply expense passed on to customers
through Idaho Power's annual Power Cost Adjustment from approximately $40 million in
2004 to approximately $60 million in 2009, and will increase the annual Power Cost
Adjustment to more than $120 million in 2012. Direct Test. Stokes at 9-10. Assuming
no new PURPA contracts, Idaho Power's annual PURPA power supply cost is expected
to increase to $167 million by 2014 and to $186 million by 2026 as contracted projects
come online. Id. This represents an approximate 465 percent increase in customer-
borne cost from 2004 to 2026. Id. This will result in dramatic rate increases for all of
Idaho Power's customers. Idaho Power Direct Test. L. Grow at 10-11 (Jan. 31, 2012).
Idaho Power has submitted extensive testimony demonstrating that the present
system for implementing PURPA in Idaho is resulting in harm to ratepayers. No party to
this proceeding has contradicted or rebutted Idaho Power's assertions of customer
LEGAL BRIEF OF IDAHO POWER COMPANY -7
harm. The Commission itself has found "that the methodologies previously approved by
this Commission, as utilized and applied by Idaho Power, do not currently produce rates
that reflect Idaho Power's avoided costs and are not just and reasonable, nor in the
public interest." Interlocutory Order No. 32498 at 2. As a result, it is incumbent on the
Commission to revise its implementation scheme as necessary to eliminate this
customer harm and provide for a system whereby customers are indifferent to PURPA
purchases while at the same time faithfully fulfilling the requirements of FERC's PURPA
regulations and ensuring that Us receive the true avoided cost rates to which they are
entitled.
D. IDAHO POWER'S RECOMMENDATIONS
Idaho Power has recommended five pnmaryrevisions 1 for the Commission to
make to its PURPA implementation scheme which, if adopted, would faithfully
implement FERC's PURPA regulations, would better ensure accurate avoided cost
rates, and would better ensure that customers are held harmless. Specifically, Idaho
Power recommends the following.
1. Authorize Idaho Power to Use a Revised IRP Avoided Cost
Methodology for All QFs
First, Idaho Power has recommended that the Commission approve Idaho
Power's Hourly Incremental Costmethodology for establishing avoided cost rates for all
QFs. Stokes, Direct, p. 4. The Hourly Incremental Cost methodology is a modivied
version of the currently approved Integrated Resource Plan ("IRP") based avoided cost
1 These five primary revisions do not cover all issues that are before the Commission in this proceeding
and that are addressed by Idaho Power in its testimony. To the extent this brief omits any such issues,
Idaho Power's position is unchanged from its testimony. Idaho Power does not concede any issue not
specifically discussed herein, and specifically reserves the right to raise, contest, agree, or otherwise
address all issues before the Commission.
LEGAL BRIEF OF IDAHO POWER COMPANY -8
methodology. This modified methodology for calculating avoided cost rates is superior
to Idaho Power's previous IRP methodology or SAR methodologies for several reasons.
First, it is simple and transparent. This increases the ability of all parties—Idaho Power,
QF developers, and Commission staff—to apply the methodology and understand its
implications. Idaho Power's proposed modified methodology uses the highest cost
displaceable resource (rather than using estimated off-system sales price or a
proxy/surrogate resource price) to value QF output during periods of system surplus
generation because such an approach better fits FERCs definition of avoided cost.
Lastly, the proposed modified methodology assumes more frequent refreshment of
model inputs to minimize the lag between when inputs change and when those changes
are reflected in calculated avoided costs. These features allow for an approach to
avoided cost calculation which is more closely aligned to the requirements of PURPA
than is possible using either the SAR methodology or the previously employed IRP
methodology.
2. Authorize Idaho Power to Limit the Term of PURPA Contracts to Five
Years
Second, Idaho Power has recommended that the Commission authorize the
utilities to enter into PURPA contracts with a five-year term rather than a twenty-year
term. Stokes, Direct, p. 4. Idaho Power is not aware of any FERC decision declaring
that a five-year limit on fixed price contracts is impermissible under PURPA. In fact, this
Commission and the Oregon and California commissions have implemented five-year
term limits in the past. Further, in the context of evaluating whether a QF has access to
long-term markets necessary to grant a waiver of a utility's must-buy obligation under
210(m), FERC has determined that contracts of one year or more are "sufficiently long-
LEGAL BRIEF OF IDAHO POWER COMPANY -9
term to meet the statutory requirement that there be 'wholesale markets for long-term
sales of capacity and energy' within the meaning of section 21 0(m)(1 )(A)(ii)." New
PURPA Section 210(m) Regulations Applicable to Small Power Production and
Cogeneration Facilities, Order No. 688-A, 119 FERC 161,305, P 27 (2007). There
does not appear to be any good policy reason to assume that FERC would require
utilities with a must-buy obligation to offer multi-year term PPAs when a QF selling at
market may not have such an option.
Twenty-year contract terms place a disproportionate amount of rate and cost risk
on the utility customer, rather than QFs. Furthermore, reducing the contract length will
not fatally inhibit QF financing. Because rates would be revisited at five-year intervals
when contracts are renewed, the Commission could better ensure that contract rates
reflect actual avoided cost rates. For these reasons, five years is an appropriate
contract term for Idaho Power.
3. Authorize Idaho Power to Adopt Its Proposed Schedule 73, Which
Establishes an Express Process and Timeline for the Negotiation of
PURPA Contracts
Third, Idaho Power has recommended that the Commission authorize Idaho
Power to adopt its proposed Schedule 73 establishing an express process and timeline
to be followed in the negotiation of PURPA contracts. Stokes, Rebuttal, p. 48. This
schedule would provide all parties with greater clarity and may diminish disputes
regarding inappropriate delays in the contracting process because the expected timeline
for the process would be established by Tariff Schedule. Staff, the three utilities, and all
intervenors that have addressed the issue support the establishment of a formalized
negotiation process. Schedule 73 is closely modeled on tariffs used for years in
LEGAL BRIEF OF IDAHO POWER COMPANY -10
Wyoming, Utah, and Oregon and is approved by the commissions of those states.
Specific objections raised by intervenors are not related to the merits of Schedule 73. In
sum, Schedule 73 fulfills a present need and is ready for implementation.
4.Authorize Idaho Power to Adopt Its Proposed Schedule 74, Which
Establishes a Process for Curtailment of QF Output Consistent with
FERC Rule 304(f)
Fourth, Idaho Power has recommended that the Commission authorize Idaho
Power to adopt its proposed Schedule 74. Grow, Direct, p. 14. This proposed schedule
would establish an express process and right to curtail QF output under circumstances
already authorized by FERC in Section 304(f) of the FERC PURPA regulations.
Adoption of Schedule 74 would provide Idaho Power with an approved method to
implement Section 304(f)'s provisions which relieve a utility from its mandatory
purchase obligations under certain light loading operational circumstances. PURPA
and FERC's regulations permit such curtailment in order to avoid harmful cost impacts
to Idaho Power customers caused when Idaho Power must back down base load
resources to accommodate QF output during light load conditions and then suffer an
otherwise unnecessary increase in cost when it must use higher cost power sources
during the interval required to ramp base load resources back up during higher load
conditions.
5.Establish that Utility Purchasers of QF Output Own the REC5
Associated with that Output
Fifth, Idaho Power has recommended that the Commission declare that when a
utility is compelled to purchase QF output under the PURPA must-buy obligation, the
environmental attributes associated with the QF output remain bundled with the QF
energy and capacity and the purchasing utility is therefore the owner in the first instance
LEGAL BRIEF OF IDAHO POWER COMPANY -11
of any RECs that subsequently may be associated with the QF output. This result is
permissible under PURPA; indeed, FERC has held that the ownership of RECs is
controlled by state law not by PURPA. American Ref-Euel Co., 105 FERC 161,004, P
23 (2003), reh'g denied, 107 FERC 61,016 (2004), appeal dismissed sub nom., Xcel
Energy Servs. v. FERC, 407 F.3d 1242 (D.C. Cir. 2005). This result also prevents Us
from taking advantage of ambiguity or uncertainty under Idaho law to unilaterally lay
claim to RECs. This result also recognizes the reality that the utility and its customers
are purchasing renewable generation. Finally, this result recognizes that states create
RECs and that the value of REC5 associated with energy sold under a PURPA contract
should appropriately be retained fo rhte benefit of the customers that must purchase
that generation—a result that better serves the public interest.
II. ARGUMENT
A. THE COMMISSION SHOULD AUTHORIZE IDAHO POWER TO USE THE
HOURLY INCREMENTAL COST METHODOLOGY FOR ALL QFS
In this section, Idaho Power sets forth the applicable legal requirements for
administratively determined avoided costs, describes how its proposed avoided cost
methodology is consistent with federal regulations, explains why its methodology
complies with the legal requirements, and explains why Intervenor's criticisms should be
discounted.
1. Statutory and Regulatory Definition of Avoided Cost
The legal requirements governing the price of QF energy and capacity originate
in Section 210(b) and 210(d) of PURPA. 16 U.S.C. § 824a-3(b), (d). Section 210(b)
prohibits utilities from paying "a rate which exceeds the incremental cost to the electric
utility of alternative electric energy." 16 U.S.C. § 824a-3(b). Section 210(d) of PURPA
LEGAL BRIEF OF IDAHO POWER COMPANY -12
defines "incremental cost of alternative electric energy" as "the cost to the electric utility
of the electric energy which, but for the purchase from such [QF], such utility would
generate or purchase from another source." 16 U.S.C. § 824a-3(d). FERC, in turn,
promulgated rules implementing PURPA, including Section 210(b) and 210(d).
a."Avoided Cost" Defined ("Rule 101(b) (6)").
FERC Rule 101 (b)(6) defines "avoided cost" as the incremental cost of energy or
capacity, or both, that the utility either (1) did not generate; or (2) did not purchase from
another source as a result of the QF purchase:
Avoided costs means the incremental costs to an electric
utility of electric energy or capacity or both which, but for the
purchase from the qualifying facility or qualifying facilities,
such utility would generate itself or purchase from another
source.
18 CFR § 292.101(b)(6) (2011).
b.FERC's Four Factors Affecting Avoided Cost ("Rule 304(e)").
FERC Rule 304(e) prescribes four broad factors states are to consider "to the
extent practicable" when setting avoided costs. 18 CFR § 292.304(e). The first factor is
the system avoided cost data and planning data a utility is required to provide pursuant
to 18 CFR § 292.302.2
2 Rule 302(b) requires each electric utility to publish the following data:
(1)The estimated avoided cost on the electric utility's system, solely with respect to the
energy component, for various levels of purchases from qualifying facilities. Such levels
of purchases shall be stated in blocks of not more than 100 megawatts for systems with
peak demand of 1000 megawatts or more, and in blocks equivalent to not more than 10
percent of the system peak demand for systems of less than 1000 megawatts. The
avoided costs shall be stated on a cents per kilowatt-hour basis, during daily and
seasonal peak and off-peak periods, by year, for the current calendar year and each of
the next 5 years;
(2)The electric utility's plan for the addition of capacity by amount and type, for
purchases of firm energy and capacity, and for capacity retirements for each year during
the succeeding 10 years; and
LEGAL BRIEF OF IDAHO POWER COMPANY -13
The second factor is "[t]he availability of capacity or energy from a qualifying
facility during the system daily and seasonal peak periods, including":
(i)The ability of the utility to dispatch the qualifying
facility;
(ii)The expected or demonstrated reliability of the
qualifying facility;
(iii)The terms of any contract or other legally enforceable
obligation, including the duration of the obligation,
termination notice requirement and sanctions for non-
compliance;
(iv)The extent to which scheduled outages of the
qualifying facility can be usefully coordinated with
scheduled outages of the utility's facilities;
(v)The usefulness of energy and capacity supplied from
a qualifying facility during system emergencies,
including its ability to separate its load from its
generation;
(vi)The individual and aggregate value of energy and
capacity from qualifying facilities on the electric
utility's system; and
(vii)The smaller capacity increments and the shorter lead
times available with additions of capacity from
qualifying facilities;
18 CFR § 292.304(e)(2). The third factor is the extent to which the Us energy and
capacity actually allows the utility to avoid capacity additions and fuel expenses.
The relationship of the availability of energy or capacity from
the qualifying facility as derived in paragraph (e)(2) of this
(3) The estimated capacity costs at completion of the planned capacity additions and
planned capacity firm purchases, on the basis of dollars per kilowatt, and the associated
energy costs of each unit, expressed in cents per kilowatt hour. These costs shall be
expressed in terms of individual generating units and of individual planned firm
purchases.
18 CFR § 292.302(b) (required by 18 CFR § 292.304(e)(1)).
LEGAL BRIEF OF IDAHO POWER COMPANY -14
section, to the ability of the electric utility to avoid costs,
including the deferral of capacity additions and the reduction
of fossil fuel use;
18 CFR § 292.304(e)(3). The fourth and final factor is line loss costs and
savings.
The costs or savings resulting from variations in line losses
from those that would have existed in the absence of
purchases from a qualifying facility, if the purchasing electric
utility generated an equivalent amount of energy itself or
purchased an equivalent amount of electric energy or
capacity.
18 CFR § 292.304(e)(4).
FERC recently explained how Rule 304(e) factors into a State's procedures for
setting avoided costs:
[VV]e emphasize that the determinations that a state
commission makes to implement the rate provisions of
section 210 of PURPA are by their nature fact-specific and
include considerations of many factors: our [Rule 304(e)]
regulations thus provide state commissions with guidelines
on factors to be taken into account, "to the extent
practicable," in determining a utility's avoided cost of
acquiring the next unit of generation.
California PUC, 134 F.E.R.C. ¶ 61,044, P 36 (F.E.R.C. 2011)(footnote omitted). State
Commissions have an obligation to provide some analysis of the four factors of Rule
304(e), they need not quantify the effect of each factor on the approved rate. Assn of
Bus. Advocating Tariff Equity v. Mich. Pub. Serv. Comm'n, 216 Mich. App. 8, 29-30
(Mich. Ct. App. 1996)(finding that state commission's incorporation of the utility's
analysis of Rule 304(e) factors with statements of its own was legally sufficient).
C. PURPA Does Not Permit Avoided Cost Rates to Subsidize OF
Development.
LEGAL BRIEF OF IDAHO POWER COMPANY -15
Adhering to the statutory and regulatory definition of avoided cost is not merely a
legal formality, but also ensures the policy goal of customer indifference. Straying from
the definition makes avoided cost rates more likely to diverge from actual avoided costs.
Divergence has repeatedly led to significant overpayment to Us. Hieronymus,. Direct,
p.30-32. The impact on utilities and customers has in some instances been dramatic as
excessive avoided cost rates bring a glut of Us. Id. (recounting instances in California
and New York of excessive QF rates leading to QF commitments forced on utilities
exceeding actual avoided cost by billions of dollars in aggregate). Idaho Power
experienced a tidal wave of new QF generation beginning in 2010 when its avoided cost
rates substantially exceeded the actual value of QF output to Idaho Power.
An avoided cost rate set higher than the actual cost of a displaced source of
power for the utility amounts to a subsidy, and is contrary to PURPA and Idaho law.
According to FERC:
The avoided cost standard dictates that Us should be paid
consistent with, not their social value, but the costs of
displaced sources of power to utilities. The criteria for
qualification as a QF must carry the burden of assuring that
the QF's mode of generation is socially desirable.
Direct Test. Hieronymus at 38 (quoting page 30 of FERC NOPR RM88-6). This
Commission has also recognized the foundational PURPA principle of ratepayer
indifference:
Ratepayers should be indifferent to whether a resource
serving them was constructed by a utility or an independent
developer. The cost and quality of service provided by either
should be the same. Ratepayers should not be asked to
subsidize the QF industry through the establishment of
avoided cost rates that exceed utility costs that would result
from an effective least cost planning process.
LEGAL BRIEF OF IDAHO POWER COMPANY -16
In the Matter of the Application of the Idaho Power Company for Approval of Prices for
the Purchase of Electricity from Cogenerators and Small Power Producers Qualifying
Under Section 210 of the Public Utility Regulatory Policies Act of 1978, IPUC Case No.
IPC-E-93-28, Order No. 25884 (1995).
In sum, FERC and this Commission have recognized that rates for purchases
from QFs satisfy the ratepayer indifference requirement when the incremental cost to
the utility of alternative energy is equal to the cost if the purchasing electric utility
generated an equivalent amount of energy itself or purchased an equivalent amount of
electric energy or capacity. Any amount in excess of this equation amounts to a subsidy
and is unlawful under PURPA.
2. The Hourly Incremental Cost Methodoloav
In this proceeding Idaho Power has proposed a single methodology for
determining avoided cost prices for all QFs of any size. Idaho Power proposes to use
the AURORA model to determine the highest displaceable incremental energy cost
being incurred during each hour of the QF's proposed contract term. The result is a
time series of displaceable incremental or avoided costs-one for each hour of the
proposed contract term. This time series of hourly avoided costs is then multiplied by
the QF's supplied hourly generation profile. These products are then summed over
heavy load and light load hours for each month to arrive at heavy load and light load
pricing for each month of the contract term. The details of the methodology are
described in pages 10-33 of the Direct Testimony of Karl Bokenkamp.
LEGAL BRIEF OF IDAHO POWER COMPANY -17
Idaho Power's proposed modified methodology, or Hourly Incremental Cost
methodology3 differs from Idaho Power's previous IRP model in two important respects:
First, whereas the previous IRP methodology required two AURORA simulations to
calculate avoided energy costs—one with the proposed QF resource and one without—
the proposed modified methodology multiplies hourly system incremental costs from a
single simulation by an hourly QF generation forecast to calculate avoided energy cost.
And, second, whereas the previous IRP methodology valued surplus QF generation at
the modeled market price, the modified methodology values such generation at the
marginal cost of its most expensive displaceable generator or power purchase contract.
Idaho Power also is proposing to change the type of proxy unit used to determine the
avoided cost of capacity and other input assumptions used in the previous
methodology, and to increase the frequency with which such inputs are refreshed.
The modified methodology does an excellent job of calculating avoided costs that
are both current and representative of the QF's actual value to the utility without
unnecessary complexity. For this reason, Idaho Power is recommending that its
modified methodology be used to calculate avoided costs for all QFs seeking to sell to
Idaho Power, including QFs under 1 00k seeking standard rate PPAs.
3. The Hourly Incremental Cost Methodology Closely Adheres to the
Definition of Avoided Cost Established by FERC and PURPA.
Under Idaho Power's previous IRP methodology, it was assumed that QF
generation that was excess to Idaho Power's system load was used to make market
sales. Such sales were valued at the AURORA-generated market clearing price.
Idaho Power refers to its proposed revisions as its "proposed modified methodology." Some of Idaho
Power's witnesses also have referred to it as the Hourly Incremental Cost methodology. The two terms
are used synonymously by Idaho Power.
LEGAL BRIEF OF IDAHO POWER COMPANY -18
Bokenkamp, Direct, p. 21. Under the proposed modified methodology, QF energy
during periods of system surplus will instead be valued at the highest displaceable
incremental cost Idaho Power is incurring during the hour (typically a Company owned
thermal plant or a long-term purchase contract). Id. Idaho Power's comparison
between the previous IRP methodology and the proposed modified methodology is
shown in Exhibit 8 to the Direct Testimony of Karl Bokenkamp (as updated by Exhibit 9
to the Rebuttal Testimony of Mark Stokes).
Idaho Power's modified methodology for valuing QF energy better embodies
FERC's definition of "Avoided Cost" than does the previous methodology. "Avoided
costs" means the incremental costs to an electric utility of electric energy or capacity or
both which, but for the purchase of the qualifying facility or qualifying facilities, such
utility would generate itself or purchase from another source." 18 C. F. R. § 292.101 (b)(6)
(emphasis added). Whereas the previous method based avoided cost on off-system
sales—a factor not allowed under FERC's definition—the proposed modified method
faithfully implements FERC's rule by basing avoided cost on the cost to generate the
energy itself or purchase it from another source. See Small Power Production and
Cogeneration Facilities: Regulations Implementing Section 210 of the Public Utility
Regulatory Policy Act of 1978, Order No. 69, 45 Fed. Reg. 12,214, FERC Stats & Regs.,
Regs. Preambles 1977-1981 130,128 at 30,870 (Feb. 19, 1980)("A qualifying facility
may seek to have a utility purchase more energy or capacity than the utility requires to
meet its total system load. In such a case, while the utility is legally obligated to
purchase any energy or capacity provided by a qualifying facility, the purchase rate
LEGAL BRIEF OF IDAHO POWER COMPANY -19
should only include payment for energy or capacity which the utility can use to meet its
total system load.").
4. Proposed Chanaes to the Avoided Cost Model thouts
a.Change Proxy Resource from a CCCT to a SCCT for the
avoided Cost of Capacity
Idaho Power proposes to use the same method for calculating the avoided cost
of capacity used in the previous IRP methodology, but to change the proxy resource
type from a combined cycle combustion turbine ("CCCT") to a simple cycle combustion
turbine ("SCCT"). Bokenkamp, Direct, p. 22. The purpose of the proxy resource is to
represent as accurately as possible the construction costs associated with the type of
resource the QF enables the utility to avoid. Because Idaho Power's capacity needs
are driven by a few summer peak periods that can be met most economically by
constructing a new SCCT, the SCCT is a more appropriate choice for a proxy resource.
Bokenkamp, Direct, p. 32-33.
b.Source of Natural Gas Price Forecast for AURORA Simulations
Idaho Power recognizes that stale gas price forecasts have resulted in
inappropriate published avoided cost rates in the past and therefore supports efforts to
increase the frequency with which gas price forecasts are updated in its AURORA
model. An approach Idaho Power supports is to use the appropriate annual natural gas
price forecast published by the Energy Information Administration ("EIA") in combination
with the most-current EIA published short-term forecast available. Stokes, Rebuttal, p.
3-4. Idaho Power noted that the EIA's gas forecast released in January 2012 is already
more than 50 percent too high compared to the May 2012 update. Stokes, Rebuttal, p.
LEGAL BRIEF OF IDAHO POWER COMPANY -20
4-5. Using the short-term updates will avoid a situation where the utility must offer a
PPA with prices it knows are not accurate.
C. Frequency of Refreshing Inputs to the Model
Idaho Power proposes as part of its modified methodology that the company's
resource portfolio used to model future avoided cost rates be updated each time Idaho
Power receives a new PPA request from a QF (or a request from a QF is withdrawn).
Bokenkamp, Direct, p. 29. Such a process will ensure that Idaho Power's avoided cost
simulations remain accurate as new resources are added (or subtracted) from the its
portfolio. In the past, such frequent updates would have been prohibitively labor
intensive. However Idaho Power's modified methodology is capable of frequent
updates. Because such updates are feasible, it makes sense that Idaho Power should
update its portfolio as often as needed to ensure that it is evaluating current (not past)
system conditions.
5. Use of the SAR Methodology Should be Eliminated for Idaho Power
Idaho Power has significant concerns about the continued use of the SAR
methodology for any size QF selling to Idaho Power. On March 22, 2012 in this
proceeding, the Commission found that "the methodologies previously approved by this
Commission, as utilized and applied by Idaho Power, do not currently produce rates that
reflect Idaho Power's avoided costs and are not just and reasonable, nor in the public
interest." Order No. 32948, p. 2. Almost all of Idaho Power's 119 approved PURPA
purchase contracts contain rates derived with the SAR methodology for published, or
standard, avoided cost rates (the 80 MW Rockland Wind contract being the only
approved contract containing IRP based rates). Idaho Power believes that the prices
LEGAL BRIEF OF IDAHO POWER COMPANY -21
generated using the SAR model in the past have been biased upward in excess of the
company's actual avoided costs. Idaho Power is confident that its proposed modified
methodology does not contain such an upward bias. Furthermore, running both the
SAR model and the Hourly Incremental Cost model would result in unnecessary
administrative burden compared to running only the IRP model.
6. The Hourly Incremental Cost Methodology can Accomodate the Four
FERC Factors in Rule 304(e)
FERC Rule 304(e) enumerates four factors to be considered when calculating
avoided cost rates for a particular project. The Commission and the Idaho Supreme
Court have recognized that these factors can be of particular importance when
negotiating PURPA contracts with QFs larger than 10 MW. Rosebud Enterprises, Inc.
v. Idaho Public Util. Comm'n, 128 Idaho 609, 620 (1996) ("Rosebud"). Once a QF has
provided information about its proposed project and Idaho Power has made an initial
determination of avoided costs using its AURORA model, the parties can negotiate any
adjustments necessary to address the factors enumerated in FERC Rule 304(e). Idaho
Power's proposed Schedule 73 notes this possibility, on Sheet No. 73-2, paragraph 3:
Within 30 calendar days following receipt of all information
required in Paragraph 2, the Company shall provide the
owner with an indicative pricing proposal, which may include
other indicative terms and conditions, tailored to the
individual characteristics of the proposed project.
Stokes, Rebuttal, Exhibit No. 10, p. 2 (emphasis added). Such a process is consistent
with the Commission's instruction on how to generate individualized QF rates
summarized in Rosebud:
The IPUC requires that rates and contracts for [facilities that
are not eligible for standard rates] be individually negotiated,
with a utility's published or filed avoided cost rates used as a
LEGAL BRIEF OF IDAHO POWER COMPANY -22
starting point for negotiations. Individualized consideration is
to be given to such issues as line losses, reliability, and the
purchasing utility's scheduling ability, and to a project's effect
on a utility's load resource balance.
128 Idaho 609, 614-15.
In many cases, the parties may agree that no adjustment to the avoided cost
generated by AURORA are necessary either because none of the Rule 304(e) factors
apply or because the cost of negotiating a Rule 304(e) adjustment would be larger than
the amount of money at stake through an adjustment. But in other cases, particularly
with large Us, the AURORA-generated numbers may substantially misrepresent actual
avoided cost unless they are adjusted for the factors contemplated by FERC Rule
304(e). In such cases the parties will need to negotiate an appropriate adjustment to
the AURORA results. If the parties cannot reach agreement on the need for an
adjustment or its appropriate value, either party can file a complaint asking the
Commission to rule on the appropriate adjustment amount. Each decision by the
Commission will, in turn, help guide Idaho Power and QFs in future negotiations. In
sum, Idaho Power's proposed methodology can accommodate adjustments to address
Rule 304(e) and thereby protect ratepayers from paying too much for QF output.
7. The Intervenors' Objections to Idaho Power's Proposed Methodology
Are Unpersuasive
Intervenors have raised several objections to Idaho Power's proposed avoided
cost rate methodology. However, for the reasons discussed below, intervenors'
objections are unpersuasive.
Use of a Single Heat Rate for AURORA Simulations - Intervenors argue
that Idaho Power's proposal to assume (in its AURORA model simulations) that each of
LEGAL BRIEF OF IDAHO POWER COMPANY -23
Idaho Power's generating units operates at its the most efficient heat rate regardless of
its load for the units, results in undervaluation of QF energy. Reading, Direct, p. 28-29.
This does not take into account the entire operation of the methodology. While it is true
that Idaho Power's modified methodology assumes a single heat rate for each thermal
resource regardless of load level, and that such an assumption reduces calculated
avoided costs, the methodology mades another simplifying assumption that increases
calculated avoided costs and counters this effect, Idaho Power values all QF output for
any hour at the incremental cost of its most expensive displaceable resource during
such hour, regardless whether that displaceable resource can be backed down to make
room for any or all of the QF generation. Bokenkamp, Direct, p. 25.-26. This
assumption means that the QF output will be valued equal to or higher than Idaho
Power's avoided cost determined without this simplifying assumption. However, this
upward bias, and the downward bias associated with modeling a single heat rate for
each thermal unit, tend to cancel each other out. Mr. Reading's assertion that QF
energy is undervalued under the modified methodology is unsupported by the evidence.
Comparability between pricing of Idaho Power-owned Resources and QFs
- Intervenors contend that Idaho Power's proposed methodology leads to avoided cost
rates that are lower than the utility's own cost to build new capacity. Reading, Direct, p.
32. However, Idaho Power has explained that its proposed methodology takes into
account certain physical differences between how utility generators and QFs are
operated which explain the difference between the IRP resource costs and resource
costs under Idaho Power's modified methodology. Stokes, Rebuttal, p. 15-18. These
differences include a 65% annual capacity factor for the CCCT IRP resource and a 92%
LEGAL BRIEF OF IDAHO POWER COMPANY -24
capacity factor for the Hourly Incremental Cost resources. Id. at 15. With a higher
capacity factor, the QF delivers energy during a considerable number of hours during
which the Company's cost to operate its existing resources are relatively low.
Consequently, the costs the QF allows the utility to avoid during these hours are
relatively low. If the QF operated in the same manner as the IRP resource, the rate
under the methodology would increase substantially. Id. Furthermore, the period over
which the 2011 IRP cost is levelized is 30 years and, the Hourly Incremental Cost QF is
levelized over a 20-year period. Id. Lastly, Idaho Power explains that the natural gas
prices used to calculate the 2011 IRP price and its proposed methodology have
changed, again explaining the difference in resulting avoided costs. Id. at 18. Simply
put, Idaho Power has explained that its proposed methodology accounts for the physical
and operating differences between a QF and a utility owned generator, explaining why
the two are treated differently in incremental cost calculations.
Treatment of Surplus QF Generation - Intervenors argue that the PURPA
must-take obligation is incompatible with Idaho Power's proposal to disregard potential
opportunity sales of QF power. Schoenbeck, Direct, p. 21. In practice, direct sales are
virtually impossible for power from intermittent Us because the amount of energy to be
delivered is uncertain and subject to curtailment by the QF without penalty. Park,
Direct, p. 9. In addition, FERC's unbundling of the bulk transmission system
complicates the task of selling energy since the utility must undesignate the QF as a
network resource before making a opportunity sale of the QF output. Park, Direct, p.
10. Most importantly, FERC's rules implementing PURPA do not require utilities to
include off-system sales when determining their Avoided Cost. FERC has stated that
LEGAL BRIEF OF IDAHO POWER COMPANY -25
when PURPA requires the utility to take QF output in excess of utility load, "the
purchase rate should only include payment for energy or capacity which the utility can
use to meet its total system load." City of Ketchikan, 94 FERC 161,293, 62,062 (2001).
FERC has also noted that a utility "does not have to buy power it does not need." New
PURPA Section 210(m) Regulations Applicable to Small Power Production and
Cogeneration Facilities, 114 FERC ¶ 61,043, P 9 (2006) (citing S. Cal. Edison Co., 70
FERC 161,215, 61,677-78, reh'g denied, 71 FERC 161,269, 62,078 (1995)).
Transparency and Practicality of Idaho Power's Proposed Methodology -
Intervenors argue that Idaho Power's proposed methodology is too complex because it
involves a large number of inputs and the need for continuous updating. Intervenors
complain that this complexity makes it difficult for them to evaluate the reasonableness
of the avoided cost rates generated by the Idaho Power methodology and that the
complexity gives the utility too great and opportunity to game the outcome. Reading,
Direct, p. 31-32; Shoenbeck, Direct, p. 21. Idaho Power disagrees with the contention
that its proposed methodology is overly complex. As discussed in Idaho Power
testimony, the proposed methodology is simple and transparent. Stokes, Rebuttal, p.
19. The AURORA model is used to determine the dispatch of utility owned resources;
beyond that all other information and calculations are done in an Excel spreadsheet. It
becomes simple to understand once people are given the opportunity to work with it. Id.
Because all the information used is available to all the parties, gaming should not occur.
Carbon Adder - Intervenors argue that Idaho Power wrongly excludes
carbon costs, which are included in Idaho Power's IRP. Schoenbeck, Direct, p. 24-25.
However, it is proper to exclude carbon costs from the IRP because carbon costs are
LEGAL BRIEF OF IDAHO POWER COMPANY -26
not at this point real, nor are they included in customer rates. Stokes, Rebuttal, p. 38.
Until these carbon costs are real and a utility may avoid incurring them by purchasing
from a QF, it is improper to include them in any avoided cost calculation.
In conclusion, Idaho Power has effectively demonstrated that none of the
objections raised by intervenors represents a fatal flaw in Idaho Power's proposed
methodology.
8. The Commission Should Maintain its Presently Required DeIa
Damages and Delay Damage Security in QF Contracts
The provisions regarding Delay Damages and Delay Damage Security contained
in the Commission-approved PURPA Firm Energy Sates Agreements ("FESA") are
necessary, reasonable, non-punitive, and in the public interest. Moreover, each party
that entered into a FESA is precluded from challenging such provisions under the well-
established doctrines of res judicata and collateral estoppel.
Delay liquidated damages provisions have been included in PURPA FESA
contracts approved by the Commission since at least 2007. See, Case No. IPC-E-06-
36. In addition, one of the first Commission approved FESA5 to contain terms requiring
the project to post liquid security was the FESA for Cassia Gulch Wind Park and Tuana
Springs Energy, Case No. IPC-E-09-24. In that case the Commission approved
provisions requiring the posting of liquid security in the amount of $20 per kW of project
capacity.
The Commission considered and approved provisions providing for the posting of
liquid security in the amount of $20 per kW of project capacity in at least four other
PURPA FESAs. See, Case No. IPC-E-09-18, IPC-E-09-19, IPC-E-09-20, IPC-E-09-25.
The Commission has since analyzed and approved provisions requiring the posting of
LEGAL BRIEF OF IDAHO POWER COMPANY -27
liquid security in the amount of $45 per kW of nameplate capacity in at least twenty-
seven different PURPA FESA5. See, Case No. IPC-E-10-02, IPC-E-10-05, IPC-E-10-
15, IPC-E-1 0-16, IPC-E-1 0-17, IPC-E-1 0-18, IPC-E-1 0-19, IPC-E-1 0-22, IPC-E-1 0-26,
I PC-E-1 0-37, IPC-E-1 0-38, I PC-E-1 0-39, IPC-E-1 0-40, I PC-E-1 0-41, I PC-E-1 0-42, I PC-
E-1 0-43, IPC-E-1 0-44, I PC-E-1 0-45, I PC-E-1 0-47, I PC-E-1 0-48, IPC-E-1 0-49, I PC-E-
10-50, IPC-E-11-09, IPC-E-11-10, IPC-E-11-25, IPC-E-11-26, and IPC-E-11-27. In
approving the change in the amount of delay damage security that is acceptable for
such contracts from $20 to $45 per kW of nameplate capacity, the Commission
specifically found such delay security to be reasonable, necessary, and not to be
punitive. Order No. 31034, p. 3-4, Case No. IPC-E-10-02 (2010).
Idaho Power supports and recommends the Commission's continued
requirements to provide for delay liquidated damages, and well as delay damage
security in its approved PURPA FESAs. As referenced above this requirement has
been specifically addressed in several cases, and found by the Commission to be a just,
reasonable, and appropriate term for a PURPA QF contract that is in the public interest.
With regard to the reasonableness of liquidated damages,
some witnesses, such as Dr. Reading, focus only upon the
comparison to the cost of replacement power should the QF
not bring its project on-line when it commits itself to a
Scheduled Operation Date that it chooses in the contract.
This highlights an important part of Idaho Power's case that
it provided much evidence of in its direct testimony, and that
is typically the Company can acquire replacement power
from other available sources at a cost that is below the
contract price in the PURPA contract. This, however, is not
the only measure of harm and damages. In addition to the
system operation and planning problems that failure to bring
generation units on-line in a timely manner and when they
are scheduled to come on-line, there is the substantial value
that the QF gets by locking in a price, and a pricing stream
with its contract. If a QF is allowed to come on-line, or not,
LEGAL BRIEF OF IDAHO POWER COMPANY -28
at its choosing with no consequences and no liability for the
value of that option, then customers are left in a financially
disadvantaged position and uncompensated for the price
lock and option they extended to the QF project. There are
financial instruments that can be purchased that would allow
a utility to lock in a 20-year, or long-term, stream of prices,
and have the option to not execute on that option at a date
certain in the future. Such products are very costly, and
could be as much as $5 per MWh of power. The $45 per kW
of nameplate capacity is very small in comparison, but at
least provides an agreed upon valuation of an assessment of
risk that the customers are bearing associated with whether
a QF generator brings its project on-line when it commits
that it will.
Stokes, Rebuttal, p. 46-47.
Idaho Power must routinely buy and sell electricity as much 18 months in
advance of the month that is needed (bought) or not needed (sold) as dictated by Idaho
Power's Risk Management Policy. The amounts that are bought and sold are based on
the overall portfolio position (surplus/deficit) that includes company-owned resources
and QF contracts. When a QF resource fails to come on-line by the Scheduled
Operation Date, Idaho Power must replace this energy by making a market purchase,
assuming transmission capacity is available to get the energy to Idaho Powers 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 is 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 the system where market liquidity is an
issue and prices are almost always higher.
LEGAL BRIEF OF IDAHO POWER COMPANY -29
Regardless of whether market prices are higher or lower than prices contained in
the QF contract, Idaho Power's customers end up assuming the risk associated with the
uncertainty, and have no control over whether the QF energy will be there or not. There
is value associated with reducing or eliminating risk even if the potential positive and
negative outcomes are evenly split. A fixed rate QF contract eliminates this risk for the
QF developer and pushes it entirely onto Idaho Power's customers. As stated in Mark
Stokes' rebuttal testimony, "There are financial instruments that can be purchased that
would allow a utility to lock in a 20-year, or long-term, stream of prices, and have the
option to not execute on that option at a date certain in the future. Such products
are very costly, and could be as much as $5 per MWh of power. Stokes, Rebuttal, p. 47
(emphasis added). The financial instrument referenced above would be a "put" option.
It is important to note the emphasized section of the passage above in that a put option
allows a party to not execute on the option if conditions are not favorable for the option
holder. It is exactly this option that is available to the QF, and the exercise of which the
QF my choose or not choose depending upon the favorableness, or unfavorableness of
the prices contained in its FESA in relation to market prices or other factors. In this
way, a QF has the ability to eliminate its own downside, to the direct and substantial
harm and detriment of Idaho Power's customers, and take advantage of the upside.
Consequently while in theory, one may argue that prices may vary either above or
below those set in the FESA, it is the QF that has the ability to eliminate the downside,
from its perspective, and it is the customers that take all of the risk, and shoulder a
disproportionate amount of price deviation from that which is contracted for.
LEGAL BRIEF OF IDAHO POWER COMPANY -30
The delay damage and delay damage security provisions that the Commission
has evolved, approved, and implemented as part of its federally delegated responsibility
to implement PURPA in the state of Idaho, represents a just, reasonable, necessary,
and non-punitive provision of a PURPA QF contract with a utility. It is aimed at
providing compensation for cost and risk allocations in the relationship between the
utility and the QF that are difficult to quantify with precision, but are none-the-less very
real to the utility and its customers. Idaho Power asks that the Commission continue to
authorize and require the provisions in a PURPA QF contract that provide for delay
damages and delay damage security.
Equally important, the doctrines of res judicata and collateral estoppel preclude
the parties from challenging the Commission's Final Orders related to the delay
damages and delay damage security contained in the relevant FESA5. The United
States Supreme Court has clearly held that a litigant's failure to raise justiciable issues
in a prior administrative proceeding precludes that litigant from raising them in a later
administrative proceeding and in subsequent litigation. See Astoria Fed. Say. & Loan
Ass'n v. Solimino, 501 U.S. 104, 107-08 (1991); see also Rest. 2d. Judgments § 83,
cmt. b (1982) ("Where an administrative forum has the essential procedural
characteristics of a court,... its determinations should be accorded the same finality that
is accorded the judgment of a court. The importance of bringing a legal controversy to
conclusion is generally no less when the tribunal is an administrative tribunal than when
it is a court.").
Here, the issues of Delay Damages and Delay Damage Security were raised and
addressed in Commission cases mentioned above. After the Commission approved the
LEGAL BRIEF OF IDAHO POWER COMPANY -31
relevant FESAs and issued Final Orders related to the same, the parties could have
sought reconsideration with the Commission or appealed the decision to the Idaho
Supreme Court. Put another way, each parties was afforded court-like substantive and
procedural due process to challenge the Commission's Final Order. No such
challenged occurred. The parties, therefore, are precluded from litigating the
reasonableness of the Delay Damages and Delay Damage Security in this proceeding.
B. THE COMMISSION SHOULD LIMIT THE TERM OF PURPA QF CONTRACTS
TO FIVE YEARS
Idaho Power requests that all PURPA contracts with forecasted avoided cost
rates be limited to a five-year term, as opposed to the current twenty year-term. Setting
a length of five years for PURPA contracts is within the Commission's discretion. By
limiting the term of all new PURPA contracts to five years, the Commission remains
faithful to its charge to implement PURPA and FERC's PURPA regulations while
ensuring that cuatomers are protected from the risk associated with the uncertainty of
avoided cost rates forecasted over multiple decades—a risk more appropriately borne
by QF investors. Further, limiting the term of PURPA contracts to five years will not
discourage or hinder QF investment or QF development because QFs will can renew
contracts every five years. The main difference between a twenty-year contract term
and a series of five-year contracts is that rates set in five-year intervals at each contract
renewal will more accurately reflect a utility's actual avoided costs than rates set once at
the beginning of the twenty-year period. For the reasons discussed below, Idaho Power
urges the Commission to adopt a five-year term for all PURPA contracts.
1. The Commission has Authority to Set a Five-Year Term for Fixed
Price Contracts
LEGAL BRIEF OF IDAHO POWER COMPANY -32
The Commission implements PURPA pursuant to the rules and regulations
promulgated by FERC. See 16 U.S.C. § 824a-3(f). However, neither PURPA nor
FERC place explicit limits on permissible contract lengths, leaving the states broad
discretion to determine what contract length is appropriate. "A state has broad authority
to implement PURPA with respect to the approval of purchase contracts between
utilities and Us." N. Am. Natural Res., Inc. v. Mich. Pub. Serv. Comm'n, 73 F. Supp.
2d 804, 807 (D. Mich. 1999) (citing Crossroads Cogeneration Corp. v. Orange &
Rockland Utils., Inc., 159 F.3d 129, 135 (3d Cir. 1998)); see also Indep. Energy
Producers Assn, 36 F.3d at 85. Without FERC regulations prescribing a PURPA
contract length, the Commission must use its own judgment to determine what contract
length is appropriate.
Intervenors argue that the Commission is required by PURPA and FERC
regulations to set a contract length that guarantees investment in QF development.
Clearwater Paper Corp., J.R. Simplot Co., Exergy Development Group of Idaho, LLC,
Reading, Direct, p. 46; Northside Canal Co., Twin Falls Canal Co., Renewable Energy
Coalition, Schoenbeck, Direct, p. 35. Dr. Reading combines the option available to Us
to have a predetermined rate available over the course of the entire contract and the
requirement that States encourage QF development found in PURPA Section 210 to
formulate a requirement that States establish contract lengths that will spur investment
in QFs. Reading, Direct, p. 46. However, Dr. Reading overstates the impact of FERC's
guidance and his reliance on these primciples is misplaced regarding the length of a
contract term. PURPA does not require that Us be able to obtain financing, only that
the QF have the option of obtaining certainty with an avoided cost rate fixed over the
LEGAL BRIEF OF IDAHO POWER COMPANY -33
term of the contract. 18 C.F.R. § 292.304(b)(5); 18 C.F.R. § 292.304(d); Order No. 69,
45 Fed.Reg. at 12,224. The Idaho Commission has previously rejected the suggestion
that a PURPA contract should be structured to promote the viability of QF projects. See
Order No. 32262 at 8 ("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."). A five-year term satisfies the FERC requirement that the term be fixed over
the entire term of the contract. There is no conflict with PURPA or FERC on this point.
Idaho Power is not aware of any FERC decision declaring that a five-year fixed
price contract is impermissible under PURPA. In fact the Idaho Commission has
repeatedly used its discretion to adjust the length of Idaho Power PURPA contracts,
reducing PURPA contract term from 35 years to 20 years in 1987, down to five years in
1992, then back to years 20 in 2002. See Commission Staff Direct Test. R. Sterling at
25 (May 4, 2012); In the Matter of the Review of the Idaho Public Utilities Commission's
Policies Establishing Avoided Costs under the Public Utility Regulatory Policies Act of
1978, IPUC Case No. U-1500-170, Order No. 21630 (1987); In the Matter of the
Application of Idaho Power Co. for an Order Approving the Methodology for Avoided
Cost Rate Negotiations with Qualifying Facilities Larger than 1 MW, IPUC Case No.
IPC-E-95-9, Order No. 26576 (1996); In the Matter of the Investigation of the Continued
Reasonableness of Current Size Limitations for PURPA QF Published Rate Eligibility
and Restrictions on Contract Length, IPUC Case No. GNR-E-02-01 (2002).
Furthermore, in the past the Oregon PUC has used its discretion and authority to also
reduce the contract term available to certain QF generators to five years. See Oregon
PUC Order No. 84-742, at 3 (1984). California has also approved PURPA fixed rate
LEGAL BRIEF OF IDAHO POWER COMPANY -34
contracts with five-year terms. See Order Instituting Rulemaking to Promote
Consistency in Methodology and Input Assumptions in Commission Applications of
Short-Run and Long-Run Avoided Costs, Including Pricing for Qualifying Facilities,
California PUG Rulemaking 04-04-003, Decision 07-09-040 2007 Cal. PUG LEXIS 443
(2007). Further, in the context of evaluating whether a QF has access to long-term
markets necessary to grant a waiver of a utility's must-buy obligation under 210(m),
FERC has determined that contracts of one year or more are "sufficiently long-term to
meet the statutory requirement that there be 'wholesale markets for long-term sales of
capacity and energy' within the meaning of section 210 (m)(1)(A)(ii)." New PURPA
Section 210(m) Regulations Applicable to Small Power Production and Cogeneration
Facilities, Order No. 688-A, 119 FERC 161,305, P 27 (2007). There does not appear
to be any good policy reason to assume that FERC would require utilities with a must-
buy obligation to offer multi-year term (in excess of even one-year) PPAs when a QF
selling at market may not have such an option.
2. A Shorter Contract Term Protects Customers by Implementing More
Accurate Avoided Cost Rates
PURPA and FERC regulations require that states establish rates for purchase
from Us at the utilities "full avoided cost." S. Cal. Edison Co. v. FERC, 443 F.3d at 95;
18 CFR § 292.304(b)(2). FERC also requires that states use procedures to forecast a
utilities avoided cost and no more. 18 CFR § 292.304(b)(2); Conn. Light & Power Co.,
70 FERC ¶ 61,012, 61,029 n.46. The Idaho Commission has stated that customers
should be "indifferent" to rates paid to independent power producers. IPUC Order No.
25884. However, these rules only apply when setting rates; if a rate is set properly,
PURPA is not violated if, at the time of delivery of QF output, fixed rates exceed or fall
LEGAL BRIEF OF IDAHO POWER COMPANY -35
below a utility's actual avoided cost, and FERC will not adjust such rates in a contract.
Rebuttal Test. Stokes at 37; 18 C.F.R. § 292.304(b)(5); 18 C.F.R. § 292.304(d); Order
No. 69, 45 Fed. Reg. at 12,224. Therefore, states must do their best to forecast rates
accurately and hope that, as FERC puts it, over and under estimations of avoided cost
"balance out" overtime. Order No. 69, 45 Fed. Reg. at 12,224.
However, primarily due to volatile natural gas prices and their role in determining
avoided costs, avoided cost rates set in Idaho have not balanced out. Rather, over the
past 30 years, QF developers have received a windfall from forecasted avoided costs
set too high. Stokes, Rebuttal, p. 7, Chart RI. Long-term contracts in Idaho exacerbate
the problem of excessively high-avoided costs. Stokes, Rebuttal, p. 33. Without the
ability to retroactively change the rates set in these contracts, utilities and their
ratepayers are stuck paying excessive rates for decades in contradiction of PURPA's
policy against subsidizing Us to the detriment of customers. Id.; Sterling, Direct, p. 30;
Hieronymus, Direct, p. 107; Independent Energy Producers Assn, 36 F.3d at 858.
The Commission may mitigate the harm caused by over and under estimations of
forecasted avoided cost rates by simply shortening the term of PURPA contracts to five
years. Direct Test. Sterling at 30-31; Direct Test. Hieronymus at 15; Direct Test. Stokes
at 44-45. Once the initial five years of the contract expires and the QF renews, rates for
the renewal period will reflect the most recent actual avoided cost data.
QF development will not, as some intervenors claim, be harmed by a shorter
contract length because investors will be uninterested in investing in a QF project with a
relatively short-term agreement. Direct Test. Reading at 46. In the purely market-based
arenas where the must-buy provision of PURPA has been removed under Section
LEGAL BRIEF OF IDAHO POWER COMPANY -36
210(m) of PURPA, FERC has found that contract lengths of only one year are sufficient
to demonstrate that Us are able to compete in the energy market. See FERC Order
No. 688-A, 119 FERC ¶ 61,305, P 27. Also, Intervenors' concerns should be alleviated
by the fact that PURPA contracts will be available again at the end of the initial five-year
period and a QF need only apply to obtain a new five-year contract with updated rates.
Hieronymus, Direct, p. 112; Stokes, Rebuttal, p.29.
3. A Shorter Contract Term Properly Places Investment Risks on the QF
and its Investors, and not on Utility Customers
The current PURPA contract length of 20 years places market risk onto
ratepayers that properly belongs on investors and QF developers. Stokes, Direct, p. 45;
Hieronymus, Direct, p. 15; IPUC Order No. 25884. Because avoided cost calculations
are based upon the natural gas index, they are extremely volatile and have fluctuated
dramatically since PURPA was conceived. Stokes, Direct, p. 45. However, in the past
QF investors and developers have been insulated from the risk of downward changing
rates through long-term contracts at a guaranteed rate. "By locking a single fixed price
or a schedule of fixed prices, PURPA projects are hedging the variable market value of
the energy for the fixed prices contained in the contract at the expense of [utility
customers]." Id.; Sterling, Direct, p. 31; Hieronymus, Direct, p. 107. While investors are
secure with a long term contract and guaranteed rate, customers, who have no say in
whether or not to pay QF prices, are exposed to the possibility that actual market rates
will fall and they will be unable to take advantage of lower prices. Rather, the customers
must pay QFs at improperly forecasted rates, foregoing the benefits of lower electricity
prices. This is exactly what has happened in Idaho. Stokes, Rebuttal, p. 7, Chart RI.
Lowering the length of PURPA contract will place the risk of short and long-term price
LEGAL BRIEF OF IDAHO POWER COMPANY -37
changes away from the ratepayers and back onto investors willing to take that risk.
Sterling, Direct, p. 30; Hieronymus, Direct, p. 15. QF developers will receive an initial
rate for a five year contract, then accept the risk that prices may change over those five
- years, and have a new rate adjusted for market conditions when they obtain a renewed
contract after the initial five years.
Properly placing market risk on QF investors and developers through shorter
contract terms should not greatly impact QF development because QF investors retain
the right to continuously renew PURPA contracts every five years which ensures that
investors will always recover properly priced avoided cost rates. Hieronymus, Direct, p.
112; Stokes, Rebuttal, p. 29. Also, the risk and benefit with a shorter contract length
exists equally for QF investors and ratepayers. It is entirely possible that after an initial
term of five years that avoided cost rates for QF projects may go up, allowing Us
renewing after five years to obtain rates they would not otherwise be able to obtain.
Sterling, Direct, p. 30; Hieronymus, Direct, p. 111.
The limitation of contract length to five years should apply to all QF project sizes,
and not (as Staff recommends) only to projects receiving avoided cost rates calculated
using the IRP methodology. Sterling, Direct, p. 31-32. The risks of market price
fluctuation exist for projects with SAR modeled rates, just as they do with IRP calculated
risks and again those risks are imposed on ratepayers. Stokes, Rebuttal, p. 35.
Reducing the contract length of all PURPA contracts available in Idaho is the best
means of limiting risk exposure to ratepayers and an exception for Us qualifying for
SAR rates should not be made. In fact, the risk of customer harm because of variance
from the prices set at the time of contracting, when those prices are established with the
LEGAL BRIEF OF IDAHO POWER COMPANY -38
SAR methodology, is greater than it is with the IRP or Hourly Incremental Cost
methodologies.
Finally, reducing the length of PURPA contracts to five years more accurately
compares to the rate recovery process utilities use to cover utility generation
investments. Intervenors argue that by reducing contract length to five years that QFs
are being treated unfairly compared to utility owned resources because utility owned
resources are paid throughout the resource's entire life-cycle. Schoenbeck, Direct, p. 9;
Clearwater Paper Corp., J.R. Simplot Co., Exergy Development Group of Idaho, LLC,
Reading, Rebuttal, p. 48. However, utility recovery of stranded costs is not guaranteed
for the entire life cycle of any generation unit. Sterling, Direct, p. 31. Also, utility-owned
resources expose customers to less risk than for PURPA resources because utility rates
are readjusted. Id. Re-adjusting avoided cost rates at the end of an initial five year
PURPA contract term would more closely mirror the process of utility rate recovery,
providing more accurate rates to customers.
C. THE COMMISSION SHOULD APPROVE IDAHO POWER'S TARIFF
SCHEDULE 73—FORMAL CONTRACTING PROCEDURE
Idaho Power respectfully requests in this proceeding "[e]stablishment of a
Commission-authorized negotiation process and procedure by which a PURPA QF can
obtain a PPA with Idaho Power." Grow, Direct, p. 14. Rocky Mountain Power proposed
its own tariff establishing a contract negotiation process closely modeled on tariffs used
by Rocky Mountain Power in Wyoming, Utah, and Oregon. See Rocky Mountain
Power, Clements, Direct, p. 3, Ex. 202("RMP Schedule 38"). Idaho Power followed suit
by proposing a contracting process in Tariff Schedule No. 73. Stokes, Rebuttal, Ex. 10
("Schedule 73"). Schedule 73 is adapted, with minimal change, from RMP Schedule 38.
LEGAL BRIEF OF IDAHO POWER COMPANY -39
Changes made by Idaho Power to adapt RMP Schedule 38 are shown as redline
markups Idaho Power's rebuttal testimony. Stokes, Rebuttal, Ex. 11.
RMP Schedule 38 "codifies in Idaho the process that Rocky Mountain Power
formally uses in Utah and Wyoming and has informally been using in Idaho for several
years." Direct Test. Clements at 3. RMP believes it to be "an efficient and productive
process for both the Company and potential QFs." Clements, Direct, p. 3. RMP
Schedule 38 originated in a Utah work-group in 2002 with participants similar to those in
the instant case. Id. at 3.
Part I of proposed Schedule 73, is closely modeled on RMP Schedule 38.
Schedule 73 would apply to all QFs "who desire to make sales to the Company at
avoided cost rates." Schedule 73 details steps a QF can take to obtain a PPA from
Idaho Power. Schedule 73 lists information a QF must provide to Idaho Power. In
addition, Schedule 73 requires Idaho to respond to a QF by set deadlines. Idaho Power
must provide indicative pricing within 30 days of receiving general project information
reasonably required for the development of indicative pricing. Idaho Power must
provide a draft PPA within 45 days of the QF requesting a draft PPA and providing
additional information needed, if any, to prepare a draft PPA. Within 45 days of the
parties reaching full agreement on the terms and conditions of a draft PPA, Idaho Power
must provide the QF with a final, executable PPA.
Part II of proposed Schedule 73 clarifies for QFs that interconnecting is a
separate process set forth in Schedule 72. Part Ill provides a process for filing
complaints regarding specific terms of a PPA wherein a QF must wait 60 days after an
impasse with Idaho Power before filing a complaint with the Commission. The waiting
LEGAL BRIEF OF IDAHO POWER COMPANY -40
period provides time for the parties to resolve a dispute before bringing it to the
Commission.
In 2011, the Wyoming Public Service Commission (Wyoming PSC) approved a
version of Rocky Mountain Power's Schedule 38. Schedule 73 and RMP Schedule 38
proposed in the instant case are very similar to the Wyoming Schedule 38. In its order
approving Schedule 38, the Wyoming PSC highlighted its benefits:
Importantly, Schedule 38 provides specific terms and
conditions, steps and a time frame for RMP and potential
Us to utilize in determining indicative or estimated avoided
cost prices for a proposed QF project. The Commission finds
the provisions contained in Schedule 38 also provide the
flexibility [a QF intervenor] requested by giving the
negotiating parties the leeway to agree on specific terms and
conditions beyond those described in Schedule 38, and by
acknowledging the Commission's continuing authority to
review proposed contracts. . . . In addition, Schedule 38
contains a provision, applicable when RMP and the potential
QF provider are unable to come to agreement, requiring
them to try for 60 days to work out their differences before
bringing the issue to the Commission. Finally, a reasonably
applied Schedule 38 may assist Us in obtaining a contract
which can be utilized in securing project financing.
In the Matter of the Application of Rocky Mountain Power to Implement a Permanent
Avoided Cost Methodology for Customers that do not Qualify for Tariff Schedule 37 -
Avoided Cost Purchases from Qualifying Facilities, Wyoming PSC Docket No. 20000-
388-EA-11, Record No. 12750, P 58, 2011 Wyo. PUC LEXIS 441 (2011).
1. Schedule 73 Will Benefit QFs. Utilities, and the Commission by
Lowering Transaction Costs and Reducing Disputes
By establishing a formal contracting process, Schedule 73 will reduce future
disputes regarding grandfathered entitlement to avoided cost rates that have been
superseded. Stokes, Direct, p. 44-45. Such disputes often center on when the QF
LEGAL BRIEF OF IDAHO POWER COMPANY -41
incurred a legally enforceable obligation and whether the parties fulfilled their respective
roles in the contracting process. By formalizing the process in a tariff, the Commission
would eliminate questions regarding the proper roles of the parties in the negotiation of
a QF agreement. Us would know when they could expect a response from Idaho
Power. And, in the face of a rush of Us seeking to legally enforceable obligations
ahead of a rate change, Idaho Power could be assured of a per se reasonable window
of time within which to conduct its due diligence.
FERC has embraced timelines in implementing PURPA. See, e.g., 18 CFR §
292.207(c)(2) (utility not required to purchase from a QF of 500 kW or more until 90
days after the QF provides notice of its QF status); see also 18 CFR § 292.207(b)(3) (90
days for FERC to respond to application for QF certification). Minimum timelines have
helped other states to resolve disputes arising from negotiations. See, e.g.,
International Paper Co. v. PacifiCorp, Oregon PUC Docket No. UM 1449, Order No. 09-
439, 2009 Ore. PUC LEXIS 374 (2009) (relying on tariff-based negotiating procedure to
resolve QF complaint).
Idaho Power's Schedule 73, if approved, could resolve potential disputes
regarding contract negotiations before they arise. In short, by establishing de facto
reasonable negotiating procedures in tariff, disputes before the Commission could in
large part be reduced to a determination of whether each party fulfilled its respective
role and met its respective deadlines under the contracting tariff.
2. Participants Agree That a Commission-Authorized Negotiation
Process and Procedure Would be Beneficial
Formalizing the PPA negotiation process has unified support from IPUC staff,
utilities, and QF developers. IPUC Staff believes that a tariff such as RMP Schedule 38
LEGAL BRIEF OF IDAHO POWER COMPANY -42
"could be helpful now for both the utilities and project developers" and "would inform
both parties of their responsibilities, informational requirements, and timelines."
Sterling, Direct, p. 32. IPUC staff added "[i]t could alleviate complaints." Id. Rocky
Mountain Power and Avista have joined Idaho Power in requesting a formal negotiation
process. Clements, Direct, p. 2; Avista, Kalich, Direct, p. 9 ("[A] tariff similar to
PacifiCorp's Schedule 38 could be helpful both to the utilities and project developers,
and could limit future complaints before the Commission.").
All QF intervenors that have taken a position in testimony also support a formal
negotiation process. Twin Falls Canal Co., Northside Canal Co., and Renewable
Energy Coalition testified that "[t]ransaction costs can be minimized by having a clear
stated time table for the QF contracting process." Schoenbeck, Direct, p. 36.
Renewable Energy Coalition, without endorsing specific components, agreed that
"elements" of RMP Schedule 38 "would have value for both the utility and the QF" and
"would provide transparency, simplicity and certainty to Us." Renewable Energy
Coalition, Sorenson, Direct, p. 4. Clearwater, Simplot, and Exergy, do not endorse the
specific tariff schedule proposed by RMP but they agree that some type of QF
contracting tariff would be useful if designed to prevent a utility from imposing
unnecessary delays in negotiations and if it imposes meaningful deadlines on the utility.
Reading, Direct, p. 61.
3. No Materially Significant Objections to Schedule 73 Have Been
Raised
Some parties, including IPUC staff, have requested that a new proceeding be
commenced to establish formal PPA contracting procedures. See e.g., Sterling, Direct,
p. 32 (recommending that the Commission direct each of the utilities to prepare a tariff
LEGAL BRIEF OF IDAHO POWER COMPANY -43
similar to RMP Schedule 38 subject to review and comment in a separate docket).
Rocky Mountain Power submitted RMP Schedule 38 for the record in this case on
January 31, 2012. Clements, Direct. However, few specific objections to the terms of
RMP Schedule 38 - which is nearly identical to Schedule 73 - have been raised, and
the objections raised do not appear to merit a separate docket.
Clearwater, Simplot, and Exergy raise the only two specific objections to RMP
Schedule 38. First, they contend the tariff "provides no assurance that any particular
process will be followed for small Us seeking published rates and standard contract
terms." Reading, Direct, p. 61. Second, they argue that "the deadlines for the utility to
respond to QF requests are far longer than deadlines authorized by the other states'
tariff from which Mr. Clements supposedly developed the proposed Idaho tariff." Id. at
61.
The intervenors' first objection, regarding assurances for Us seeking published
rates, is not really a criticism of RMP Schedule 38 - nor is it a criticism, by association,
of Schedule 73. Schedule 73 is intended to apply to all Us "who desire to make sales
to the Company at avoided cost rates." The objection as it relates to "standard contract
terms" is misplaced because Idaho does not have standard PPAs for QFs.
The intervenors' second objection—that timelines in RMP Schedule 38 exceed
the timelines in other states—neglects that Wyoming Schedule 38 uses an identical
timeline. The timelines in RMP Schedule 38 and Schedule 73 are identical to the
timelines in Rocky Mountain Powers Schedule 38 approved in 2011 by the Wyoming
Public Service Commission ("Wyoming PSC"): 30 days to provide indicative pricing, 45
days to provide a draft agreement, 45 days to provide an executable agreement. RMP
LEGAL BRIEF OF IDAHO POWER COMPANY -44
Wyoming Schedule 38 is available at: httD://www.rockymountainpower.net/aboutlrar/wri.html .
Rocky Mountain Power's Schedule 38 tariffs for Oregon and Utah do have different
timelines than for Wyoming. But RMP Schedule 38 (along with Schedule 73) is not "far
longer than deadlines authorized by the other states' tariff from which Mr. Clements
supposedly developed the proposed Idaho tariff."
In sum, Clearwater, Simplot, and Exergy agree that some contracting procedure
tariff is desirable, and their specific objections are misplaced.
4. Schedule 73 Is Ripe for Commission Approval
For the reasons stated above, Idaho Power agrees with Rocky Mountain Power
that the utilities' respective contracting procedure tariffs should be approved without
further proceedings. See Rocky Mountain Power, Clements, Rebuttal, p. 3. Schedule
73 closely adheres to tariffs that have been approved and used for years in neighboring
states. No commenters have raised specific objections that merit additional
proceedings. If the Commission decides to order a separate proceeding to consider
contracting procedures, Idaho Power respectfully requests that the Commission
approve Schedule 73 on an interim basis pending the outcome of that separate
proceeding.
D. THE COMMISSION SHOULD APPROVE IDAHO POWER'S TARIFF
SCHEDULE 74 -OPERATIONAL DISPATCH
FERC Rule 304(f)(1) excuses a utility from accepting QF output during light load
periods if, because of operational circumstances, purchase of QF output will result in
costs greater than costs the utility would incur if it did not make the QF purchase and
instead generated the energy itself:
LEGAL BRIEF OF IDAHO POWER COMPANY -45
Periods during which purchases not required. (1) Any
electric utility which gives notice pursuant to paragraph (0(2)
of this section will not be required to purchase electric
energy or capacity during any period during which, due to
operational circumstances, purchases from qualifying
facilities will result in costs greater than those which the
utility would incur if it did not make such purchases, but
instead generated an equivalent amount of energy itself.
18 CFR § 292.304(f)(1) (2012). FERC recently acknowledged this exception to the
must-buy rule of Section 210 of PURPA. See Entergy Services, Inc., 137 FERC ¶
61,199, P 54-56 (2011). Idaho Power has proposed Schedule 74 to clarify the process
for invoking a Rule 304(f) curtailment. As explained below, Idaho Power's customers
increasingly are incurring costs arising from excess QF generation during light load
periods; FERC and PURPA intend that those costs not be borne by the utility customer;
and thus relieves the utility from its obligation to purchase during these defined periods.
Idaho Power's proposed Schedule 74 reasonably implements FERC Rule 304(f) to
correct this misallocation of costs.
1. FERC Rule 304(t) is a Viable Exception to PURPAs Must-Buy
Obllaation
FERC explained, in its order adopting Rule 304(f), that its intent was to make an
exception to the must-buy obligation during light load periods when certain system
conditions are present:
The proposed rule provided that an electric utility will not be
required to purchase energy and capacity from qualifying
facilities during periods in which such purchases will result in
net increased operating costs to the electric utility. This
section was intended to deal with a certain , condition that can
occur during light loading periods. If a utility operating only
base load units during these periods were forced to cut back
output from the units in order to accommodate purchases
from qualifying facilities, these base load units might not be
able to increase their output level rapidly when the system
LEGAL BRIEF OF IDAHO POWER COMPANY -46
demand later increased. As a result, the utility would be
required to utilize less efficient, higher cost units with faster
start-up to meet the demand that would have been supplied
by the less expensive base load unit had it been permitted to
operate at a constant output.
Order No. 69, 45 Fed. Reg. at 12,227. During certain system conditions when loads are
light, accepting QF purchases will force the utility to shut down one or more of its most
economical units in order to make room on its system for QF purchases. When system
loads go back up (typically the next on-peak period), the utility must rely on its more
expensive peaking units until the slower starting, more economical units are available.
The result is that the QF purchases have caused the utility to substitute peaking units
for base load units—with a resulting higher cost to the utility's customers. This
substitution is uneconomical, and can also lead to system emergency if the utility has
inadequate peaking units available to meet its next peak.
While PURPA generally does not permit utilities to curtail Us for "economic"
reasons, 304(f) is an explicit exception. PURPA's exception allowing curtailment during
light load periods serves several important policy objectives. It reduces the utility's
marginal costs; it reduces wear on base load units caused by cycling them; and it
reduces the likelihood of a capacity shortfall during the next peaking cycle.
2. Rule 304(t) Is Not Limited to "Real-Time" Contracts
Intervenors allege that Rule 304(f) does not apply to contracts where the avoided
cost rate was pre-determined and fixed in the contract. See Idaho Wind Partners I,
LLC, Guy, Direct, p. 5. Such an interpretation would make Rule 304(f) inapplicable to
virtually all of Idaho Power's PURPA contracts. Mr. Guy asserts that such an
interpretation is required by the following passage from Order No. 69:
LEGAL BRIEF OF IDAHO POWER COMPANY -47
[FERC] does not intend that this paragraph override
contractual or other legally enforceable obligations incurred
by the electric utility to purchase from a qualifying facility. In
such arrangements, the established rate is based on the
recognition that the value of the purchase will vary with the
changes in the utility's operating costs. These variations
ordinarily are taken into account, and the resulting rate
represents the average value of the purchase over the
duration of the obligation. The occurrence of such periods
may similarly be taken into account in determining rates for
purchases.
Order No. 69, 45 Fed. Reg. at 12,228 (emphasis added). Mr. Guy has taken FERC's
statement, above—which refers only to a sub-category of fixed-rate contracts—and
incorrectly concluded that it applies equally to all fixed-rate contracts. See Commission
Staff Rebuttal Test. R. Sterling at 4-5 (June 29, 2012) ("Mr. Guy's and Mr.
Schoenbeck's interpretations of the proper application of Section 304(f) might be correct
if the presumptions described by FERC in Order No. 69 and in the Entergy order
[Entergy Services, Inc., 137 FERC 161,199] were correct for Idaho. However, those
presumptions, in fact are not correct for Idaho.").
A careful reading of the passage above makes clear that FERC is talking only
about contracts with fixed rates that account for light load conditions contemplated by
Rule 304(f). Several phrases in FERC's statement compel the conclusion that there are
more than one type of fixed rate contracts and that FERC is only talking about one type:
The word "ordinarily", in the third sentence, indicates that there are at least two types of
contracts—the "ordinary" contracts, and non-ordinary contracts. "Ordinary" contracts,
according to FERC, above, are those with rates that take into account the light load
conditions contemplated by Rule 304(f). It follows, logically, that non-ordinary avoided
cost contracts do not take into account the light load conditions contemplated by Rule
LEGAL BRIEF OF IDAHO POWER COMPANY -48
304(f). In the next sentence, above, FERC says that such light load periods "may" be
taken into account in determining rates for purchases. The use of "may" as opposed to
"shall" indicates FERC permits both types of contracts under PURPA. In the case of
ordinary contracts—those that take Rule 304(f) conditions into account when setting the
rate—allowing the utility to curtail a QF during circumstances described in Rule 304(f)
would, in effect, give the utility two remedies for the same event. Therefore, the first
sentence in the above indented quote clarifies FERC's position that Rule 304(f)
curtailment of QF output in instances where the contract rate already takes Rule 304(f)
conditions into account would impermissibly "override" the resolution of the issue
embodied in the contract. Pub. Serv. Co. of Okla. v. State, 2005 OK 47, 56, 115 P.3d
861, 884 (2005) ("While we agree with the [Oklahoma] Commission that purchase rates
may take periods of operational circumstances into account, thereby rendering moot the
provisions of § 292.304(f), we agree with [the utility] that the record in this case does not
provide substantial evidentiary support for the [Oklahoma] Commission's contention
[that such operational circumstances are accounted for in the instant purchase rates].").
However, if a state chooses not to account for such effects when setting rates, then
curtailment would not be duplicative, nor would it override the contract. Under such
facts, curtailment is the only means left by which the utility may exercise its right under
Rule 304(f) to prevent customers from having to bear such costs.
The Entergy order, cited on page 5 of Mr. Guy's Direct Testimony, does not alter
this analysis or conclusion. In that order, FERC observed:
Many avoided cost rates are calculated on an average or
composite basis, and already reflect the variations in the
value of the purchase in the lower overall rate. In such
circumstances, the utility is already compensated, through
LEGAL BRIEF OF IDAHO POWER COMPANY -49
the lower rate it generally pays for unscheduled QF energy,
for any periods during which it purchases unscheduled QF
energy even though that energy's value is lower than the
true avoided cost. On the other hand, for avoided cost rates
that are determined in real-time, such avoided costs adjust
to reflect the low (or zero or negative) value of the
unscheduled QF energy, allowing the QF to make its own
curtailment decisions. In neither case is the utility authorized
to curtail the QF purchase unilaterally.
Entergy Services, Inc., 137 FERC 1 61,199, P 56 (emphasis added). As in Order No.
69, the Entergy order uses words of limitation (italicized above) that make clear that
FERC is speaking about a subset of contracts rather than the universe of QF-utility
relationships. The Entergy order goes beyond Order No. 69 regarding yet another type
of QF contract—those wherein the avoided cost is determined in real-time. FERC
concludes that a utility may not unilaterally curtail QF output under either: (a) a fixed
price contract that accounts for Rule 304(f) conditions, or (b) a real-time priced contract.
However the Entergy Order, like Order No. 69, does nothing to limit Rule 304(f) as
applied to contracts with long-term fixed rate prices that do not take into account
circumstances contemplated in Rule 304(f).
Order No. 69 and the Entergy order make clear that Rule 304(f) does not permit
a utility to curtail a QF with a fixed-price contract if the prices in the contract take into
account tight load conditions contemplated in Rule 304(f). However, those orders say
nothing to limit the utility's right to curtail when fixed-rate prices have been calculated
without accounting for such light load conditions. Intervenors' attempt to extend those
orders to all QF contracts contradicts the plain language upon which they rely. Such an
interpretation also would render meaningless the plain language of Rule 304(f)(1).
Mont. Air Chapter No. 29, Assn of Civilian Technicians, Inc. v. Fed. Labor Relations
LEGAL BRIEF OF IDAHO POWER COMPANY -50
Auth., 898 F.2d 753, 761 (9th Cir. 1990) (citing Bow/es v. Seminole Rock & Sand Co.,
325 U.S. 410, 89 L. Ed. 1700, 65 S. Ct. 1215 (1945), for the proposition that an
agency's interpretation of its own rule must comport with the rule's language).
The distinction between contracts that do and contracts that do not take into
account light load conditions contemplated in Rule 304(f) is critical, since according to
Commission staff engineer, Rick Sterling, power purchase agreements in Idaho with
published avoided cost rates do not take such conditions into account:
LEGAL BRIEF OF IDAHO POWER COMPANY -51
I have been the person responsible for computing Idaho's
published avoided cost rates for the past 18 years. Although
I did not create the original SAR model used to compute
published avoided cost rates, I have made the extensive
changes to the model that have been ordered over the past
18 years, I have maintained the model, and I have been
responsible for making all of the avoided cost computations
adopted by the Commission since 1995. Based on my
extensive experience with the SAR model, Idaho's published
avoided cost rates do not already reflect the variations in the
value of the purchase in the lower overall rate during the
specific low loading scenarios when 304(f) is clearly
intended to apply.
Sterling, Rebuttal, p. 5 (emphasis in original). Mr. Sterling goes on to explain that there
are no post-model adjustments to avoided cost prices that take Rule 304(f) into account.
Nor does the wind integration adjustment, the 90/110 performance band, the
Mechanical Availability Guarantee, or any other step in the SAR model process provide
for an adjustment to address Rule 304(f) costs. Id. at 9-13. Likewise, the AURORA
model used by Idaho Power under its proposed IRP methodology does not in any way
account for light load conditions in the way contemplated in Rule 304(f). Reading,
Direct, Ex. 504, 41 (Idaho Power Company's Response to the Second Production
Request of the Commission Staff to Idaho Power Company, Response to Request No.
6). Because Idaho Power's avoided cost rates do not take into account Rule 304(f),
Idaho Power retains the right to curtail QFs under the circumstances contemplated in
the rule. Intervenors' protests to the contrary are unpersuasive.
3. Rule 304(t) Applies to Existing. Fixed-Price Contracts
Intervenors argue, in the alternative, that Rule 304(f) at least cannot apply to
existing QF contracts because doing so would change an established bargain. See
Direct Test. Schoenbeck at 37 ('[Schedule 74] unilaterally modifies otherwise
LEGAL BRIEF OF IDAHO POWER COMPANY -52
negotiated and existing contractual rights."); see also Guy, Direct, p. 6; Reading, Direct,
p. 50. This argument runs counter to the principle that extant applicable law is a part of
every contract as if it were expressly cited or its terms incorporated in the contract. See
Fidelity Trust Co. v. State, 72 Idaho 137, 149 (1951) (finding "it is axiomatic that extant
law is written into and made a part of every written contract."); Pub. Serv. Co. of Okla.,
2005 OK at 54, 115 P.3d at 884. In Public Service Co. of Oklahoma v. State, the
Oklahoma Supreme Court applied this principle and found that a utility retained the right
to curtail output under Rule 304(f) even though there was no provision in the QF
contract expressly incorporating Rule 304(f):
An intent to modify applicable law by contract is not effective
unless the power is expressly exercised. A contractual
adjustment of rights contrary to law must be clearly
expressed in the agreement if applicable law is not to be
applied. Hence, the provisions of § 292.304(f) remain
available to [the utility] regardless of whether they are
expressly included in the contract.
2005 OK at 54, 115 P.3d at 884. (internal citations omitted; emphasis added). The
Oklahoma Supreme Court's opinion makes clear that Intervenors' assertion that extant
law must be expressly included into a QF contract is wrong; extant law is part of every
contract unless excluded, and QF contracts in Idaho do not exclude Rule 304(f). See
Direct Test. Sterling at 38 ("I think Idaho Power has always had [Rule 304(f)] authority
whether or not it is expressly spelled out in a contract or a tariff'); see also Sterling,
Rebuttal, p. 13 ("none of the provisions contained in any of the Idaho Wind Partners'
contracts (or any other QF contracts) address or capture variations in an overall rate
that would encompass circumstances described in FERC Order No. 69 or in the Entergy
LEGAL BRIEF OF IDAHO POWER COMPANY -53
order'). Therefore Idaho Power, like the utility in Public Service Co. of Oklahoma v.
State, retains its right to curtail under Rule 304(f).
4. Idaho Power's Proposal to Implement Rule 3040) with Schedule 74 Is
Not Novel
Idaho Powers right to curtail Us under Rule 304(f) conditions exists without any
further action from the state. However, a tariff or other official statement of policy may
improve the effectiveness of such curtailments, when the need arises. Nevada,
California, and Florida have all implemented Rule 304(f) curtailment in a fashion similar
to Schedule 74. These three states found it appropriate to clarify rights under Rule
304(f).
Possibly most similar to Schedule 74 is the Nevada Public Service Commission's
("Nevada PSC") implementation of Rule 304(f). Saguaro Power Co. v. Nevada Power
Co., Nevada PSC Docket No. 93-5037, 1994 WL 780897 (November 30, 1994)
(implementing Rule 304(f) with respect to two pre-existing QF contracts which were
later repealed as part of a settlement wherein the Us and the utility amended their
power purchase agreements.). In Saguaro, the Nevada PSC resolved a dispute over
the utility's right to make a Rule 304(f) curtailment under two existing PPAs by providing
a specific curtailment procedure. Id. at attachment "Policy and Procedure for
Curtailment of Certain PURPA Qualifying Facilities" (appears in the record as Exhibit.
No. 4 to Direct Testimony of Idaho Power witness Tessia Park) (the "Nevada
Procedure"). The Nevada Procedure allows the utility to curtail on a pro rata basis the
two Us when accepting QF output would result in negative avoided costs. Nevada
Procedure at P 3, 5. Negative avoided costs may arise when the utility is using only
base load resources and is not making economy purchases. Id. at P 6. Base load
LEGAL BRIEF OF IDAHO POWER COMPANY -54
resources are, inter alla, the utility's coal generation and the utility's allocation of the
Hoover hydroelectric project, and resources required for system regulation. Id. at P 3.
The Nevada Procedure also imposes notice and recordkeeping requirements on the
utility. Id. at P 7.
In implementing standard offer PURPA contracts, the California Public Utilities
Commission ("California PUC") provided that utilities could curtail QF purchases when
avoided costs are negative. Rulemaking on the Commission's own motion to establish
standards governing the prices, terms, and conditions of electric utility purchases of
electric power from cogeneration and small power production facilities, California PUC
Decision 82-01-103, ordering paragraph 14, 8 CPUC2d 20, 1982 Cal. PUC LEXIS 1296
(Jan. 21 1982). Rather than defining base load resources, the California PUG provided
an example of when negative avoided costs may occur:
[I]f a base load or a large oil-fired intermediate load plant
were shut down at night, due to an excess of QF electricity,
but then could not be restarted and brought up to its rated
output for the next day's peak load, and necessitated instead
startup of a plant with very high generating costs (e.g., a gas
turbine peaker or an expensive emergency purchase of
capacity), the cost to meet the day's peak load might
substantially exceed the avoided cost of the previous night's
shutdown.
Id. at *100. The California PUG concluded that negative avoided cost did not occur
merely because, to balance its system and accept QF output, a utility had to spill water
it otherwise would have used to generate. Id. at *99..100. The California PUG limited
curtailment to QFs of 1 MW or greater capacity. Id. at ordering paragraph 16. Although
the California PUC expected curtailment circumstances were unlikely to occur in more
than 100 hours per year, it did not place a limit on curtailment. Id. at *101. The
LEGAL BRIEF OF IDAHO POWER COMPANY -55
California PUC also imposed notice and recordkeeping requirements on the utilities. Id.
at ordering paragraphs 15, 17.
The Florida Public Service Commission ("Florida PSC") approved the utility's
curtailment plan as a reasonable means to deal with minimum load conditions that
would have caused negative avoided costs. In Re: Petition.., curtailing purchase from
qualifying utilities in minimum load conditions, Order No. PSC-95-1 I 33-FOF-EQ, 164
PUR4th 173, 1995 Fla. PUC LEAS 1274, *28 (1995). Under the curtailment plan,
minimum load occurs when utility generation plus QF generation plus other utility
purchases are greater than demand. Id. at *3 The Florida PSC rejected the argument
made by QFs that the utility should not be allowed to curtail during minimum load
because minimum load resulted from poor planning by the utility. Id. at *11. The
Florida PSC found that "lower than projected minimum load growth, and greater than
projected QF capacity, created [the utility's] minimum load problem." Id. The Florida
PSC explained how to determine whether avoided costs are negative:
We find that a utility should consider all of the costs to
generate electricity with and without QFs, including fuel cost,
O&M, variable operating costs, unit shut-down and start-up
costs, replacement power costs, incremental unit impact
costs, and transmission losses, to determine whether
negative avoided costs would occur during a minimum load
condition.
Id. at *17 (incremental unit impact costs mean the increased operation and maintenance
costs of cycling base load coal units). The utility procedure imposes four measures it
must take prior to curtailing QFs: (1) minimize off-system energy purchases; (2)
maximize economic off-system sales; (3) make maximum use of voluntary QF output
reductions; and (4) reducing its own units to minimum reliable generation levels. Id. at
LEGAL BRIEF OF IDAHO POWER COMPANY -56
*20 . If curtailment is needed despite the utility's mitigation efforts, non-firm Us are
curtailed first and, if necessary, firm QFs are curtailed. Id. at *25..26 QFs with firm
capacity contracts are paid the capacity portion of rate during curtailment. Id. at *26 .
The utility's procedure provides for advance notice of curtailment to QFs. Id. at 19 .
Nevada, California, and Florida have each implemented written procedures
describing how Rule 304(f) is applied. The differences between them illustrate that
States have flexibility to determine how Rule 304(f) is implemented so long as
implementation is not inconsistent with the Rule. Schedule 74's features are similar in
breadth and detail to written procedures adopted in Nevada, California, and Florida.
Implementing Schedule 74 to address light load curtailments is a progressive, but by no
means unprecedented, mechanism for implementing FERC Rule 304(f).
5. Idaho Power's Proposed Schedule 74 Comports with PURPA
Idaho Power has proposed Schedule 74 to establish the terms and conditions
under which Idaho Power will exercise Rule 304(f) curtailment rights. Schedule 74 will
apply whenever the utility is confronted with the choice during low load periods of
curtailing QF output or not curtailing Us and thereby causing Idaho Power to meet the
next peak or peaks with a more expensive resource, such as a less efficient gas
peaking unit. The specific requirements of Schedule 74 are tailored to comply with
Rule 304(f).
a. "Base Load Resources" - Schedule 74 defines "Base Load
Resources" to clarify which Idaho Power resources may remain on-line during a Rule
304(f) curtailment. Base Load Resources include Idaho Power's coal-fired generating
resources, its run-of-river hydro generators, its Hells Canyon hydroelectric complex, and
LEGAL BRIEF OF IDAHO POWER COMPANY -57
its Langley Gulch combined-cycle combustion turbine plant (when operable). Each of
these resources is discussed below.
Coal-Fired Resources .- Idaho Power operates coal-fired generating
units at Jim Bridger, Valmy, and Boardman. These units require several days to restart
each time they are shut down. Park, Rebuttal, p. 6. Because these units cannot be
curtailed during light load periods and restored in time to meet subsequent peaks, Idaho
Power will curtail QF generation prior to curtailing each of its coal-fired units.
Run-of-River Hydro Resources - Idaho Power must curtail QFs
prior to run-of-river hydro generators during Rule 304(f) conditions because such
facilities have license or permit requirements that prevent them from spilling water for
the purpose of not generating. Park, Direct, p. 20 ("Pursuant to the FERC licenses
Idaho Power has for its run-of-river hydro electric projects, the Company is obligated to
take whatever generation flows through them; it does not have the ability to decrease or
increase the generation."); Reading, Direct, Ex. 504, 11 (Idaho Power Company's
Response to the Second Production Request of Exergy Development Group of Idaho to
Idaho Power Company, at 22) ("The proposed operations in the applications for FERC
licenses and state water quality certifications did not include spill except when flows
exceeded plant capacity or when generators tripped off-line in emergency situations.
To the contrary, operations may require an amendment to the FERC licenses and/or
state water quality certifications.").
Hells Canyon Complex - Idaho Power must curtail QFs prior to
reducing the Hells Canyon Complex generation below approximately 350 MW in order
to comply with its FERC license and other regulatory and reliability requirements.
LEGAL BRIEF OF IDAHO POWER COMPANY -58
Applicable requirements include instantaneous and 3-day average minimum flows at
each project, total dissolved gases ("TDG") limitations below each project; and North
American Electric Reliability Corporation ("NERC") and Western Electric Coordinating
Council ("WECC") system reliability criteria. These requirements are summarized on
pages 24-27 of Idaho Power Company's Response to the Second Production Request
of Exergy Development Group of Idaho to Idaho Power Company. Direct Test.
Reading, Ex. 504,13-16.
Langley Gulch - Idaho Power will curtail QFs prior to reducing
Langley Gulch generation below its minimum generation level (approximately 160
MW4). Idaho Power cannot take Langley Gulch down to 0 MW during light load periods
because Langley Gulch must run at about 160 MW in order to provide system
regulation. Rebuttal Test. Park at 8 ("However, although Langley Gulch has the ability
to ramp up and down, there are still limitations on taking it off-line during low loading
periods. To ensure its availability to ramp when the variable intermittent resources drop
or fall off, Langley Gulch will need to be on-line and running at minimum loadings during
some periods, making it a 'must run' resource, in order to provide the regulation service
and other ancillary services required by [NERC] mandatory reliability standards"). Idaho
Power, like most other utilities, requires a load-following generator(s) to balance the
difference between its base load generators and system load. Historically, Idaho Power
used the Hells Canyon Complex for this function. However the potential load fluctuation
of unscheduled energy on Idaho Power's system will soon exceed the regulation
capabilities of the Hells Canyon Complex. Park, Direct, p. 12-14. When Langley Gulch
"Reading, Direct, Ex. 504, 17 (Idaho Power Company's Response to the Second Production Request of
Exergy development Group of Idaho to Idaho Power Company, at 28, Response to Request for
Production No. 21).
LEGAL BRIEF OF IDAHO POWER COMPANY -59
comes on line, one of its vital roles will be to supplement system regulation currently
provided by the Hells Canyon Complex. Curtailment of Langley Gulch during light load
conditions would compromise Idaho Power's ability to regulate large fluctuations in
system load. Therefore, Idaho Power classified Langley Gulch as a Base Load
Resource in Schedule 74. Park, Rebuttal, p. 8.
Some Intervenors have objected to Idaho Power defining non-coal units as Base
Load Resources.5 Those objections read Rule 304(f) too narrowly. Rule 304(f) cannot
be read so narrowly as to require the utility to curtail all resources except slow ramping
thermals. Such an interpretation likely would cause a system emergency because the
thermal base-load units are not able to perform the essential function of ramping up and
down quickly to keep loads and resources in constant balance. Such an interpretation
would also cause Idaho Power to violate FERC licenses and other regulations which
limit its legal ability to turn off generation at its hydroelectric power plants. Other state
commissions have recognized that Rule 304(f) does not require curtailment of all non-
coal resources. New York permits utilities to include nuclear plants, must-run fossil
units, and run-of-river hydro. Proceeding on Motion of the Commission to Establish
Conditions Governing Curtailment Clauses in Contracts for On-Site Generation, New
York Public Service Commission Case No. 88-E-081, 1989 N.Y. PUC LEXIS 71 (July
27, 1989). Nevada allowed long-term take or pay, non-dispatchable contracts, test
energy, and resources required for system regulation. Nevada Procedure at P 3.
Montana found that Rule 304(f) may be triggered even though the utility is purchasing
power, provided the purchased power contract met certain conditions. In the Matter of
the Petition of North Western Energy for a Declaratory Ruling on the Applicability of 18
See Schoenbeck, Direct, p. 42; see also Looper, Direct, p. 5.
LEGAL BRIEF OF IDAHO POWER COMPANY -60
C.F.R. § 292.304(f) and ARM § 38.5.1903(1) to Contracts with Qualifying Facilities,
Montana PSC Order No. 7172, 2011 PUC LEXIS 51 (Sept. 1, 2011), order on reh'g,
Order No. 7172a, P 8-9, 2011 Mont. PUG LEXIS 57 (October 13, 2011)
("North Western"). In sum, it is common practice for utility commissions to allow
continued operation of non-base load thermal resources during Rule 304(f)
curtailments. Schedule 74 clarifies which resources must run during Rule 304(f)
curtailment events due to legal, safety, or system reliability related requirements, and
reasonably implements Rule 304(f).
b. "Applicable QFs" - Schedule 74 applies to all Us with nameplate
capacity over 10 MW with Generator Output Limiting Controls (GOLCs) ("Applicable
Us"). Idaho Power chose not to curtail Us without GOLCs during Rule 304(f)
conditions because such Us cannot be dispatched within a 1-hour period, and
therefore could not be relied upon by Idaho Power when it seeks to reduce generation.
Direct Test. Park at 26. Furthermore, the contribution of such Us to the surplus of QF
generation during Rule 304(f) events is believed to be negligible. Park, Direct, p. 26.
The choice is reasonable given the reasons articulated above. Idaho Power has
created two classes of Us based on objective plant characteristics relevant to their
ability to alleviate Rule 304(f) conditions. All Us belonging to the same class are
treated equally under the Schedule. Rule 304(f) (unlike Rule 307) does not mandate
that QF curtailment occur in a nondiscriminatory basis. Ci 18 CFR § 292.307 (During
a system emergency, sales to Us may be discontinued, provided "such discontinuance
is on a nondiscriminatory basis.") To the contrary Rule 304(f)(2), which states in part
that a utility invoking Rule 304(f) curtailment must notify "each affected qualifying
LEGAL BRIEF OF IDAHO POWER COMPANY -61
facility", assumes that Rule 304(f) curtailment does not apply to all QFs. Under these
conditions, exempting QFs that are under 10 MW or do not have GOLC capability is
reasonable.
C. Notice - Rule 304(f)(2) requires a utility invoking the rule to notify
each affected QF in time for the QF to cease the delivery of energy or capacity to the
utility. Such notice shall be in accordance with State law or regulation. Rule 304(fl(2).
Because Idaho Power only proposes to curtail QFs with GOLC capability, one-hour
notice is sufficient for a QF to cease delivery. However, because QFs have an interest
in knowing about curtailments further in advance, Schedule 74 obligates Idaho Power to
use commercially reasonable efforts to provide such notice as soon as reasonably
possible. Idaho Power intends to comply with this requirement by providing notice to
QFs on a day-ahead basis, updated no later than one hour before curtailment, if the
need to curtail changes. Park, Direct, p. 25. Rule 304(f)(3) provides that any utility
which fails to comply with the notice provisions of paragraph 304(f)(2) pay the QF for
generation and capacity as though a light load period had not occurred. Idaho Power
understands that this remedy would be available to QFs regardless of whether or not
such remedy is set forth in Schedule 74.
d. Verification - Rule 304(f)(4) provides that the utility's claim that a
light load condition contemplated in Rule 304(f) has occurred (or will occur) is subject to
verification by the Idaho Commission before or after the occurrence as the State
determines necessary or appropriate.
A claim by an electric utility that such a period has occurred
or will occur is subject to such verification by its State
regulatory authority as the State regulatory authority
LEGAL BRIEF OF IDAHO POWER COMPANY -62
determines necessary or appropriate, either before or after
the occurrence.
Rule 304(f)(4). Schedule 74 attempts to accommodate this requirement by setting forth
Idaho Power's obligation to maintain records of loads and outputs from all units prior to,
during, and after each period of curtailment. Schedule 74 also requires Idaho Power, at
the end of each curtailment period, to notify all curtailed QFs of the duration of the
curtailment.
e. Off-System Sales - Intervenors allege that Idaho Power should
pursue off-system sales before invoking Rule 304(f) to curtail QFs. Schoenbeck, Direct,
p. 42. While Idaho Power may make sales where the opportunity presents, such sales
should not be required as a condition to curtailing QFs under Rule 304(f). QFs do not
deliver pursuant to any enforceable energy schedule, and consequently Idaho Power
cannot sell the energy ahead of time. Idaho Power receives no schedule for intermittent
QFs and therefore does not know how much energy it will have available to sell. This
makes advance sales virtually impossible. Park, Direct, p. 9. If Idaho Power were to
attempt to sell surplus QF output, it many times would not find a market due to regional
energy glut conditions. Id, at 8-9. Idaho Power is aware that other State Commissions
have insisted on the utility maximizing off-system sales prior to implementing Rule
304(f) curtailment. See eg., Saguaro Power Co. v. Nevada Power Co., Nevada PSC
Docket No. 93-5037, 1994 WL 780897; In Re: Petition ... curtailing purchase from
qualifying utilities in minimum load conditions, Order No. PSC-95-1 1 33-FoF-EQ 164
PUR 4th 173, 1995 Fla. PUC LEXIS 1274. However, those decisions predate FERC's
unbundling of the bulk transmission system. Unbundling has complicated the task of
LEGAL BRIEF OF IDAHO POWER COMPANY -63
selling economy energy since the utility must undesignate the network resource status
of the source of such sales. Park, Direct, p. 10. All of the factors, above, make sale of
surplus generation during Rule 304(f) conditions an unworkable option for Idaho Power.
f.Economic Impact - Intervenors allege that Schedule 74 should be
rejected because it could have unacceptable economic consequences on their existing
projects. See Guy, Direct, p. 6. Intervenors attempt to insert a limitation that does not
exist in the rule. However, nothing in Rule 304(f) suggests that economic impact to the
QF should limit a utility's Rule 304(f) rights. If Idaho Power were to propose or accept
such a cap, Idaho Power would, in effect, be modifying the avoided cost by foregoing
potential savings in excess of the cap. In any event, because the level of Rule 304(f)
curtailment anticipated by Idaho Power is minimal in comparison to the QF's total PPA
revenues, the essence of Intervenors' assertions—that Schedule 74 will threaten the
viability of existing projects—is unfounded.
g.Schedule 74 Does Not Repeat Fatal Errors of North Western
Energy's Proposed Curtailment Tariff in Montana - Montana recently rejected a
utility proposal to curtail Us ostensibly under circumstances contemplated in Rule
304(f). North Western, Order Nos. 7172, 7172a. Intervenors' witness, Don Reading,
alleges that the North We stern orders identify two problems with Idaho Power's
proposed Schedule 74. First, he argues that the Montana Commission correctly
rejected NorthWestern's proposal because Rule 304(f) is narrower than NorthWestern
believed it to be. Reading, Direct, p. 57. Second, he notes that NorthWestern's
proposal, unlike Idaho Power's, faithfully incorporated the remedy for failure to provide a
QF with proper advanced notice set forth in Rule 304(fl(3). Id. Mr. Reading's
LEGAL BRIEF OF IDAHO POWER COMPANY -64
allegations are unpersuasive. As explained previously, the fact that Idaho Power did
not expressly incorporate Rule 304(f)(3) into Schedule 74 does not render it ineffectual
because Schedule 74 is not controlling as between it and the FERC Rules. See
NorthWestern Order No. 7172a at P 11 (stating that NorthWestern's QF-1 tariff does not
trump FERC and state rules). Mr. Reading's other point, that Northwestern's rule is
broader than allowed by Rule 304(f), has no bearing on the different and distinct
provisions of Schedule 74. NorthWestern's proposed curtailment tariff would have
allowed it to curtail QF generation any time such generation would increase its system
costs. The Montana PSC found that such a rule "far exceeds the scope of [Rule
304(f)]." North Western Order No. 7172a at P 6. Schedule 74 contains no analogous
provision. Schedule 74 allows curtailment only during light load periods when QF
generation would cause baseload resources to be unavailable during ensuing peak
periods and Idaho Power must replace those resources with more expensive thermal
peaking units. Schedule 74 is fully consistent with Rule 304(f).
h. Schedule 74 Better Implements Rule 304(f) Than Having No
Schedule - Finally, Intervenors provide no meaningful alternative to Idaho Power's
Schedule 74. Staff agrees with Idaho Power that Rule 304(f) has always been available
to the utilities and exists whether or not the Commission approves Schedule 74.
Sterling, Direct, p. 38. Even Dr. Reading appears to admit that Rule 304(f) would apply
under the right circumstances. See Reading, Direct, p. 52 ("[Rule 304(f)] would apply if
the utility had to instead meet the next peak with a more expensive peaking resource,
such as a less efficient gas peaking unit."). If the question is whether Idaho Power
should invoke Rule 304(f) with a Schedule or without one, implementing the Rule
LEGAL BRIEF OF IDAHO POWER COMPANY -65
through a Schedule has several advantages. It provides clear notice to Us of the
existence of Idaho Power's Rule 304(f) rights. It provides the algorithm for determining
when Rule 304(f) conditions are present. And it sets forth Idaho Power's duties to the
QF during such conditions. All of the above will improve efficiency in implementing Rule
304(f) and reduce disputes between Idaho Power and the QFs regarding whether Rule
304(f) has been implemented correctly. For all the reasons above, Idaho Power
Schedule 74 should be allowed to take effect.
E. THE COMMISSION SHOULD DETERMINE THAT UTILITY PURCHASERS OF
QF GENERATION OWN RENEWABLE ENERGY CREDITS ASSOCIATED
WITH THAT GENERATION
Idaho Power asks the Commission declare that when a utility is compelled to
purchase QF output under the PURPA must-buy obligation, the environmental attributes
associated with the QF output remain bundled with the QF energy and capacity and the
purchasing utility is therefore the owner in the first instance of any RECs that
subsequently may be associated with the QF output. This result is permissible under
PURPA; indeed, FERC has held that the ownership of RECs is controlled by state law
not by PURPA. American Ref-Fuel Co., 105 FERC 1 61,004, P 23 (2003), reh'g denied,
107 FERC 61,016 (2004), appeal dismissed sub nom., Xcel Energy Servs. v. FERC,
407 F.3d 1242 (D.C. Cir. 2005). This result also prevents Us from taking advantage of
ambiguity or uncertainty under Idaho law to unilaterally lay claim to RECs. This result
also recognizes the reality that the utility and its customers are purchasing renewable
generation. Finally, this result recognizes that states create REC5 and that the value of
RECs associated with energy sold under a PURPA contract should appropriately be
LEGAL BRIEF OF IDAHO POWER COMPANY -66
retained fo rhte benefit of the customers that must purchase that generation—a result
that better serves the public interest.
Approximately 25 states and the District of Columbia have enacted renewable
portfolio standards ("RPS"). Utilities in states with an RPS must obtain a designated
percentage of their annual energy needs from renewable energy sources. About half of
RPS states provide for compliance through use of renewable energy credits ("RECs").
In general, a REC represents the "environmental attributes" associated with I MWh of
electricity generated by a renewable energy resource. See Grand View PV Solar Two,
LLC v. Idaho Power Company, IPUC Case No. IPC-E-1 1-15, Order No. 32580, 4 (June
21, 2012) (citing In the matter of a Petition filed by Idaho Power Co. for an Order
Determining Ownership of the Environmental Attributes Associated with Qualifying
Facility Upon Purchase by a Utility of the Energy Produced by a Qualifying Facility,
IPUC Case No. IPC-E-04-2, Order No. 29480 (2004); In the Matter of the Application of
Idaho Power Co. for Authority to Retire its Green Tags, IPUC Case No. IPC-E-08-24,
Order No. 32002 (2010)).
Idaho does not have an RPS program. Grand View PV Solar Two, LLC, Order
No. 32580 at 5 ("[T]he Idaho Legislature has considered but not adopted an RPS.")
Idaho's QFs and utilities are nevertheless interested in owning the environmental
attributes or RECs associated with the power that they generate or purchase in the
state. Such attributes or RECS may have value through selling them to utilities in need
of RECs in states with active RPS programs.6 Moreover, if a state or federal RPS is
6 One way to currently monetize and sell environmental attributes associated with energy generated or
purchased in Idaho would be to register those attributes as RECs with the Western Renewable Energy
Generation Information System ("WREGIS"). According to its website, WREGIS "is an independent,
renewable energy tracking system for the region covered by the Western Electricity Coordinating Council
LEGAL BRIEF OF IDAHO POWER COMPANY -67
adopted, such attributes or RECs may have direct compliance value to Idaho Power
and its customers.
The parties have asked the Commission to determine who owns RECs in Idaho
when a QF generates renewable energy and compels an Idaho utility to purchase that
energy under the PURPA must-buy obligation. In general, QF developers ask the
Commission to conclude that QFs own the RECs,7 and the utilities ask the Commission
to conclude that utilities own the RECs.8 Commission staff has recommended that the
RECs be owned by the utilities but has suggested that the avoided cost price paid by
utilities for QF power may need to be augmented (increased) under the SAR
methodology, but not the IRP methodology, in order to ensure that QFs are adequately
compensated for the transfer of RECs.9 For the reasons set forth below, Idaho Power
urges the Commission to recognize its inherent authority to determine ownership of
RECs in the absence of any Renewable Portfolio Standard (RPS) program or REC
program adopted by the Idaho legislature, to recognize the need to decide REC
ownership in Idaho now, and to recognize the compelling reasons why RECs from utility
("WECC") [which includes Idaho]. WREGIS tracks renewable energy generation from units that register
in the system using verifiable data and creates renewable energy credits (REC5) for this generation.
WREGIS Certificates can be used to verify compliance with state and provincial regulatory requirements
(Renewable Portfolio Standards, for example) and in voluntary market programs." See
http://www.wreciis.org/.
'E.g., Reading, Direct, p. 59-60.
8 See Clements, Direct, p. 7 ("Environmental Attributes generated by a QF project should go to the utility
whenever that QF sells energy to the utility and receives compensation for that energy at approved
avoided cost rates."); Kalich, Rebuttal, p. 9 ("[T]o the extent the Commission chooses to assign RECs to
utilities, Avista opposes adjusting (i.e., increasing) avoided cost rates inlexchange for obtaining the
RECs."); Stokes, Rebuttal, p. 42-43 ("Idaho Power, similar to other parties to this docket, requests that the
Commission specifically find that the Environmental Attributes or RECs from utility purchased QF
generation are owned by the purchasing utility.").
IPUC Staff Direct Test. R. Sterling at 46-47 ("[T]he cost of RECs would, already be accounted for in
computing avoided cost rates using the IRP methodology. Under the SAR methodology, however,
some adjustment to the avoided cost rates may be necessary.").
LEGAL BRIEF OF IDAHO POWER COMPANY -68
purchased QF generation in the state of Idaho should be determined to be owned in the
initial instance by the purchasing utility.
1. States Have the Authority to Decide the Ownership of RECs
It is well established that the question of REC ownership is properly decided by
the states. PURPA does not govern the question, even when the renewable energy in
question is sold pursuant to the PURPA must-buy obligation. American Ref-Fuel Co.,
105 FERC 161,004, P 23 (2003) ("American Ref-Fuel 1'), reh'g denied, 107 FERC ¶1
61,016 (2004) ("American Ref-Fuel If'), appeal dismissed sub nom., XceI Energy Servs.
v. FERC, 407 F.3d 1242 (D.C. Cir. 2005) ("States, in creating RECs, have the power to
determine who owns the REC in the initial instance, and how they may be sold or
traded; it is not an issue controlled by PURPA"); Wheelabrator Lisbon, Inc. v. Conn.
Dept. of Wit. Control, 531 F.3d 183, 190 (2nd Cir. 2008) (affirming that "state law
governs the conveyance of REC5."); Morgantown Energy Assoc., 139 FERC ¶ 61,066,
P 46 (2012) ("PURPA does not address the ownership of REC5 ... states have the
authority to determine ownership of RECs in the initial instance, as well as how they are
transferred from one entity to another."); Grand View PV Solar Two, LLC, Order No.
32580 at 14 ("RECs are created by the states and exist outside the confines of
PURPA.").
These principles were first articulated by FERC in 2003 in response to a petition
for declaratory order filed by American Ref-Fuel and three other QF owners. The QFs
asked FERC for an order declaring that avoided cost contracts entered into pursuant to
PURPA do not inherently convey RECs to the purchasing utility (absent an express
LEGAL BRIEF OF IDAHO POWER COMPANY -69
contract provision to the contrary). American Ref-Fuel I, 105 FERC 161,004, P 2. In
response, FERC issued a declaratory order concluding:
(1)"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." Id. at P 23. "While a state may decide that a
sale of power at wholesale automatically transfers ownership
of the state-created RECs, that requirement must find its
authority in state law, not PURPA." Id at P 24.
(2)"[C]ontracts for the sale of QF capacity and energy
entered into pursuant to PURPA do not convey RECs to the
purchasing utility (absent an express provision in the
contract to the contrary)." Id.
(3)"[A]voided cost rates . . . are not intended to
compensate the QF for more than capacity and energy." Id.
at P 22. "[A]voided cost rates. . . do not convey the RECs,
in the absence of an express contractual provision." Id. at P
18.
A number of utilities requested rehearing. On April 15, 2004, FERC issued an
order denying rehearing. American Ref-fuel II, 107 FERC 61,016. FERC noted that its
reference to "express contractual provision" in the 2003 declaratory order seems to
have been misunderstood. Id., at P 6, n.1. FERC is referring to its statement that a
PURPA contract does not convey RECs "absent an express provision to the contrary in
the contract" and to its statement that avoided cost rates do not convey RECs "in the
absence of an express contractual provision." In the order denying rehearing, FERC
clarifies: "All we intended by this language was to indicate that a PURPA contract did
not inherently convey any RECs, and correspondingly that, assuming State law did not
provide to the contrary, the QF by contract could separately convey the RECs." Id.
This clarification is critical. As explained by the United States Court of Appeals
for the Second Circuit, it means that "American Ref-Fuel does not stand for the
LEGAL BRIEF OF IDAHO POWER COMPANY -70
proposition that PURPA requires an express contractual provision in order for RECs.
to be transferred to a public utility pursuant to a PURPA contract ... ." Wheelabrator
Lisbon, Inc., 531 F.3d at 189 (quoting and affirming Wheelabrator Lisbon, Inc. v.
Connecticut Dept. of Pub. Util. Control, 526 F. Supp. 2d 295, 306 (D. Conn. 2006)).
In light of the clarification made in American Ref-Fuel II and explained by the
Second Circuit in Wheelabrator, FERC's conclusions regarding RECs and PURPA
transactions may be summarized as follows:
(1)States determine initial ownership of RECs and how
RECs may be sold or traded. PURPA does not control the
question. The State determination must be based on state
law not PURPA.
(2)PURPA contracts do not inherently convey RECs to
the purchasing utility. However, a PURPA sale may transfer
RECs if the PURPA contract so provides or if transfer of
RECs to the utility is a consequence of the State's law on
ownership of RECs.
(3)Avoided cost rates are not intended to compensate
the QF for more than capacity and energy. Payment of
avoided cost rates does not inherently convey RECs to a
utility. However, RECs may transfer to the utility upon
payment of avoided cost if the PURPA contract so provides
or if transfer of RECs to the utility is a consequence of the
State's law on ownership of RECs.
FERC's decision to deny rehearing of American Ref-Fuel was appealed to the
United States Court of Appeals for the District of Columbia Circuit. The Court found that
it lacked jurisdiction to review FERC's declaratory order. The Court noted that FERC
"has in effect merely announced the position it would take in any future enforcement
action" and the Court stated that FERC's declaratory order "is of no legal moment
unless and until a district court adopts that interpretation when called upon to enforce
PURPA." XceI Energy Services, Inc., 407 F.3d at 1244. The Court concluded: "FERC's
LEGAL BRIEF OF IDAHO POWER COMPANY -71
position is reviewable by this court only after someone—a utility, a QF, or the
Commission—brings an enforcement action in the district court and appeals therefrom."
Id.
For the reasons discussed by the D.C. Circuit Court, FERC's determinations in
American Ref-Fuel are merely advisory at present. However, American Ref-Fuel
provides compelling evidence of the position FERC can be expected to take in any
enforcement action. Moreover, FERC's conclusion—that states decide ownership of
REC5 and that PURPA does not govern REC ownership—has been widely adopted by
state commissions, state courts, and the federal court. See, e.g., Wheelabrator, 531
F.3d at 184; In the Matter of the Ownership of Renewable Energy Certificates, 913 A.2d
825 (N.J. Super. Ct. App. Div. 2007) (the New Jersey court of appeals affirmed a state
utility commission's exercise of authority to determine the ownership of REC5); ARIPPA
v. Penn. PUC, 966 A.2d 1204, 1211 (Pa. Commw. Ct. 2009) (the Pennsylvania court of
appeals noted that FERC in American Ref-Fuel, the U.S. Court of Appeals for the
Second Circuit in Wheelabrator, and the New Jersey court of appeals in In re
Ownership of RECs, have all affirmed a state's authority to determine the ownership of
RECs, and the Pennsylvania court agreed that PURPA does not preempt a state
commission's authority to determine the ownership of RECs); City of New Martinsville,
Nos. 11-1738, 11-1739, 2012 W. Va. LEXIS 308, at *16..17 (W. Va. June 11, 2012)
(Supreme Court of West Virginia upheld the state utility commission's determination that
utility owned RECs associated with power sold under a PURPA contract and cited with
approval to FERC's reasoning in American Ref-Fuel that ownership of RECs is a state
determination not governed by PURPA).
LEGAL BRIEF OF IDAHO POWER COMPANY -72
Significantly, the Idaho Commission recently agreed with FERC that states
decide initial ownership of RECs and that PURPA does not control the question. Grand
View PV Solar, LLC, Order No. 32580 at 14 ("RECs are inventions of state property law.
FERC has consistently held that PURPA does not control the ownership of RECs. More
to the point, RECs are created by the states and exist outside the confines of PURPA
(with the exception of express provisions in a PPA). (internal citations omitted).
In sum, it appears that FERC, numerous state commissions, the United States
Court of Appeals for the Second Circuit, the Connecticut Supreme Court, the West
Virginia Supreme Court, the court of appeals in Pennsylvania, the court of appeals in
New Jersey, and the Idaho Commission all agree that ownership of RECs is decided by
states even in the context of a PURPA power sale. Idaho Power is not aware of any
decision in any jurisdiction suggesting that states do not have the authority to determine
ownership of RECs as an initial matter.
2. The Commission Has the Subject-Matter Jurisdiction to Decide
Ownership of RECs from PURPA Sales Even in the Absence of an
Idaho RPS Statute
As discussed in the preceding section, states have the power to decide who
owns environmental attributes or RECs in the first instance. This decision can be made
legislatively by statute. or it can be made administratively by order of a state utility
commission. However, utility commissions only have the powers delegated to them by
statute. Before a utility commission can administratively determine the ownership of
RECs, it must have the statutory authority or subject-matter jurisdiction to do so.
All state utility commissions have broad general powers enumerated in the
commission's organic or enabling statutes. These powers may be sufficient to authorize
LEGAL BRIEF OF IDAHO POWER COMPANY -73
a commission to determine ownership of RECs. In addition to these organic or enabling
powers, some states have passed RPS legislation, which may grant their state utility
commission additional statutory authority to regulate ownership of RECs.
Even when the legislature passes an RPS and addresses ownership of RECs
generally, there may be questions of ownership that are not addressed by the RPS
legislation. For example, most RPS legislation fails to state whether the utility or the QF
owns the RECs for renewable energy purchased under a PURPA contract that pre-
dates the passage of the RPS statute. Under such circumstances, many utility
commissions have made an administrative determination of REC ownership (most,
perhaps all, commissions have determined that the RECs are owned by the utility under
such circumstances). Edward A. Holt et al., Who Owns Renewable Energy
Certificates? An Exploration of Policy Options and Practice, at xiv (Ernest Orlando
Lawrence Berkeley National Laboratory 2006); see also infra n. 10-11 (discussing the
aforementioned report).. In making such an administrative determination of REC
ownership, state commissions are concluding that they have subject-matter jurisdiction.
The Pennsylvania utility commission has found subject-matter jurisdiction to
decide REC ownership based on the combined effect of the state RPS statute and the
commission's organic statutes. Petition for a Declaratory Order Regarding the
Ownership of Alternative Energy Credits, Penn. PUC P-00052149, 2006 Pa PUC LEXIS
110, at *4856 (2006). The Pennsylvania court of appeals has upheld this finding of
subject-matter jurisdiction. ARIPPA, 966 A.2d at 1212.
The West Virginia utility commission has found that it has subject-matter
jurisdiction to determine REC ownership on the separate and independent grounds of
LEGAL BRIEF OF IDAHO POWER COMPANY -74
both the state RPS statute and the commission's organic statutes. Monongahela Power
Co., W. Va. PSC Case No. 11-0249-E-P, 2011 W. Va. PUC LEXIS 2760, at *43 (2011).
The West Virginia commission reasoned:
We determine that the Legislature has vested the
Commission with jurisdiction and authority over this matter.
Not only does the Commission have subject-matter
jurisdiction over this matter and the parties based on the
Portfolio Act [the State of West Virginia's RPS statute], the
Commission also has jurisdiction over this matter pursuant to
the provisions of Chapter 24 of the West Virginia Code [the
Commission's organic enabling act] related to the
Commission's powers and duties to regulate public utilities,
to establish just and reasonable rates. . . and to review and
approve [power purchase agreements]. Id.
The West Virginia Supreme Court affirmed the commission's decision to award REC
ownership to utilities but the court did not address subject-matter jurisdiction
(presumably because jurisdiction was not raised on appeal). City of New Martinsville,
2012W. Va. LEXIS 308.
The Connecticut utility commission appears to have found that it has subject-
matter jurisdiction to determine REC ownership on the basis of its organic statutes
alone even though Connecticut also has an RPS statute. Wheelabrator Lisbon, Inc. v.
Dep't of Pub. Wit. Control, 931 A.2d 159, 171 (Conn. Sup. Ct. 2007) ('We see no
reason to conclude that the department lacked jurisdiction to make these determinations
under [statutes providing for declaratory orders] merely because the certificates were
created and § 16-245a, which recognized and gave value to the certificates, was
enacted after the execution of the 1991 agreement."). The Connecticut courts have
upheld the commission's finding of jurisdiction without resort to the state RPS statute.
LEGAL BRIEF OF IDAHO POWER COMPANY -75
Wheelabrator Lisbon, Inc. v. Dept of Pub. Util. Control, 2006 Conn. Super. LEXIS 858,
at *1214 (Conn. Super. Ct. 2006), affd Wheelabrator Lisbon, Inc., 931 A.2d at 167-171.
Finally, the Wyoming utility commission has exercised subject-matter jurisdiction
to decide REC ownership on the basis of its organic statutes alone and in the absence
of a state RPS statute. See In the Matter of the Application of Rocky Mountain Power to
Implement a Permanent Avoided Cost Methodology, Wyo. PSC Docket No. 20000-388-
EA-11, Record No. 12750, P 50, 2011 Wyo. PUC LEXIS 441 (2011) (Commission
discussed its various powers under its organic statutes and noted that "[r]ead in pan
material, these statutes articulate the basic mechanism of the public interest standard
which the Commission is to follow in its decisions."). The Wyoming Public Service
Commission held that RECs arising from the sale of renewable QF power under a
PURPA contract are owned by the purchasing utility. Id. at P 63 ("... the Commission
finds [the utility] should continue to retain the RECs since they represent tangible value
for the ratepayer, and they should not be routinely severed from the underlying green
power generated."). To date, the Wyoming commission's exercise of jurisdiction has not
been subjected to judicial review.
These cases indicate that state commissions enjoy subject-matter jurisdiction to
decide the ownership of RECs even in the absence of a state RPS. Indeed, the West
Virginia, Connecticut, and Wyoming commissions all concluded that a state utility
commission's organic statutes are sufficient on their own, and without support from a
state RPS statute, to establish a commission's subject-matter jurisdiction to determine
the ownership of REC5.
LEGAL BRIEF OF IDAHO POWER COMPANY -76
The Idaho Legislature has not enacted an RPS statute or otherwise made an
express grant of authority to the Idaho Commission to determine the ownership of
REC5. Moreover, the Idaho Commission "exercises limited jurisdiction and has no
authority other than that expressly granted to it by the legislature." Alpert v. Boise
Water Corp., 118 Idaho 136, 140 (1990). The Idaho Supreme Court has further
explained:
The Commission . . . exercises a limited jurisdiction and
nothing is presumed in favor of its jurisdiction. As a general
rule, administrative authorities are tribunals of limited
jurisdiction and their jurisdiction is dependent entirely upon
the statutes reposing power in them and they cannot confer
it upon themselves, although they may determine whether
they have it.
Wash. Water Power Co. v. Kootenai, 99 Idaho 875, 879 (1979) (internal citations
omitted).
Nevertheless, through the Commission's organic statutes—the public utility laws
(Chapters 1-7 of Title 61, Idaho Code)—the Idaho Legislature has established a
"comprehensive scheme for the regulation of investor-owned public utilities ... ." Alpert,
118 Idaho at 140. More specifically, the authority granted to the Commission includes:
[T]he power to investigate and fix rates and regulations, I.C.
§ 61-503; determine the reasonableness of rates, I.C. § 61-
502; investigate proposed interstate rates, I.C. § 61-506;
determine rules and regulations affecting the performance of
public utilities, I.C. § 61-507; order improvements to utility
facilities, I.C. § 61-508; investigate accidents occurring on
public utility property arising from its maintenance or
operation, I.C. § 61-517; determine standards and practices
for the measurement of quantity, quality or other conditions
pertaining to the supply of a public utility product or service,
I.C. § 61-520; ascertain the value of public utility property,
I.C. § 61-523; and issue certificates of convenience and
necessity, I.C. § 61-526.
LEGAL BRIEF OF IDAHO POWER COMPANY -77
Id., at 140, n.1. Regarding the extensive range of powers granted to the Commission,
the Idaho Supreme Court has noted:
There is no question that much of the work of the
Commission, particularly in the areas of ratemaking, requires
expertise, technical skill and constant attention. . . . Such
was held to be a strong argument for the delegation of the
legislative authority to a commission under statutes
established by the legislature.
Wash. Water Power Co., 99 Idaho at 882.
The Idaho Supreme Court has recognized that the Idaho Commission has the
authority to approve the terms and conditions of PURPA contracts but that the
subsequent interpretation and enforcement of contracts generally does not fall within
the Commission's powers. Idaho Power Co. v. Cogeneration, Inc., 129 Idaho 46, 49
(1996).
Under Idaho Code § 61-328, a public utility may not transfer utility property
without the approval of the Commission. See e.g., In the Matter of the Application of
Idaho Power Company for Authority to Sell to PaciflCorp the Goshen Series Capacitor
Bank, IPUC Case No. IPC-E-09-32, Order No. 31007, 2 (2010) ("Pursuant to Idaho
Code § 61-328, the Idaho Public Utilities Commission is charged with the responsibility
to review the sale of electric public utility property to ensure that (1) the transaction is
consistent with the public interest, (2) the cost of electricity and service rates will not be
increased because of the transaction, and (3) the buyer of the electric utility's property
has both the intent and the financial ability to operate the property in the public
service.").
Given all of the powers vested in the Idaho Commission by its organic statutes—
including the power to investigate and fix rates and regulations (I.C. § 61-503), the
LEGAL BRIEF OF IDAHO POWER COMPANY -78
responsibility to determine the reasonableness of rates (l.C. § 61-502), the responsibility
to determine rules and regulations affecting the performance of public utilities (l.C. § 61-
507), the responsibility to approve transfers of utility property (l.C. § 61-328), and the
responsibility to review and approve the terms and conditions of PURPA contracts—the
Commission has organic authority comparable to the authority the commissions of West
Virginia, Connecticut, and Wyoming concluded was adequate authority to consider and
decide the ownership of RECs.
3. The Idaho Commission Should Hold that Utilities Own All
Environmental Attributes or RECs Associated with QF Enerav Sold
to the Utilities Under the PURPA Must-Buy Obligation
As discussed above, states determine who owns RECs and the Commission has
jurisdiction to decide ownership of RECs in Idaho. Most utility commission decisions on
REC ownership involve circumstances where the state has enacted an RPS program
but the renewable energy in question is sold under PURPA contracts executed before
the state established its RPS program (or any associated REC program).10 Because
the PURPA contract pre-dates the RPS program, the contract typically is silent
regarding ownership of environmental attributes. In the absence of an express
contractual provision, state commissions are left to decide who owns the attributes as a
10 At least nine state commissions have faced these circumstances and all reportedly concluded they
utility owns the RECs. See In the Matter of the Ownership of Renewable Energy Certificates, 913 A.2d
825, 828 (N.J. Super. 2007) (citing Edward A. Halt, et at., Who Owns Renewable Energy Certificates? An
Exploration of Policy options and Practice, at xiv (Ernest Orlando Lawrence Berkeley National Laboratory
2006). The most helpful decisions—either because they have been thoroughly appealed or because they
contain particularly clear analysis—can be found in the following jurisdictions: Connecticut: cases
culminating in Connecticut Supreme Court decision Wheelabrator Lisbon, Inc., 931 A.2d 159. West
Virginia: cases culminating in West Virginia Supreme Court decision City of New Martinsville, 2012 W.
Va. LEXIS 308. Pennsylvania: cases culminating in Pennsylvania court of appeals decision ARIPPA,
966 A.2d 1204. New Jersey: cases culminating in New Jersey court of appeals decision In the Matter of
the Ownership of Renewable Energy Certificates, 913 A.2d 825.
LEGAL BRIEF OF IDAHO POWER COMPANY -79
matter of state law and policy. The question becomes: Who owns environmental
attributes when a utility is required to buy renewable energy under a PURPA contract
but there was, or is, no state RPS or REC program in place at the time the contract was
executed? This is essentially the same question faced by the Idaho Commission. In
response to this question, state commissions have generally held, and state courts have
affirmed, that the utility owns the RECs.11
In 2004, the Connecticut Department of Public Utility Control ("DPUC") was faced
with the question of who owned RECs (referred to as "GIS Certificates") when a utility
bought renewable energy under a PURPA contract that had been executed before the
state adopted its RPS program. Petition of the Riley Energy Corp. for Contract
Approval, Conn. PUG Docket No. 91-01-I2RE0I, 2004 Conn. PUC LEXIS 148
(December 6, 2004). The DPUC held that the GIS Certificates quantify the renewable
attributes of the electricity sold by the QF to the utility and that—because the parties
and DPUC intended that the PURPA contract necessarily involve the sale of renewable
energy—the utility obtained ownership of the GIS Certificates as part of its ownership of
the renewable power. Id. at *31..32 ("The GIS Certificates, which nominally quantify the
renewable energy attributes of the 'electricity' are and were intended by the Department
to be sold by Riley [the QF] and purchased by CL&P [the utility].").
See, e.g., Wheelabrator, 931 A.2d at 163 ('... we conclude the [state utility commission] reasonably
determined that the [renewable energy] certificates were owned by the utility"); City of New Martinsville,
2012 W. Va. LEXIS 308 at*33 ('... the decision of the Commission finding that the credits at issue are
owned by the Utilities is affirmed."); ARIPPA, 966 A.2d ati 214 ("... this court accepts the Commission's
persuasive interpretation and reasoning in concluding that electric distribution companies own the credits
..."); In the Matter of the Ownership of RECs, 913 A.2d at492; see also Edward A. Holt, et al., Who Owns
Renewable Energy Certificates? An Exploration of Policy options and Practice, at xiv (Ernest Orlando
Lawrence Berkeley National Laboratory 2006); but see, Petition of Southwestern Pub. Ser. Co. for
Declaratory Order Interpreting Commission Rule Implementing Pubic Utility Regulatory Act, 2005 Tex.
PUC LEXIS 6, *11 (March 16, 2005) (Texas Commission determines RECs are owned by QFs where
state regulation expressly requires award of RECs to generators of energy).
LEGAL BRIEF OF IDAHO POWER COMPANY -80
The DPUC's decision was appealed and upheld by the Superior Court of
Connecticut. Wheelabrator Lisbon, Inc. 2006 Conn. Super. LEAS 858. The Superior
Court noted: "[The QF's] argument is that 015 Certificates are unrelated to the
electricity generated and sold to [the utility]." Id. at *17. This is was essentially an
argument by the QF that the RECs were "unbundled" before sale of the energy to the
utility. The Superior Court further notes with approval:
The department rejected this argument finding that the GIS
Certificates merely quantified the renewable attributes of the
renewable fuel generated electricity. Thus, the GIS
Certificates can not exist apart from the generated electricity.
DPUC found the GIS Certificates inseparable from the
renewable energy. . . . The DPUC determined from the
evidence that the GIS Certificates were an integral part of
renewable energy and that the [PURPA contract] conveyed
renewable energy generated by [the QF] to [the utility].
Thus, the GlS Certificates were also conveyed by such
agreement.
Id. at *1718. Effectively, the Connecticut commission found that, in the context of a
PURPA contract entered into before the state had any RPS or REC program, the
renewable energy and associated environmental attributes remain bundled and the
utility compelled to purchase the renewable energy also obtains the associated
environmental attributes.
The Superior Court's decision was then appealed to the Supreme Court of
Connecticut which also upheld the DPUC's determination that the utility owns the
environmental attributes. Wheelabrator Lisbon, Inc., 931 A.2d 159. In upholding the
DPUD decision, the Connecticut Supreme Court observed that the very concept of
"unbundling" established by the state's RPS program and the state's use of GIS
Certificates implies that prior to adoption of a program authorizing "unbundling" the
LEGAL BRIEF OF IDAHO POWER COMPANY -81
environmental attributes of renewably generated electricity are an inherent attribute of
that electricity. As a result, electricity sold by contract executed before the state
established its RPS program is electricity that inherently includes any environmental
attributes. As the Supreme Court held:
[T]he term "unbundling" itself implies that the renewable
attribute of the energy generated by renewable energy
sources is an inherent attribute of the energy ... It was
reasonable, therefore, for the department to conclude that
the word "electricity," as used in ... the 1991 agreement [the
PURPA contract], meant renewable energy. In other words,
the terms "electricity" necessarily includes the renewable
attribute that later was "unbundled" from the energy [per the
states subsequent RPS program] and represented by the
[GIS] certificates. Accordingly, we conclude that the
department reasonably determined that the certificates were
owned by the utility.
Id. at 176.
The New Jersey Board of Public Utilities ("BPU") has similarly held that where a
utility is compelled to purchase renewably generated energy under a PURPA contract
executed before New Jersey established a RPS program, the utility owns the
environmental attributes. In the Matter of the Ownership of RECs, BPU Docket No.
E004080879. More specifically, the BPU held:
as a matter of law and policy. . . that with respect to
existing QF... contracts, the sale of power to the [utilities] in
the first instance, and the [BPU's] approval of the sale and
the terms and conditions associated therewith, were
inextricably linked to the renewable attribute thereof and that
special consideration was given by the [BPU] to the
renewable projects because of the renewable nature of the
power being sold. Therefore, the [BPU] FINDS that these
attributes belong to the purchasing [utilities] for the duration
of those contracts...
LEGAL BRIEF OF IDAHO POWER COMPANY -82
Id. at 18. The New Jersey court of appeals upheld the BPU's determination that utilities
own the RECs from power purchased under PURPA contracts that pre-date the state's
RPS program. In the Matter of the Ownership of RECs, 913 A.2d 825 (N.J. Super.
2007). The court of appeals noted that assignment of the RECs to the Us would have
meant that retail customers would pay more for electricity and the court concluded that
"this result would be unfair to retail customers, who have already paid for [the QF's
renewably-generated] electricity, and it is entirely inconsistent with the governing state
legislation." Id. at 830.
The Maine utility commission has also considered REC ownership in the context
of PURPA sales. See, Investigation of GIS Certificates Associated with Qualifying
Facility Agreement, Me. PUC Docket No. 2002-494, 2003 Me. PUG LEXIS 74, *7
(February 14, 2003) ("The Commission has initiated an Investigation and has tentatively
concluded that the utilities have the right to the GIS certificates associated with QF
contracts and that the certificates should be transferred to the entitlement purchaser.")
The Maine commission was of the opinion that environmental attributes remain bundled
when renewable power is sold under a PURPA contract. See, Petition for Declaratory
Order Regarding Ownership of Alternative Energy Credits, Pa. PUC P-00052149, 2006
Pa. PUG LEXIS 110, *6061 (July 5, 2006) (discussing the Maine PUG's position that
environmental attributes remain bundled with power sold under PURPA and therefore
are owned by the purchasing utility). However, the Maine commission suspended its
investigation of the question pending the outcome of the American Re-Fuel proceeding
before FERC. The Maine commission then subsequently terminated its investigation
without resolving the question of REC ownership. Investigation of GIS Certificates
LEGAL BRIEF OF IDAHO POWER COMPANY -83
Associated with Qualifying Facility Agreement, Me. PUC Docket No. 2002-506, 2007
Me. PUG LEXIS 152 (June 11, 2007).
The Pennsylvania PUG has also ruled on ownership of RECs in the context of a
PURPA contract executed before there was any state RPS program. Petition for
Declaratory Order Regarding Ownership of Alternative Energy Credits, 2006 Pa. PUG
LEXIS 110, The Pennsylvania Commission held that "the ownership of the
alternative energy credits generated within the long-term power purchase agreements
entered into pursuant to PURPA prior to the passage of the Alternative Energy Portfolio
Standards Act, 73 P.S. §1648.1 et seq., which do not anticipate or mention the
alternative energy credits, belong to the electric distribution companies [the purchasing
utilities]." Id. at *92. The Pennsylvania Commission reasoned that to rule otherwise
would create a perverse result where the utility and its customers would not get credit
for purchasing renewable generation when that is in fact what they are doing under the
PURPA contract. Id. at *35 Effectively, the Pennsylvania Commission found that the
environmental attributes and energy remain bundled in a PURPA sale that was
contracted for before the state adopted an RPS program. The decision was challenged
but upheld by the Pennsylvania court of appeals. ARIPPA v. Penn. PUC, 966 A.2d
1204 (Pa. Commw. 2009). The court held:
the purpose of [Alternative Energy Portfolio Standards Act
(AEPS)] is to encourage the creation and use of energy from
alternative sources, and the fact that the credits are a
tradable commodity is a secondary effect of the statutory
scheme to effectuate that goal. Where, as here, the [utility]
has already purchased energy from an alternative energy
supplier (albeit under a pre-2005 agreement that made no
provision for alternative energy credits), the underlying
purpose of AEPS has been satisfied. Nonetheless, if the
credits attributable to that power belong to the [QF]
LEGAL BRIEF OF IDAHO POWER COMPANY -84
generating company, the [utility] will have to purchase credits
separately and pass that additional charge along to the
consuming public. Thus, the Commission concluded that the
public interest favored awarding ownership rights in the
credits to the [utility]. Moreover, the contracts themselves
are entirely silent on the issue of these rights, and any
attempt to determine the parties' intent or how they might
have structured the contract if they had anticipated the future
creation of saleable credits is speculative at best. Thus, as
there is no controlling statutory language in the applicable
version of AEPS, no controlling precedent, and no guiding
language in the contracts themselves, this court accepts the
Commission's persuasive interpretation and reasoning in
concluding that [utilities] own the credits under the
circumstances presented here.
Id. at 1214.
In each of the decisions discussed above, a state utility commission considered
who owned the environmental attributes associated with power sold under PURPA
contracts executed before adoption of an RPS statute. In effect, these decisions
analyze who should own environmental attributes when a PURPA contract is executed
in the absence of a state RPS statute. That is the very question currently before the
Idaho Commission. The reasoning in the above decisions is therefore instructive.
In each case, the state utility commission effectively decided that, in the absence
of a state RPS, the QF energy sold under a PURPA contract transfers a bundled
product. The utility therefore obtains ownership of both the energy and the bundled
environmental attributes. When a QF compels a utility to purchase renewably-
generated energy under a PURPA contract, and it does so in a state like Idaho that has
no RPS statute, then the QF has no statutory or other right or basis by which to
"unbundle" environmental attributes from the renewably-generated energy. The state
involved—in this case Idaho—determines initial ownership of REC5 and when and how
LEGAL BRIEF OF IDAHO POWER COMPANY -85
RECs can be traded or sold. American Ref-Fuel!, 105 FERC 161,004, P23. There is
no right or ability to "unbundle" energy and environmental attributes and to thereby
create RECs unless and until the state has established such a right. Simply put, in the
absence of an Idaho RPS statute, there is no reason to conclude that a QF selling to an
Idaho utility has any right or ability to unbundle energy and environmental attributes.
It appears that the Wyoming Public Service Commission has adopted this
approach. By order issued November 4, 2011, the Wyoming PSC held that RECs
associated with QF sales in Wyoming are owned by the utility. In the Matter of the
Application of Rocky Mountain Power to Implement a Permanent Avoided Cost
Methodology for Customers that do not Qualify for Tariff Schedule 37, Wy. Public
Service Commission, Docket No. 20000-388-EA-1 1, Record No. 12750, at PP 63-64
2011 Wyo. PUC LEXIS 441(2011). The critical holdings on RECs are made in
paragraphs 63 and 64 of the order, which state:
63. [lnterwest Energy Alliance (lEA)] advocated the QF
should retain the RECs until such time as the wind proxy is
included in the QF pricing determination or the REC value is
included in the pricing determination (if the utility retains the
REC5). The Commission finds lEA has failed to support its
proposed treatment of REC5. The Commission finds the
testimony of [Rocky Mountain Power (RMP)] witness
Clements more persuasive on this issue. In his rebuttal
testimony, Clements gives two reasons why RECs should be
retained by the utility. (RMP Exhibit 4, pp. 2-3.) The
Commission finds his second argument, i.e., "Wyoming
customers should not have to pay something extra for—or
be deprived of the right to truthfully claim—something that is
actually taking place, which is PacifiCorp's purchase of
energy from a particular QF" to be the more persuasive.
(RMP Exhibit 4, p. 3.) Consistent with the current treatment
of RECs, the Commission finds RMP should continue to
retain the RECs since they represent tangible value for the
ratepayer, and they should not be routinely severed from the
underlying green power generated. The Commission has in
LEGAL BRIEF OF IDAHO POWER COMPANY -86
the past made it clear that REC revenues are a key
component used to mitigate, to an extent, the effects on
customers of the ongoing series of rate increases filed by
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.
64. lEA's assertion that wind development will not occur if
RECs are not allowed to be retained by the QF is not
supported by the facts, as the evidence shows that wind
development by substantial QF entities has occurred in the
state. Further, lEA's assertion that REC retention by the QF
serves as a tool in encouraging economic development is
not a viable argument because the Commission is not an
economic development agency. Further, RMP is not an
economic development agency but rather a business entity
engaged in securing green energy and reasonable prices
and under reasonable conditions on behalf of its consumers
and itself.
The Wyoming PSC's holdings are consistent with a theory that the environmental
attributes associated with QF power remain bundled with the power purchased by the
utility. The Wyoming PSC stated that the utility "should continue to retain the REC5
and they should not be routinely severed from the underlying green power generated.
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." Id., at 63. These
statements are remarkably consistent with the theory that the environmental attributes
or RECs remain bundled with the energy. Perhaps this is not surprising because
Wyoming, like Idaho, has no RPS statute.
In the absence of an RPS statute, it would seem to be most consistent with state
law to hold that environmental attributes and energy remain bundled. Like the Wyoming
PSC, the Idaho Commission can best serve the public interest by concluding that in
Idaho, and in the absence of a legislatively mandated RPS program, the environmental
LEGAL BRIEF OF IDAHO POWER COMPANY -87
attributes associated with QF output remain bundled with the power and that the utility
therefore owns the environmental attributes as a consequence of purchasing the
bundled power, all of which ultimately flows back as a benefit to Idaho Power's
customers.
As the state utility commissions in Wyoming, Pennsylvania, New Jersey,
Connecticut, and West Virginia have all found, there are sound public interest reasons
to conclude that, in the absence of an RPS or other state statutory requirement to the
contrary, QF output purchased in Idaho is a bundled product and includes both
renewable energy and environmental attributes.
4. Awarding RECs to the Utility Does Not Make a Constitutional Taking
or Conflict with American Ref-Fuel
As discussed above, it is in the public interest for the Commission to conclude
that all energy sold in Idaho under the PURPA must-buy obligation is bundled energy
and the utility buyer therefore owns the energy and any associated environmental
attributes. As a result, any RECs that may arise from such environmental attributes are
owned in the first instance by the utility. For the reasons discussed below, this outcome
does not represent an unconstitutional taking nor does this outcome conflict with
FERC's holding in American Ref-Fuel.
In many of the cases discussed above—where a state utility commission
determined that RECs or environmental attributes belonged to the utility—the QF
argued that such an outcome represented in an unconstitutional taking without
compensation in violation of the state and federal constitutions. The courts have
consistently rejected this argument. Idaho Power is not aware of a single case where
LEGAL BRIEF OF IDAHO POWER COMPANY -88
the state law decision to assign initial ownership of a REC to a utility was found to
constitute an unconstitutional taking.
In Wheelabrator Lisbon Inc., 931 A.2d 159, the Supreme Court of Connecticut
rejected the takings argument. It held:
The trial court concluded in the present case that the transfer
of the certificates to the utility did not constitute an
unconstitutional taking of property from the plaintiff because
the certificates were not the plaintiffs property. We have
concluded that the trial court correctly determined that it was
within the jurisdiction of the department to determine the
ownership of the certificates and that the department
reasonably concluded that the utility owned them.
Accordingly, we agree with the trial court that the
department's decision could not constitute an
unconstitutional taking under the state constitution because
no property owned by the plaintiff had been taken.
Id. at 177. In reference to the same decision by the Connecticut PUC, the United States
District Court for the District of Connecticut held that there was no violation of the
federal constitution:
The generators claim that the [Connecticut] PUG's decisions,
ordering them to transfer the [REC5] to [the utility] violate the
• . . Takings Clause. . . . The RECs... are creations of
state legislation and regulation, and the [Connecticut] PUC
has determined that [the utility] is the owner of the [REC5]
associated with the renewable energy it purchases from [the
QF5] pursuant to the parties' [power purchase agreements].
Accordingly, the generators have not been deprived of a
property interest because NEPOOL's initial assignment to
them did not confer ownership of REC5..
Wheelabrator Lisbon Inc., v. Connecticut PUC, 526 F. Supp. 2d 295, 306-07 (Conn.
Dist. 2006).
LEGAL BRIEF OF IDAHO POWER COMPANY -89
The Supreme Court of West Virginia has also rejected the takings argument. In
City of New Martinsville v. Pub. Ser. Comm. of West Virginia, 2012 W. Va. LEXIS 308 at
*27 n.13 (2012), it held:
MEA also argues that Commission's decision to award the
credits to the Utilities results in the taking of private property
without just compensation to the owners, i.e., the
Generators, in violation of the federal and state constitutions.
Again, we find no merit to this argument because the
Commission determined that the credits were owned by the
Utilities in the first instance. The Commission's decision
could not constitute an unconstitutional taking because no
property owned by the Generators was taken.
As another example, the Colorado PUC has also rejected the takings argument.
In the matter of the proposed rules implementing renewable energy standards 4 CCR
723-3, Co. PUC Docket No. 05R-1 12E, Decision No. C06-0091, at P 45, 2006 Cob.
PUG LEXIS 67 at *31 (2006) (After deciding RECs are owned by the utility under
PURPA contracts that pre-date the state's REC legislation, the Colorado PUG rejected
the takings argument holding the "QFs have no vested property interest in the REC5
we find that no taking could have occurred.").
If the Idaho Commission decides that environmental attributes remain bundled as
part of the sale of energy under an Idaho PURPA contract, and if the Commission
therefore concludes that the utility owns any RECs in the first instance—the
Commission can also reject any takings argument on the grounds that the QF never
owned the RECs.
For the same reason, it is not necessary to include, or create, any upward
adjustment to the avoided cost price paid for QF power in an attempt to compensate
QFs for the value of a REC. If the Commission determines that utilities own the RECs
LEGAL BRIEF OF IDAHO POWER COMPANY -90
in the first instance, there is no need to compensate QFs because there has been no
transfer of REC ownership. In consequence, the Commission should reject staffs
suggestion that avoided cost rates should be adjusted to account for the transfer of
REC5. Sterling, Direct, p. 46-47.
Further, the approach recommended by Idaho Power does not conflict with
FERC's holding in American Ref-Fuel. As discussed in section A above, American Ref-
Fuel as interpreted on rehearing and by the Second Circuit in Wheelabrator, 531 F.3d
183, announces the following principles: (1) ownership of REC5 is decided by state law,
not PURPA; (2) a PURPA sale does not inherently involve the transfer of RECs; and
(3) avoided cost rates compensate for energy and capacity only, they do not
compensate for the transfer of RECs.
Under these principles, it would conflict with PURPA for a state commission to
hold that QFs are the initial owners of RECS but that a PURPA sale automatically
transfers ownership of the REC to the utility and the payment of avoided cost provides
the QF with compensation for the change in REC ownership. The American Ref-Fuel
decision gives states the latitude to decide that either a utility or a QF owns RECs as an
initial matter. But it does not give states the latitude to hold that unbundled RECs,
owned in the first instance by the QF, are transferred to the utility as a necessary
consequence of a PURPA sale. See American Ref-Fuel, 107 FERC 61,016 at n.1 ("...
a PURPA contract [does] not inherently convey any REC5 ... ."). However, as both
FERC and the Second Circuit have recognized, a REC may change ownership as part
of a PURPA sale if transfer is by express agreement of the parties or by application or
operation of some state law requirement. Id.; Wheelabrator, 531 F.3d at 189. The point
LEGAL BRIEF OF IDAHO POWER COMPANY -91
is that a state cannot deem a transfer of RECs to have occurred as an inherent
consequence of the PURPA-mandated sale of QF power.
It would also run afoul of American Ref-Fuel for a state commission to declare
that the avoided cost rates alone provide compensation or consideration for the transfer
of RECs from the QF to the utility.12 However, under the approach advocated by Idaho
Power, the Commission need not find that avoided cost rates provide adequate
compensation for RECs because no RECs are transferred. Rather, the Commission
can and should conclude that the environmental attributes remain bundled as an
inherent part of the energy and capacity sold under the PURPA contract and that the
utilities are the owners of any REC5 in the first instance.
5. The Commission Should Use Its Inherent Authority to Recognize
That, in the Absence of a State RPS and REC Program. Ownership of
REC5 Associated with Idaho QFs Belonu to the Utilities
This Commission has, until now, refrained from determining or declaring the
rights of the utility to RECs from Idaho QFs. Unless the Commission exercises its
jurisdiction to decide ownership of RECs soon, Idaho QFs may cause serious harm to
ratepayers by employing a "REC stripping scheme" recently reviewed by FERC to
unilaterally claim ownership of RECs in the face of inaction by the Commission and the
Idaho Legislature. In Idaho Wind Partners, FERC found that a QF could sell and
12 FERC has clearly stated "avoided cost rates are not intended to compensate the QF for more than
capacity and energy." American Ref-Fuel, 107 FERC 61,016 at P15. However, the soundness of this
conclusion has been questioned. See Wheelabrator, 931 A.2d at n. 25 (the Connecticut Supreme Court
notes that FERC was split on the question of whether avoided costs can be found to compensate for
RECs, that the decision has been criticized by commentators, that the court in New Jersey declined to
follow it, and that the decision appears to be inconsistent with the United States Supreme Court's
determination in American Paper Institute, Inc. v. American Electric Power Service Corp., 461 U.S. 402,
406 (1983), that the avoided cost scheme was intended to provide an incentive to develop renewable
energy sources). Furthermore, FERC's holding in American Ref-Fuel is presently "of no legal moment"
and represents nothing more than an announcement of the position FERC may take in a future
enforcement action. Xcel Energy Services, Inc. v. FERC, 407 F.3d 1242, 1244 (D.C. Cir. 2005).
LEGAL BRIEF OF IDAHO POWER COMPANY -92
repurchase QF output before the point of delivery, and resell it to the utility, stripped of
RECs, consistent with PURPA. See, Idaho Wind Partners 1, LLC, 134 FERC ¶ 61,217
(March 17, 2011), order granting clarification and dismissing rehearing, 135 FERC ¶
61,154 (May 19, 2011), rehearing dismissed, 136 FERC 61,174 (September 15, 201 1)13
This transaction makes clear that, even though Idaho does not have a REC program,
there is some environmental attribute from QF output that has commercial value, and
Us are likely to use this transaction to deprive utilities of that value absent action by
the state or Commission.
The specter of QFs stripping environmental attributes so that they may be sold to
third parties notwithstanding unresolved issues of ownership threatens to deprive the
customers of significant value or, at the least, cause protracted litigation to unwind such
transactions. This threat presents REC ownership in a different context than in past
Commission proceedings on REC5. Whereas until recently, QFs and utilities resolved
ownership of RECs contractually, the Idaho Wind Partners decision gives QFs a
mechanism to unilaterally deprive utility customers of any benefits associated with
RECs.
QF control over RECs runs counter to numerous other states' findings that pre-
RPS REC5 originate with the utility (See, supra, n. 10) and runs counter to the Wyoming
Public Service Commission's finding that RECs remain with Wyoming utilities. These
precedents favoring utility ownership of environmental attributes from Us where the
13 Idaho Wind Powers petitioned for a declaratory order asking FERC whether it would violate PURPA or
jeopardize QF states if a first QF sells its renewable power to a second QF and then instantaneously re-
buys its power from the second QF without the RECs (which remain with the second QF) before
compelling a public utility to purchase the unbundled (and "REC-less") power pursuant to the PURPA
must-buy obligation; FERC has stated that such a transaction does not violate PURPA or jeopardize QF
status. Idaho Wind Partners 1, LLC. 134 FERC 161,217, P 19-21.
LEGAL BRIEF OF IDAHO POWER COMPANY -93
state does not have an RPS or a REC program are not controlling; however they are
evidence of the strength of the utility's claim of REC ownership. QF control of
environmental attributes from Idaho QFs also runs counter to the recommendation of
the Idaho Staff. Commission staff takes the position that the utility should own the
environmental attributes from an Idaho QF because such ownership is in the public
interest. Sterling, Direct, p. 42. Although Idaho utilities are not subject to an RPS at
present, it might become subject to a federal or state RPS in the future. In that event, if
the utility does not retain the environmental attributes from QF contracts, it might need
to purchase RECs to comply with future RPS standards. Such an outcome would result
in the utility's customer paying more for power.
The "REC stripping scheme" proposed by QFs in Idaho Wind Partners, 134
FERC 161,217, P 1, would be ineffectual if environmental attributes remain bundled
until a QF sells to a utility under PURPA. Because environmental attributes and energy
must remain bundled, the "inside the fence" transactions proposed by the Us in Idaho
Wind Partners cannot unbundle REC5 and strip them prior to sale of energy to utilities.
Idaho Power urges the Commission to look at its authority to regulate
environmental attributes associated with Idaho Us in light of the threat of harm posed
by schemes designed to strip RECs and deprive utility customers of those benefits. The
fact that the rights to such attributes are being bought and sold notwithstanding the fact
that Idaho does not have an RPS or REC program suggests that they may be property
subject to the Commission's jurisdiction under Idaho Code § 61-328 (see supra, Section
II.E.2). If environmental attributes are property of the utility, then they are subject to
Commission jurisdiction and regulation.
LEGAL BRIEF OF IDAHO POWER COMPANY -94
The consensus among other states that environmental attributes from QF power
flow to the utility prior to the creation of a state RPS or REC program suggests that the
utilities own such environmental attributes in Idaho as well. Where actions are
occurring that threaten to deprive Idaho's electric utilities of valuable property that they
will need to comply with a future state or federal RPS, the Commission has a strong
interest in protecting the public interest. The fact that ownership of RECs from Idaho
QFs is a matter squarely within the Commission's administrative expertise and that
Idaho Wind Partners threatens to moot the issue of ownership unless the Commission
suggest that this issue is neither theoretical nor beyond the Commission's jurisdiction.
6. In the alternative, the Commission Should Authorize the Utilities to
Include a "Reservation of Riqhts" Provision in Each QF Power
Purchase Agreement Clarifying that Ownership of RECs is Currently
Undetermined But Will Follow Any Determinations Ultimately Made
by Idaho Statute or Regulation
If the Commission declines to decide ownership of RECs, Idaho Power urges the
Commission to confirm, as it did in Grand View Solar Order No. 32580, that ownership
of RECs is a question of state law, to confirm that the State of Idaho has not yet
answered the question, and to authorize the utilities to include a "reservation of rights"
provision in each QF power purchase agreement. If the QF and the utility can agree on
an allocation of REC5, then a "reservation of rights" provision will be unnecessary and
the power purchase agreement can simply state the Parties agreement on ownership of
RECs. Otherwise, in the interest of avoiding further dispute, the utility should have the
right to insert a "reservation of rights" provision. The reservation of rights provision
would state the following points:
(1) The parties have not agreed to a contractual
allocation of any REC5;
LEGAL BRIEF OF IDAHO POWER COMPANY -95
(2)Ownership of any RECs associated with the energy
and capacity sold under the power purchase agreement is a
question of state law;
(3)The State of Idaho has not yet established whether
the utility or the QF owns such RECs in the first instance;
and
(4)The parties to the PPA acknowledge that ownership
of any RECs associated with the energy and capacity sold
under the PPA will be as ultimately determined by future
Idaho statute, Idaho Public Utilities Commission regulation,
or other determination of Idaho law made by the Idaho
Legislature, the Idaho courts, by the Idaho Public Utilities
Commission, or by any other entity, state or federal, with
jurisdiction and authority to determine the issue.
A reservation of rights provision of the type describes above is in the public
interest. It will put the parties in future PURPA contracts on notice that ownership of
RECs is currently unsettled in Idaho. It will clearly reserve both party's rights regarding
ownership of RECs. And it will avoid the need for litigation of the type currently pending
before the Commission in Grand View PV Solar Two, LLC, v. Idaho Power Co., IPUC
Docket No. IPC-E-11-15, a complaint proceeding brought by a QF in an attempt to
compel Idaho Power to agree that it is not the owner of the RECs associated with the
energy and capacity to be sold under a proposed QF power purchase agreement.
The Commission has the authority to authorize a reservation of rights provision
like that proposed by Idaho Power. See, Idaho Power Co. v. Cogeneration, Inc., 129
Idaho 46, 49 (1996) (Idaho Commission has the authority to approve the terms and
conditions of PURPA contracts); Afton Energy v. Idaho Power Co., 107 Idaho 781, 789
(1984) (affirming Commission jurisdiction over issues related to QF contracts and noting
that "[c]ontracts entered into by public utilities with [QFs] or decisions not to contract
LEGAL BRIEF OF IDAHO POWER COMPANY -96
with [QFs] have a very real effect on the rates paid by consumers both at present and in
the future."), modified on reh'g 107 Idaho 781, 793 (1984); Grand View PV Solar Two,
LLC V. Idaho Power Company, IPUC Docket No. IPC-E-11-15, Order No. 32580, at 7
(2012) (discussing Commission's jurisdiction over QF contracts).
The proposed reservation of rights provision does not compel any concession of
rights from the QF or the utility. It merely acknowledges the current undecided state of
the law in Idaho and acknowledges what is already true—that ownership of RECs will
be determined by extant Idaho law. Fidelity Trust Co. v. State et al., 72 Idaho 137, 149
(195 1 ) ("... it is axiomatic that extant law is written into and made a part of every written
contract.").
While the precise language of the reservation rights provision could take many
forms so long as it establishes the four key points listed above, Idaho Power proposes
the following provision for consideration and approval by the Commission:
Reservation of Rights Regarding Ownership of RECs
The Parties make no contractual assignment or transfer
regarding the ownership of Green Tags or Renewable
Energy Certificates (REC5) associated with the energy and
capacity generated by Seller's Facility and sold to Idaho
Power under this Agreement. The Parties further
acknowledge and agree that Idaho law controls the question
of which Party owns such Green Tags or RECs but that the
State of Idaho has not yet decided the question. As such,
both Parties hereby expressly reserve any and all rights that
they have under current or future Idaho law regarding
ownership of such Green Tags or RECs. The Parties
acknowledge that ownership of such Green Tags or REC5
will be as determined by future Idaho statute, Idaho Public
Utilities Commission regulation, or other applicable
determination of Idaho law made by the Idaho Legislature,
the Idaho courts, the Idaho Public Utilities Commission, or by
any other entity, state or federal, with jurisdiction and
authority to determine the issue.
LEGAL BRIEF OF IDAHO POWER COMPANY -97
III. CONCLUSION
For the reasons above, Idaho Power respectfully requests that the Commission
grant the relief requested herein.
DATED this 20th day of July 2012.
LEGAL BRIEF OF IDAHO POWER COMPANY -98
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 20th day of July 2012 I served a true and correct
copy of the LEGAL BRIEF OF IDAHO POWER COMPANY upon the following named
parties by the method indicated below, and addressed to the following:
Commission Staff
Kristine A. Sasser
Deputy Attorney General
Idaho Public Utilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, Idaho 83720-0074
Avista Corporation
Michael G. Andrea
Avista Corporation
1411 East Mission Avenue, MSC-23
Spokane, Washington 99202
PacifiCorp dlbla Rocky Mountain Power
Daniel E. Solander
PacifiCorp d/b/a Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Exergy Development, Grand View Solar II,
J.R. Simplot, Northwest and Intermountain
Power Producers Coalition, Board of
Commissioners of Adams County, Idaho,
and Clearwater Paper Corporation
Peter J. Richardson
Gregory M. Adams
RICHARDSON & O'LEARY, PLLC
515 North 27th Street (83702)
P.O. Box 7218
Boise, Idaho 83707
Exergy Development Group of Idaho, LLC
James Carkulis, Managing Member
Exergy Development Group of Idaho, LLC
802 West Bannock Street, Suite 1200
Boise, Idaho 83702
X Hand Delivered
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LEGAL BRIEF OF IDAHO POWER COMPANY -99
Dr. Don Reading Hand Delivered
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drcäbeniohnsonassociates.com
Grand View Solar II
Robert A. Paul
Grand View Solar II
15690 Vista Circle
Desert Hot Springs, California 92241
J.R. Simplot Company
Don Sturtevant, Energy Director
J.R. Simplot Company
One Capital Center
999 Main Street
P.O. Box 27
Boise, Idaho 83707-0027
Northwest and Intermountain Power
Producers Coalition
Robert D. Kahn, Executive Director
Northwest and Intermountain Power
Producers Coalition
1117 Minor Avenue, Suite 300
Seattle, Washington 98101
Board of Commissioners of Adams
County, Idaho
Bill Brown, Chair
Board of Commissioners of
Adams County, Idaho
P.O. Box 48
Council, Idaho 83612
Clearwater Paper Corporation
Mary Lewallen
Clearwater Paper Corporation
601 West Riverside Avenue, Suite 1100
Spokane, Washington 99201
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LEGAL BRIEF OF IDAHO POWER COMPANY - 100
Renewable Energy Coalition and Dynamis
Energy, LLC
Ronald L. Williams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, Idaho 83702
Renewable Energy Coalition
John R. Lowe, Consultant
Renewable Energy Coalition
12050 SW Tremont Street
Portland, Oregon 97225
Dynamis Energy, LLC
Wade Thomas, General Counsel
Dynamis Energy, LLC
776 East Riverside Drive, Suite 150
Eagle, Idaho 83616
Interconnect Solar Development, LLC
R. Greg Ferney
MIMURA LAW OFFICES, PLLC
2176 East Franklin Road, Suite 120
Meridian, Idaho 83642
Bill Piske, Manager
Interconnect Solar Development, LLC
1303 East Carter
Boise, Idaho 83706
Renewable Northwest Project, Idaho
Windfarms, LLC, and Ridgeline Energy LLC
Dean J. Miller
Chas. F. McDevitt
McDEVITT & MILLER LLP
420 West Bannock Street (83702)
P.O. Box 2564
Boise, Idaho 83701
Megan Walseth Decker
Senior Staff Counsel
Renewable Northwest Project
421 SW 6th Avenue, Suite 1125
Portland, Oregon 97204
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LEGAL BRIEF OF IDAHO POWER COMPANY - 101
Idaho Windfarms, LLC
Glenn Ikemoto
Margaret Rueger
Idaho Windfarms, LLC
672 Blair Avenue
Piedmont, California 94611
Twin Falls Canal Company and North Side
Canal Company
C. Thomas Arkoosh
CAPITOL LAW GROUP, PLLC
205 North 10th Street, 4th Floor
P.O. Box 2598
Boise, Idaho 83701-2598
ELECTRONIC SERVICE ONLY
Lori Thomas
CAPITOL LAW GROUP, PLLC
205 North 10th Street, 4th Floor
P.O. Box 2598
Boise, Idaho 83701-2598
ELECTRONIC SERVICE ONLY
Donald W. Schoenbeck
RCS, Inc.
900 Washington Street, Suite 780
Vancouver, Washington 98660
ELECTRONIC SERVICE ONLY
Twin Falls Canal Company
Brian Olmstead, General Manager
Twin Falls Canal Company
P.O. Box 326
Twin Falls, Idaho 83303
ELECTRONIC SERVICE ONLY
North Side Canal Company
Ted Diehl, General Manager
North Side Canal Company
921 North Lincoln Street
Jerome, Idaho 83338
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LEGAL BRIEF OF IDAHO POWER COMPANY - 102
Birch Power Company
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 11th East
Idaho Falls, Idaho 83404
Blue Ribbon Energy LLC
M.J. Humphries
Blue Ribbon Energy LLC
3470 Rich Lane
Ammon, Idaho 83406-7728
Arron F. Jepson
Blue Ribbon Energy LLC
10660 South 540 East
Sandy, Utah 84070
Idaho Conservation League
Benjamin J. Otto
Idaho Conservation League
710 North Sixth Street (83702)
P.O. Box 844
Boise, Idaho 83701
Snake River Alliance
Liz Woodruff, Executive Director
Ken Miller, Clean Energy Program Director
Snake River Alliance
P.O. Box 1731
Boise, Idaho 83701
Energy Integrity Project
Tauna Christensen
Energy Integrity Project
769 North 1100 East
Shelley, Idaho 83274
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LEGAL BRIEF OF IDAHO POWER COMPANY - 103
Idaho Wind Partners I, LLC
Deborah E. Nelson
Kelsey J. Nunez
GIVENS PURSLEY LLP
601 West Bannock Street (83702)
P.O. Box 2720
Boise, Idaho 83701-2720
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C rista Bearry, Legal Assistan
LEGAL BRIEF OF IDAHO POWER COMPANY - 104
NON-PARTY CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 20th day of July 2012 I served a true and correct
copy of the LEGAL BRIEF OF IDAHO POWER COMPANY upon the following
individuals who are not named parties in this proceeding by the method indicated below,
and addressed to the following:
Big Wood Canal Company and American
Falls Reservoir District No. 2
C. Thomas Arkoosh
CAPITOL LAW GROUP, PLLC
205 North 10th Street, 4th Floor
P.O. Box 2598
Boise, Idaho 83701-2598
Mountain Air Projects, LLC
J. Kahle Becker
The Alaska Center
1020 West Main Street, Suite 400
Boise, Idaho 83702
Michael J. Uda
UDA LAW FIRM, P.C.
7 West 6th Avenue, Suite 4E
Helena, Montana 59601
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Christa. Bearry, Legal Assistant
LEGAL BRIEF OF IDAHO POWER COMPANY - 105
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
EXHIBIT NO. 12
REQUEST NO. 6: If Idaho Power's proposed Schedule 74 were to be approved
by the Commission and QFs were curtailed during certain low load conditions, would
the avoided cost rates computed based on Aurora analysis be impacted? Has Idaho
Power conducted any Aurora analysis to compute avoided cost rates under an
assumption that QFs could be curtailed under certain low load conditions?
RESPONSE TO REQUEST NO. 6: Avoided cost rates computed by AURORA
are set for the duration of the contract based upon the QF's estimated hourly generation
profile for a period of one year, and this computation is not impacted by possible
curtailment. However, if Idaho Power must pay for curtailment, it must also be able to
recover such payments. If Idaho Power may curtail without payment, no adjustment to
avoided costs through the integration charge is necessary.
In its updated wind integration study, the Company has been careful to not
include any costs associated with curtailment in the wind integration cost analysis. The
AURORA model used by Idaho Power to determine the avoided cost of energy is not
capable of modeling wind curtailment and therefore curtailment is not valued in the
pricing proposed by Idaho Power. Because a certain amount of curtailment is
anticipated in the modeling performed as part of the wind integration study, Idaho Power
does not believe it would be appropriate to account for curtailment in the avoided cost
pricing model.
The response to this Request was prepared by M. Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY S RESPONSE TO THE SECOND PRODUCTION Exhibit No. 12
Case No GNR-E-1 1-03 REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -8 Legal Brief IPC
Page 1 of 1
:1:1 .TTtT
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
EXHIBIT NO. 13
REQUEST FOR PRODUCTION NO. 19: Reference the Direct Testimony of
Tessia Park, p. 20, stating, Pursuant to FERC licenses Idaho Power has for its run-of-
river hydro electric projects, the Company is obligated to take whatever generation flows
through them; it does not have the ability to decrease or increase the generation."
(a)Please identify each of the run-of-river hydro plants and provide the
capacity of each.
(b)Please provide the FERC license for each project (in electronic format if
available).
(c)Please identify the provision (page number, section number, as
applicable) in each FERC license that Idaho Power relies on to determine it does not
have the ability to decrease or increase the generation.
(d)For each plant, please explain whether the plant has the operational
capability to spill water without generating electricity, and any restrictions on Idaho
Power's ability to do so.
RESPONSE REQUEST FOR PRODUCTION NO. 19:
(a) Following are the run-of-river hydro plants and their capacity:
Milner - 59.45 MW
Twin Falls - 52.74 MW
Shoshone Falls - 12.5 MW
Upper Salmon Falls A - 18 MW
Upper Salmon Falls B - 16.5 MW
Lower Salmon Falls —60 MW
Upper Malad —827 MW
Lower Malad —135 MW
Bliss - 75 MW
Swan Falls —25 MW
Exhibit No. 13
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Case No GNR-E-1 1-03 OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -20 Legal Brief IPC
Page lof4
(b)Electronic versions of the licenses identified above are provided in the
non-confidential CD.
(c)Mime r. A complete reading of the Milner license shows that the Milner
project is designed to generate with flows that are not used for irrigation as they pass
through the project (run-of-liver).
Twin Falls. A complete reading of the Twin Falls license shows that the
Twin Falls project is designed to generate with flows as they pass through the project
(run-of-river).
Shoshone Falls. A complete reading of the Shoshone Fails license shows
that the Shoshone Falls project is designed to generate with flows as they pass through
the project (run-of-liver). See Article 401.
Uer Salmon Falls A. A complete reading of the Upper Salmon Falls
license shows that the Upper Salmon Falls project is designed to generate with flows as
they pass through the project (run-of-river). See Article 401.
Uer Salmon Fab B. A complete reading of the Upper Salmon Falls
license shows that the Upper Salmon Falls project is designed to generate with flows as
they pass through the project (run of river). See Article 401.
Lor $ain Falls. A complete reading of the Lower Salmon Falls
license shows that the Lower Salmon Falls project is designed to generate with flows as
they pass through the project (run-of-river). See Article 401.
Upper Malad. A complete reading of the Malad license shows that the
Malad project is designed to generate with flows as they pass through the project (run-
of-river). See Article 401.
Exhibit No. 13
IDAHO POWER COMPANYS RESPONSE TO THE SECOND PRODUCTION REQUEST Case No. GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -21 Legal Brief IPC
Page 2 of 4
Lower Malad. A complete reading of the Malad license shows that the
Malad project is designed to generate with flows as they pass through the project (run of
river). See Article 401.
Bliss. A complete reading of the Bliss license shows that the Bliss project
is designed to generate with flows as they pass through the project (run-of-river). See
Article 401.
Swan Falls. A complete reading of the Swan Falls license shows that the
Swan Falls project is designed to generate with flows as they pass through the project
(run-of-river).
In addition, the non-confidential CD contains a copy of a Settlement Agreement
between Idaho Power and the U.S. Fish and Wildlife Service which contains certain
environmental provisions that place constraints around how the Company operates the
Mid-Snake hydro projects (e.g.), Shoshone Falls, Bliss, Upper Salmon, and Lower
Salmon).
At run-of-river projects, generation increases as flow increases and generation
decreases as flow decreases.
(d) Each licensed facility has the physical capability to spill water without
generating electricity. The proposed operations in the applications for FERC licenses
and state water quality certifications did not Include spill except when flows exceeded
plant capacity or when generators tripped off-line in emergency situations. To the
contrary, operations may require an amendment to the FERC licenses and/or state
water quality certifications.
Exhibit No. 13
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Case No GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -22 Legal Brief, IPC
Page 3 of 4
The response to this Request was prepared by Lewis Wardle, Senior Biologist,
Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho
Power company.
Exhibit No. 13
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Case No GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -23 Legal Brief IPC
Page 4 of 4
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
EXHIBIT NO. 14
n
REQUEST FOR PRODUCTION NO. 20: Reference the Direct Testimony of
Tessia Park, p. 23, stating, "the Company must maintain constant flows below Hells
Canyon dam for environmental compliance, thus limiting the ability to curtail generation
out of the Hells Canyon Complex to no less than approximately 350 MW."
(a)Please identify the individual plants/dams at the Hells Canyon Complex
and the MW capacity of each.
(b)Please explain the environmental compliance requirement for each that
limits the ability to curtail generation and provide the minimum generation of each
individual project. Please identify the government agency imposing the compliance
requirement.
(c)For each plant, please explain whether the plant has the operational
capability to spill water without generating electricity. Please explain why generation
cannot be curtailed to 0 MW by spilling, or to any cumulative output below 350 MW for
the Complex.
RESPONSE TO REQUEST FOR PRODUCTION NO 20
(a)The Hells Canyon Complex consists of three projects: Brownlee, Oxbow,
and Hells Canyon. The nameplate MW ratings for the aforementioned projects are as
follows Brownlee-585.40, Oxbow-1 90 00, and Hells Canyon-391.50
(b)FERC:
Brownlee, Oxbow, Hells Canyon
. Minimum reservoir level
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Exhibit No. 14 E
-
11
-
03 OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -24 Legal Brief IPC
Page 1 of 4
Hells Canyon Dam
• Minimum flow 1 3,000 cubic feet per second ("cfs") at Lime
Point 95 percent of the time (flows less than 13,000 cfs
must be negotiated with Corps of Engineers)
a Maximum ramp rate 1 ft. / hour
. Minimum instantaneous flow 5,000 cfs
Corps of Engineer ("COE"):
Hells Canyon Dam - Requested 13,000 cfs variance
• Minimum instantaneous flow 8,500 cfs (measured at Snake
River at Hells Canyon) when previous 3-day moving
average Brownlee Reservoir inflow is at or above 8,500
cfs.
• Minimum instantaneous flow 11,500 cfs (measured at
Snake River below McDuff Rapids) unless it would require
drafting Brownlee Reservoir.
• When the previous 3-day moving average for Brownlee
Reservoir inflow is less than 8,500 cfs, the instantaneous
minimum Hells Canyon flow shall not fall below the
previous 3-day moving average for Brownlee Reservoir
inflow.
National Ocean Atmospheric Administration ("NOAA") - National Marine
Fishery Services: (Endangered Species ACT)
• Provide stable Hells Canyon outflow for salmon spawning
and establish minimum flow level for spring emergence.
a Provide minimum flow level for spring emergence.
• Perform entrapment surveys for spring emergence salmon
to mitigate 4" ramp rate.
Exhibit No. 14
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Case No. GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -25 Legal Brief IPC
Page 2 of 4
Environmental Protection Agency ("EPA") - State Department of
Environmental Quality:
• Maintain total dissolved gases ("TDG") below Hells Canyon
Dam below 110 Parts Per Million ("PPM")
United States Fish and Wildlife Service:
• Maintain TDG below 110 PPM to protect Endangered
Species Bull Trout.
(c) Power plants in the Hells Canyon project are not able to decrease
generation to 0 and spill water without generating electricity for the following reasons, as
per regulatory standard requirements:
North American Electric Reliability Corporation ("NERC") - Western
Electric Coordinating Council ('WECG"):
• NERC Standard BAL-002-1 Disturbance Control Standard
("DCS" ) - utilize contingency reserve to balance resources
and demand and return interconnection frequency within
defined limits following a reportable disturbance.
• WECC Standard BAL-002-W EGG-I Contingency Reserve
- provide reliable operation of the interconnected power
system Adequate generating capacity must be available at
all times to maintain scheduled frequency, and avoid loss
of firm load following transmission or generation
contingencies.
• NERC Standard BAL-005-0.2b Automatic Generation
Control ("AGC") - provide necessary AGC to calculate
Area Control Error ("ACE") and to routinely deploy the
Regulating Reserve
• WECC Standard BAL-STD-002-0 Operating Reserve -
provide adequate generating capacity to be available at all
times to maintain scheduled frequency and avoid loss of
firm load following transmission or generation
contingencies This generating capacity is necessary to
supply requirements for load variations, replace generating
capacity and energy lost due to forced outages of
Exhibit No. 14
IDAHO POWER COMPANYS RESPONSE TO THE SECOND PRODUCTION REQUEST Case No GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -26 Legal Brief, iPC
Page 3 of 4
generation or transmission equipment, meet on-demand
obligations, and replace energy lost due to curtailment of
interruptible imports.
FERC:
• Maintain generation MW levels for undesignated sales.
Hells Canyon Dam TOG will elevate over 110 PPM for spill above 3000 cfs.
The response to this Request was prepared by Tessia Park, Director Load
Serving Operations, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
Exhibit No. 14
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Case No. GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -27 Legal Brief IPC
Page 4 of 4
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
EXHIBIT NO. 15
REQUEST FOR PRODUCTION NO. 21: Reference the Direct Testimony of
Tessia Park, p. 1, stating dispatch costs for the Company's coal units are approximately
$30/MWh and for Langley Gulch are $22/MWh.
(a)Please explain why the Company would not take its coal plants offline and
instead run Langley Gulch during times when it expects to have light loading periods.
(b)For Langley Gulch, the run-of-river hydro projects, and the Hells Canyon
Complex, please provide the minimum and maximum output for each that Idaho Power
could reasonably expect to obtain during periods of the year that Idaho Power expects
to experience light loading events. Please explain the basis for the estimates for each
category.
RESPONSE TO REQUEST FOR PRODUCTION NO. 21:
(a)Coal plants cannot be shutdown and restarted on a daily basis and,
consequently, they can only be turned down to minimum generating levels during light
load periods in order to have their capacity available for the next days' heavy load
period.
(b)When on-line, Langley Gulch will typically be operated during light loading
events between its minimum and maximum generating levels. It is expected that
Langley Gulch will be dispatched somewhere between its minimum and maximum
levels depending primarily on system load, actual wind generation, and plant
economics. The minimum and maximum levels vary seasonally, but are reasonably
expected to be about 160 MW and 300 MW, respectively.
The minimum and maximum output for the run-of-river hydro projects during light
loading events is dependent on water conditions in the Snake River Basin as no
Exhibit No. 15 IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Case No GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -28 Legal Brief, IPC
Page 1 of 3
significant reservoir storage is available at any of Idaho Power's projects. The water
conditions are very predictable with respect to short-term planning; however, a longer-
term basis review of Snake River Basin streamfiow records indicates pronounced
season-to-season and year-to-year variability. Therefore, expected minimum and
maximum output levels depend on the type of water year. For capacity planning
purposes, under median water, Idaho Power expects to get 285 MW from the run-of-
river plants (see 2011 IRP, page 117).
For light loading events occurring during the nearly eight month period from mid-
October through May, the minimum output for the Hells Canyon Complex is driven by
Idaho Power's efforts to maintain flow levels suitable for Snake River fall Chinook
salmon spawning, rearing, and emergence. Idaho Power manages its operations to
provide stable flows during the approximately two month spawning period (mid-October
to mid-December) and, after spawning, maintains the Hells Canyon Complex outflows
at or above the stable spawning flow level through rearing and emergence (mid-
December through May). The spawning flow level varies from year-to-year depending
on water supply in the Snake River Basin, but, in the past, has ranged from about 8,500
cfs to 14,000 cfs. While minimum output can vary from hour-to-hour depending on
water management for the three dam complex, it is reasonable to estimate minimum
output of about 300 MW during years when spawning flows of 8,500 cfs are provided,
and about 550 MW during years when spawning flows of 14,000 cfs are provided.
Outside of the mid-October through May period, Idaho Power maintains minimum
Hells Canyon Complex outflows in compliance with downstream navigation
requirements. These requirements depend on several factors, including inflow to
Exhibit No. 15
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Case No. GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -29 Legal Brief, [PC
Page 2 of 3
Brownlee Reservoir and Salmon River discharge, but generally Idaho Power maintains
Hells Canyon Complex outflows of 6,500 cfs or higher during this period (June to mid-
October). High Brownlee inflow conditions, particularly during the early summer, may
necessitate Hells Canyon Complex outflows substantially greater than 6,500 cfs.
Minimum output during these high flow periods is variable, and typically quite high.
During periods when Hells Canyon Complex outflows can be reduced to levels of
approximately 6,500 cfs, it is reasonable to estimate minimum output levels of about
250 MW.
With respect to maximum output, Idaho Power manages the Hells Canyon
Complex such that maximum output during light loading periods is typically only
nominally higher than the minimum output obtained. Capacity during these periods is
not needed, and the flexible generators of the Hells Canyon Complex can vary their
output accordingly.
The response to this Request was prepared by M. Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
Exhibit No. 15
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Case No GNR-E-1 1-03
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -30 Legal Brief, IPC
Page 3 of 3