20150423Reading Direct.pdf

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ATTORNEYS AT LAW
Gregory M. Adams
Tel: 2O8-938-2236 Fax: [phone]
[e-mail]
P.O. Box 7218 Boise, lD 83707 - 515 N.27th St. Boise, ID 83702
April23,2015
Jean J. Jewell, Secretary
Idaho Public Utilities Commission
472 W est Washington Street
Boise,Idaho 83702
Case Nos. IPC-E-I5-01, AVU-E-15-01, PAC-E-15-03
Direct Testimony and Exhibits of Dr. Don C. Reading
Dear Ms. Jewell:
I have enclosed the Direct Testimony and Exhibits of Dr. Don C. Reading for filing in the above-
referenced dockets on behalf of the J.R. Simplot Company and Clearwater Paper Corporation.
Please contact me with any questions.
Enclosures: Direct Testimony and Exhibits of Don C. Reading
cc: Service list (e-mail only)
Very truly yours,
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF rDAHO POWER )
coMPANy',S PETITION TO MODIFY TERMS ) CASE NO. IPC-E-15-01
AND CONDITION OF PURPA PURCHASE )AGREEMENTS )
TN THE MATTER OF AVISTA CORPORATION'S )
PETTTION TO MODIFY TERMS AND ) CASE NO. AVU-E-15-01
CONDITIONS OF PURPA PURCHASE )AGREEMENTS )
tN THE MATTER OF ROCKY MOUNTAIN )
POWER COMPANY',S PETITION TO MODIFY ) CASE NO. PAC-E-15-03
TERMS AND CONDTTIONS OF PURPA )
PURCHASE AGREEMENTS )
DIRECT TESTIMONY AIiD EXHIBITS OF
DR. DON READING
ON BEHALF OF
J.R. SIMPLOT COMPANY AND CLEARWATER PAPER CORPORATION
APRIL 23,2015
a.PLEASE STATE YOUR NAME A}[D BUSINESS ADDRESS.
My name is Don Reading and my business address is Ben Johnson Associates, 6070 Hill
Road, Boise, ldaho. I am Vice President and Consulting Economist for Ben Johnson
Associates.
HAVE YOU PREPARED AN EXHIBIT OUTLINING YOUR QUALIFICATIONS
AND BACKGROUND?
Yes. ExhibitNo. 201 serves that purpose.
ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS CONSOLIDATED
DOCKET?
The J.R. Simplot Company (Simplot) and Clearwater Paper Corporation (Clearwater).
WHAT IS THE PURPOSE AI\ID GENERAL CONCLUSION OF YOUR
TESTIMONY IN THIS CASE?
I have been retained by Simplot and Clearwater to review the petitions filed by the Idaho
Power Company (ldaho Power), Avista Corporation (Avista), and Rocky Mountain
Power (RMP) asking the Idaho Public Utilities Commission (Commission, IPUC) to
modify the terms and conditions of Public Utility Regulatory Policies Act of 1978
(PURPA) contracts. I will explain why the recommendations of the three utilities is an
unreasonably overbroad approach. Both the Federal Energy Regulatory Commission
(FERC) and the ldaho Commission have correctly stated that PURPA projects need
contracts of duration longer than five years to allow for financing of a PURPA generation
facility. I will explain why the examples used by ldaho Power to criticize PURPA are
misleading, and will demonstrate that Idaho Power's claim of a "flood" of incoming
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PURPA contracts is misleading. It is far from certain from the evidence provided that
these projects will ever be built. I recommend the Commission maintain the current20-
year contract length for qualifying facilities (QFs) eligible for the IRP methodology rates,
or at a minimum for non-intermittent QFs, and if adjustments need to be made they
should be through the calculation of avoided cost rates and not limiting the term of the
contract.
YOU INDICATED YOU ARE TESTIFYING ON BEHALF OF SIMPLOT. DOES
SIMPLOT OPERATE OR INTEND TO DEVELOP QF PROJECTS IN IDAHO?
Yes. Simplot currently operates an existing QF project at its fertilizer plant in Pocatello,
Idaho, which utilizes a renewable fuel in the form of waste heat in an industrial
cogeneration process and has a nameplate capacity of 15.9 megawatts (MW). It has sold
the output from that plant under a series of PURPA contracts, and recently entered into a
one-year replacement contract for that PURPA facility. Simplot will need another
replacement contract within the next year. Although Simplot has recently obtained QF
contracts with published avoided cost rates, it has also requested indicative pricing under
the IRP methodology and considered increasing its generation well above l0 average
monthly MW on a consistent basis, which would require a contract containing the IRP
methodology avoided cost rates. In recent years, I understand that Simplot has
considered contract lengths ofup to seven years for this project.
Additionally, Magic Reservoir Hydroelectric QF (Magic) is a wholly owned
subsidiary of Simplot. Magic is a nine MW hydro facility in Southern ldaho, and
currently has a 35-year contract to sell the output to ldaho Power, which expires in 2024.
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Simplot also recently contacted ldaho Power to request indicative pricing for a
cogeneration QF sized up to 25 MW, to be developed at the new Idaho Project potato
processing facility in Caldwell, Idaho. I understand that Simplot faces difficulty even
analyzing the viability of this proposed facility without a fixed rate schedule in excess of
five years. It is likely the project will not proceed if the Commission reduces the
maximum contract length to five years.
YOU ALSO TESTIFIED THAT YOU ARE TESTIFYING ON BEHALF OF
CLEARWATER. DOES CLEARWATER OPERATE OR INTEND TO
DEVELOP QF PROJECTS IN IDAHO?
Clearwater owns four generators at its wood pulp, paperboard, and tissue manufacturing
facility near Lewiston, Idaho, which primarily utilize as fuel the black liquor byproduct
of the paper production process and wood waste. These four generators are cumulatively
capable of generating approximately 109 MW of electrical output. Although they
primarily use a renewable fuel in the form of biomass, these facilities also use the steam
output as process steam in the production ofpulp, paperboard and tissue products, and are
each certified as cogeneration QFs. Clearwater has previously sold its output from these
generators to Avista under PURPA contracts, and Clearwater has maintained its QF
certification to allow it to again make sales under PURPA in the future. Currently,
Clearwater operates under a2013 agreement whereby Clearwater uses its generators to
serve Clearwater's own load, and Avista compensates Clearwater for its excess
generation at the retail electricity rate. The 2013 agreement remains in effect until June
30, 2018, but provides Clearwater with a limited right to terminate its energy sales to
Avista with 90 days notice.
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Additionally, I understand from communications with Clearwater personnel that
Clearwater and Avista have had periodic conversations over the last five years about the
viability of siting a large cogeneration project at Clearwater's Lewiston facility. Given the
large and nearly constant steam demand at the Lewiston site, this facility could support a
base-load plant of an incremental 75 to 125 MW that would approach 70Yo thermal
efficiency depending on the sizes and types of prime movers selected for the project. The
net impact of this project would be an incremental lowering of greenhouse gas emissions
for the western U.S. as it would displace base-load coal plants and assist the State of
Idaho to comply with the E.P.A.'s recently proposed, and likely promulgated, Section
I I I (d) carbon reduction rule. The expected economics of such a project would likely
require non-recourse financing with terms of at least l5 years, with 20 years being a more
feasible term. A limitation of a five-year power purchase agreement takes this type of
high efficiency, greenhouse-gas-reducing project off the table as an option at Lewiston.
Clearwater does not think this artificial limitation is in the best interest of the ratepayers
of Idaho.
ASIDE FROM PURPA OR SERVING THEIR OWN LOADS, ARE THERE ANY
OTHER YIABLE OPPORTUNITIES TO SELL THE OUTPUT FROM
PROJECTS LIKE SIMPLOT'S AND CLEARWATER'S IN THIS REGION OF
THE COUNTRY?
Unlike the three regulated utilities that petitioned the Commission in this docket, state
law bars Simplot and Clearwater from selling electricity at retail to any customer. This is
also true of neighboring states that largely bar the sale of electricity at retail.
Additionally, FERC has stated that Section 210(m) of PURPA is intended to relieve
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1 utilities of their PURPA obligation if there is a sufficiently competitive wholesale market
2 for QFs to sell power. But there is no such economically viable wholesale market for the
3 sale of electricity that meets PUMA's requirements in this region. Therefore, aside from
4 PURPA sales to utilities, neither Clearwater nor Simplot have a legal or economically
5 viable market, retail or wholesale, to sell electricity.
6 Q. IDAHO POWER SUGGESTS THAT THE IDAHO COMMISSION HAS THE
.7 AUTHORITY TO REDUCE CONTRACT LENGTHS FOR FIXED AVOIDED
B COSTS TO ANY LENGTH IT CHOOSES. WHAT IS THE ORIGIN OF A LONG.
9 TERM CONTRACT WITH FIXED AVOIDED COST RATES?
10 A. PURPA is a federal law that directs FERC to implement regulations that encourage
11 cogeneration and small power production from renewable resources. I have included as
12 Exhibit No. 202 a copy of the FERC regulation regarding a QF's right to a legally
13 enforceable obligation for a specified term, which is contained in I 8 Code of Federal
L4 Regulations Part292.304. The FERC regulation provides that each QF shall have the
15 option:
t6 (2) To provide energ/ or capacity pursuant to a legally enforceable obligationfor
11 the delivery of energt or capacity over a specified term, in which case the rates
1 B for such purchases shall, at the option of the qualifuing facility exercised prior to
79 the beginning of the specified term, be based on either:
20 (i) The avoided costs calculated at the time of delivery; or
27 (ii) The avoided costs calculated at the time the obligation is incurued.r
I g*hibit No. 202 (containing l8 c.F.R. g 292.304(dX2)).
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a.COULD YOU PLEASE STATE FERC'S EXPLAI\ATION AS TO THE INTENT
OF THIS RULE, AS PROVIDED IN THE FEDERAL REGISTER AT THE TIME
FERC PROMULGATED THE RULE?
Yes. I have provided as Exhibit No. 203 an excerpt of FERC's Order No. 69, which was
published in the Federal Register on February 25, 1980, and explained FERC's decision
to adopt this regulation. FERC stated:
Paragraphs (b)(5) and (d) are intended to reconcile the requirement that
the rates for purchases equal the utilities' avoided cost with the needfor
qualifuingfacilities to be able to enter into contractual commitments based, by
necessity, on estimates of future avoided costs. Some of the comments received
regarding this section stated that, if the avoided cost of energt at the time it is
supplied ls /ess than the price provided in the contract or obligation, the
purchasing utility would be required to pay a rate for purchases that would
subsidize the qualifyingfacility at the expense of the utility's other ratepayers. The
Commission recognizes this possibility, but is cognizant that in other cases, the
required rate will turn out to be lower than the avoided cost at the time of
purchase. The Commission does not believe that the reference in the statute to the
incremental cost of alternative energ) was intended to require a minute-by-minute
evaluation of costs which would be checked against rates established in long term
c o ntract s be tw e e n q uolifu ing fac i I it ie s and e le ctr ic ut i I i t ie s.
Many commenters have stressed the needfor certainty with regard to
return on investment in new technologies. The Commission agrees with these
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latter arguments, and believes that, in the long run, "overestimations" and
"underestimotions" of avoided costs will bolance out.
,f,1.**
Paragraph (d)(2) permits a quolifyingfacility to enter into a contract or
other legally enforceable obligation to provide energl or capocity over a
specrfied term. Use of the term "legally enforceable obligation" is intended to
prevent a utilityfrom circumventing the requirement thot provides capacity credit
for an eligible qualifuingfocility merely by refusing to enter into a contract with
t he q ua I ify i ng fac i I i ty.z
I RECOGNIZE THAT YOU ARE NOT AN ATTORNEY AND CANNOT
PROVIDE A LEGAL OPINION ON FERC'S INTERPRETATION OF ITS OWN
REGULATION, BUT AS A MATTER OF ECONOMICS,IS IT YOUR OPINION
THAT A FIVE-YEAR CONTRACT TERM WILL,IN FERC'S WORDS,
"PREVENT A UTILITY FROM CIRCUMVENTING THE REQUIREMENT
THAT PROVIDES CAPACITY CREDIT FOR AN ELIGIBLE QUALIFYING
FACILITY"?
No. The QF will not be able to cause the utility to avoid future capacity additions if the
contract term is shortened to five years. One of the ways a utility can avoid, or
"circumvent" in FERC's terminology, entering into a QF contract is to limit the contract
term to such a short period that being able to finance the project becomes impossible. The
contract terms recommended by the three utilities in this case of two, three, and five years
2 p*,iUit No. 203 at 2 (containing FERC Order No. 69, 45 Fed. Reg. 12214,12,224 (Feb.25, 1980).
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are all too short to allow a QF to be economically viable or to provide, and be
compensated for, the capacity value.
AS A MATTER OF ECONOMICS, IS IT YOUR OPINION THAT A FIVE-YEAR
CONTRACT TERM WOULD SATISF"T *THE NEED FOR CERTAINTY WITH
REGARD TO RETURN ON INVESTMENT IN NEW TECHNOLOGIES'?
No. The only "certainty" that comes to mind with a QF contract term of five years or less
is that it is very unlikely the project would ever be built. This conclusion is suppomed by
the fact that utility non-PURPA power purchase agreements are for terms much longer
than five years. For example, Idaho Power's Neal Hot Springs power purchase
agreement is for a Zl-year term, and ldaho Power retained the right to extend the term of
that agreement. In his comments on the Neal Hot Springs contract, IPUC Technical
Staff, Rick Sterling, identified the right to extend the term as one of the "benefits" of that
agreement in recommending its approval.3
ALL THREE OF THE UTILITIES ASK FOR A PURPA CONTRACT TERM OF
FIVE YEARS OR LESS. IF CONTRACT LENGTH WERE ONLY FIVE YEARS
OR SHORTER,IS IT YOUR OPINION THAT A QF PROJECT COULD RELY
ON THE CONTRACT TO FINAI{CE THE DEVELOPMENT?
No. The "Enron meltdown" provided an ldaho example of the impact of shortening the
term of QF contracts to five years. As the Commission noted when increasing the term
limit from five years to 20 years (after reducing them earlier), only one PURPA contract
was signed in ldaho with the shortened contract length. At that time, the Commission
explained,
3 nUC Sta6Comments,IPUC Docket No. IPC-E-09-34, pp. l3-14 (filed May 3, 2010).
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This Commission also cannot ignore the fact that since reducing the eligibility
threshold to I MII and contract term to 5 years, there has been only one PURPA
contract signed in ldaho. A longer contract, we find, better coincides with the
amortizotion period or planned resource life of the renewable or cogeneration
resources being offered, better reflects the amortizotion period of generation
projects constructed by the utilities themselves and will coincidently provide a
revenue stream that willfacilitate the financing of QF projects.a
DOES THE IDAHO COMMISSION LIMIT UTILITY.OWNED GENERATION
RESOURCES TO A FIVE.YEAR TERM FOR COST RECOVERY OF THE
INVESTMENT?
No. Any utility-owned resources of any significance that I am familiar with are approved
by the Commission with terms in some cases up to 50 years, and are seldom shorter than
20. Of course, for a utility-owned resource the ratepayer is on the hook for providing the
utility with a return both of and on the investment for the facility once it is put into rate
base. Treating PURPA resources on an equal footing with utility-owned resources would
mandate they also should receive longer-term contracts.
FERC ALSO REFERENCED "LONG TERM CONTRACTS.' IF YOU WERE
TO ASSUME THAT PURPA REQUIRES A LONG-TERM CONTRACT, IN
YOUR OPINION,IS FIVE YEARS A LONG TERM IN THE CONTEXT OF A
UTILITY.SCALE CAPITAL INVESTMENT?
No. When considering financing significant capital investments, such as utility
generation plants, "long-term contracts" would certainly mean more than five years.
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4 IPUC order No. 29029, at p.7,
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a.IF I WERE TO TELL YOU THAT FERC'S RULES REQUIRE THE
COMMISSION TO IMPLEMENT LONG.TERM, FIXED AVOIDED COST
RATES THAT PREVENT THE UTILITY FROM CIRCUMVENTING THE
NEED TO PAY FOR THE QF'S CAPACITY OR THAT ARE OF SUFFICIENT
LENGTH TO SUPPORT INVESTMENT IN A UTILITY GENERATION
FACILITY,IS IT YOUR OPINION THAT A FIVE.YEAR CONTRACT TERM
MEETS THAT TEST?
No. Using such an unreasonably overbroad approach of shorting the contract length so
that QFs cannot obtain financing is a way around FERC's rules. Developing accurate
avoided cost pricing is a more rational approach that meets FERC's regulations.
HAS THE IDAHO COMMISSION ITSELF MADE FINDINGS REGARDING
THE LENGTH OF CONTRACTS WITH A FIXED RATE THAT IS NECESSARY
TO ENCOURAGE QF DEVELOPMENT AND SUPPORT FINANCING FOR A
QF PROJECT?
Yes. Just a few years ago, the ldaho Commission found:
Ile find that a 20-year contract length, along with other factors, has been
beneficial in encouraging PURPA development in ldaho. We continue to believe
that 2)-year controcts better coincide with the useful life of the
renewable/cogeneration resources. lVhile it is not this Commission's
responsibility to ensure a contract length that allows a QF to obtainfinancing, we
find that reducing maximum contract length to five years would unduly hinder
PURPA development. That is not the Commission's objective. l|/e believe that, by
utilizing other tools to ensure an accurote and up-to-date avoided cost valuation,
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we can continue to encourage the types of projects that were envisioned by
PURPA while maintaining the tronsporencyfor ratepayers as PURPA requires.
Therefore, we find that a maximum contract length of 20 years is appropriate.
The parties to a power purchase agreement are free to negotiate a shorter
contract if that would be most suitable for the project. As in the past, this
Commission will consider contracts of more than 20 years on o case-by-case
basis.5
THE COMMISSION STATED, "WE FIND THAT REDUCING MAXIMUM
CONTRACT LENGTH TO FIVE YEARS WOULD UNDULY HINDER PURPA
DEVELOPMENT." DO YOU AGREE?
Yes, I believe Commission is correct. Real world economics dictate that a project will not
get financing with a contract length of five years unless the investment has a five-year
pay-back period. A five-year pay-back is far shorter than generally understood to be
necessary for long-term utility-scale investments.
HAVE CONDITIONS CHANGED SINCE2OI2 WHEN THE COMMISSION
STATED THAT REDUCING THE CONTRACT LENGTH WOULD UNDULY
HINDER PURPA DEVELOPMENT?
No. The length of the QF contract has to do with the ability to obtain funds in order to
build the project. Those conditions have not changed. The utilities' avoided costs may
have changed and that should be the determining factor in whether projects are
developed, rather than an arbitrarily short contract term that is designed to deprive
financing and capacity payments to the QF.
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ARE 2O.YEAR CONTRACT TERMS OUT OF THE ORDINARY FOR
ELECTRIC UTILITIES?
Not at all. For example, according to Idaho Power's most recent l0-K filing, in April of
2012ldaho Power issued $75 million in first mortgage bonds that mature after 30 years.
Long-term financial commitments are routine in all utilities' financing and planning.
DR. READING, WHAT PRECIPITATED THE CONSOLIDATION OF
PETITIONS FILED BY THE THREE UTILITIES IN THIS DOCKET?
Idaho Power filed a petition on January 30, 2015, to reduce the length of PURPA
contracts to two years. The Commission granted the Company interim relief temporarily
reducing QF contracts from 20 years to five years. On February 27,2015, Avista
petitioned the Commission for the same temporary and permanent relief that would be
granted to ldaho Power and a five-year contract length for wind and solar QFs. Four
days later on March 2,2015, Rocky Mountain Power filed its petition seeking the same
interim relief and a perrnanent reduction in the length of QF contracts to three years,
along with an adjustment in the method of calculating avoided costs. The Commission
consolidated the three cases into a single docket. I will discuss each of the utilities'
petitions.
COULD YOU PLEASE TELL US IDAHO POWER'S REASON FOR FILING
THE ORGINAL PETITION FOR THIS CASE?
According to the Company's petition, it faces what some have called a "tsunami" of wind
and solar PURPA projects washing over Idaho Power's system.6 Idaho Power proposes
to limit contract terms for all QFs eligible for IRP methodology rates to two years.
6 ldoho Power's Petition,lPUC Case No. IPC-E-15-01, p.21.
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a.WHAT IS IDAHO POWER'S RATIONALE FOR LIMITING PURPA PROJECTS
TO ONLY TWO YEARS IN DURATION?
Idaho Power's claim is that PURPA is imposing "risk" and "harm" to ratepayers. Idaho
Power's petition largely discusses a problem with intermittent wind and solar QFs that
have the capability of creating an oversupply problem on Idaho Power's system during
certain periods of the year. According to ldaho Power's subsequent pleadings, the
problem is not just intermittent wind and solar projects but PURPA itself in obligating
ratepayers to the Commission-approved rates for aZ}-year period.T In an attempt to
prove its case, Idaho Power provides "examples" of the price paid for PURPA
generation. Idaho Power claims customers must purchase power at these higher PURPA
prices when the power is not needed to serve load or can be obtained in the market at a
cheaper price.
DO YOU BELIEVE IDAIIO POWER MAKES A COMPELLING ARGUMENT
WHEN PRESENTING ITS EVIDENCE?
No. Idaho Power arrives at its conclusions by only telling half of the story. When valid
comparable evidence is presented, it shows the Company's own generating resources
commit the same oosins" as the PURPA resources that they are asking the Commission to
discourage.
COULD YOU PLEASE EXPLAIN WHAT YOU MEAN BY ONLY PRESENTING
HALF THE STORY?
The first half of the story is told when comparing the cost of PURPA resources to Mid-
Columbia (Mid-C) prices. As shown in Exhibit No. l0 of Company witness Allphin's
7 Uaho Power's Answer to Simplot/Clearvvater Joint/Cross Petition,lPUC Case No. IPC-E- l5 -01, at p. 2
(filed March 19,2015).
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direct testimony, historical Mid-C prices have been lower than PURPA prices since 2002
to the present and are projected by Idaho Power to be lower over the next 20 years. What
this comparison fails to recognize is capital costs are included in the PURPA per MWh
price. Mid-C prices are market prices and are more reasonably related to the variable
running costs of existing generating resources that do not contain capital costs. Both
variable and capital costs are rolled together in the rates customers pay. When a utility's
generating resource is approved in rate base, the ratepayers are "forced" to pay the capital
costs of the resource over the approved life, even when the Company's own generating
resources are not needed to serve load.
WHAT DO YOU CONSIDER A MORE APPROPRIATE CAMPARISON?
The cost of PURPA resources paid by Idaho Power are passed through to customers in
the retail rates customers pay. PURPA rates should be compared to what Idaho Power's
customers pay for power from the Company's own generation facilities, which would
include the rate based capital costs along with the fixed and variable running costs.
HAVE YOU MADE THAT COMPARISON WHERE BOTH PURPA PROJECTS
AI\D IDAHO POWER'S GENERATING RESOURCES ARE MEASURED ON AI\
EQUIVALENT BASIS?
Yes, a reasonable comparison can be made by using Idaho Power's FERC Form I data
for production costs and Idaho Power's Responses to Simplot's discovery request for the
capital portion of the costs. Chart I below displays the results of including the estimated
capital costs along with the variable running costs of Idaho Power's generating facilities
on a per MWh basis for 2013, therefore comparing them on an equivalent basis to the
PURPA costs in retail rates. For 2013, as expected, the market Mid-C prices are the
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lowest cost non-hydro resource on [daho Power's system. Two of the Company's coal
resources have a lower cost than PURPA resources with the other four thermal units at a
higher cost. This does not take into account the additional costs that might be necessary
for coal plant upgrades for environmental compliance for the Company's non-PUMA
resources that may be necessary in the near future.
Chart 1
ldaho Power Ratepayer Power Costs 2013 & Mid-C S/MWh
Bennett Mt.**
Danskin* *
Langley Gulch * *
Valmy+ +
PURPA*
Boardman* *
Jim Bridger**
Mid-c*
s100 s1s0
s/riltvh
Source:
+ R. Allphin Exhibit 10
+* Attachment 2 - Responseto Simplot's Request No. 13, 2013;'Net Plant' *.18 for Capacity;
ResponsetoSimplot's RequestNo.5(d),annual reveunerequirementis 18%ofcapital Cost;
Production Expense'and 'Net Generation', 2013 FERC Form 1
DR. READING,I DO NOT SEE IDAHO POWER'S HYDRO RESOURCES IN
YOUR CHART 1. SINCE, DEPENDING ON STREAM FLOWS, IDAHO
POWER'S HYDRO RESOURCES MAKE UP HALF OF TIIE COMPAIIY'S
ENERGY SUPPLY, WHY HAVE YOU EXCLUDED THEM FROM YOUR COST
COMPARISONS?
Idaho Power's hydro facilities are certainly the Company's lowest cost resource with a
depreciated rate base and very low variable running cost. Also, depending on stream flow
B
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1 conditions the capacity factors will vary significantly from year to year, and that would in
2 turn cause the cost on a per MWh basis to also vary significantly. So the year picked for
3 the analysis could be misleading. Due the above factors I felt looking at thermal
4 resources along with the market price would be a more reasonable comparison.
5 Q. ARE THERE ANY OTHER REASONS TO EXCLUDE HYDRO RESOURCES
6 FROM YOUR ANALYSIS?
7 A. Yes. Idaho Power has been in the process of relicensing its Hells Canyon Complex
B ("HCC") for well over a decade. [t appears that the capital and variable costs associated
9 with the massive environmental remediation associated with that relicensing will
10 dramatically change the economics of the Company's hydro resources as a whole - and
1 1 not just the costs associated with the HCC. The final cost of relicensing HCC won't be
L2 known for years; therefore it would be speculative for me to include the unknowable
13 increased costs of the Company's hydro resources in my analysis.
74 a. Do THE OTHER TWO UTILITIES IN THIS CASE SUPPORT COMPARING
15 THE PRICE OF PURPA RESOURCES TO THE MID-C PRICES THAT DO NOT
L6 INCLUDE THE CONSIDERATION OF CAPACITY COSTS?
71 A. I don't know about Avista, but PacifiCorp has stated in Washington Utilities and
1B Transportation Commission (WUTC) cases that it is inappropriate to make the
19 comparison of PURPA resources with the Mid-C market prices. I have provided as
20 Exhibit No. 204 excerpts of the testimony of Gregory Duvall before the WUTC in recent
27 general rate cases. PacifiCorp witness Gregory Duvall states,
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The inclusion of capocity payments in avoided costs indicates that market prices
alone are not equivalent to avoided cost prices.S
And the same PacifiCorp witness in a later WUTC docket stated,
If avoided cost prices are greater than market prices years after the PPA was
signed, it does not mean that the avoided cost prices in the QF PPA are excessive
or otherwise violate PURPA's strict requirements.
PURPA requires that the prices poid to QFs be equal to o utility's
avoided cost of energt and capacity. Each state has on opproved methodfor
colculating these avoided costs, and the resulting prices are heavily scrutinized
and ultimately approved by the respective regulatory commissions. The avoided
cost calculation is intended to ensure that customers are indffirent to QF
generation, i.e., that the price paid to the QF is the some os the price the utility
would otherwise incur if it was generating the electricity itself. Comporing QF
PPA prices for a single test year to the variable cost of market purchases or the
Compony's existing resources is insufficient to determine whether QF prices are
reasonable and prudent from a ratemaking standpoint.g
Subsequently, Mr. Duvall further testified:
First, simply relying on morket prices does not reflect Pacific Power's actual
avoided costs as determined by the Commission because it fails to account for the
impact of a QF on the Company's existing resources or the QF's ability to defer
8 p*nitit No. 204 at I I (containing the Rebuttal Testimony of Gregory Duvall, WUTC Docket UE-
130043, August 2,2013, p.22).
9 g*nibit No. 204 at l7 (containing Direct Testimony of Gregory Duvall, WUTC Dockets UE-140762, -
140617, -131384, -140094, May,20l4, p. I l).
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future capacity additions. PURPA requires the Company to purchase energt and
capacity made available by QFs.lo
As PacifiCorp's witness, Mr. Duvall testifies in its Washington jurisdiction that
comparing market prices to PURPA resource prices is inappropriate and misleading.
IDAHO POWER CLAIMS THAT RATEPAYERS ARE HARMED WHEN THE
COMPANY IS FORCED TO PURCHASE PURPA POWER WHEN IT IS NOT
NEEDED. DO YOU AGREE?
No more or less than when ratepayers are "forced" to pay for the utilities' own generating
resources when they are not needed. Company witness Allphin presents a series of 24
separate graphs in his Exhibit No. 6 for the first week of each month for the years 2016
and 20l7.Each graph displays, on an hourly basis, total system load along with the
Company's "must-run" resources, "must-take" non-PUMA PPA's, along with "must-
take" PURPA resources. The "must-run" Company-owned facilities are their hydro and
coal generation units at their minimum operational levels that cannot be backed down
further for environmental reasons for hydro resources, or shut down for coal generation
units. Market purchases and sales are excluded from the Exhibit's graphs.
WHAT IS THE IDAIIO POWER WITNESS ATTEMPTING TO
DEMONSTRATE WITH THE SERIES OF 24 GRAPHS?
Again, Idaho Power is telling only half of the story. According to Mr. Allphin's
testimony,
This analysis shows the frequency with which ldaho Power's system, when in o
state where it cannot be backed down any further, will have generation resources
l0 g*niUit No. 204 at25-26 (containing Rebuttal Testimony of Gregory Duvall, WUTC Dockets UE-
140762, -140617, -13 1384, -140094, November, 2014,pp. l4-15).
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in excess of its system load. This will put the system into an imbalanced, over-
generation state unless some remedial actions are taken to balance the system. If
remedial actions are not available, or not employed in a timely manner, then the
Company can have system reliability violations, events, and/or outages and
damage.ll
An examination of the monthly graphs over the two-year period indicates, as one would
expect, a mix of relationships among the Company's load patterns over the 24 months
considered, and the output of the power supply depicted, indicating both an over and
under supply of power in various months.
COULD YOU BE MORE SPECIFIC AND PROVIDE EXAMPLES FOR Tlilr.24
GRAPHS THAT INDICATE THE OYER AI\D UNDER SUPPLY OF POWER ON
IDAHO POWER'S SYSTEM RELATIVE TO THE SYSTEMS LOADS?
I have selected two months as examples that are at the ends of the spectrum of when the
graphs indicate first an oversupply relative to loads and second when the situation is
reversed and there is an undersupply. The two example months are April and August of
2016 and indicate there are times when both the Company-owned resources and PURPA
power contribute to filling part of the gap when output is less than load and other times
when the Company's own "must-run" resources alone are producing power greater than
system load needs.
COULD YOU PLEASE EXPLAIN WHAT YOU MEAN USING THE APRIL2OI6
GRAPH FOUND ON PAGE 5 OF 12 OF MR. ALLPHIN'S EXHIBIT NO. 6?
Below is copy of the April 2016 Graph included in Mr. Allphin's testimony.
I I Direct Testimony of Randy Allphin, Idaho Power, IPUC Case No. IPC-E-I5-01, pp. 9-10.
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ldaho Porrer Forecasted load s. For€c6ted Must Run or Talc Generaffon (MW]
4.4, 2Or l..5, 'raE]stVr,bClof fie Marth
-U
ilWofPUPA$|,proFd
r PURPA$lr un&rcdt-t
IPURPAWId
Ima.rckdntWlnd rd5l-
Imoulllty MudT.L PP '3
;i lEoMu*{un @nardd
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As can be seen in the above graph for April, when loads are relatively low, system loads
are less than both the o'must run" ldaho Power generation units as well as PURPA
resources. This would mean that Idaho Power's "must run" units are contributing alone to
the "system reliability violations, events, and/or outages and damage" unless remedial
action is taken in a timely manner, even if there is no PURPA power being produced.
COULD YOU PLEASE EXPLAIN TITE OTHER END OF TIIE SPECTURM,
AUGUST 2016 WIIEN BOTH IDAHO POWER'S RESOURCES AT *MUST.
RUN" AI\D PURPA RESOUSES ARE NOT SUFFICIENT TO MEET THE
SYSTEMS LOADS?
As can be seen below in a copy of Mr. Allphin's graph for August 2016,that is predicted
to be a relativity high load month. [n this graph, Idaho Power's "must run" resources and
PURPA are significantly below system loads.
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ldaho Power Forecasted Load vs. Forecasted Must Run or Take Generation (MW)
/\/\/\
\/\/\/\/\/
I
"ll^.J t I \-I tITF
l
TF
,1.
I.l
F
I
I
i
ytr
l,2016 tut2,2016 tutl,2ol6 Auaa,A$ &t5,2015 tua5.t15 Aut7,2O16
Firstl betofthe Month
PUnPASol.r undercontrad
IPURPA.xcludinS Wand.nd
IlPCoUiliq Mu* T.le PPA's
lPCoMun-Ru. G.n..ation(Hydro.nd 266 Mw ofco.l)
-lPCoLo.d
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This means PURPA generation is contributing to the Company's system load demands
just as ldaho Power's Company-owned resources are. The other monthly first week
graphs display a mix of over and under generation during certain hours over the first
week of each month.
DO YOU HAVE ANY ADDITIONAL OBSERVATIONS ABOUT IDAHO
POWER'S EXHIBIT NO.6?
Yes, for the casual observer, since PUMA, other PPAs and Company-owned resources
are all defined as "must run" in the Exhibit No. 6, PURPA could just as easily be
displayed along the horizontal axis first with the utility-owned resources on top. This
could lead one to assume the Company-owned resources are the problem of ldaho Power
being "forced" to receive power when it is not needed, not PURPA resources. The graph
below uses the same data for April 2016 as used by in Exhibit No. 6 and only reorders
how the resources are displayed in the graph.
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ldaho Po$rerForecastedloadvs. Forecsted Must Run or Bh GerPratlcr (Mw|
rur td
IMt eldtf,ba&a
IIE.I&UOdfuFA'
dooa,...at
o&rt--ta x.t.rla rra.lE l.r.rt&ra.!la &.t.!ta
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As can be seen, reversing the display of the various resources causes it to appear that
Idaho Power's "must-run" resources are the source of oversupply, not PURPA. In truth,
all of the resources are all part of the same power supply system and contribute to over
and undersupply at any point in time.
ARE YOU IMPLYING THAT COMPANY-OWNED RESOURCES AND PURPA
RESOUCES ARE THE SAME THING?
No. There are important differences depending on the type of resource, and both impose
different risks and provide benefits for ratepayers under different load and resource and
power market conditions. The off-system price of power is currently relatively low, and
the Northwest currently has a surplus of power. However, history shows that power
market prices in the Northwest have been volatile and power surpluses and deficits can
change quickly. One thing that is certain is there will be ups and downs in the future, and
the current situation will not stay the same as today over the next 20 years.
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a.CAN YOU PROVIDE AN EXAMPLE OF WHAT YOU MEAII BY SAYING
THERE CAN SOMETIMES BE RAPID CHANGES IN POWER MARKETS?
The most dramatic swing in market prices for power in the Northwest in the recent past is
the so-called "Enron meltdown" when Mid-C prices got as high as $677 per MWh in
June of 2000 on a daily basis.l2 At the same time, due to a variety of causes, utilities
were facing power shortages. With the then-dramatic swings as background, the
Commission issued Order No. 29029 quoted above and increased the length of PURPA
contracts to 20 years from five years and raised the eligibility cap for published rates.l3
WHAT OTHER ACTIONS DID THE COMMISSION UNDERTAKE IN THIS
VOLATILE MARI(ET TIME FRAME?
The Commission, in July of 2001, approved a Certificate of Public Convenience and
Necessity (CPCN) for Idaho Power's peaking facility, the Mountain Home Generation
Station (Danskin). In its decision the Commission said,
We note that the procedurefollowed in this cose has limited the type and
extent of review that would otherwise occur in a certificate filing. The price of
power on the spot market, the shortage of waterfor hydro generation ond the
Company's projected inability to serve native load requirements with Company
generation and contract supplies have all joined to create the unique factual
situation presented ond have also fashioned the particular regulatory treatment
requested by the Company.
l2 https://www..nwcouncil.org.Appendix C Electricity-Price-Forecast-.pdf.
l3 IPuc order No. 2go2g, at p.7 .
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We ore convinced that the volatility of the electric spot market created a
situation that justified a deviationfrom the Company's 2000 IRP and its actions
in developing plans for the Mountain Home Station.l4
4 Faced with the upheaval in the power markets at this time, the Commission reacted by
5 increasing the length of PURPA contracts to 20 years and approving a peaking plant that
6 was not included in ldaho Power's Near-Term Action Plan in its 2000 IRP. The point of
1 the above example is that over a time period of a just a few years unforeseen
B circumstances can significantly impact market conditions for both supply and price.
9 Current power market conditions today have no guarantee they will remain the same over
10 a20-year period.
11 A. COULD YOU PLEASE EXPLAIN FURTHER WHAT YOU MEAN BY SAYING
72 BOTH UTILITY-OWNED RESOURCES AND PURPA RESOURCES HAVE
13 DIFFERENT RISKS AND BENEFITS FOR RATEPAYERS?
74 A. Utility-owned resources and PURPA supply costs impact ratepayers in different ways. A
15 PURPA project will only get paid when it supplies power to the utility. On the other
76 hand, with a rate-based, utility-owned resource, the capital portion of the plant is rolled in
11 customer rates even if the facility is idle. This means for a utility-owned resource the
18 capacity costs are factored into retail rates on a per-MWh basis, and they can vary
19 significantly as the capacity costs of the facility are spread over higher and lower power
20 output. For a PURPA resource, the capital portion of the price is included in the levelized
21 dollars per MWh, and ratepayers are charged only when the facility provides power.
l4lpUC OrderNo. 28773,at pp. I l-12.
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Idaho Power says it is concerned that as QF contracts get longer there is increased
2 risk and potential harm to ratepayers, without recognizing their own resources lock in
3 ratepayers as well to pay for their own generating resources. The Commission Staffasked
4 ldaho Power;
REQUEST NO. 18: On page 22, the Petition states that ". . . the risk and
potential harm increases, the longer the price estimates are locked in." Does
Idaho Power believe long-term, locked-in price estimates could potentially benefit
Idaho Power in some circumstances?
RESPONSE TO RE]UEST NO. l8: No.ts
10 What ldaho Power is failing to acknowledge is that their own plants are also "locked in"
11 for ratepayers for the plant life that is 20 or more years.
L2 A. DOES THIS EXAMPLE DEMONSTRATE AI\IY OTHER POINTS?
13 The above example also points out that PURPA projects, even those with 20-year
L4 contracts, do provide a risk hedge and a benefit to ratepayers. PacifiCorp's witness Mr.
15 Duvall agrees with this point and has testified at length before the Washington
L6 Commission regarding the extensive benefits of PURPA projects:
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20 **'t*
In addilion to providing the copacity benefits discussed obove, the out-of-
state QFs provide significant beneJits because they ore renewable, emission-free
27
22
Emission-free resources may act as a hedge against future corbon
regulation, the exoct nature of which is currently unknown. Infact, the
l5 Iduho Power's Response to IPUC Staff Production Request No. 18.
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I Commission has aclcnowledged that future cqrbon regulation may have a
2 significant impact on the Company's operations. The out-of-state QFs,like all of
3 the Company's renewable resources, will help to mitigate thot impact.l6
4 Q. ARE THERE OTHER WAYS THAT PURPA POWER PROJECTS CAN LOWER
5 RISKS FOR RATEPAYERS THAT UTILITY-OWNED RESOURCES DON'T?
6 A. In addition to not requiring ratepayers to pay for the capital portion of undelivered
'7 electricity, PURPA resources avoid the fuel cost risks ratepayers face from a utility's own
B resources. All three utilities that are part of this case have some form of a power cost
9 adjustment mechanism that, on an annual basis, allows them to recover the majority of
10 their net power supply expenses. This means the utility is able to pass onto ratepayers any
11 fluctuations in the costs of their fuel supplies so that it is the ratepayer, not the utility, that
12 assumes the risk.
13 a. THE THREE INVESTOR OWNED UTILITIES ALL ARE PROPOSING TO
14 SHORTEN THE CONTRACT LENGTH FOR ALL PURPA PROJECTS ABOVE
15 THE ELIGIBILITY RATE CAP, IDAHO POWER FOR TWO YEARS AND
76 ROCKY MOUNTAIN POWER THREE YEARS. AVISTA RECOMMENDS FIVE
11 YEARS AND BELIEVES IF A VERY FAVORABLE OPPORTUNITY WAS
18 PRESENTED TO THE UTILITY IT SHOULD HAVE AN OPTION FOR A
19 LONGER CONTRACT.IT DO YOU AGREE WITH THE
20 RECOMMENDATIONS OF THE UTILITIES?
16 p*hibit No. 204 at28-29 (containing Rebuttal Testimony of Gregory Duvall, WUTC Dockets UE-
I 407 62, -l 40617, - I 3 I 384, -l 40094, November, 20 I 4, pp. I 7- I 8).
l7 Direct Testimony of Clint Kalich, Avista Corporation, February 27,2015, AVU-E-15-01, p.3.
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The Companies are advocating an unreasonably overbroad approach by treating all types
of PURPA resources the same. Limiting the contract length will cause all types of
PURPA projects to become uneconomic due to the inability to obtain financing, not just
"wind and solar." The ldaho Commission has established precedent for setting different
terms and conditions for different types of PURPA projects.
Recently, in Case No. GNR-E-10-04 the Commission lowered the eligibility cap
for wind and solar to 100 kW while leaving the higher l0 average monthly MW cap for
all other project types. The Commission's rationale for doing so was that wind and solar
resources have unique characteristics not found in other types of PURPA QFs.
Based upon the record, the Commissionfinds that a convincing case has been
made to temporarily reduce the eligibility cap for published avoided cost rates
from I 0 aMW to I 00 kW for w ind and solar only while the Commission further
investigates the implications of disaggregated QF projects. lile maintoin the
eligibility cap at l0aMLTfor QF projects other than wind and solar (including but
not limited to biomoss, small hydro, cogeneration, geothermal, and waste-to-
energt). The Petitioners have not convinced us that lowering the eligibility cap
for these other QF technologies is necessory or in the public interest.
Wind and solar resources present unique characteristics that dffirentiate
themfrom other PURPA QFs. llrind and solar generation, integration, capacity
and ability to disaggregate provide a basis for distinguishing the eligibility cap
for wind and solar from other resources.lS
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Currently, the three utilities have posted different published avoided cost rates for
different resource types. Each of the utilities recognizes QFs have different defining
characteristics.
BOTH CLEARWATER AND SIMPLOT CURRENTLY HAVE
COGENERATION PROJECTS. DO YOU BELIEVE THEY HAVE
CHARACTERISTICS THAT DISTINGUISH THEM FROM WIND AIID SOLAR
AS WELL AS OTHER PROJECTS?
Cogeneration projects have "unique characteristics" that are distinct from other types of
PURPA projects. They are more fuel efficient than traditional generation and support a
stronger economy. FERC defines a cogeneration facility as,
A cogenerationfacility is a generatingfacility that sequentially produces
electricity and anotherform of useful thermal energ) (such as heat or steam) in a
way that is more efficient than the separate production of bothforms of energt.
For exomple, in addition to the production of electricity, large cogenerotion
facilities might provide steamfor industrial uses infacilities such as paper mills,
refineries, orfactories, orfor HVAC applications in commerciol or residential
buildings.te
FERC regulations also exempt cogeneration QFs from the 80 MW cap imposed on other
types of qualifying facilities, and FERC has stated that,
l9 http://www.ferc.eov/industries/electric/een-info/qual-fac/what-is.asp
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Cogenerationfacilities can use significantly less fuel to produce electric energ/
and steam (or other forms of energt) than would be needed to produce the two
separately.2o
According to an Iowa State University doctoral dissertation,
Cogeneration has afuel fficiency of 80% to 90 % compared to the 33%fuel
effi c i e ncy of c o nv e nt i o na I e le c tr i c i ty ge ne r at i o n un i t s.2 |
YOU STATED ABOVE THAT COGENERATION SUPPORTS A STRONGER
ECONOMY. WHY DO YOU SAY THAT?
Cogeneration supports the economic viability of Idaho industrial facilities. While this
not linked directly to a utility's avoided cost, it contributes to the strength of ldaho's
economy and employment, which in turn helps make a stronger utility. Also,
cogeneration facilities produce electric power without using additional fuel or
contributing additional pollution, which also benefits society. Cogeneration represents
one of the most effective approaches to energy conservation, because it produces two
types of energy at once - electric power and thermal energy. Conventional thermal
power generators typically range from 33%o to 60% efficient, with coal plants in the
lower end of the range and combined cycle gas plants in the upper range. They
essentially waste between 40o/o to 67Yo of the fuel energy -- whereas cogeneration
facilities can achieve efficiencies of 80%. On top of that, cogeneration facilities make the
host manufacturing plant more financially secure with all the attendant societal benefits
20 pERc order 688, Docket RM06-010, at p. l4 (oct. 20, 2006).
2 I the Economic and Environmental Performance of Cogeneration under the Public Utility Regulatory
Policies Act, Daniel, Shantha E., Iowa State University,2009,p.4.
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of having a more robust economy. Cogeneration also significantly reduces carbon
emissions, reduces business costs, relieves grid congestion and improves energy security.
ARE THERE OTHER CONSIDERATIONS RELATED TO THE BENEFITS OF
COGENERATION IN THE CONTEXT OF THIS PARTICULAR CASE?
Yes. As I noted earlier, Idaho Power's petition primarily points to a problem of
oversupply of generation that is occurring during certain times of the year as a result of
intermittent and relatively unpredictable PURPA output from wind and solar projects.
Cogeneration QFs are base-load resources that do not provide intermittent deliveries, and
their output should be more easily predicted and managed during these over-supply
periods.
WHAT IS THE POSITION OF THE THREE UTILITIES RELATING TO THE
PURPA PROJECTS PROPOSED IN THEIR RESPECTIVE SERVICE
TERRITORIES?
The perceived "flood" of PURPA projects varies among the three utilities. Idaho Power
states the Company currently has 461 MW of PURPA solar capacity under contract with
an additional 885 MW in the queue actively seeking power sales agreements.22 Rocky
Mountain Power states it has had an o'exponential increase in PURPA contract requests"
consisting of 97 projects totaling 1,553 MW in the last two years throughout its multi-
state system.23
WHAT IS AVISTA'S POSITION WITH REGARD TO QFS SEEKING PURPA
CONTRACTS IN TTS SERVICE TERRITORY?
22 Hoho Power's Petition,lPUC Case No. [PC-E-15-01, p. 18.
23 Rocky Mountain Power's Petition,lPUC Case No. PAC-E-15-03, p. 19.
Reading, Di, Simplot/Clearwater
IPC-E-l 5-01, AVU-E-15-01, PAC-E-l 5-03
o.
A.
o.
30
1 A. While Avista is not claiming there is a torrent of PURPA projects in its service territory,
2 its concern is if a neighboring utility such as Idaho Power offers only five-year contacts
3 "sophisticated and motivated PURPA developers" will seek longer term contracts by
4 wheeling the QF output to Avista.24 Avista advocates for the ability to contract for
5 PURPA projects with terms longer than five years in the event of a very favorable
6 PURPA opportunity.25 Avista, however, does not offer specifics on what a o'very
7 favorable PURPA opportunity" means, and it does not state that it supports continuing
B z0-year QF contracts for projects subject to the IRP methodology.
9 Q. DO yOU AGREE WITH AVISTA'S POSITION THAT UTILITIES SHOULD BE
10 ALLOWED TO NEGOTIATE A TERM LONGER THAN THE COMMISSION-
11 AUTHORTZED TERM?
12 A. Yes. Under the Commission's long-standing rules, utilities have always been allowed to
13 negotiate a term longer than the Commission-approved contract length. I agree that
74 regardless of the outcome of this proceeding the utility and the QF should be allowed to
15 agree to a longer term under the appropriate circumstances.
L6 a. DOES AVISTA PROVIDE AI\Y EVIDENCE THAT ANY QFS HAVE TRIED TO
71 WHEEL THEIR OUTPUT TO SELL IT TO AVISTA, GMN THE
18 OVERSUPPLY PROBLEM ON IDAHO POWER'S SYSTEM?
19 A. No. Avista provides no evidence any QF has tried to wheel its power to Avista to sell to
20 it from off-system. Avista only points to a single QF, operated by Kootenai Electric
21 Cooperative, Inc., that sought to wheel its output atuay from Avista and to ldaho Power.
24 DirectTestimony of Clint Kalich, Avista Corporation, IPUC Case No. AVU-E-15-01, p.5.
25 td. utpp.2-3.
Reading, Di, S implot/C learwater
IPC-E-l 5-01, AVU-E-l 5-01, PAC-E-l 5-03
31
1
2
3
4
9
10
11
o.DOES AVISTA PROVIDE AI\Y REASON TO BELIEVE THAT THE LARGE
NUMBER OF PROSPECTIVE SOLAR QFS DISCUSSED IN IDAHO POWER'S
PETITION MAY SEEK TO SELL TO AVISTA INSTEAD?
No. Avista's avoided costs for solar resources are lower than Idaho Power's avoided
costs for solar resources because Avista has a different load profile that does not lend
itself to high avoided costs for solar output. Avista's published rates for solar projects are
currently set at $49.77 per MWh on a2}-year levelized basis for an online date in 2016,
while ldaho Power's comparable rate for a2016 online year is $66.85 per MWh. I would
expect the IRP methodology rates may well be lower than the $49.77 per MWh amount,
plus the off-system solar QF would need to pay to wheel the output to Avista. There is
no reason to believe solar QFs would be able to rely on the economics of those low rates
to finance a solar QF.
IDAHO POWER, AS YOU POINTED OUT ABOVE, STATES IT HAS 461 MW
OF PURPA SOLAR CAPACIY UNDER CONTRACT AI\D AI\ ADDITIONAL 885
MW rN THE QUEUE TO BE ON-LINE rN 2016. DO yOU HAVE AN OprNrON
AS TO THE PROBABILITY THAT ALL THOSE QF PROJECTS WILL
ACTUALLY BE CONSTRUCTED?
In Response No. 2 to the ldaho Conservation League and Sierra Club's First Production
Request ldaho Power stated,
As of the date of the response to this Request, 380 megawotts ("MW") of
the 521 MW of QFs under contract, but not yet on-line, are in compliance with
their respective agreements; therefore, Idaho Power has no reason to assume they
will not come on-line as stated in their agreements. To date, l4l MIV of the 521
Reading, Di, SimplotiClearwater
IPC-E-l 5-01, AVU-E-15-01, PAC-E-l 5-03
A.
5
6
1
o
72
13
L4
15
t6
71
21
22
23
a.
18 A.
19
20
32
1
2
3
4
5
6
1
B
9
10
11
L2
13
L4
15
t6
L1
1B
19
20
2L
MW are not in compliance with their respective QF agreements and ldaho Power
is taking the appropriate actions as allowed within those agreements.26
Based on a copy of a letter provided to me by the developer, Idaho Power has now
terminated the four projects with l4l MW of capacity, Clark Solar I through 4. I have
provided a copy of this leffer as Exhibit No. 205. This means more than one-fourth of the
capacity of the signed QF contracts due to come on line in2016 have had their contracts
terminated. At this point, the status of the others under contract is uncertain.
The projects that do not have executed contracts appear to be unlikely to ever
obtain a contract or be developed in the near future. Under Idaho Power's Schedule 73, a
developer must only provide basic project information in writing to receive indicative
pricing, and must provide a few additional items, such as proof of site control over the
property underlying the project, in order to obtain a draft contract. In response to Simplot
Production Request No. 4, Idaho Power indicates, of the 48 PURPA projects that
comprise the 885 MW in the queue requesting pricing or contracts, only one of the
proposed projects has provided sufficient information to receive a draft energy sales
agreement and 610/o of the ldaho projects have failed to provide enough information to
receive indicative pricing. Idaho Power has provided no documents supporting an
assertion that most of these projects provided anything more than a simple inquiry
through a telephone call.
In addition, if any of the solar projects failto be on-line before the end of 2016,
the investment tax credits for capital costs will drop from 30o/o to l0%. Thus, there is
26 Iduho Power's Response to ldaho Conservation League/Sierra Club Production Request No. 4.
Reading, Di, Simplot/Clearwater
IPC-E-l 5-01, AVU-E-l 5-0 l, PAC-E-l 5-03
33
a.
A.
1
2
4
5
6
sufficient evidence to doubt that the volume of solar projects claimed by Idaho Power
will actually be producing electricity by the end of 2016, if ever.
ARE THERE OTHER ISSUES FOUND IN ANY OF THE UTILITIES' FILINGS?
Yes. Rocky Mountain Power proposes to change the IRP methodology to better respond
to a large influx of QFs. Rocky Mountain Power stated they are seeking the Commission
to approve,
Modification of the Company's avoided cost methodolog,,such that preparation of
indicative pricingfor QFs re/lects all active QF projects in the pricing queue
ahead of any newly proposed QF requests for indicative pricing.2T
DO YOU AGREE WITH ROCKY MOUNTAIN POWER THAT THE
COMMISSION SHOULD CONSIDER REVISIONS TO THE AVOIDED COST
PRICING METHODOLOGY?
Yes. For the reasons I will explain further below, it would be appropriate to address the
avoided cost pricing methodology if the utilities have truly demonstrated that there is an
oversupply problem. However, unlike Rocky Mountain Power, I believe that adjusting
the pricing methodology to send accurate price signals is the only step that needs to be
taken to rectify any problems with ldaho's implementation of PURPA.
HAVE THERE BEEN SOME OTHER CHANGES IN THE METHOD TO FIND
AVOIDED COST SINCE THE COMMISSION ISSUED ITS ORDER IN GNR-E-
11.03, THE CASE THAT APPROVED THE CURRENT METHOD?
Yes. When Idaho Power filed with the Commission its PURPA contracts with Boise City
Solar (IPC-E-14-20) and Grand View PV Solar Two (IPC-E-14-19) the Commission
27 RoclE Mountain Power's Petition,IPUC Case No. PAC-E-15-03, p. 4.
Reading, Di, Simplot/Clearwater
IPC-E-l 5-01, AVU-E- I 5-01, PAC-E- I 5-03
9
10 a.
11
t2
13 A.
t4
15
L6
l1
20
27
22
18 a.
\9
A.
5q
1
2
3
q
5
6
1
o
9
10
11
15
76
71
1B
1,9
20
27
22
a.
Staff filed Comments stating they were correcting some "errors" caused by the
simplifying assumption in Idaho Power's single-run method approved by the
Commission. Staffthen recalculated the rates offered by ldaho Power for the two
contracts.2S The two projects decided to accept the lower rates based on Staffls
methodological changes that were subsequently corrected by ldaho Power. Rocky
Mountain Power's suggestion to update the resource stack more quickly to respond to
large influxes of QFs may also be appropriate.
IDAHO POWER ASSERTS THAT IT HAS AI\ OVER.SUPPLY PROBLEM
DURING CERTAIN TIMES THAT CAUSES IT TO SELL PURPA POWER ON
THE MARKET AT AI\ ECONOMIC LOSS. DO YOU KNOW OF OTHER
ADJUSTMENTS TO THE AVOIDED COST METHODOLOGY THAT COULD
POTENTIALLY BE EXAMINED?
Idaho Power is describing a situation where the actual avoided costs during certain time
frames may be negative because the Company states it would incur an economic loss by
accepting the QF power. The Commission's Staff Production Request No. l4 asked if
Idaho Power's single-run IRP methodology accounts for such instances by assuming
excess PURPA generation will be sold at a loss, and thus lower the overall average
avoided cost over the term of the contract. The Company responded,
Within the Inuementql Cost IRP Methodologt (IRP methodologt) the hourly
price is assigned based on the highest increment cost displaceable generation
resource operating in that hour. The displaceable resources being ldaho Power-
owned generation, including ony must-run limitations and ldaho Power morket
28 nttC Sta6Comments,IPUC Case No. IPC-E-14 -20, p. 5 (filed Oct. 31,2014).
Reading, Di, Simplot/Clearwater
IPC-E-l 5-0 l, AVU-E-l 5-01, PAC-E-l 5-03
72
13 A.
74
35
7 purchases. If there are no displaceable resources available in a specific hour, the
2 energl rate is set to $0 in that hour. The methodologt does not assume excess
3 PLIRPA generation will be sold at a loss.29
4 Q. HOW DO YOU INTERPRET THE COMPANY'S RESPONSE?
5 A. Idaho Power indicated that the single-run methodology does not address the circumstance
6 where the avoided costs are negative due to uneconomic off-system sales during the over-
7 supply event, and instead assigns an avoided cost of zero when the actual avoided cost is
B negative.
e Q. WHAT WOULD BE THE IMPACT OF CHANGING THE METHODOLOGY SO
10 THAT IT COULD ACCOUNT FOR NEGATIVE AVOIDED COSTS?
11 A. The average avoided cost offered to the QF would incorporate these instances of negative
72 avoided costs, and the instance of negative avoided costs would cause the overall average
13 rate calculated over the term of the agreement to be lower.
1,4 a. WHAT WOULD BE THE REAL-WORLD IMPACT OF A LOWER OVERALL
15 AVOIDED COST ASSOCIATED WITH THE INSTANCES OF NEGATIVE
1,6 AVOIDED COSTS?
71 A. The impact would be that the IRP methodology rates offered to prospective QFs would
18 be lower. That lower price signal would, based on that QF's projected output profile,
79 determine whether the project could be economically developed. In this example, I
20 would expect that a lower avoided cost rate would have the impact of deterring PURPA
27 development.
29 tdut o Power's Response to IPUC Staff s Production Request No. 18.
Reading, Di, SimploVClearwater
IPC-E-l 5-01, AVU-E-l 5-01, PAC-E-l 5-03
36
1Q.
2
IN YOUR OPINION,IS AN ACCURATE PRICE SIGNAL A BETTER WAY TO
ADDRESS THE ALLEGED PURPA PROBLEM IDAHO POWER IDENTIFIED
THAN A SHORTER CONTRACT TERM?
Yes.
DO YOU HAVE ANY OTHER COMMENTS ON THE LIMITATIONS OF THE
CURRENT SINGLE-RUN METHODOLOGY?
The prior double-run methodology would have accurately taken into account the
instances where off-system sales caused the avoided costs to be negative, and in my
opinion would send more accurate price signals.
YOU HAVE JUST DISCUSSED POTENTIAL ADJUSTMENTS THAT HAVE
BEEN MADE OR COULD BE MADE TO THE CALCULATION OF AVOIDED
COSTS. ARE YOU RECOMMENDING ANY OF THESE CHA}IGES BE MADE
AND APPROVED BY THE COMMISSION?
No, not without considering other potential adjustments to send accurate price signals. In
a fully litigated case dealing with avoided cost methodologies, there would no doubt be
changes to the method of calculating avoided costs that would cause resulting increases
and decreases to QF prices offered by the utilities. What I am suggesting is that correct
pricing should be used rather than an arbitrarily short contract length that will, on its own,
discourage PURPA development. If the price is not sufficient to make a project
profitable at the utility's avoided costs, the length of the contract is irrelevant and projects
will not be built. The key is to properly price the avoided costs at the utility's avoided
costs. This is what PURPA was intended to do and will only encourage projects when
they meet a threshold price of the project being economical.
Reading, Di, Simplot/Clearwater
IPC-E-l 5-0 l, AVU-E-l 5-0 l, PAC-E-l 5-03
3
4
5
6
1
B
9
10
t_1
72
13
L4
15
16
t7
1B
L9
20
2T
22
23
A.
a.
A.
a.
A.
1
2
3
4
5
6
1
B
9
10
11
72
13
L4
15
t6
t1
1B
79
20
2t
a.
A.
WHAT ARE YOUR RECOMMENDATIONS FOR THE COMMISSION?
Because limiting the term of contracts to five years or less will essentially eliminate all
types of PURPA projects including those that are environmentally sound, fuel efficient,
and contribute to the economy of the state, I recommend the Commission maintain the
current 2D-year contract length for QFs eligible for the IRP methodology, or at a
minimum for all non-intermittent QFs. If adjustments need to be made to the
Commission's implementation of PURPA, they should be made through the calculation
of avoided cost rates and not arbitrarily limiting the term of the contract to a length that is
intentionally designed to prohibit financing or otherwise ensure that no QF receives
capacity payments.
DOES THIS END YOUR TESTIMONY AS OF APRIL 23,2015?
Yes.
Reading, Di, Simplot/Clearwater
Ipc-E-l 5-0 l, AVU-E-l 5-01, PAC-E-t 5-03
a.
A.
3B
BEFORE TFM
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-E.I5.OI, AVU.E.I5.OI, PAC.E.I5.O3
J.R. SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBITNO.2OI
Don C. Reading
Ptesent positiot y'ice President and Consulting Economist
Educatiot 3.S., Economics; Utah State University
vI.S., Economics; Universiry of Oregon
)h.d., Economics; Utah Sate Uruversity
ron Delta Epsilon, NSF Fellowship
Johnson Associates, Inc.:
989 Vice President
986 Consulting Economist
Pubhc Utihties Commissron:
1 98 1 -86 Economis t/Director of Policy and Adrrunis tration
eaching:
980-81 Associate Professor, University of Hawaii-Hilo
1970-80 Associate and Assistant Professor, Idaho State Universiry
968-70 Assistant Professor, Middle Tennessee Sate University
. Readrng provides expert testimony concerning economic and regulatory issues.
has testified on more than 35 occasions before utiJity regulatory commissions in
California, Colorado, the Distnct of Columbia, Hawaii, Idaho, Nevada,
kota, North Carolina, Oregon, Texas, Utah, Wyoming, and Washington.
Readrng has more than 35 years expedence in the Eeld of economics. He has
icipated in the development of indices reflecting economic tends, GNP growth
, forergn exchange markets, the money supply, stock market levels, and inflati
has analyzed such public policy issues as the minimum wage, federal spending
ion, and import/export balances. Dr. Reading is one of four economists
iding yearly forecasts of statewide personal income to the State of Idaho for
rposes of establishing state personal income tax rates.
n the field of telecommunications, Dr. Reading has provided expert testimony on
issues of marginal cost, price elasticity, and measured service. Dr. Reading prepared
te-specific study of the pnce elasticity of demand for local telephone service in
and recendy conducted research for, and directed the preparation of, a report
ldaho legislanrre regarding the status of telecommunications competition in that
te.
Exhibit No. 201
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/C learwater
Page I
r. Reading's areas of expertise in the field of electric power include demand
asting, long-range planning, price elasticity, marginal and average cost pricing,
-simulation modeling, and econometric modeling. Among his recent
an electric rate design analysis for the Industrial Customers of Idaho Power. Dr
ling is currendy a consulant to the Idaho Legislature:s Committee on Electric
tfuctuflng.
the past three years Dr. Reading has been a consultant to Idaho
n Line (ICON), a virtual charter school, providing data analysis and statis
In addition to building a model that replicated the Idaho's Star Rati
em he completed a study focused on the demographic and socioeconomi
cteristics of the school's population and academic achievements. He is
working with the measurement of ICON's Mission Specific goals
he 201 4-2075 school year.
1999 Dr. Reading has been affiliated with the Climate Impact Group (CIG) at
University of Washington. His work with the CIG has involved an analysis of
impact of Global Warming on the hydo facilities on the Snake fuver. It also
an investigation into water markets in the Northwest and Florida. In
ition he has analyzed the economics of snowmaking for ski area's impacted by
Warming.
Dr. Reading's recent projects are a FERC hydropower relicensing study (for
Skokomish Indian Tribe) and an analysis of Northern States Power's North
kota rate desrgn proposals affecting large industnal customers (for J.R. Simplot
). Dr. Reading has also petformed analysis for the Idaho Governor's O
the impact on the Northwest Power Grid of various plans to increase salmon
the Columbia fuver Basin.
Reading has prepared econometdc forecasts for the Southeast Idaho Council of
nts and the Revenue Projection Committee of the Idaho Sate hgl
has also been a member of several Northwest Power Planning Council Statistical
dvisory Committees and was vice chairman of the Governor's Economic Research
il in Idaho
at Idaho State University, Dr. Reading performed demographic studies using
rt/suwival model and several economic impact studies using input/output
is. He has also provided expert testimony in cases concerning loss of income
ulting from wrongfrrl death, injury, or employment discrimination
, Reading has recendy completed a public interest water rights transfer case. He
also just completed an economic impact analysis of the of the proposed Boulder
Clouds National Monument.
2
Exhibit No. 201
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/C learwater
Page2
ioal ['Energzing [daho", Idaho Issues Online, Boise State University, Fall
.boisestate.edu/tustory/issuesonline/ fa12006 issues/index.htrnl
Economic Impact of the 2001 Salmon Season In Idaho, Idaho Fish
nd Wildhfe Foundation, April2003.
Economic Impact of a Restored Salmon Fishery in Idaho, Idaho Fish
nd Wildhfe Foundation, Apnl, 1999.
Economic Impact of Steelhead Fislung and the Return of Salmon
ishing in Idaho, Idaho Fish and Mldlife Foundation, September, 199 , .
Cost Savings from Nuclear Resources Reform: An Econometnc Model
ith E. Ray Canterbery and Ben Johnson) Soathem EnnomicJoumal,Spn
996.
Visitor Analysis for a Birds of Prey Public Attraction, Peregrine Fund,
, November, 1988.
stigation of a Capitalization Rate for Idaho Hydroelectric Projects,
daho State Tax Commission, June, 1988.
Post-PURPA Views," In Proceedings of the NARUC Bienrual Regula
ference, 1983.
n Input-Output Analysis of the Impact from Proposed Mining in the
hallis Area (with R. Davies). Public Policy Research Center, Idaho State
iversity, February 1980.
and Soathea$: A Sodo Etvnonic Anafiis (with J. Eyre, et al).
Research Institute of Idaho State University and the
theast Idaho Council of Governments, August 1975.
;matingGeneral FundReuenues of the Stan of ldaho (with S Ghazanfar and D
lley). Center for Business and Economic Research, Boise State
ersity, June 1975.
A Note on the Distnbution of Federal Expenditures: An Interstate
rison, 1 933-1 939 aod 7961 -'1965." ln T he Anerican E tvnonitt,
ol. XVIII, No. 2 (Fall '1974),pp.1,25-1,28,
Deal Acuvity and the States, 1933-1939." h Journal of Etvnomic
ittory,Yol. X)O(III, December 1973, pp. 792-810.
Exhibit No. 201
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 3
BEFORE TT{E
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC.E.15.OI, AVU.E.I5.OI, PAC.E.I 5.03
J.R. SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBITNO.2O2
S 292.304 Rates for purchases.,'18 C.F.R. S 292.304
Code of Federal Regulations
Title r8. Conservation of Power and Water Resources
Chapter I. Federal Enerry Regulatory Commission, Department of Enerry
Subchapter K Regulations Under the Public Utility Regulatory Policies Act of ;978
Patt2g2. Regulations Under Sections zor and zro of the Public Utilrty Regulatory PoliciesAct of.rg78
with Regard to Small Power Production and Cogeneration. (Refs &Annos)
Subpart C. Arangements Between Electric Utilities and Quaffing Cogeneration and Small Power
Production Facilities Under Section zro of the Public Utility Regulatory Policies Act of r9Z8 (Refs
&Annos)
r8 C.F.R. $ z9z.3o4
9 z9z.So4 Rates for purchases.
Currentness
(a) Rates for purchases.
( I ) Rates for purchases shall:
(i) Be just and reasonable to the electric consumer of the electric utility and in the public interest; and
(ii) Not discriminate against qualifying cogeneration and small power production facilities.
(2) Nothing in this subpart requires any electric utility to pay more than the avoided costs for purchases.
(b) Relationship to avoided costs.
( I ) For purposes of this paragraph, "new capacity" means any purchase from capacity of a qualifring facility, construction
of which was commenced on or after November 9, 1978.
(2) Subject to paragraph (b)(3) ofthis sectiono a rate for purchases satisfies the requirements ofparagraph (a) ofthis section
ifthe rate equals the avoided costs determined after consideration ofthe factors set forth in paragraph (e) ofthis section
(3) A rate for purchases (other than from new capacity) may be less than the avoided cost ifthe State regulatory authority
(with respect to any electric utility over which it has ratemaking authority) or the nonregulated electric utility determines
that a lower rate is consistent with paragraph (a) of this section, and is sufficient to encourage cogeneration and small
power production.
(4) Rates for purchases from new capacity shall be in accordance with paragraph (bX2) of this section, regardless of
whether the electric utility making such purchases is simultaneously making sales to the qualifuing facility.
Exhibit No. 202
Case Nos. IPC-E-15-01, AVU-E-l 5-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page I
Westla,vNext
S 292.304 Rates for purchases., 18 C.F.R. S 292.304
(5) In the case in which the rates for purchases are based upon estimates ofavoided costs over the specific term ofthe
contract or other legally enforceable obligation, the rates for such purchases do not violate this subpart ifthe rates for such
purchases differ from avoided costs at the time of delivery.
(c) Standard rates for purchases.
( I ) There shall be put into effect (with respect to each electric utility) standard rates for purchases from qualifuing facilities
with a design capacity of 100 kilowatts or less.
(2) There may be put into effect standard rates for purchases from qualifring facilities with a design capacity of more
than 100 kilowatts.
(3) The standard rates for purchases under this paragraph:
(i) Shall be consistent with paragraphs (a) and (e) ofthis section; and
(ii) May differentiate among qualifuing facilities using various technologies on the basis of the supply characteristics of
the different technologies.
(d) Purchases "as available" or pursuant to a legally enforceable obligation. Each qualifuing facility shall have the option either:
(l) To provide energy as the qualifoing facility determines such energy to be available for such purchases, in which case
the rates for such purchases shall be based on the purchasing utility's avoided costs calculated at the time of delivery; or
(2) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery ofenergy or capacity over
a specified term, in which case the rates for such purchases shall, at the option of the qualifuing facility exercised prior
to the beginning of the specified term, be based on either:
(i) The avoided costs calculated at the time of delivery; or
(ii) The avoided costs calculated at the time the obligation is incurred.
(e) Factors affecting rates for purchases. In determining avoided costs, the following factors shall, to the extent practicable,
be taken into account:
(l) The data provided pursuant to 5 292.302(b), (c), or (d), including State review ofany such data;
Exhibit No. 202
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-l 5-03
D. Reading, Simplot/Clearwater
Page 2
!n/estIawNext
S 292.304 Rates for purchases., 18 C.F.R. S 292.304
(2) The availability of capacity or energy from a qualifting facility during the system daily and seasonal peak periods,
including:
(i) The ability of the utility to dispatch the qualifuing facility;
(ii) The expected or demonstrated reliability of the quali$ing 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 qualifring facility can be usefully coordinated with scheduled outages
of the utility's facilities;
(v) The usefulness of energy and capacity supplied from a qualifring 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 qualifuing facilities on the electric utility's system;and
(vii) The smaller capacity increments and the shorter lead times available with additions of capacity from qualifting
facilities; and
(3) The relationship of the availability of energy or capacity from the qualifting facility as derived in paragraph (e)(2) of
this section, to the ability ofthe electric utility to avoid costs, including the deferral ofcapacity additions and the reduction
offossil fuel use; and
(4) The costs or savings resulting from variations in line losses from those that would have existed in the absence of
purchases from a qualifling facility, if the purchasing electric utility generated an equivalent amount of energy itself or
purchased an equivalent amount ofelectric energy or capacity.
(f) Periods during which purchases not required.
(l) Any electric utility which gives notice pursuant to paragraph (f)(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 qualifoing
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 ofenergy itself.
(2) Any electric utility seeking to invoke paragraph (0(l) of this section must notift, in accordance with applicable State
law or regulation, each affected qualifying facility in time for the qualifiing facility to cease the delivery of energy or
capacity to the electric utility.
Exhibit No. 202
Case Nos. [PC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 3
f/esttawNext
S 292.304 Rates for purchases., 18 C.F.R. S 292.304
(3) Any electric utility which fails to comply with the provisions of paragraph (0(2) of this section will be required to
pay the same rate for such purchase ofenergy or capacity as would be required had the period described in paragraph (f)
(l) ofthis section not occurred.
(4) 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 determines necessary or appropriate, either before or after the
occurTence.
SOURCE: 44 FR 65746, Nov. 15, 1979; 45 FR 12234, Feb. 25, 1980; 50 FR 40358, Oct. 3, I 985; 52 FR 5280, Feb. 20, I 987;
52FR28467, July 30, 1987;53 FR 15381, Apil29,1988;53 FR.27002, July 18, 1988;53 FR40724, Oct. 18, 1988;57 FR
21734, llay 22, 19921' 60 FR 4856, lan. 25, I 995, unless otherwise noted.
AUTHOzuTY: l6 U.S.C. 79la-825r,2601-2645;31 U.S.C. 9701;42 U.S.C. 7l0l-7352.; Public Utility Regulatory Policies
Act of 1978, l6 U.S.C. 2601 et seq., Energy Supply and Environmental Coordination Act, l5 U.S.C. 791 et seq. Federal Power
Act, 16 U.S.C. T92 et seq., Department of Energy Organization Act, 42 U.S.C. 7l0l et seq., E.O. 12009, 42 FR 46267.
Notes of Decisions (120)
Current through April 9, 2015; 80 FR 19036
l, rrtl rtl Dttt tt tttt'rtt i rirrri,r I J(1.'L r(r i \t,,t \ 1r,\!,.
Exhibit No. 202
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 4
!n/estlarvNext
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC.E.I5.O1, AVU-E-I5.01, PAC.E.I5.O3
J.R. SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBITNO.2O3
1:2214 Federal Register / Vol. 45, No. 3S / Monilay, February 25, 1980 /.Rules and Regulations
sbuctural failue of the airtame,
accomplbh a compnehensive iospection
of all areas modified byfte Raiebeck
Group, as follorm:
A. Before fiulher Bight, Iaspect for
devlatlons &om the aupplemental type deslgn
in accordatrce with Paragraphr I lhroqghM
and VI, ofFAA approvedRaisbeck Servlce
BulteUn No.25. Inspect for discrepanc.ies ruch
a9:
LPluggedhoter
2. Obloog. eSSshaped, overslzed, or
Imegular holes
8. Tapered holeail. Excesa holes
5. Inadequate edge dlstancee
8. Gougee
7. Imp1nper faeteaers (type and number)
8. lmpruper clearancea
9. Any other lrregularitiea wbich are not
consletent wlth standsrtl ai&mft practice.
B. Before accunuladon ofaooo fllgftthotus
tlme-ln gervlce after modiEcatton by SEC
SA087NW lnapect the horlzontal stabillzer
ond elevator ln accordance wiih Paragraphr
V(A) and V(B) of FAA approveil Raigbeok
Service Bulletin No. 25. Repeat this lo4rection
at lntervale not sysg6,ltng E,(x)ofllght hourr
llme.ln-servlca thereaften
C. Before accumulatioo of aoOo llight hours
aime-ln-eervice alleraodilicalion by SIE
6A087NW or STC SA847NW. inapect ihe
rvtng leading'bd8e tobccordance wltb
Paragraph V(D) of PAA approveil Raisbeck
Servlce Sulletla No. 25. Repeal rhlq lnElecUon
at intervale not 6g6sgdirg 5,(X,O fllgLthourg
tlme.ln.aelvice lf, ereafter.
D. Before accunulation oIto,ooo lligfrt'
houre time-ln aenricd aRm modification by
STCSAOSTNW or STG SAS4TNW,ioepect the
overrvlng modlfi cation io accordame wtth
Paragraph V(Q ofPAA approved Ralsbeck
Servtce Bulletln No. 25. Rapeat tbla lnispeclion
at lnlervale aot sx6ggilng 10.000 llight hours
llme-ln-senlice lhercafter.
E lnapectlona are to be conducted at
factlltlea rpeciltcally a'uttorized bythe Chiel,
Englneertry aoil Mauufacturlng Brancb, FAA
NorthrveetRegion.'F. Dlacrepancier dlscover€d as a result of
the inapecUonr are to be reported to the '
Chief, Engfaeering and Manulacturing
Branch, PAANorthrvest Region Repalr or
modlficationr requlred becauoe of theee
probleme are to 5e FAA appmvdd by tbe .
Chief, Engineerlng aod ltf anufacturing
Branch. FAA, Northweat Region or
epeciflcally aulhorized DERs.
G.Nrplaner uaybe feuied; ln accorilance
rvith FAR 21.199, to a Ealntenance base, for
lhe purpose of complylng with thls AD.
H. fte hepeclione noted herein may be
accompllehed as noteal or in a manner
approved by tlre Chtef, Englneedng and
Manufacturirg BraactL FAA. Northrvesl
Reglon.
L Areaaprevlouelytnapected io -
aocordance rylth Amendment 39-3880'may be
excluded from the impecUons required by
thla AD.
The manufacturet'e specillcations and
procedurea ldentlfieil anil describeil ln this
dtrecllve are tncorporated herein and made a
porl hereof puruant to 5 U.S.C.55z(a)(1).
All peraona allected by thle directive who
have not already rccetved lhese documents.
&om the manufactuer. may obtain coples
upon request lo lhe Rairbeck Gmup, 727
Perimeter Road, Seattle, WrshinSton 9810&, l}ie anendnent becomes ellecuve upon
publtcadori ln tha Federd Regiater and rvas
eEeclive earlier to all recipients of the
tdegraphic AD T80-NW-2 dated lanuary 17.
1980.
(Secs. A3t1), 0m. anil SG, Federal Avlatlon
Act of 195& ar amenilerl (le US.c. 133*(a),
142il, mal lrlzt) and Seclou 8(cJ of the.
Deparhent of Tlaneporta6otr Apt (49 U.S.C
1055(c)); and 14 ctrR 11.89)
Nola-llte PAA bae determloed that lbis
document involves I regulado! which ls not
consldereal to be slgnificant rmder the
provloloor of Brecudve Order lZll4 and as
lmplemeoted by Department of
f hanaportadoa.Regulatory Policle&atrd
hocsdures (t!t FR 11t134: Febmary 24 1979).
lgsued ln Seatue. Waehtngtonn on pebruary
13,1S80.
Note.-Ile incorpontion by ruferenco
provislon3 i! lhe doc{ment were approved by
the Diractor of &e Federal Register on fune
10.1967.
C. B.WaUsfr"
Dinctor, Norlhwost Region.
rSlhc os83oElcd2+2+ aa5 lot
Brll.,rlg OoDE a9rGlt{
OFFICE OFTHE UNITED STATES
TBADE BEPRESEiITATIVE
15 CFB Chapter XX
CFR Ghapter Heading and
Nomenclalure Change
&bnrary19,1980.
AGENSY: OfEce of the United States
Trade Representative,
AcnogFinalrule.
SuilMABy: lhis rule changes Chapter )O(
ofTitle 15, Gode of Federal Regulations,
fron "OEcE of the Special
Representative for Trade Negotiations"
to "Of{ice of the United States Trade
Representativs" Within the body of the
Ghapter )OL all refereaces to the "Olfice
of the Special Representative for Trade
Negotiadons", to lhe "Special
Represeutadve for Trade Negoliadons",
and to the t'Special Repregentatve" or
"Deputy Specid Repreeentative" are
6fienged to lte "O[Ece of the United
Stateg Trade Representdtive", to "the
United Stateg Trade RepreseDtallve",
and the'Trade Representallve" or'
"Deputy Trade Representative"
respec'tivelp these changes are
authorized ae part of Reorganizslisl
Plan No. 3 of1979 (44 ER 69273) rvhich
was inplemeuted by Executive Order
No. 11188 of lanuary 2, 1S80 (45 fR 989).
EFFEGIVE DA?E: Febnrary 25,1980.
FOR FUETIIER TNFORiIATION COTTACT:
Alice Zalik General Council's Oflice,
Office of the United States Trade
Representatlve, 18{D G Sheel, NW,,
lllashlnglon, D.C. 20500. [phone].
Accordingly' each refErence lo "lho
OIfice of lh-e Speclal Representallvo for
Trade Negotlaiiona" conlslnsd wlthln
Chapter )O( of Tttle 15 of the Code of
Federal Regulatlona, lncludlng lho
heading, ie changed to "lhe Ofllcs of the
United Statea Trade Reprcsentotlvo".
' Each reference to "lhe Speclal
Representative lor Trade Negollo llons"
containsd lvlthln the chapter ls changod
to "the Unlted States Trhde
Representative". Each referenco to lho
"special Representodve" and to lho
'I)eput5l Special Representallve" ls
sfinn8ed to the 'Trade Reprsgentallvo"
and to the "Deputy Trade
Representativel reepecllvety.
Robort G Cassldy,
Ceneml Counsol,
FR Doc &go0g PUcd Z-e!-04 eas ut
aulilo coDE Stto-o|-I
DEPARTMENTOF ENERGY
Federal Energy Begulatory
Commlsslon
18 CFB Part2g2
IDockGt No. BM70-55, Ordcr No.69)
Small Power Productlon and
Cogenerallon Facllltlet; Regulatlona
lmplementlng Ssctlon 210 ot tho Publlo
Utlllty Regulatory Pollclca.Act of 1970
ncexcv: Federal Eneryy Rcgulatory
Commlssion.
AcrtouFinal mle.
smmlAnn The Federal Enorgy
Regulatory Cornnisslon heroby adopte
regulations that tnplement seotlon 210
of the Public Uttlity Regulatory Pollcloe
Act of 1978 (Pt RPA). The rulee requlro
electric utllities to purchaso eleclrlc
power from and aell electrlc porvet lo
qualifying coSenerallon ond omallporvor
production fecllltiea, and provldo for tho
e-xemption of qualifyfu facllitlos from
iertain fedenl and State regutotlon,
lnplementation of lhese rules ls
reserved to State regulatory authorltieu
anrl nonregulated eloctric utilltieu.
EFrECf,tyE DAT4 March 20, 1080.
FOR FURTHER IIIFORHATIOil GONTACT:
Roes AtL Offico ofths Genoral Couneol,
Federal Energy Regulatory Commlgslon
825 North Capitol Slrool, N.E., Warbtnglon,
D.C. 20428. 202-3 87-8,,16,
Jobn O'Sulllvon, OIIice of tho Gencral
Counsel, Fedetal EnerBl Regulolory
Commlsslon.82S North Copttol Slrool. N,E..
Wa shins ton. D. C 20f,28. 20245, -Ml 7.
Adam Wennen OfIIce of lho Gonoral
Counsol Federol Enorgy Rogululory
Commlssion, S2S North Ctpttol Slrool, N,ll,,
Wa ehington, D .C z0AZe, 202457 4031,
Exhibit No. 203
Case Nos. IPC-E- I 5-01 , AVU-E- I 5-01 , PAC-E- 15-03
D. Reading, Simplot/Clearwater
Heinonline - 45 Fed. Reg. 122 l4 1980 Page I
\
1g3224 Federal Reglster I Vol.45, No. 38 / Monday, February 25, 1980 / Rulee and Regulatione
Many comnenters at the
Commigsion'a public hearings and in
unitten comments recommended that
the Gommission ehould reguhe the
establiehnent of "net energy blllingl! for
emall qualifuing facilitiee. Untler this
bllling method, the outputftom a -
qualifying facility reveraes the elechic
meter usedl to measur.e ssles from tte
electric utility to the qualifying facility.lhe Commieeion believes that this
bllling method may be an apprupriate
way of appmximatinghvoided cost in
some circumstances, but does not
believe that this ie the onlypracdcal or
approprlate method to establieh rates
for small qualifying facllitles. the
Commlealon obsenres that net energy
billing is likely to be appropriate when
the retail rates are marginal coet-base4
time-of-day ratee, Accordingly, the
Comnission will leave to tte State
regulatory authoritiee and the
nonregulated elechic utilidee the
detennination ag to whether to institute
net energy billing.
Paragraph (cl(s)(i) provirles that
atandard ratea for puchase eLoulil take
lnto account the factors setfofih in
paragraph (e). Ihese factorr relate to tte
quality of powerhomthe qualifying
facility. and its abilit5r to fit bto the
purchasing utilityla generating min
Paragraph [e](vt) ig ofparticular
eigrilicanca for facilitiee of 100kW or
less. This paragraph providea that rates
for purchase shall take into acoormt "the
individual and aggregate value ofenergy
and capacity from qualifying facilitieg
on the electrlc udlitfa Byetem. . .".
Several commenters preeenteil
persuaeive evidence showing that an
effeotive amount of capacity may be
provlded by diaperaed emall ayeteus,
even in the caae where delivery of
energy from any pardcular facility te
otochaetic. Similarly, qualifying faciliEes
may be able to enterinto operating
agxeementa with each otherUywhich
they are able to increaee the aeaureil
availability of capacity to the utility py
"oo.dfustin8 scheduled maintenance
and providiag mutud back-up aenrica
To the extent that this nggregate
capacity value canbe reasonably
estimated it muat be rellected in
etandard rates for purchaees.
Several conmenlers obeened that the
pattems of availability of partictlar '-
energy Eources caa and ehould be
reflected in staudard ratee. An example
of this phenomenon is the availability of
wind and photovoltaic energ:y on a
aummer peaking system. If it can be
ahown that ayetem peak occurp when
there ls bright sun and no wind, rateg for
purchase could provide a higher
capaoity.payment for photovoltaic cells
than for wind eriergl conversion
systems. For eystems peaHng on dark
windy days, the reverse miSht be hue.
Subparagraph (3)[ii) thus provides that
atandard rates lor pruchases may
diffErentiate amorry quallfyiug facilities
on the basia of the eupply
characterigtics of the particular
techlology.
t9292.?04 (b)(51anil (d) l*goily
enforceable obllgati ons.
Paragrdphs (bl(Sl and (d) are intended
to reconclle the requirement that the
ratea for purchasea egud the utilities'
avoided coet with the needfor
qualifying fasilldes to bs able to enler
into contrectual comlnihqntB based, by
necesaity, sasstimslss of futrue avoided
costs. Some of the commeatg received
regardiqg thie section etated thal if lhe
avoided coet of energr at the rime it le
aupplied is less thaa theprlce provided
in the conhact or obligation, the
purchasing ufity would be requlred to
pay a mte for purchaaes &at would
subsidize the qualifyingfacility at the
e:rpenae of the utility's other ratepayeralte Commission recoggizee thie
possibility, butis coguizant thatin other
casea, the reqgired rate wlll tura outlo
be lower thar&e avoided oost at thEti-e of purchase. the Qqrntnlsslsa dgsg
not believe that the reference in thr
statute to the incremental cost of
alternative enelgy wao intended to
require a minute-by-mluute evaluaton
of costs which would be checked
against rates established in long tenn
coDhacts between qudifuiug facilidee
and elechic'utilities.
Many coumentere have ebessed lhe
need for certainty with regerd to retum
on inveshent in uew technologies. lIe
Comnieaion agreee with these latter
argummts, and believes that, in the long
ru!, "overegdnationg" and
"undereaUmadors" of avoided costs
will balance out.
Paragraph (bJ[S) adtheeses the
gituation inwhich a qualifying facility
hae enteredinto a conhact.wi(h an
elecbic utllitJr, or wherethe qualifying
facility haa agreed to obligate itself to
deliverat a futrue date energy and
capacity to the elecbic utillty. Ite
tmport of this section is to ensure that a
qualifuing facility which has obtained
the certainty of an arrangement ie not
deprived of &e benefrts of its
commilmspl as a result of Changed
circumstances. lbis provision can also
rvork to presenre the bargain entered
into by the electric utility; should the
actualavolded cost be highep than those
- conbact6d fon the elechic ufility is
nevertheleeg enti0ed to retain the
bepifrt ofits contracted for, or
otherwise legally enforreable, Iolver
price for puchaaee from the qualltylng
faciUty. Ihia eubparagraph wlll lhuo
ensure the certalnty ofralea for
puchasee from a quallfylng faclllty
which entere Into a commltmontto
deliver eneryy or capaclty to a utlllty.
Para$apli[d)(1) provldee lhat a
qualifyiru facillty may provide eneryy or
clpacity on an "a's avallabls" bools, 1.0,,
withouf legal obligatlon. Ihe proposod
nrle provided that rates for such
ourchasee ehould be baged on "actuol"ivoided cogts. Many cornrnents notod
that tasinS ratea for purchasea tn auch
ca8e8 on tf,e utlllty'a-'actual avoldod
co8te" Ia mleleadfu and could requlro
rehoactive ratemalilng.In llShi of theso
connenls, the Commlselon haa revlsed
lhe rule to provide lhat the rateg for
purchasee are to be based on the
pruohasLtg utllit/e avolded cootr
igUmated at the tlme of dellvery.r'
Paragraph [d)[2) permttr a quallfylng
facility to enter lnto a conlmot or olhor
legally enforceable obligatloh to provldo
energy or capacity over a epeclfled lsrm.
Uae of lhe term "legally enforceabls
obligation" ie lntanded to prevent a
utility hom clrcumventlng ttre
requlrement that provldea capaclty
cedit for an elteible qualifyktg foclllty
merely b5rrefualng lo enter lnto a
conhact with the qualifying faclllty.
Many comnrentera noted lhe sume
problems for eotabliehing ratec for
purchaaer under eubparagroph (21 ao ln
aubparagraph (1). The Comnleslon
intenrla fhat ratea for purchaees be
based, at the option of the quallfying
facility, on ei&er the avoldsd cosls ut
the ttne of deliveq, or the avolded costs
calsulated at the time the obllgatlon le
incurred. lhla chance enables u
qualifytru fadlity td'establish o flxod
ctnhactprice for ita energy and
capacity at the outeet of lla obllgallon or
to receive thE avolded costo determlned
at the tlme of delivery.
Afactltty whlch enters lnto a long
tern conhact to provide enerSy or
capacity to a utility rray wieh to rocolvo
a greaterpercentage oftho totol
purchaee prlce durlng Ge beglnnlng of
the obligation. For example, q level
palmrent schedule from the utillty to lho
qualifuing facility may bE used to match
more cloCely the gchedule of debt
senrice of the facllity. So long aa tho
total payment over the duration o[ tho
conlract term doeg not exceed the
esttutrated avolded costs, nothlng ln
lhese nrles would prohlbit a State
regulatory authority or non-regulated
electric utility from approving such on
artangemenl.
t.ta addltlon to tlre ovoldod coclr ofonoryy. thuso
coslr nuet Include the prorated ohom o[ tho
aggregate capaclty value of such lscllllles.
Exhibit No. 203
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
HeinOnline -- 45 Fed. Reg. 12224 l98O Page 2
{
Federal Register / Vol. 45, No. 38 / Monday, February 25, 1g8O / Rules qnd tqgrlqlrotg___!ryS
5 mZ.oo4c| Fac&irc offecting mtcs furpurchoses.
CopacityValue
Au issue baslc to this paragraph is lhe
question ofrtcognition of the capaciU
value of qualifying ficilitiee.
In the proposed rule, the Commisgion
adopted the argumeut set forlh in the
Sta$Discussion Paper that ihe proper
interpretation of section 210(b) o[
RIRPA requiree that the rates for
pruchases indude recognition of the
capacity vdue provided by qualifying
cogeueration and small power
production facilities. Tte Commission
noted that language used in section 210
ofP[JRPA and the Conference Report as
well as in the FederalPowerAct
supports this proposidon
Io ihe proposed nrle, the Commission
cited the fiaalparagraph ofthe
Couhrence Report with regard to
sectior210ofPt RP,{:
ltecooferees e:cpect that the Commisriou
in indging whether the dec{ric porcr
supphod by the oogenerator or small porwr
producer will replaoe firtuc power rhic;h the
utility would otherwtse hsve to gercmte
itself either &rorrgh odstiqt cspacity or
adilitionr !o capacigr or purrhasc from oiber
rotces, will trke into account lhe rcliability
of the porver suppliedby the oogcnentor or
saall power producer by rcaroa of ray
lqelly eoforoeable obligatim of ructr
cogeneralor or small power prcduo to
supply Ero power to lhe utility.tr
In addition to that citation, the
Qsmmiqgiss nstes that the C;onference
Repmt states that:
In iaterpnelirU the term "incranentd odr
of dternedve enerd'. the confcreel cxpect
$at the Commirsioa and lbe Stater rnry lool
beyond thc coals ofdteraative sourcee whlch
are instartaoeously available to lLe utility.rc
Several commenters conleoded that.
since section2l0[a][2) of PURPA
provides that elechic utilities musl
'purchase elechic eoergr" from
qualifying facilitieo, the rate forsuch
pruchaser should not include paSments
for capacitSt lte Gommission obrerves
that the statutory language uaed in lhe
Federal Power Act uses ihe tenn
"electric energr" to describe 'Le rates
lor sales for resale in interstate
commerce Demand or capacit5r
palmeuts are a baditional part of such
rates.Ite terur "elechic eneXry" is uged
l5pnghout ihe Act to refer both to
elecbic energr and capacigr. The
Commigsion does not fin{any evidence
that the tenn "electric eneigy" in section
210 of PURPA was intended to refer only
to fuel qnd operating anil maintenance
expenies. inrtead ofall of lhe costs
associated with the pmrision of electric
sen'ice.
In addition" lhe Commission noles
that to interpret thir phrare to include
only energlr would lead to lhe
conclusion that lhe rales for ralea lo
qualtfying facilitieg could only include
the energl compotrent of the rate since
section 9lo alro refen to "eleclric
energ5r" with regrrd lo ruch raler. Il is
.the Gomnisrionl bellef that lhir war
not the intended rerulL Ilb pmvider an
additional reaeon to ialerprct the phrare
"elechic encrgy" lo includo both eneqy
and capacity.
In imphmenting lhia ctatutory
standard. it ir helpful lo review induslry
practice respecting oaler between
utlitiee. Saler of eleclric power arc
ordinarily clasrilied er either firu rdee.
where ihe rcller provider power al the
customer's rcqucrL ornon-fitan power
salcr. whero the reller and not lhe bu1'er
maker the decirion whcther ornot
power ir to be availeble. Retea for lirrr
poruer purcharer includc paymentr lor
the cost of fuel aud opereling expentea
andalro fior lha Bxed cortr arrocieted
with the oonrtruclion of generating unils
needed to provide power at lhe
pure.hecerL dircrction The degree of
certainty of dcliverabillly required lo
constitute "Iiro power" can ordinrrily
be obtaincd only if a utillty har reveral
generating unitr aad adequsle relen'e
capacity. Itrc oprcity paymenL or
demaod cbarge, will reflect the cort of
the utility'r gcsq2ting unit!.
In conharl the ability to provide
eleclric powar.l &g 3gllinS utilityt
diacretiou inporer no rcguirement that
the reller conrtrucl or reserue capecily.
In order !o povide power to cutloner
at the reller'r dircrellon the aeUlng
utility necd only cbargc for the cott of
operating itr geoerating unitr and
adminisEqlioo. ft est corlr, called
"enexg/" @ttr, ordinarily art the ones
arsociaied withnou-trm ralea of pon'er.
Purc;harer of power fmm qualifyinS
facilitieo will fall romewbcrc on ths
continuum between there two tlper of
elecbic rrvice.ltur, for cxample, wind
machiner that furuieh power only wben
wind velocity exceedc twelse rniler per
horu may be ro uncerlain in availability
of output that they would only permit e
uUlity to evoid generaUng an eguivalent
amount of eneryy.In lhat ritualiou the
utilily murt cuntinue to pmuide capacily
that is available lo meet the needr of itr
customera. Sincr lhere arc no avoided
capacity cortg. rater for such spondic
purchases should thus be based on lhe
utility eyttem s auolded incremental
cmt of energy. On the other hand.
testimony al the Commisrion'r public
hearings indicated that elfective
emounE of lirn capaci$r exist for
dispersed wind r1'r1ems, even lhough
each machine, considered sePamtely,
could not provide cepacity valua The
uggregate capacit5l value ofsuch
facilities must be coruidered in lhe
calculation of ratas forputhaset, and
thc paluent distrtbuted lo lhe dass
providtU the capacitlr.
Some teclnolqgieg such ss
photovoltric cdh dihougb eubiect to
aomo uncertainty in power outpuL hate
lheSenenl edvaotqge of providiqg their
maximun power coincident rt'ltL the
eyrlem pcakwbeu used on a gumner
pcaking syrtem. Thc value of suc,h
power ir greater to lbe utility thaa
powcr delivcred druing oE-peak periods.
Since lhc need for capacity lr based, in
parl m ryrlom peakr,the gualifying
facilityl cdmideu with the system
peak should be rellected in &e
olloweoca of come capacity value and
sn cncrgf ooEponcot thatrellccts the
avolded ener67 coatl at thc tine of lhe
pealc
A facility buraiqg municipalwaste or
biomars mry be aHe to operate Elore
prealict.bly .Dd reliably than colar or
wind ryrlenr.Il ern rchedule its
outager duing tiDes when deuand on
0rc utility r rysten ie low.If such a unit
demonclrelea e degree of reliability thal
would pcrarit the utility to defer or avoid
coDtttuction of e gencnti'tg unit or the
purchare of frro powerhom alo&er
utility. lhtrn tba rate fot ruch a puchase
should bc brrcd ou thc avoidanca of
bolh euergr ud cepaci[rcoctc
In ordei to dcfer or canccl the
conslruction of new Senerat;nt ruits, a
ulility murt obtrin a coomihentfrom a
qualifying facility that pmYidcs
conlraclual or othcr legdly enfom€able
agsuraucar lhet capacity hom
altemelive aourcea will be arailable
sulficienily ehcrd of lhe date onwhich
thc utility would othcrwise have to
commit ilrelf to thc conshrtion on
purchase of new capaci$.If a quali&irg
facility providar ruch assurarces, it is
entitled to receire rates based on ihe
capacity cocts tbat the utili$t c'n avoid
as a result ofltr obtaining capacigrtorr
the qualifyiug facility.
Olher commeub wilh regard to tbe
requlrement lo include capacity
palzreutr in aroidad costs generally
track tholc rct forth in the StaS
Discuesioa Faper aad &e poposed nrle.
The thnrrt of there comroenls is lhal io
order to rrceivc credit for capacity and
to comply with fhe requirement lhat
rates forpurchases not excaed the
lncmmenlrl cmt of alteraative eoergy,
capacity payoentr can only be required
when &c eveilabiligr of capacigr from a
qualifying facility or facilities ac'tudly
permils lhe purchesing utility to reduce
Exhibit No. 203
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
rsConlerencc Report on H.R. {or& Puulic Ulitil}
Rejulatory Policiee Act ofrn H. R?p. !io, 178(t s9.
91h C6& 2.136& (1s7a}EId- pp.E{
HeinOnline - 45 Fed. Reg. 12225 1980 Page 3
t2228 Federal Begister / Yol. 45, No. 38 / Monday, February 25, 1980 / Rules and Regulationi
Its need to provide capacity by deferring
the conetrdction ofnew plant or
commitmente to lirm power purchase
contracte. In the proposedrule, the
Commlsalon stated thet tf a qualifying
facllity offers energy of aufficient
reliability and with sufficient legally
enforceable guaranteeo of deliverability
to permit the purrchaeing electric utility
to avold the need to conelruct a
generating plant, to'enable it to build a
smallen leee expenaive plant, or to .
purchaoe lesg firm porver hom another
utility'than it would otherwiee have
purchaaed, lhen the rates for purchas.es
from the qualifuing facility must include '
lhe avolded capacity and energy coste.
Ae indlcated by the preceding ,
diecusgion, the Comsriseion continues to
belleve that lheae principles are valid
and appropriate, and lhat they properly
fulfill the mandate of the atatute. '
The Commission dso continueg to
belleve, as stated in the proposed rule,
that this rulemaking represents an ellort
lo evolve concepts i4 a newly
developlng area within certaln statutory
constraints. The Comrnission recognizes
that the hanilation of the princlple of
avoided capacity coats from theory into
practice ie an exbemoly difficult
exercige, and is one which, by
deflnltion, le based on estlmatlon and
forecaeting of future occurrences.
Accordingly. the Commission supportg
lhe recommendation made in tha Staff
Dlscussion Paperthat it ehould leave to
the Statee and nonregulated utilitiee
"flexlblllty for experimentation and
accorrmodation of epecial
circumslances" with regard to
lmplementation of rates for purchasea.
Therefore, to the extent that a method of
calculating the value of capacity from
quallfylng facilitles reasonhbly accounte
for the utilit/s avoided coatg, and does
not fail to provide the required
encouragement of cogeni:ratiop and
amall power production, it will be
considered ae satisfactorily
lmplementing the Commisalon's rules.
8 202,80ak) Factors affecting mtes forpurchoses.
Ae noted.previously. several
oommenterg observed that the utility
eyetem coet data required under
g 2S2.3OZ cannot be direc0y applied to
ratee for purchaee. The Commisgion
acknowledges this point and, as
diecugsed previously, hae provided that
these data arc lo be ueed as a starting
polnt for the calculation of an
appropriate rate for purchases equal to
the utility'e avoided cost. Accordingly,
the Gommission has removed the
reference to the utility Bystem cost datq
from the delinition of rates for'
purchsses, and has inserted lhe
reference to these data in paragraph (e),
as one fabtor to be oonsidered in -
calculatfu rates for purchases.
Subparagraph (1) states that these data
shall, to the extent practicable, be taken
into account in the calculation of a rate
for purchaees
Subparagraph (2) deals rvith the
availability of capacity from a qualifying
facility durlng eystem daily and
seasonal peak periods. If a qualifying
facility can proviile energy to a utility
drutrg peak periods when the electric
uUlity iB mnning its most expensive
generating unite, ihis energy has a
higher value to the utility than energy
supplied during off-peak periods, durlng
which only units rvilh lower running
coste are operatiug.
The preamble to thg proposed rule
provided that, to the extent that
metering equipment is available, the
State regulatory euthorigr or
nonregulated electric utility ehould take
iuto account the time or season in whicb
the purchase from the quallfulng facility
occurs. Several comnenters interpreted
this etatement as implying that, by
refusing to install metering equiirment,
an elechic utility could avoid the
obligation to consider the time at which
purchasee occru. thig le not the intent of
thie provlslon. Clearly, Oe more
precisely the tirne'of purchase is
recorded the more exact the calculation
ofthe avoidid codts, and thus the rate
for purchaees, can be. Rather than'specifuing that exact tine-of-day or
seaeonal rates for purchaees are
required, howeveri the Comnisslon
believes that the aelection of a
methodology is best left to the State
regulatory authorities and nonregulateil
electric utilidee charged with the
hnplementation of lhese provisions.
Clausea{i} tb"oqh [v) concera
varioua aspects of the reliability of a
qualilying facility. When an electricutility provides power from its'own
generating uhits or ftom those of another
ilectric udlity, it normally controlslhe
producdon of such power from a cenhal
location. Ite ability to so control power
produotion enhances a'utility'a ability to
respond.to changes in demand, and
thereby enhancea the value of that
power to.the u$lity. .{ qualifying,facility
may be able to enler into an
arangement with the utility which gives
Oe utility the advantage of dispatching
the facility. By so doing, it increases its
value to the utility. Conver.sely. if a
utility cannot diepatch a qualifuing
facility, that facility may be of less value
to the utility.
Clause (ii) refere to the expected or
demonstrated reliability of a qualifying
facility. A utility cannot avoid the
conshrction or purchase of capacity if it
ia likely lhat lhe quallfylng foclllly
whlch would claim to replace euch
capaclty may go out of servlco durlng
the period when lhe utlllty needs lte
power lo meet eyslem domand. Bosod
on the estimated or demonetrated
reltablllty of a quallfylng faclllty, tho
rate for purchsses from I quollfylng
faotlity should be adjueted to ruflect ltu
value to the utillty.
Glauee (iii) refere to the length of tlmo
durfu which the qualifylng faclllly hoo
contractualty or othetwise guarantood
that it wlll eupply energy or capaclty lo
the electdc utlllty. A utlllty-owned
Seneratlng unlt normally wlll aupply
power for the life of the plant, or untll lt
ie replaceil by more efliolent copoclty. ln
contrast, a -cogeneratlon or small porvor
prcduction unit mtght ceaee to produoo
power as a result of changes ln the
industry or ln the lndustrlal procogoo8
utilized. Accordingly. the valuo o[ tho
seMce from the qualtfylng facllily to tho
electric utlllty may be affeoted by tho
degree to whlch the qualifylng faolllty
ensures by contract or other tegally
enforceable obligatlon that lt 1vlll
continue to provide powor;lnfiudod ln
thls deteminaUon, among olher factorg,
are the term of lhe oomslltment, lho
requlrement for notlce prlor to
terminatlon of the commltment, and ony
penalty provisiona for broach of the
obligatlon.
In order lo provlde capaclty voluo lo
an electrio utility a quallfylng fuclllty
need not necessarily agree to provldo
power for the life of the planl. A utlllty'e
Seneratlon expansion plans oftsn
lnclude purchasee ofllrm porver from
other utilitlea in yeare lmmedlately
precedlng the addttion of a major
generatlon unlt If a qualifylng faclllty
contracts to deliver power, for exomplo,
for a one year perlod, it may enoble tho
purchaslng utillty to avold enterlng lnto'a bulk power purchaae arrangemonl
with another utility. The rate for auch a
purchase should thug be based on tho
price at whlch such power le purchoeod,
or can be expecterl to be purchosod,
based upon bona fide offsra from '
another utilily.
Clause (iv) addresses psrlods dulng
whlch a qualifylng factllty lg unublo lo
provide power. Electrlc utlllflos schodulo
maintenance outages for thelr olvn
generatlng unite durlng perlode whon
demand ts low.If a quallfylng foolllty
can slmllarily achedule lts malnteflunco
outagep durlng periods of low demand,
or durihg periods in whlc.h a utlllty'eom capacity will be adequate to hondlo
existing demand, lt wlll enable ths
utillty to avoid the expensss oesoclutod
with providing an egulvalent omount of
Exhibit No. 203
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
HeinOnline - 45 Fed. Reg. 12226 1980 Page 4
Federal Register I Vol. 45, No. 3& / Monday. February ?5, 78{cf) / Rules end Rcgulations 722tt
capacity. These saviags should bc
rellected in lhe rate for purchases.
Clause [v) referr to a quali$ing
facility's ability and willingness to
proride capacity aud energy druing
system eneryeadea. Sectios?4l1s.trl ol
these regulatioEs coucems the prurrisioa
of elecbic gervice during rystem
emergeucies. It provides thaL to the
extent rh,t a qualifying facility is wiling
to forego ib orrn use of energr during
s1'ateu emergeucles and provide power
to a utilit5r'a system. the rate for
purchases hom the qualifuing fadlity
should rellect the value of that service-
Small power pmduction and
cogeueratiou facilities could provide
significant back-up capabilip to elechic
syttens during euergeucies. One
benefit of the encouragement of
inlercoanected cogeneration and small
powerproduction may be lo increarc
overall system reliability during such
emergeocy conditions. Aoy such benefit
sbouldbe reflected in the rate for
purchases from suc;h qualifying
faciliHes.
Amther related factor which aEects
the capacityvalue of a Eralifriqgfacility ic itc ability to separate itc load
from its generation during cystem
emetgencies. Druiqg suc.h emergencies
an elecbic utilig may inetitute load
shed.ting procerlures which may. aruong
olher thiqgs. require that indusbial
anstomers or other large loada stop
receivingpower. As a Esult, to pmvide
optimal benefrt to a utility in aa
emeqgmcy situation a qualifying facili$,
might be rcqutued to coutinue opemdon
ae a generatingplaaL while
simultaneously ceasing operation as a
load on the utility's syslem. To the
extent that a facility is unable to
separate its load from its generation, its
value to the purthasing utilitgr decreases
during system emergencies. To rellecl
suc,h a possibilit5r, clause (v) provides
that the purchasiqg utility may consider
the qualifying facility's ability to
separate its loail from its generation
during syeteu emergencies in
determining lhe value of the qualifying
facility to the elechic utility.
Cl"use (vi) refere to the aggregate
capability of capacitjr from qualifying
facilitiee to displace planned utility
capacity. In some instances, lhe rmall
amounts of capacigr provided from
qualifyiag facilities taken individudly
might not enable a purrhaslug utility to
defer or avoid scheduled capacity
additions. Ite aggrcgate capability of
such purchaues man however, be
sufEcient to permit the deferral or
avoidance ofa capacity addition.
[\,toreoyer, while an individual qualifying
lacility may uotpnovide the equivalent
of firm power to lhe elechic uUlil!', the
divereity of thele facllitier may'collectirrcly muprire the equiualent of
capacit3l.
Clarue (vli) refen to the fact that the
Iead ':-e auocieled with tha addition
of capacig from qualifyiag facillties
may be lesr thrn thc lcad lime that
would heYe been requlred if the
pruchaslng utility had constructed itr
own gencmting unit Suchrtduccd lead
time migbt producc raviogr in ihe
utility'r tohl powcrpmduction cotts, by
permittirU utilitier to avoid lhe
'{nmpinel3r" ltrd tenporaryr excesr
capaclty eroclaled lherewlth, which
norndly occur wben utililies bring oa
line large generatirg unit!. In addiiion.
reduced lerd timc provider the ulility
with greeterllexibilily with wblclr lt can
accommodats cheagei ln forecaslr of
peak deuend.
Subparegraph (31 concems lhe
relatioushlp of energr or capaclty from e
quaUfying facility lo the purcbaring
electric utility'r aeed for ruch cnergl or
capacity. If en electrlc utilily bar
snfficient caprcity to neet itr demand.
and ir notplanni4g to add any ncw
capacltlr !o itr ryrten lben lhe
availability of capaclg &oro Sualifyin3
facilitiea will not immediately cnable -
&e utility !o avoid any capacity cortr.
Howcver. an electsic ulili$ eyrlem witb
excess capacit5r nay neverlheless plan
to add new, more efEcient capactty lo
its systen lf purcharea Eom qualifying
facilitier eneble a utility lo defer or
avoid lher new planned capacity
additiona lhc rate for ruch purc.baret
shoulil rellecl the avoideil corlr ofthese
adilitionr Howet'er. a8 loterl by reveral
clmmenlcr!. tbe rleferral or avoirlance
of such r unit wi[ dlo prcvent lhe
substitulion of lbe tower energt coltt
tbat wouldhave accompanied the new
capaclty. Al a rerull the price for lhe
pulchase ofeneryy rnd capaclty rhould
rellect thcre lowcr avoided ctrergy costs
that the utility wonld havc incurred had
the new cepecitybaeu added.
Tbic ir uot to ray that electric utilities
which have excerr capacity need uol
make purcharer hom qualifying
facilitier; qualifying facilitier may obtainpalment bared on the avoided eneryy
cotts on a purthasiag utilil/r tyrleu.
Irlany ufityryrtemr wltb excest
capacity have interoeillala or peaking
unitr whlch ure higb+ost fossl-l fuel fu
a result druing peakboura tho encrgy
ciosts oE the ryrleme are high. ond tf,us
the rate to a qualifying utility from
which the eleclric utiligr purchores
energy should similarly be high.
Subparegraph (4) addresses the costs
or savingr resulting from line losser. An
appropriate rate for pue.hases from aqualifi'ing facility should rellect tbc cost
rasingr ectually eccuing to the electric
utility. If enargyproduced iom a
quolfgqg frcility underyoes line losses
auch thet lba dclivarcd powcr is not
eguivdcnt to tbe pwer lhal would bare
been dalivgred Aoo &e source of power
it replacce theu tbe qudifyiug facility
should not bc reimburaed for lhe
dilference ia locses. If ihe load senred
by the qualifyitrg facility ir doser to &e
qualifyiry frcilig lhan it is lo the utility.
it ls poriblc that ihcre may be net
eavingr rarulting Aom reduced line
lorrcr. Io rucb carer. the rales should be
, M.wfi kriods daring v''hich
purthose an not tquind.
lhe proporeil nrle provided that aa
elechic utilily will not be required to
purcherc aatrgr and capacity ftom
qualifying fecilitiar druiog perioda in
whlch rrrch pur&arcg wi[ t€sult iEnet
Iacreased opc5x".g costr to the dectric
utility. Ttrir rection wac hterded to ded
61fi i cslrln conditioawhis,h can
occur during lighl 1s6.l;ng periods. Ifa
ulility opcnting only bare load units
during lbcra periodr were forced to sut
back oulpulfrom lhe ruitr in orderto
acco-rnodatc purcharer ioo qu8lryilg
facililleerbere barc load urits Eigbt
not be rbla to laqeare their outpui level
rapldly when the rystem demand later
incrcared. Ar r resulL the utilitlr would
be raquired lo utiliza lers eEdent
higher coat unitr with fasterctart-up to
meet the &Esd thatwouldhavebeen
aupplied by thE lest ocpensil'e base load
unit had lt been permitted to operate at
a constanl outpuL
The renrlt of ruc.h e bansaction would
be lbatntber than avoirtirg costs as a
rtsult of lhc purc,hase homi quali$ing
facililt'. the pruc,hasiog electric utility
would incurSreater costs tban it would
have hed It not purchased energy ot
capacity from the qualifying faciliS'. e
strict application oftbe auo-ided cost
principle ret forth in lhis section would
arscrr lbere edditioud costs as
negatlve rvoided costr which uust be
relmbursed by the qualifrfu facilitr In
ordet to rvoid the anomalous result of
foming a qualifying utility to pay ar
electric ulility forpurchasiug its oulpuL
the Comniesioopropored that an
electric utility be rcquired to identi&pcriuh dudng which this situation
would occur. ro that lhe qualifying
facility could ceare ddivery oi
eleclricity druint those pedods.
Many o[ ihe comne[B receiyed
rellected r rurpicion that electric
utillties n'ould abuse this paragraph to
cirtumrcnt iheir obUgation to purchasr
from qualifying facilities. Ia order to
minimize thet porsibilitlr,. the
Commission bas r:r'ised this paragraph
Exhibit No. 203
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
HeinOnline - 45 Fed. Reg.12227 1980 Page 5
BEFORE TFM
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-E.15.01, AVU.E.15.OI, PAC.E-15.03
J.R. SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBIT NO.2O4
Exhibit No._(GND-7CT)
Docket UE-I30043
Witness: Gregory N. Duvall
BEFORE THE WASHINGTON
UTILITIES AI\D TRANSPORTATION COMMISSION
Docket UE-130043
PACIFICORP
REDACTED REBUTTAL TESTIMONY OF GREGORY N. DUVALL
August 2,2013
Exhibir No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, SimploVClearwater
Page I
WASHTNGTON UTILITIES AND
TRANSPORTATION COMMISSION,
V.
PACIFICORP d/b/a
Pacific Power & Light Company
I should consider changes in this case as a part of the post-trial period review of the
2 WCA.r6
3 Q. Did parties accept any of the Company's proposed modifications to the WCA?
4 A. Yes. Staffexplicitly supported the Company's proposal to include the entire ldaho
5 Power PTP transmission contract in the WCA, apparently on the basis that it reduces
6 NPC.'7 While Boise challenged a list of what it characterizedas the proposed
7 changes to the WCA and argued generally that changes to the WCA were not
8 reasonable at this juncture, it chose not to remove the change to the Idaho Power PTP
9 contract.ls
l0 California and Oregon QF contracts
I I O. Does any party support the Company's proposal to include the costs associated
12 with Oregon and California QF contracts in west control area NPC?
13 A. No. Staff, Boise, and Public Counsel each argue against inclusion of California and
l4 Oregon QF contracts in west control area NPC.le In one form or another, the parties
l5 all assert that allocating west control area QF contracts to Washington inappropriately
16 requires Washington customers to pay for QF-related policy choices made by Oregon
17 and California.
l8 a. Are all of the contested QF contracts from renewable resources?
19 A. Yes. The QF contracts are all connected to renewable resources located in Oregon
20 and California. Because the QF contracts do not include renewable energy credits
tu td.,1l5e.
'' Exhibit No._(DCG-l cr) at page 7.
'8 Exhibit No._(MCD-lCT) at pages 5-6.
re See Exhibit No._(MCD-lCT) at pages 5-8; Exhibit No._(DCG-lCT) at pages 8-13; Exhibit No._(SC-
ICT) at pages l5-18.
Redacted RebuttalTestimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E- I 5-01 , AVU-E- I 5-0 I , PAC-E- I 5-03
D. Reading, Simplot/Clearwater
Page 2
Exhibit No._(GND-7CT)
Page 13
I (RECs), however, the Company may not use them to comply with the EIA.20
2 Q. Is one of the goals of PURPA to support the development of renewable energy
3 resources?
4 A. Yes. FERC has observed that: "With PURPA, Congress was seeking to diversify the
5 Nation's generation mix and promote more effrcient use of fossil fuels when they
6 were used for generation by encouraging renewable technologies and cogeneration, in
7 orderto cushion against further price shock and reduce dependence on fossil fuels."2l
8 Q. Does Washington state policy promote the development and use of renewable
9 energy?
l0 A. Yes. There are strong statements in support of renewable energy development and
ll use in the declaration of policies included in the EIA and in the legislative findings
12 that support the EPS.22
13 a. Did the Commission recently adopt policies to promote the development of small
14 renewable generation?
l5 A. Yes. On July 19, 20l3,the Commission adopted new rules to simplify the process to
l6 connect small energy systems, which are often solar or wind generators, to the
17 electrical system. In announcing the new rules, Commission Chairman David Danner
l8 said: "By streamlining these rules we are advancing Washington's policies that
19 encourage renewable energy, including distributed generation. This is one more step
20 RCw 19.285 et seq.
" ln re Southern California Edison, Tl F.E.R.C. P 61,269,62,079 (1995).
" RCW 189.285.020; RCW 70.235.005; and RCW 80.80.005(lXd).
Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No._(GND-7CT)
Exhibit No. 204 Page 14
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 3
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to help Washington's citizens and businesses participate in our state's efforts to
reduce greenhouse gas emissions."23
Is asking Washington customers to pay their allocated share of the Company's
west control area QF contracts (while other west control area states also pay
their allocated share of Washington's QF contracts) contrarT to Washington
state energy policy?
No. Washington, like its neighbors in Oregon and California, clearly supports the
underlying policy goals of PURPA. Indeed, continuing to single out QF contracts for
different regulatory treatment than any other west control area resource discriminates
against small, renewable resources in a manner that appears directly contrary to
Washington energy pol icy.
Has the number of Oregon and California QF contracts included in the
Company's case decreased since its initial filing?
Yes. Since the initial filing, four Oregon QF contracts were terminated. The impact
of removing these contracts is included in the Company's rebuttalNPC. This update
also reduces the impact of parties' proposed adjustments to exclude Oregon and
California QF contracts by approximately l0 percent.
Does PURPA include specific provisions related to utility cost recovery for QF
contracts?
Yes. I understand that PURPA specifically requires that electric utilities "recover[]
all prudently incurred costs associated with the purchase" of energy or capacity from
A.
a.
A.
a.
A.
23 http://www.utc.wa.sov/aboutUs/ListsNews/DispForm.aspx?lD:209
Redacted RebuttalTestimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 4
Exhibit No._(GND-7CT)
Page 15
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a.
A.
a QF contract.2a The Company's proposal in this case modifies the WCA to provide
for the full cost recovery for QF contracts dictated by PURPA.
What specific justification does Staff provide for the exclusion of the Company's
contracts with QFs in Oregon and California?
Staff first argues that inter-jurisdictional allocation is not based on actual power flow
studies and therefore the fact that Oregon and California QFs may physically deliver
power to meet Washington load is irrelevant.2s Public Counsel makes the exact
opposite argument.26 It claims that PacifiCorp has failed to provide any analysis
showing how Washington load is satisfied by QFs from outside the state and, without
such a detailed power flow study, it is not possible to assign these costs to
Washington customers. In other words, Staffclaims that allocation is not, and has
never been, based on power flow studies, and Public Counsel claims that power flow
studies are a necessary predicate to any inter-jurisdictional allocation methodology.
How do you respond to these arguments?
The Commission has made clear that the Company does not need to "demonstrate
each resource in the system provides a direct benefit, i.e., electron flow, to be
considered used and useful for service in this state."27 Public Counsel's claim that a
detailed power flow study is necessary is incorrect. However, Staff is also incorrect
that the physical location of the Oregon and California QFs within the west control
area is irrelevant to their inclusion in west control area NPC.
'o l6 u.s.c. g 82aa-3(m)(7).
2s Exhibit No._(DCG-lcr) at page 10.
'u Exhibit No._(SC-lCT) at page 17.
27 Wash. Utils. & Transp. Comm'n v. PacifiCorp d/b/a/ Pacific Power & Light Company. Docket UE-050684,
Order 04, !l 68 (April 17 ,2006).
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Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 5
Exhibit No._(GND-7CT)
Page 16
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Please explain.
The underlying premise of the WCA is that all generation resources located in the
west control area are used and useful to Washington customers and are therefore
included in Washington rates. When approving the WCA, the Commission observed:
"Based as it is on the generation resources that are actually used to keep the west
control area in balance with its neighboring control areas, the WCA method is a solid
foundation for determining the resources that actually serve load in Washington.2s
The fact that the Oregon and California QFs are located in the west control area
means that, like all other west control area generation resources (including PPAs with
non-QF generators), the costs and benefits of these contracts should be included in
Washington rates.
Does Staff provide any other justification for the exclusion of costs associated
with Oregon and California QF contracts from west control area NPC?
Yes. Staff claims that the requirements, size of eligible resources, contract term
lengths, and pricing for QF contracts are determined entirely by state-specific
policies.2e As discussed above, Staff argues that Washington customers should not be
subject to the policy decisions of other states related to QF contracts.
Do other parties make similar arguments?
Yes. Boise also argues that Washington customers should be protected from other
stateso policies on QF contracts.30
28 Wash. Utils. & Transp. Comm'nv. PaciJiCorp d/b/a Pacific Power & Light Company, Docket UE-061546,
Order 08, ![ 53 (June 21,2007).
" Exhibit No._(DCG-lCT) at page 10.ro Exhibit No._(MCD-lcr) at page 7.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, S implot/Clearwater
Page 6
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Exhibit No._(GND-7CT)
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Is Staff correct that the requirements, size of eligible resources, contract term
lengths, and pricing for QF contracts are driven entirely by state-specific
policies?
No. I understand that PURPA-a federal statute-requires the Company to enter into
QF contracts and makes clear the price paid to a QF cannot exceed the utility's
avoided costs.3l I also understand that FERC regulations govern the specific
requirements regarding the types of resources that are eligible for a QF contract,32 the
size of resources eligible for QF contracts,33 and the methodology for determining
avoided cost prices for purposes of QF contracting.3a
Staffclaims that Commission policy dictates shorter contract lengths and
smaller capacity sizes than Oregon and California to better protect customers.3s
Do you agree?
No. Staff s testimony states that the Commission has established policies that strictly
limit QF eligibility for standard contracts and strictly limits standard contract length.36
However, Staff s claims are at odds with the Commission's rules and Commission-
approved PURPA tariffs.
First, Staff states that WAC 480-107-095 limits eligibility for standard
contracts to QFs that have a capacity of 2 megawatts (MW) or less.37 WAC 480-107-
095 does not include a cap, however, stating only that "utilities must file a standard
" See, e.g.,l6 U.S.C. $$ 82aa-3(b), (d); l8 C.F.R.5292.304(2);American Paper lnstitute, Inc. v. American
Elec. Power Service Corp.,46l U.S. 402,413 (1983).
" See, e.g.,l8 C.F.R. $$ 292.203-.205.
" See, e.g.,l8 C.F.R. $ 292.304(c).
'o See, e.g., l8 C.F.R. S 292.304.
3s Exhibit No._(DCG-lcT) at page 13.
'u Id. atn.29.
37 Id.
Redacted RebuttalTestimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
PageT
Exhibit No._(GND-7CT)
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tariff for purchases from qualifying facilities rated at one megawatt or less."
Currently, both PSE's Schedule 9l and Avista's Schedule 62 provide standard offer
contracts for QFs with capacities up to 5 MW; PacifiCorp's Schedule 37 provides
standard contracts for QFs with capacities up to 2 MW.
Second, Staff states that WAC 480- 107-095 provides for fixed pricing for a
term of only five years.38 Again, that rule says nothing about fixed prices or the
length of a contract. WAC 480-107-095 merely states that prices may oonot exceed
the utility's avoided costs for such electric energy, electric capacity, or both," and that
the tariff "may be based upon market prices and include incremental costs associated
with purchasing smallquantities of power."
PacifiCorp's current Schedule 37 publishes a lO-year stream of fixed prices
available for a contract term of five years. PSE's tariff specifies that to receive fixed
prices, contracts must be at least five years in length, and the tariff reflects l5 years
of fixed prices. Of note, current Washington prices, which were set in PacifiCorp's
20 I I general rate case, Docket UE- I 1 I 190, include the end of a 25-year QF contract
with the City of Walla Walla with calendar year 2014 prices of $156.90 per MWh.
Staff argues that the longer terms of QF contracts in Oregon and California
expose customers to increased risks from decreasing avoided cost rates in recent
years.3e How do you respond?
Staff overstates this risk by understating the number of Oregon and California
contracts entered in the last five years. Staff claims that approximately 34 percent of
the QF contracts are post-2009; in fact, of the expected QF generation in 2014
38 Id.
" Exhibit No._(DCG-lCT) at pages l2-13.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 8
Exhibit No._(GND-7CT)
Page 19
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included in this case, over 76 percent is from contracts entered in the last five years.ao
The vast majority of the contracts that are included in NPC in this case have been in
place five years or less.
Does Boise identi$ any specific state policies from Oregon and California that it
claims are in conflict with Washington policies?
Yes. Boise claims that Oregon and California have fixed price standard offer
contracts for QFs, but Washington does not.al Boise claims that Washington
customers should not be exposed to the risk associated with these types of policy
decisions made in other states.
Does this argument have merit?
No. Boise's argument is premised on an incorrect understanding of Washington's
implementation of PUMA. As described earlier, the Company's Schedule 37 tariff
in Washington provides a fixed price standard offer option for QFs up to 2 MW of
capacity.
Other than the incorrect reference to the lack of a fixed price contract in
Washington, does Boise provide any other examples of QF policies in Oregon or
California that differ from those in Washington?
No. Boise's claims that Washington customers are exposed to harm caused by
decisions made by the states of Oregon and California are unsubstantiated.
Are Washington customers harmed by other states' determination of QF prices?
No. As I described in my direct testimony, prices paid to QFs are determined based
'0 This includes the impact of removing the terminated Butter Creek wind QFs. Before removing the Butter
Creek QFs, 74 percent of the Company's expected QF generation in the Company's initial filing was from
contracts entered in the last five years.o' Exhibit No._(MCD-lCT) at page 6.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E- I 5-01 , AVU-E- I 5-0 I , PAC-E- I 5-03
D. Reading, SimploUClearwater
Page 9
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Exhibit No._(GND-7CT)
Page 20
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on a utility's avoided cost of energy and capacity, in compliance with PURPA. Each
state has an approved method for calculating these avoided costs, and the resulting
prices are heavily scrutinized and ultimately approved by the respective commissions.
The avoided cost calculation is designed to set QF contract prices at a level where
customers are indifferent between a utility purchasing from the QF or obtaining
energy and capacity from the next available resource. No party has provided
evidence that the avoided cost prices in Oregon or California exceed the Company's
actual avoided costs in violation of PURPA.
What justification does Public Counsel provide for the exclusion of the
Company's contracts with QFs in Oregon and California?
In addition to the arguments addressed above regarding the Company's lack of power
flow studies, Public Counsel claims that Oregon and California QF contracts are
priced higher than other long term purchase power costs for 2014.42
How do you respond to this argument?
It is improper for ratemaking purposes to compare the avoided cost price in QF
contracts that are several years old with the cost of other purchases in the current
NPC study. Such a comparison does not account for the information available at the
time the various contracts were entered. Nevertheless, the difference in price cited by
Public Counsel was less than seven percent. In addition, all of the long-term
contracts included in the comparison were executed more than l0 years ago,
including two low-cost contracts entered in l96l and 1989 that were based on cost-
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o'Exhibit No._(SC-lcT) at page 17.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page l0
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of-service rates. It is unreasonable to compare recent avoided cost prices with that of
a contract entered more than 50 years ago.
Public Counsel also claims that the Company perceives the Oregon and
California QF contracts as local or state-specific matters.43 Is this correct?
No. For every state served by the Company other than Washington, the Company
allocates the cost of QF purchases located in all states (including Washin$on's QF
contracts) to alljurisdictions. Washington is the only state served by PacifiCorp that
does not reflect their allocated share of other states' QF contracts in NPC.
Boise argues that excluding the Oregon and California QF contracts from west
control area NPC is equivalent to replacing these resources with market
purchases in GRID.aa Do agree this is a reasonable approach?
No. Boise's argument is based on the incorrect premise that current market prices are
an appropriate proxy for avoided cost. Schedule 37 requires the Company to pay QFs
in Washington a payment for both energy and capacity, with energy payments
reflecting the Company's incremental cost of market transactions and thermal output,
and capacity payments reflecting the fixed costs associated with a simple cycle
combustion turbine for three months per year. The inclusion of capacity payments in
avoided costs indicates that market prices alone are not equivalent to avoided cost
prices.
What does the Company recommend regarding the treatment of California and
Oregon QF contracts in west control area NPC?
The Company recommends that the Commission allow the Company to include
43 Id. at16.
na Exhibit No._(MCD- I cr) at page 7.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page I I
Exhibit No._(GND-7CT)
Page22
1 Califomia and Oregon QF contracts in the determination of west control area NPC in
2 the same manner as all other west control area generation resources, with a portion of
3 the costs allocated to Washington customers.
4 East Control Area Sale
5 Q. How do parties respond to the Company's proposal to remove from the NPC
6 calculation the assumed sales from PacifiCorp's west control area to its east
7 control area?
8 A. Boise and Staffeach recommend that the Commission reject the Company's proposal
9 and recommend that west control area NPC continue to include an assumed east
l0 control area sale.as
I I a. What is the basis for Boise's opposition to the Company's proposal?
12 A. Boise provides no factual argument, but instead rejects the proposal to remove the
l3 east control area sale because the parties to the collaborative process did not agree to
14 the change.ou Fo. the same reasons discussed above, this argument is unpersuasive.
l5 a. What basis does Staff provide for the inclusion of the east control area sale?
16 A. Staff s argues that the imputed east control area sale remains an integral and crucial
17 part of the WCA and should therefore not be modified.aT
l8 a. When the Commission adopted the WCA, what did it say with respect to the east
l9 control area sale?
20 A. The Commission noted that the Company accepted the east control area sale subject
2l to further scrutiny in the future and approved the establishment of a monitoring
ot Exhibit No._(DCG-lCT) at pages l3-16; Exhibit No._(MCD-lCT) at page 8.
ou Exhibit No._(MCD-lcr) at page 8.o'Exhibit No._(DCG-1CT) at page 16.
Redacted RebuttalTestimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 12
Exhibit No._(GND-7CT)
Page 23
CONFIDENTIAL PER WAC 480.07.I60
Exhibit No._(GND-lcT)
Docket UE-14_
Witness: Gregory N. Duvall
BEFORE THE
WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION
Docket UE-14
PACIFIC POWER & LIGHT COMPANY
REDACTED DIRECT TESTIMONY OF GREGORY N. DUVALL
May 2014
Exhibit No. 204
Case Nos. IPC-E- l5-01, AVU-E- l5-01, PAC-E- I 5-03
D. Reading, Simplot/Clearwater
Page 13
WASHINGTON UTILITIES AND
TRANSPORTATION COMMISSION,
v.
PACIFIC POWER & LIGHT COMPANY,
a division of PacifiCorp
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differences in west control area loads and resources by reducing actual short-term
balancing purchase or sales transactions.
PROPOSED TREATMENT OF QF RESOURCES
IN THE WEST CONTROL AREA
Please explain the Company's proposed treatment of PPAs with west control
area QFs.
In this case, the Company renews its proposalto include Washington's share of the
costs and benefits associated with all PACW (Oregon, Califomia, and Washington)
QF PPAs in the calculation of west control area NPC.
Did the Company originally propose this treatment in the 2013 Rate Case?
Yes. The Commission rejected this proposal in Order 05 the 2013 Rate Case, and the
Company sought judicial review of this issue.
Why is the Company again asking to include the cost of PPAs with QFs in
Oregon and California in this case?
The Company respectfully asks the Commission to reconsider its approach to
including PPAs with west control area QFs in Washington rates for the following
reasons:
Including all PPAs with QFs in the west control area in the NPC calculation is
consistent with the treatment of other generation resources under the WCA and is
a more accurate representation of the Company's operations in the west control
area because these resources are all located in the west control area, physically
deliver power to meet Washington load in the same manner as any other west
control area resource, and provide direct benefits to Washington customers.
There are now a material number of QFs serving Washington customers, but the
costs of the PPAs with these QFs are not reflected in Washington rates. In the pro
forma period, Oregon and California QFs are projected to supply 806,799
megawatt-hours (MWh) of generation in the west controlarea. Collectively, west
controlarea QFs provide a significant source of power supply to Washington
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_ . .Direct:lqstimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 14
Exhibit No._(GND-lCT)
Page 8
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customers, but Washington customers only pay for PPAs with QFs located in
Washington.
Including west control area QF PPAs in Washington rates is consistent with the
Public Utility Regulatory Policy Act of 1978 (PURPA). The QF PPAs included
in this case were executed at avoided cost prices calculated under PURPA, and no
party has ever alleged that the prices exceed the Company's actual avoided costs
at the time the PPAs were executed. PURPA explicitly requires FERC to "ensure
that an electric utility that purchases electric energy or capacity from a tQF] . . .
recovers all prudently incurred costs associated with the purchase."2
All of the Oregon and California PPAs are with QFs that are eligible resources
under Washington's Energy Independence Act (EIA). Allowing the Company to
recover the costs of these Oregon and California QF PPAs in rates implements the
EIA's policy of encouraging renewable resource development on a regional basis
and diversifying the portfolio of renewable resources serving Washington
customers.
In the 2013 Rate Case, the Commission reasoned that the Company's proposal
was the equivalent of adopting the Revised Protocol method just for QF
.esor."es.3 Do you agree?
No. The Company's proposal to include the costs of PPAs with QFs in Oregon and
California in the calculation of west control area NPC is consistent with the WCA and
strictly tracks the Commission's underlying rationale for the WCA. As reiterated in
the 2013 Rate Case Order, the WCA is based "on the generation resources that are
actually used to keep the west control area in balance with its neighboring control
areas."4 Oregon and California QFs are used to keep the west control area in balance
just like all other west control area generation resources. The only distinguishing
' t6 U.S.C. $ 824a-3(m)(7)(A); see also FreeholdCogeneration Assocs., L.P. v. Bd. of RegulatoryComm'rs of
the State of N.J.,44 F.3d I 178, I 194 (3d Cir. 1995) ("[A]ny action or order by the [state commission] to
reconsider its approval or to deny the passage ofthose rates to [the utility's] consumers under purported state
authority was preempted by federal law.").
' I,yash. (Jtils. & Transp. Comm'nv. PacifiCorp d/b/a PaciJic Power & Light Co., Docket UE-130043, Order
05, fl I 10 (Dec. 4, 2013).
n Order 05 fl I l0 (quoting t(ash. Iltils. & Transp. Comm'n v. Pacific Power & Light Co., Docket UE-061546,
Order 08, !f 53 (June 21,2007).
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B.r,rfiiffi1fr?stimony of Gregory N. Duvall
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 15
Exhibit No._(GND-lcT)
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factor between QF resources and all other west control area resources is the fact that
PURPA requires the Company to purchase power from QFs at prices established by
regulators in west control area states. This mandate makes recovery of the costs of
these resources more appropriate under the WCA, not less.
In addition, the 2010 Protocol, which is the current inter-jurisdictional
allocation methodology used in the PacifiCorp's other five state jurisdictions,
allocates the costs of QF PPAs across PacifiCorp's system. In this case, the Company
is not proposing to system-allocate PPAs with QFs in all six states served by the
Company.
Are Washington customers harmed because west control area NPC is higher
when all PPAs with west control area QFs are included?
No. Washington customers are not harmed by paying rates that more accurately
represent the cost to serve them. These resources are used in providing service to
Washington customers, and including the costs of these resources in rates is fair, not
harmful.
Furthermore, while including all west control area QF PPAs increases
Washington-allocated NPC by approximately $10.0 million, this only shows that the
prices paid for Oregon and California QF resources are higher than the variable cost
of market purchases and other resources used to balance the GRID study. QF prices,
on the other hand, are established in advance, consistent with PUMA, and are fixed
for a number of years over the term of the PPA. Long-term contract prices will
inevitably be different from short-term market prices as time progresses. QF prices
may also include a capacity component in addition to payment for energy. In
- . .Direct:lqstimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 16
Exhibit No._(GND-lcT)
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Washington, for example, Schedule 37 rates compensate QFs for both energy and
capacity, with energy payments based on the incremental cost of market transactions
and thermal output, and capacity payments reflecting the fixed costs of a simple cycle
combustion turbine for three months per year. If avoided cost prices are greater than
market prices years after the PPA was signed, it does not mean that the avoided cost
prices in the QF PPA are excessive or otherwise violate PURPA's strict requirements.
PURPA requires that the prices paid to QFs be equal to a utility's avoided cost
of energy and capacity. Each state has an approved method for calculating these
avoided costs, and the resulting prices are heavily scrutinized and ultimately approved
by the respective regulatory commissions. The avoided cost calculation is intended to
ensure that customers are indifferent to QF generation, i.e., that the price paid to the
QF is the same as the price the utility would otherwise incur if it was generating the
electricity itself. Comparing QF PPA prices for a single test year to the variable cost
of market purchases or the Company's existing resources is insufficient to determine
whether QF prices are reasonable and prudent from a ratemaking standpoint.
In response to Order 05 in the 2013 Rate Case, did the Company analyze other
approaches to addressing Oregon and California QF PPAs in Washington?
Yes. In an effort to respond to the Commission's concerns in Order 05 about
including the energy and capacity costs of allwest controlarea QF PPAs in the
determination of west control area NPC, the Company examined two alternative
approaches to addressing the Oregon and California QF PPAs:
l) A "load decrement" approach, which excludes the costs and energy of Oregon
and California QF PPAs from the NPC calculation, and excludes an equivalent
- . .Direct^lqstimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 17
Exhibit No._(GND-lCT)
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amount of QF output from WCA loads used to calculate NPC and inter-
jurisdictional allocation factors; and
2) A "Washington re-pricing" approach, which includes Oregon and California QF
PPAs in the NPC calculation but re-prices them using the Washington avoided
cost rates in effect at the time of PPA execution.
Table 2 below compares the revenue requirement impact of these two alternative
approaches with the Company's proposal to include all west control area QF PPAs as
west control area resources. This table, and supporting detail, is provided in Exhibit
No._(NCS-7) accompanying Ms. Siores testimony.
Table 2
Revenue
Requirement
Variance from
Filed
As Filed S27.2 million
Washinston Re-Pricins $24.9 million ($2.3 million)
Load Decrement $23.1 million (S4.1 million)
Situs Assisned (exclude OR and CA QF PPAs)$17.2 million fSl0.0 million)
Please explain the load decrement approach.
Under this approach, Oregon and California QF PPAs are deemed to serve customers
in those states, consistent with the situs treatment ordered by the Commission in the
2013 Rate Case. Because Oregon and California QF PPAs are not recognized as
WCA resources, the costs and related energy are removed from the calculation of
west control area NPC. Next, because Oregon and California QF PPAs are deemed to
serve customers in those states, the retail load in those states served by these
resources is also removed from the calculation of west control area NPC. Finally, the
retail load in Oregon and California served by QF resources is subtracted (i.e.
decremented) from the energy and peak loads used to determine each state's
allocation factors under the WCA.
_ . .Dircctlqstimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-l 5-01, AVU-E-15-01, PAC-E-15-03
D. Reading, S implot/Clearwater
Page 18
Exhibit No._(GND-lCT)
Page 12
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What is the impact to Washington of removing Oregon and California QF PPAs
and load?
Removing Oregon and California QF PPAs and load reduces west control area NPC
and reduces the total load served by west control area resources. The allocation of
remaining west control area costs is adjusted to account for the decremented load-
i.e. the share of the total costs allocated to Oregon and California is decreased
reflecting the reduced requirement to serve customers in those states. Washington's
allocated share of remaining WCA costs is increased as a result of the QF-PPA-
related decrements to Oregon and California load. The net impact is a reduction to
the Company's current filing of approximately $4.1 million.
Why is an adjustment to the inter-jurisdictional allocation factors required
under the load decrement approach?
Adjusting the inter-jurisdictional allocation factors under the load decrement
approach ensures that the full impact of treating QF PPAs as situs resources is
reflected in Washington revenue requirement. If Oregon and California customers
are being served by specific resources, they should not also be allocated the cost of
the remaining west control area resources. Decrementing Oregon and California load
for allocation purposes appropriately reduces the share of west control area costs
allocated to those states.
Please explain the alternative approach of re-pricing Oregon and California QF
PPAs using Washington avoided costs.
Under this alternative, the Oregon and California QF PPAs are included in west
control area NPC but are re-priced using Washington avoided cost rates that were
- . .Dircct:lestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 19
Exhibit No._(GND-lcT)
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calculated at the time the PPA was signed. This alternative removes the impact of
differences in individual state commission approaches to determining avoided cost
prices. Some of the Oregon and California QF PPAs have contract terms that extend
beyond the last year for which the Company had calculated avoided cost prices in
Washington. For example, an Oregon QF PPA signed in June 2009 would be priced
using the WashinSon Schedule 37 prices approved by the Commission in February
2009, which were only calculated through 2013. In examples such as this, the last
annual price was escalated with inflation through the pro forma period. Several
Oregon and California QF PPAs in the pro forma period were signed in the early
1980s, and one was signed in the early 1990s. At that time, the Company also had
two-long term QF PPAs in Washington, one with the City of Walla Walla (signed in
1984) and one with Yakima-Tieton lrrigation District (signed in 1985). Prices paid
under the Walla Walla PPAs were applied to the early- 1980s contracts in Oregon and
California, and prices paid under the Yakima Tieton PPA were applied to the PPA
signed in 1993.
Currently, the Company's Schedule 37 only allows fixed-price contracts for a
term of up to five years. Has that always been the case?
No. Schedule 37 was first implemented in 2004, and it included a five-year limit on
fixed-price contracts. However, the two long-term Washington QF PPA contracts
signed in the 1980s mentioned above were for terms of 25 and20 years, respectively.
Washington's current administrative rules allow a utility to sign contracts for
electricity purchases for any term up to twenty yea.s.s
'wAC 480-lo7-075(3).
_ . .Dircct:[qstimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 20
Exhibit No._(GND-lCT)
Page 14
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What is the impact to Washington NPC of re-pricing all of the Oregon and
California QF PPAs?
As shown in Table 2, the impact of re-pricing all of the Oregon and California QF
PPAs using contemporaneous Washington avoided cost rates is a reduction to the
Company's current filing of approximately $2.3 million.
Why is the Company discussing these alternative methods in this case?
The Company's proposal for treatment of west control area QF PPAs in this case is
the same as in the Company's 2013 Rate Case-full recognition of the costs of the
Company's PPAs with Oregon and California QFs in Washington rates. The
Company renews this proposal because it best captures the prudent and reasonable
costs to serve Washington customers. But in response to the Commission's past
criticism of its proposal, the Company provides the alternative methods as a middle
ground between full recovery or full disallowance of the costs of all west control area
QFs in Washington NPC.
CHAI\GES IN SALES AIID LOADS
Please summarize the changes in Washington sales in this case compared to the
Company's 2013 Rate Case.
As shown in Table 3 below, the Company's Washington sales in the historicaltest
period (the l2 months ended December 31,2013) were 9,549 MWh, or 0.2 percent
higher than the sales included in the 2013 Rate Case on a weather-normalized basis.6
The increase in sales is largely driven by increased sales to the commercial class and
6 In this case, the Company calculated temperature normalization for the residential, commercial, and inigation
customers consistently with the methodology approved by the Commission in the Company's 2005 general rate
case, Docket UE-050684,2006 general rate case, Docket UE-090205, and the Company's 2013 Rate Case,
Docket UE-130043.
- . .Ditect:lqstimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 2l
Exhibit No._(GND-lCT)
Page 15
ExhibitNo. GND-47
Docket UE-140762 et al.
Witness: Gregory N. Duvall
BEFORE THE WASHINGTON
UTILITIES AI\D TRANSPORTATION COMMISSION
WASHINGTON UTILITIES ANI)
TRANSPORTATION COMMISSION,
Complainant,
v.
PACIFIC POWER & LIGHT
COMPANY,
Respondent.
In the Matter of the Petition of
PACIFIC POWER & LIGHT
coMPANY,
For an Order Approving Deferral of
Costs Related to Colstrip Outage.
In the Matter of the Petition of
PACIFIC POWER & LIGHT
coMPANY,
For an Order Approving Deferral of
Costs Related to Declining Hydro
Generation.
Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 22
DOCKETS UE-140762 and UE-140617
(consolidated)
DOCKET UE-131384 (consolidated)
DOCKET UE-140094 (consolidated)
PACIFIC POWER & LIGHT COMPANY
REBUTTAL TESTIMONY OF GREGORY N. DUVALL
November 2014
I its members, "including the Packaging Corporation of Ameica, fMa Boise White
2 Paper, L.L.C. (PCA), PacifiCorp's largest customer in Washington[,]"la and further
3 stated that "ICNU indirectly participated in PacifiCorp's most recent general rate case
4 (UE-130043) as PCA[.]"rs
5 Q. Given that this update is occurring in your rebuttal testimony, does the
6 Company object to allowing the parties an opportunity to provide responsive
7 testimony on this issue?
8 A. No. The Company does not object to parties addressing the Company's NPC update
9 in supplemental pre-filed testimony or in testimony at the hearing, provided the
l0 Company has a chance to respond to this testimony.
I I COMPANY RESPONSES TO PROPOSED NPC ADJUSTMENTS
12 Exclusion of California and Oregon QF PPAs
l3 a. Does any party support the Company's proposal to include the costs associated
14 with Oregon and California QF PPAS in west control area NPC?
l5 A. No. Staff, Boise, and Public Counsel each reject including California and Oregon and
16 QF PPAs in west control area NPC.r6 Similar to arguments made in the Company's
17 2013 general rate case, Staff and Boise assert that allocating west control area QF
l8 PPAs to Washington inappropriately requires Washington customers to pay for QF-
19 related policy choices made by Califomia and Oregon. Public Counseldoes not
20 address the appropriate allocation of California and Oregon QF PPAs, but indicates
ta See LV'ash. Iltils. & Transp. Comm'n v. PacifiCorp, Docket No. UE- 14061 7, Petition to Intervene and
Opposition of the Industrial Customers of Northwest Utilities, fl 3 (Apr. 25,2014).
's td.,14.
16 See Testimony of David C. Gomez, Exhibit No. DCG-lCT at 9-10; Responsive Testimony of Bradley G.
Mullins, Exhibit No. BGM-lCT at23.
- . .Reb.uttal Jestimony of Gregory N. Duvall Exhibit No. GND-47Exhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 Yage tz
D. Reading, Simplot/Clearwater
Page 23
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that Public Counsel supports the Commission's findings in Docket UE-130043 (2013
Rate Case) and removes the cost of these QFs from west control area NPC.
Is the Company's proposal in this case exactly the same as in the Company's
2013 Rate Case?
No. While the Company's main proposal in this case is similar to the 2013 Rate Case
in that the costs associated with Califomia and Oregon QF PPAs are included in west
control area NPC, the Company also provided two alternative approaches that would
reasonably reflect the impact of California and Oregon QF PPAs on NPC. First, the
Company proposed re-pricing the out-of-state QFs at Washington avoided cost prices,
so that the costs associated with the QFs reflected Washington state policy choices.
This proposalwould decrease Washington revenue requirementby $2.2 million.
Second, the Company proposed a load decrement approach to QF pricing that would
remove the costs of the out-of-state QF PPAs and also offset each west control area
states' load with the QFs in that state for purposes of allocating costs and benefits
under the WCA. This proposal would decrease Washington revenue requirement by
$3.9 million. The rebuttaltestimony of Ms. Natasha C. Siores provides the detailed
revenue requirement impact of each proposal. I reproduced her summary table here
for ease of reference. l7
TABLE 1
Reven ue Req u i rem ent S u m m ary
Revenue
Requirement Change fiom Filed
tebuttal Position 31,938,957
le-Pricinq at WA QFs Arcided Costs 29,763,224 Q.',175.733',
-oad Decrement 28.009.625 (3,929.3321
Situs-Assiqned - Excl. OR/CA QFs 22,',t81,879 (9,757,0791
Ref NGS-I 1, Page 1.'
Ref NqS-l2, Page 2
Ref NCS-12, Page 3
Ref tlcs-l2, Page 4
'' Rebuttal Testimony of Natasha Siores, Exhibit No. NCS-12.
_ . .Rebuttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, SimplotiClearwater
Page 24
Exhibit No. GND-47
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Did the parties address the Company's alternative proposals?
Yes. Both Staffand Boise dismissed the Company's alternative proposals as
inconsistent with the Commission's decision in the 2013 Rate Case.
What is the parties' primary argument against Pacilic Power's proposals?
Based on the Commission's order in the 2013 Rate Case, Staffand Boise argue that
excluding the California and Oregon QF PPAs from the west control area NPC is
equivalent to replacing these resources with market purchases in CRID.ts Staff and
Boise claim that re-pricing the QF PPAs at market prices protects Washington
customers from policy decisions made by other states and is consistent with the cost
causation principles underlying the WCA.
Is re-pricing the out-of-state QF PPAs at current market prices consistent with
PURPA?
No. It is my understanding that re-pricing the out-of-state QF PPAs at current spot
market prices is inconsistent with PURPA's requirement, as interpreted by the
Commission in the Company's Schedule 37,that utilities purchase allenergy and
capacity made available by QFs at the utility's avoided cost.
Why is re-pricing the out-of-state QF PPAS at current market rates inconsistent
with PURPA's avoided cost requirements?
There are two primary reasons. First, simply relying on market prices does not reflect
Pacific Power's actual avoided costs as determined by the Commission because it
fails to account for the impact of a QF on the Company's existing resources or the
a.
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a.
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" See, e.g., Testimony of David C. Gomez, Exhibit No. DCG-lCT al
Mullins, Exhibit No. BGM-l CT at 25-26.
- . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E- I 5-0 l, AVU-E- I 5-0 l, PAC-E- I 5-03
D. Reading, Simplot/Clearwater
Page25
I l; Responsive Testimony of Bradley G.
Exhibit No. GND-47
Page 14
I QF's ability to defer future capacity additions. PURPA requires the Company to
2 purchase energy and capacity made available by QFs.
3 Second, the curuent market price does not accurately reflect Pacific Power's
4 avoided cost of energy included in long-term QF PPAs that were executed years ago
5 with avoided cost prices determined at the time of execution. PURPA allows QFs to
6 enter into long-term PPAs with utilities and, at the option of the QF, the avoided cost
7 prices in those PPAs can be determined at the time the PPA is executed, not at the
8 time that the energy is delivered to the utility.
9 The Commission's decision to price out-of-state QF PPAs at the current
l0 market price ignores the Company's obligation under PURPA to pay a fixed avoided
I I cost price over the life of the QF PPA. Thus, even if market prices accurately
12 reflected Pacific Power's avoided cost of energy, the relevant market prices were
13 those that were forecast at the time the QF PPAs were executed, not current spot
14 market prices.
l5 a. Has the Commission recognized that avoided cost prices must account for both
16 energy and capacity?
17 A. Yes. Pacific Power's current Schedule 37 requires the Company to pay QFs in
l8 Washington for both energy and capacity, with energy payments reflecting the
19 Company's incrementalcost of market transactions and thermal output, and capacity
20 payments reflecting the fixed costs associated with a simple cycle combustion turbine
2l for three months per year. The inclusion of capacity payments in Washington's
22 avoided cost calculation demonstrates that, in the current view of the Commission,
23 market prices alone are not equivalent to avoided cost prices.
_ . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E- I 5-01 , AVU-E- I 5-01 , PAC-E- I 5-03
D. Reading, Simplot/Clearwater
Page 26
Exhibit No. GND-47
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Has Staff recognized that wind resources provide capacity value to Washington
customers?
Yes. Staff s cost of service testimony expressly recognizes that wind resources
provide capacity to meet the Company's peak load.le As described in the cost of
service testimony of Ms. Joelle R. Steward, the Company's west control area wind
resources, including the out-of-state QFs, contribute 25.4 percent of their nameplate
capacity to meet total system peak load.
Why is it necessary for the avoided cost prices to account for both energy and
capacity?
It is my understanding that PURPA mandates the use of avoided cost prices to ensure
customer indifference to the QF transaction. In other words, customers should be no
better or worse off because Pacific Power is purchasing its energy and capacity from
a QF rather than from another source. However, if Washington customers are paying
for only the energy from out-of-state QFs, Washington customers are benefiting from
the capacity value provided by the QFs without paying for it. Therefore, re-pricing
the out-of-state QF PPAs at market prices does not result in customer indifference.
Has the Commission previously recognized the importance of ensuring customer
indifference?
Yes. The Commission has observed that "[b]y its own terms, PURPA was meant to
protect the ratepayers. Avoided cost prices should be established to be no greater
than that which the ratepayers would be expected to pay without PURPA."2o
p Testimony of Jeremy B. Twitchell, Exhibit No. JBT-lT at l5-16.
20 Spokane Energt, Inc. v. ll/ash. llater Power Co., Cause No. U-86-l 14,
^ . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 27
1987 WL 1498338 (Apr.22, 1987).
Exhibit No. GND-47
Page 16
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How do current market prices compare with the market prices at the time the
QFs were executed?
The majority of the out-of-state QFs were executed within the last six years. During
that time, market prices have decreased by more than half. Thus, even if the
Commission's re-pricing method was reasonable for purposes of determining the
avoided cost of energy, the contracts must be re-priced at the higher market prices
that were anticipated at the time each PPA was executed. The Company's re-pricing
proposal effectively captures the relevant forward prices and demonstrates the
declining market prices.
Staffclaims that the Company provided only vague assertions regarding the
benefits provided by the out-of-state QFs to Washington custom".s." Boi."
claims that the Company did not identiff any direct benefit provided by these
QFs that would support full cost "ecorery." What benefits are provided by the
out-of-state QFs?
In addition to providing the capacity benefits discussed above, the out-of-state QFs
provide significant benefits because they are renewable, emission-free generators.
Washington state policymakers have been clear that renewable generation provides
significant environmental, cultural, economic, and health benefits to Washington
residents. Thus, the state has taken extensive measures to mandate and promote the
development of exactly the types of resources that Staff and Boise claim provide no
benefit to Washington.
a.
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2r Testimony of David C. Gomez, Exhibit No. DCG-1CT at 9.
22 Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at26.
- . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 28
Exhibit No. GND-47
Page 17
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Emission-free resources may act as a hedge against future carbon regulation,
the exact nature of which is currently unknown. In fact, the Commission has
acknowledged that future carbon regulation may have a significant impact on the
Company's operations.23 The out-of-state QFs, like allof the Company's renewable
resources, will help to mitigate that impact.
What other benefits are provided by the out-of-state QFs?
The QFs provide diversity to the Company's resource portfolio, which can act to
reduce risk. Indeed, in this case Mr. Mullins testified on behalf of Boise about the
many benefits provided by wind resources, including the out-of-state QFs:
Portfolio diversification is one of the fundamental principles
relied on by utilities in order to develop a least-cost, least-risk
portfolio . . . . For purposes of utility planning, this means that
a utility will benefit from procuring power supplies that are
dependent on many different fueland resource types.2a
Thus, Mr. Mullins concluded that the Company's "overall system is benefiting as a
result of the diverse nature of all the resources in its portfolio."2s
Do the QFs allow the Company to avoid other costs?
Yes. Without the energy and capacity provided by the QFs, Pacific Power may have
had to procure additional resources. These additional resources may or may not have
been renewable, yet under the WCA these resources would have been included in
Washington rates.
Are there any other benefits provided by QFs?
Yes. In a docket before the Public Utility Commission of Oregon (OPUC), Boise's
" See,e.g., PacifiCorp's 20t3 Electric Integrated Resource Plan,DocketNo. UE-120416, Commission
Acknowledgement Letter (Nov. 25, 2013).
2a Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM- I CT at 57 .
2s Id. at 58.
0.
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- . .fte!.uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E- I 5-0 I , AVU-E- 15-01, PAC-E- I 5-03
D. Reading, Simplot/Clearwater
Page 29
ExhibitNo. GND-47
Page l8
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8
energy trade association ICNU submitted testimony from its expert Mr. Donald W.
Schoenbeck. ICNU's testimony identified I I different benefits provided by QFs,
including the following:
The second benefit is reliability. A system of 50 smaller
generators of 200 MW each is significantly more reliable than
a similar size system of 20 larger generators of 500 MW each.
The smaller unit system is 100 times less likely to lose 1,000
MW of capacity simultaneously.
***
The fourth benefit is system diversity. Because they distribute
electrical generation among smaller, more efficient generating
facilities, policies that promote cogeneration increase the
reliability of an energy portfolio in the same way a diversified
investment strategy protects investors.
***
The fifth benefit is transmission reliability. Cogeneration
provides a major source of distributed generation for the
electric grid which is a significant operating benefit. By
providing multiple power sources throughout the state, the
demand on the state's electrical grid and the risks of losing
power when centralized generating facilities fail is reduced.
**{<
The eighth benefit is reduced transmission losses.
Cogeneration conserves electricity by producing power near
the places it is consumed. This reduces transmission losses and
saves an additional amount of fuel from being burned.26
Boise also claims that whether or not the out-of-state QF prices are excessive is
irrelevant to cost allocation under the WCA.2' How do you respond?
PURPA makes the QF prices extremely relevant. PURPA requires the Company to
contract with the out-of-state QFs at prices equal to Pacific Power's avoided cost.
The fact that not a single party in this case has argued that the QF PPA prices exceed
26 Investigation Relating to Electric [/tility Purchases from Qualifying Facilities, OPUC Docket No. UM I 129,
Direct Testimony of Donald W. Schoenbeck on Behalf of the Industrial Customers of Northwest Utilities at 6-7
(Aug. 3, 2004).
27 Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at26.
- . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204
Exhibit No. GND-47
Page 19Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 30
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Pacific Power's avoided cost prices is significant because, without such a finding, it is
unreasonable to exclude the QF PPAs from rates.
Staff and Boise also argue that the out-of-state QF PPA prices are driven by
policies and decisions made by other states to encourage QF development that
should not impact Washington rates.28 Boise further claims that states have
significant leeway in implementing PURPA to 6'set avoided cost rates at higher
or lower levels to reflect state renewable energy policies."2e How do you respond
to these claims?
I disagree with Staff and Boise for several reasons. First, I disagree with the
implication that Califomia and Oregon have inflated the avoided cost prices in the QF
PPAs as a reflection of those states' renewable energy policies. It is my
understanding that states cannot set an avoided cost price that includes a 'obonus" or
ooadder" intended to encourage renewable development. FERC has stated:
[T]the State can pursue its policy choices concerning particular
generation technologies consistent with the requirements of
PURPA and our regulations, so long as such action does not
result in rates above avoided cost.30
Moreover, no party to this case demonstrated or even alleged that the avoided cost
prices included in the out-of-state QF PPAs are greater than the Company's actual
avoided costs as of the time the PPAs were executed. Thus, there is no basis to
conclude that California and Oregon are manipulating the avoided cost prices to
promote state-specific energy or environmental policies.
28 Testimony of David C. Gomez, Exhibit No. DCG-lCT at 9-10; Responsive Testimony of Bradley G. Mullins,
Exhibit No. BGM-lCT at 24.
2e Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at27.
'o Re So. Calif. Edison Co.,70 F.E.R.C. n6l,2l5 at61,676 (1995) (emphasis added).
A.
- . .Reb-uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-l 5-03
D. Reading, Simplot/Clearwater
Page 3 I
Exhibit No. GND-47
Page 20
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Second, it is my understanding that PURPA is specifically intended to
encourage QF development. Therefore, StafPs and Boise's argument has merit only
if one assumes that Washington has decided to not encourage QF development, a
decision that would be contrary to the fundamental purpose of PURPA and contrary
to the Commission's prior statements.
Third, as I discussed previously in my testimony, the states' energy policies
are strikingly similar and Washington has taken a decidedly regional approach to
encouraging renewable energy development. Both Oregon and Washington, for
example, have used PURPA development to promote distributed generation.
Therefore, the policy differences perceived by Staffand Boise are not as extensive as
they claim.
Fourth, if the Commission remains concerned that the avoided cost prices of
the California and Oregon in the QF PPAs reflect those states' policy decisions, then
the Commission should approve the Company's alternative recommendation to re-
price the QF PPAs at avoided cost prices determined according to Washington state
policy. As described in more detail below, this re-pricing proposal effectively
removes any perceived differences in PURPA implementation and results in
Washington rates that indisputably reflect Washington state policy decisions.
Staff and Boise claim that the Company's proposal is based on the "physical
flow of power" and not cost causation.3l How do you respond?
I disagree with this characterization. In my testimony, I stress the fact that the out-of-
state QFs provide energy and capacity to serve Washington customers because that
rr Testimony of David C. Gomez, Exhibit No. DCG-lCT at l0; Responsive Testimony of Bradley G. Mullins,
Exhibit No. BGM-lCT at25.
- . .Reb-uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 32
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fact-which is undisputed--{emonstrates that Washington customers are benefiting
from the QFs. As I discuss above, if Washington customers are receiving energy and
capacity from these QFs, along with all of the other benefits discussed, then it is
reasonable for Washington customers to pay the fullcosts of the QF PPAs.
Otherwise, Washington customers are receiving the benefits without paying the
associated costs. Thus, the Company's proposal is consistent with principles of cost-
causation.
Staffalso discounts the fact that the Commission has allowed Avista
Corporation dlbla Avista Utilities (Avista) to recover the full costs of out-of-state
QF PPAs in Washington rates, claiming that the Commission has not always
relied on cost causation when allocating costs across multiple states.32 Staff
claims that the Company's out-of-state QF costs are higher than Avista's and
therefore must be situs assigned. Do you agree?
No. There is no principled basis to allow one Washington utility to recover out-of-
state QF costs while denying Pacific Power recovery of the same types of costs.
PURPA contains no materiality threshold governing cost recovery. Consistency in
regulation requires consistent treatment for all utilities. Simply pointing out that
Avista has had fewer out-of-state QFs does not support differing treatment.
A.
12 Testimony of David C. Gomez, Exhibit No. DCG-lCT at
- . .Reb-utta-lJestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, S implot/Clearwater
Page 33
Exhibit No. GND-41
Page 22
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Staffalso claims that the Commission can disregard cost causation based on the
degree to which state-specific policies may be driving the avoided cost prices. To
support this claim, Staff relies on a 1983 Washington Water Power Company
order regarding the allocation of costs for an Idaho QF PPA.33 Does that order
support StafPs position in this case?
No. Contrary to Staff s claim that the Commission situs assigned the ldaho QF PPA
costs to ldaho, a careful reading of the Commission's order shows that the
Commission did not situs assign the QF costs at all. Rather, the Commission
determined that the avoided costs in the QF PPA were excessive and disallowed cost
recovery of the amounts that exceeded Washington Water Power's avoided costs. In
other words, the Commission applied the Company's alternative proposal and re-
priced the QF PPA at Washington avoided cost prices.
What is the basis for your conclusion that the Commission re-priced the QF PPA
at Washington's avoided cost prices?
The issue presented in the case was whether Washington Water Power's proposed
rate revision, which would have included the full Washington-allocated costs of the
QF PPA, was just and reasonable. The Commission observed that, "[i]n reaching this
ultimate determination, the commission must make the underlying determination
whether the proposed purchase agreement is based on a proper methodology to
calculate the avoided cost as defined by federal and state laws and rules."34 Thus, the
r3 Testimony of David C. Gomez, Exhibit No. DCG-lCT at l0 (citing lVash. L/tils. & Transp. Comm'n v. Ll/ash.
Wqter Power Co., Cause No. U-83-14, Second Suppl. Order, 56 P.U.R.4th 615 (Nov. 9, 1983)).la W'ash. Utils. & Transp. Comm'n v. LVash. Water Power Co., Cause No. U-83-14, Second Suppl. Order, 56
P.U.R.4th 615, 1983 WL 909042 at 2 (Nov.9, 1983).
- . .Reb.uttal festimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, S implot/Clearwater
Page 34
a.
A.
a.
A.
Exhibit No. GND-47
Page 23
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a.
Commission analyzed whether the avoided cost prices in the QF PPA were consistent
with PURPA. The Commission did not simply situs assign the costs to Idaho.
In the Washington Water Power case, Staffconcluded that the rates in the QF
PPA were higher than Washington Water Power's avoided cost and therefore
inappropriate. The Commission agreed, concluding that the "amount to be paid under
the purchase agreement is in excess of properly determined avoided costs."35 Thus,
the Commission disallowed cost recovery of the amounts that exceeded the avoided
cost price as determined by the Commission. Applying the same standard to this case
would require approval of the Company's Washington re-pricing proposal.
Stafftestifies that in the Washington Water Power case, the QF PPA "pricing
and terms were driven by Idaho state policies at the time."36 Do you agree with
this characterization of the order?
No. Nowhere in the order does it suggest that the avoided cost price in the QF PPA
was the result of Idaho state policies. In addition, Staff testifies in this case that once
the Commission chose to situs assign the costs to ldaho, the ldaho commission
accepted that decision. Again, however, the Commission did not situs assign the
costs to ldaho, and the order says nothing about how the Idaho commission responded
to the Commission's order.
Staff and Boise reject the Company's alternative proposal to re-price the out-of-
state QF PPAs as if they were Washington QF PPAs. What is the basis for their
rejection of this proposal?
The parties argue that this proposal is inconsistent with cost causation and merely
A.
a.
A.
)s Id. at8.
16 Testimony of David C. Gomez, Exhibit No. DCG-lCT at 13 n.24.
- . .Reb,uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 35
Exhibit No. GND-4'I
Page 24
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discounts the cost impact of state policy decisions made by California and Oregon.37
Boise also claims that the Washington re-pricing proposal still burdens Washington
customers with other states' energy policies because there is no way to know if the
out-of-state QFs would have been developed if they had been subject to Washington's
PURPA policies.38
Does the Company's re-pricing proposal require Washington customers to pay
rates that reflect policy decisions made by other states?
No. Re-pricing the QF PPAs at Washington avoided cost prices mitigates concerns
that the avoided cost prices for the QF PPAs are driven by policy choices made by
other states. The use of the avoided cost pricing for QF PPAs is intended to keep
customers indifferent to the QF transaction. If the QF PPAs are re-priced at the
amount that this Commission has found will result in customer indifference, then
customers will be no better or worse off than they would be without the QF PPA.
The parties' concerns that the re-pricing proposal still reflects other state's policy
decisions has merit only if one assumes that the Commission's avoided cost prices are
excessive. The re-pricing proposal, therefore, ensures that Washington rates reflect
only the decisions of Washington policy makers.
Doesn't the fact that customers rates will increase by $7.6 million under your re-
pricing alternative suggest that the parties' concern has merit?
No. The fact that customer rates will increase if they pay the avoided cost prices
determined by the Commission suggests that situs assignment of California and
37 Testimony of David C. Gomez, Exhibit No. DCG-lCT at l5-16; Responsive Testimony of Bradley G,
Mullins, Exhibit No. BGM-lCT at29-30.
38 Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at 30.
Exhibit No. GND-47
Page 25
_ . .Reb-uttal festimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 36
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Oregon QF PPAs has allowed Washington customers to receive benefits for which
they have not paid.
Is there any precedent for this type of re-pricing?
Yes. As discussed above, the Commission used this approach in the 1983
Washington Water Power case relied on by Staff. It is also my understanding that the
North Carolina Utilities Commission (NCUC) took this same approach to a QF PPA
that was approved by the Virginia State Corporation Commission (VSCC). The
NCUC analyzed the QF PPA and concluded that the pricing exceeded the utility's
actual avoided costs.3e The NCUC therefore denied cost recovery of the amount that
the NCUC found to be greater than the utility's avoided costs. It is my understanding
that on judicial review, the North Carolina Supreme Court affirmed the NCUC's
order, concluding that the disallowance'odoes not violate PURPA to the extent it only
excludes the amount above avoided costs."40
I also understand that the OPUC approved a stipulation for Idaho Power
Company that required Idaho Power to re-price its Idaho QF PPAs to reflect Oregon's
non-levelized pricing policy.ar
Has any party alleged that the Washington avoided cost prices used in the re-
pricing alternative proposal do not accurately reflect the Commission's avoided
cost prices in effect at the time the out-of-state QFs were executed?
No. There is no basis in the record to conclude that the re-pricing does not reflect the
'n Re N. Carolina Power, E-22, SUB 333, 1993 WL216264 (Feb.26, 1993) aff'd sub nom. N. Carolina Power,
450 S.E.2d 896.
oo State ex rel. Utilities Comm'n v. N. Carolina Power,338 N.C. 412, 450 S.E.2d 896, 900 ( 1994). Importantly,
as I discuss above, since this case, FERC has been clear that PLIRPA prohibits inflating the avoided cost price
as the VSCC apparently did to promote state policies.
at Re ldaho Power Co.,DocketNo. UE 257,Order No. l3-166 (May 6,2013).
a.
A.
- . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, S implot/Clearwater
Page 37
ExhibitNo. GND-47
Page 26
I costs that would have been incurred if the out-of-state QF PPAs had been executed in
2 Washington.
3 Q. Staff and Boise both reject the Company's alternative load decrement proposal
4 because they claim it is based on power flows, not cost causation.a2 How do you
5 respond?
6 A. The load decrement approach is consistent with cost causation. No party disputes that
7 the out-of-state QFs serve Washington customers. Washinglon customers, however,
8 are not paying their fair share of the costs by paying only current market prices. The
9 load decrement alternative is intended to account for this fact by allocating additional
l0 costs to Washington to reflect the benefits Washington customers receive.
I I a. Boise claims that the load decrement approach is unreasonable because it would
12 assign more transmission costs to Washington customers even though the
l3 presence of QFs in California and Oregon does not reduce those states' use of
14 the Company's transmission network.a3 Does this claim have merit?
l5 A. No. Again, no party disputes that the QFs located in California and Oregon serve
16 Washington customers. As discussed above, Boise's trade group, ICNU, previously
17 testified before the OPUC that distributed generation, like the out-of-state QFs,
l8 typically decreases the need for transmission because the electricity is generated
l9 closer to load. This is particularly true for the out-of-state QFs because they are
20 typically located closer to Califomia and Oregon load and therefore use less
2l transmission to serve that load. So it is reasonable to credit out-of-state customers for
22 reduced transmission usage due to the QF development in those states.
a2 Testimony of David C. Gomez, Exhibit No. DCG-lCT at l5; Responsive Testimony of Bradley G. Mullins,
Exhibit No. BGM-lCT at29.o' Responsive Testimony of Bradley C. Mullins, Exhibit No. BGM-lCT at29.
_ . .Rebuttal lestimony of Gregory N. Duvall Exhibit No. GND-47Exhibit No. 204
case Nos. Ipc-E-15-01, AVU-E-15-01, PAC-E-15-03 Page 27
D. Reading, Simplot/Clearwater
Page 38
I Q. Boise claims that it would be unjust, unreasonable, and illegal to include the
2 costs of the out-of-state QF PPAs in rates, in part, because the Commission does
3 not have jurisdiction over the QFs.aa Is it your understanding that the
4 Commission must have jurisdiction over PPA counterparties to allow cost
5 recovery of the PPAS in rates?
6 A. No. Most, if not all, of the Company's long-term PPAs are with counterparties that
7 are not public utilities regulated by the Commission. Nevertheless, the costs of these
8 PPAs are regularly recovered in rates. In addition, PURPA specifically exempts QFs
9 from regulation by state utility commissions.
10 a. What is the Company's recommended treatment of the costs associated with
I I California and Oregon QF PPAs in west control area NPC?
12 A. The Company recommends that the Commission allow the Company to include the
13 costs of California and Oregon QF PPAs in west control area NPC in the same
14 manner as all other west control area generation resources, with a portion of the costs
l5 allocated to Washington customers. Altematively, the Company proposes the out-of-
16 state QF PPAs be re-priced using Washington avoided cost prices and then included
17 in the determination of west control area NPC or that the Commission adopt the
l8 proposed load decrement adjustment.
19 Energy Imbalance Market
20 a. Please describe Boise's adjustment to NPC related to the EIM.
2l A. Boise proposes to reduce Washington NPC by more than $5 million based on the
22 Company's participation in the EIM, while also including certain ElM-related costs.
23 Boise proposed this NPC reduction in October 2014 before the EIM even began
oo Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at 25.
- . .Reb,uttal Jestimony of Gregory N. DuvallExhibit No. 204
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 39
Exhibit No. GND-47
Page 28
a.
A.
Does this conclude your rebuttal testimony?
Yes.
,.r,r*fktsltdfestimony of Gregory N. Duvall
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, SimploUClearwater
Page 40
ExhibitNo. GND-47
Page 67
BEFORE TFM
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC.E-I5.01, AVU-E.I 5.0I, PAC.E.I 5.03
J.R. SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBITNO.2O5
ftffi*.
An IDACORP Companv
DONOVAN E. WALKER
Lced Gounrcl
dwal kcn6[d ahoorycr. com
April 15, 2015
VIA HAND DELIVERY
Jean D. Jewell, Secretary
ldaho Public Utilities Gommission
472 West Washington Street
Boise, ldaho 83702
Re: Energy Sales Agreements Termlnations
Gase No. IPC-E-1+28, Clark Solar 1, LLC
Case No. IPGE-1+29, Clark Solar 2, LLC
Case No. IPC-E-1+30, Clark Solar 3, LLC
Case No. !PGE-1+31, Clark Solar 4, LLC
Dear Ms. Jewell:
On April 6, 2015, ldaho Power Company ("ldaho Powef) terminated the Public
Utility Regulatory Policies Act of 1978 (.'PURPA") Energy Sales Agreements ("ESAs')
with each of the above-referencd PURPA qualiffing faclllties ("QF'). Each of the
referenced QF ESAs was approved by the ldaho Public Utilities Commission
('Commission') by Order, as noted in the table below.
Profect Gase Number Order Number Datr of Order
Clark Solar 1, LLC IPGE-14-28 Order No. 33208 01/08/15
ClarkSolar2, LLC IPG-E-14-29 OrderNo.33209 01/08/15
Clark Solar 3, LLC IPGE-1+30 Order No. 33204 01/08/15
Clark Solar 4, LLC IPC-E-1+31 Order No. 33205 01/08/15
Enatas to Oder Nos. 33208 and 33209 were issued on January 9, 2015.
The ESAs require that a Security Deposit be posted within 30 days of final non-
appealable Commission orders approvlng the ESAs. The required Security Deposits
were not paid, and ldaho Power provided Notice of Default and Material Breach on
March 2,2015. Subsequently, ldaho Power and the projects' developer, lntermountain
Energy Partners, LLC, entered into an agroement (attached hereto as Attachment 1)
1221 W. ldaho st. (83702)
P.o. Box 7o Exhibit No. 205
Case Nos. rpc-e- r s-o f,"hVB-8213 -o r, pAC-E- I s-03
D. Reading, Simplot/Clearwater
Page I
Jean D. Jewell
April 15,2015
Page 2ot 2
setting forth the agreed to provisions by which the prolects were to cure the Material
Breach of thE ESAs. The Security Deposits were not so posted for the above-
referenced Clark Solar proiects; thus, the associated ESAs were termlnated as of April
6, 2015. The Security Deposits for the Mountain Home Solar and Pocatello Solar
projects were paid according to this agreement and thus were not terminated.
To keep the Commission apprised of these terminations, ldaho Power has
enclosed an original and four (4) courtesy copies of this letter and its attachment fur
your convgnience. Please contact me if 1ou have any comments, questions, or
@noems.
DEVV:csb
Enclosurcscc: Dean J. Miller (w/encl.) - via e-mail
Rick Sterling (dencl.) - via e-mail
Donald L. Howell, ll (w/encl.) - via e-rnail
novan E. Walker
Exhibit No. 205
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page2
<EHH&,
An toAcoFP companY
DOiIOVAI{ E.WALKERlredCounrl
March 17,2015
loe@mdevlfr-mille r. com
Dean J. Mller
McDevitt & Mlller LLP
420 W. Bannock Street
P.O. Box 256+83701
Boise, ldaho 83702
VIA ELECTRONIC TIAIL
Re: Securlty Deposits - Mountain Home Solar 1, Pocatello Solar 1, Clark
Solar 1, Clark Sohr2, Cla* Solar 3, Claft Solar4.
Joe:
ldaho Ponrrcr ls in rcceipt of the momo fiom Mark van Gulik dated Marct 17,
2015, regadlng the speclflc anangements being pureued by lntermountain Energy
Partners ("lEP')to cure the material brsach of the Energy Sales Agreements ("ESA')fur
each of the above referenced solar projects "as expedltlously as possible."
ldaho Pourcr will aeept your proposed schedule of erents outlined ln your March
17, 2015, memo urhlch outlines actlvltles startlng today to securB the necessary
deposfts ard oontinulng through the statod deadfines of March 31, 2015, fur Mountaln
Home Solar and Pocatello Solar- and April 3, 2015, for Glark Solar 1 through 4.
ldaho Power will further accept the proposal of a "Non-Appealable' agr€emont
and provlslon that lf the deposlts are not pald ln accordance wlth these dates, that the
Energy Salee Agrcements will immedlately termlnate, and that IEP will not contest the
termlnatlon at the ldaho Publlc tltilities Commieelon, or eleewhere. Becauso of the
shortness of time before tomonou/e ESA termlnatlon deadline, please let thlg letter
serve as both parties'written acknodedgement of thls agrcement:
Consequently, both ldaho Power Company and lntermountain Energy Partners
hereby egreo that the final and definitiw deadllne wlth w?rlch IEP ls to cur€ the meterial
breach of the ESAa for each of the above rcferencad colar prolecls under oontract wlth
ldaho Pourcr is March 31, 2015, for Mountaln Home Solar and Pocatello Solar - end
April 3, 2015, for Clark Solar 1 through 4, ae eet forth ln lEPs March 17,2015, momo,
lncorporated herein by thls refercnce.
IEP shall cause the approprlate amount of security deposrt as referencsd ln
each projec't's respectve ESA, as well as in ldaho Powe/s March 2,2015,l,lotlce of
l22l W ldaho 5t (8l7o2l
PO Box r0
8oi!e, lO 83707
Exhibit No. 205
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, SimPlot/Clearwater
Page 4
Dean J. Mlller
March 17,2015
Page2ot 2
Default Matedal Breach - and ldaho Polre/s March 4, 2015, Notloe to Terminate, to
be posted on or before S:fi) p.m., mountrain tlme, on Tuesday, Marct 31, 2015, forthe
Mountaln l-lome Solar and Pocatello Solar proJects - and on or before April 3, 2015, for
Clarlt Solar 1, Clart Solar 2, Clark Solar 3, and Clark Solar 4. lf the required security
deposlt ls not paid by these deadllrcs, then each aasoclated ESA wlll immediately
terminate. IEP wlll acoept sald temlnatlon and shall not contest sald termination ln any
manner wtrat-so-ewr, elther ln law or egulty, before the ldaho Publlc Utllltles
Commission or any otherforum. ldaho Poupr understande from lEFe March 17, 2015,
memo, and fiom lts oonwrtatlons wlth Mr. van Gullk, and Mr. Mlller, that the r€quard
securlty wlll be posted ln cash. lf an altematiw mehod is utllzed (1,e., lete(s) of credit
or parent guanantees) then the necessary anangomenb and approvals of such
altematlw meffitods must be oompleted on or beforo the deadllne, or th€ deadline shall
be deemed to have NOT been met.
lf thls ls agreeable, please execute thls letter below and retum a slgned copy
back to me.
ldaho Poner Company
Agreed to and Acceiled by, on behatf of lntermountaln Energy Partners:
DEI/\I:ccb
oc:
Exhibit No. 205
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, SimPlot/Clearwater
Page 5
6-novan E. Wa'lker
CERTITICATE OF SERVICE
I HEREBY CERTIFY that on the 23rd day of April, 2015, a true and
correct copy of the within and foregoing DIRECT TESTIMOI{Y OF DR. DON
READING ON BEHALF OF CLEARWATER PAPER CORPORATION and the J.R.
SIMPLOT COMPANY was served as shown to:
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington
Boise, Idaho 83702
i ean. i ewell@puc. idaho. eov
Donald L. Howell, II
Daphne Huang
Deputy Attorneys General
Idaho Public Utilities Commission
472 West Washington
Boise, ID 83702
don. howell@puc. idaho. eov
daphe. huane(apuc. idaho. sov
C. Tom Arkoosh
TWin Falls Canal Company
North Side Canal Company
American Falls Reservoir District #2
Arkoosh Law Offices
8O2 W Bannock Ste 900
Boise ID 83702
tom. arkoosh@arkoosh. com
Erin Cecil
Arkoosh Law Offices
erin. cecil@arkoosh. com
Ben Otto
Idaho Conservation League
710 N 6th
Boise ID 83702
bo tto(Eidahocon servation. org
X Hand Delivery
_U.S. Mail, postage pre-paid
_ Facsimile
_ Electronic Mail
_ Hand Delivery
_U.S. Mail, postage pre-paid
_ Facsimile
X Electronic Mail
_ Hand Delivery
_U.S. Mail, postage pre-paid
_ FacsimileX Electronic Mail
_ Hand Delivery
_U.S. Mail, postage pre-paid
_ Facsimile
X Electronic Mail
Leif Elgethun PE LEED AP _ Hand Delivery
Intermountain Energr Partners LLC _U.S. Mail, postage pre-paid
PO Box 7354 _ Facsimile
Boise lD 83707 X Electronic Mail
le if@ site basedenerqv. co m
Dean J Miller _ Hand Delivery
McDevitt & Miller LLP _U.S. Mail, postage pre-paid
PO Box 2564 _ Facsimile
Boise lD 83702 X Electronic Mail
i oe@mcdevitt-miller. com
Daniel E Solander _ Hand Delivery
Yvonne R. Hogel _U.S. Mail, postage pre-paid
PacifiCorp/dba Rocky Mountain Power _ Facsimile
201 South Main Street Ste 2400 X Electronic Mail
Salt Lake City UT 841 I 1
daniel. solander@pacifi corp. com
wonne. hoqel@pacifi corp. com
datareque st@pacifi corp. com
Ted Weston _ Hand Delivery
Roclry Mountain Power _U.S. Mail, postage pre-paid
201 South Main Ste 2300 _ Facsimile
Salt Lake City UT 84111 X Electronic Mail
ted.weston@pacifi corp. com
Kelsey Jae Nunez _ Hand Delivery
Snake River Alliance _U.S. Mail, postage pre-paid
PO Box l73l _ Facsimile
Boise ID 83701 X Electronic Mail
knune4E sn ake riveralli an ce . o rq
Ken Miller _ Hand Delivery
Snake River Alliance _U.S. Mail, postage pre-paid
[e-mail] _ Facsimile
X Electronic Mail
Donovan E. Walker
Lisa A. Grow
RandyAllphin
Idaho Power Company
l22l West tdaho Street
Boise,ID 83702
dwalke r(Eidahopowe r. com
[e-mail]
rallphin@idahopower. com
do ckets(Eidah opowe r. com
Clint Kalich
Avista Corporationl4ll E Mission Ave MSC-7
Spokane WA 99202
clint. kalich@avistacorp. com
Michael Andrea
Avista Corporationl4tl E Mission Ave MSC-23
Spokane WA 99202
michael. andrea@avistacorp. com
Scott Dale Blickenstaff
The Amalgamated Sugar Company LLC
1951 S Saturn Way Ste 100
Boise ID 83702
s blicken staff@amalsusar. c o m
Richard E. Malmgren
Micron Technologr Inc
800 South Federal Way
Boise ID 83716
remalmqren@micron. com
Frederick J. Schmidt
Pamela S. Howland
Holland & Hart LLP
377 South Nevada Street
Carson City NV 89701
fschmidt@hollandhart. com
_ Hand Delivery
_U.S. Mail, postage pre-paid
_ Facsimile
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_ FacsimileX Electronic Mail
Matt Vespa
Sierra Club
85 Second St 2nd Floot
San Francisco CA 94105
matt. ve spa@sierraclub. orq
Eric L. Olsen
Racine, Olson, Nye, Budge & Bailey,
chd.
PO Box 1391
Pocatello, ID 83204- 139 1
[e-mail]
Anthony Yankel
29814 Lake Road
Bay Village, OH 44140
[e-mail]
Ronald L. Williams
Williams Bradbury, PC
1015 W. Hays St
Boise, lD 83702
ron@williamsbradbury. com
Irion Sanger
Sanger Law, PClllT SW 53.4 Avenue
Portland, OR 97215
[e-mail]
Andrew Jackura
Camco Clean Energr
9360 Station Street, Suite 375
Lone Tree, CO 80124
andrew. i ackura@camcocleanenergv. com
_ Hand Delivery
_U.S. Mail, postage pre-paid
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Signed\
Nina M.