20150422Beach Direct.pdf

Benjamin J. Otto (ID Bar # 8292)
710 N 6'h Street
Boise,ID 83701
Ph: [phone] x12
Fax [phone]
[e-mail]
MattVespa (CA Bar #222265)
Sierra Club
85 Second St., 2nd Floor
San Francisco, CA 94105
Ph: (als) 977-57s3
Fax [phone]
[e-mail]
Attorneys for the ldaho Conservation League and Sima Club
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY TERMS
AND CONDITIONS OF PURPA PURCHASE
AGRTEMENTS
IN THE MATTER OF AVISTA
CORPORATION'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
IN THE MATTER OF ROCKY MOUNTAIN
POWER COMPAI.IY'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
Idaho Conservation League and the Sierra Club
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
CASE NO. AVI.]-E-I5-OI
CASE NO. PAC-E-15-03
Direct Testimony of R. Thomas Beach
April23,2015
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TABLE OF CONTENTS
Executive Summary. .........i
I. Introduction. .. . . .. ... . .. . .. . ..1
[. Background on PURPA.......... .............2
III. The Term of PURPA Contracts. ........6
ry. The Commission's IRP Method Is Working Well.... ...........11
V.Ratepayer Benefits from Fixed-price PURPA Generation .......13
a. REC revenues / avoided carbon mitigation costs....... ............15
b. Hedgingbenefits. ....16
c. Market price mitigation. ......20
d. Capacityoptionality .........22
e. Economic development........... .............24
f. A window of opportunity to procure low-cost solar. ........24
System Reliability. .........26
Refinements to the IRP Method....... .......29
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Exhibits
ICL/SC-3OI
ICL/SC-302
ICL/SC-303
Curriculum Vitae of R. Thomas Beach
Selected Discovery Responses from Idaho Power
Fact Sheet from CALISO/NV Energy on the Energy Imbalance Market
EXECUTIVE SUMMARY
Idaho Power has filed a Petition asking the Commission to reduce from 20 years to two
years the term of power purchase contracts with large renewable generation projects developed in
its service territory under the Public Utilities Regulatory Policies Act (PURPA). Idaho Power is
concerned that, if the 2D-year term is retained, it may have to execute up to 885 MW of
additional contracts with solar projects in Idaho. The utility has expressed concerns with the lack
of need, the cost, and the system reliability impacts of this additional renewable generation.
The Idaho Conservation League and the Sierra Club oppose Idaho Power's Petition.
First, it is clear that the intent of the utility's Petition is to make it impossible to finance
additional solar projects in its service territory. Capital-intensive solar projects cannot be
financed with trvo-year contracts. It is questionable whether such a step complies with the legal
requirements of PURPA to encourage the development of qualifring renewable generation that
can be developed at the utility's avoided costs. If Idaho Power does not want to comply with its
PURPA obligations, there are well-established ways for the utility to replace its traditional
PURPA obligation and for the state of Idaho to assume greater control over utility procurement
of renewable generation in the state. However, these alternative means will require fundamental
changes to the energy markets in Idaho.
Second, the prices in PURPA contracts are set based on the utility s avoided costs, that is,
on the costs that the utilitywould incur for the same amount of power if it did not purchase the
PURPA generation. As a result, Idaho Power's ratepayers will be indifferent, on a forecast basis,
to the purchase of the additional solar generation. Idaho Power claims that it is too rislcy and
unnecessary to make these long-term commitments. This testimony responds to these
arguments, and shows that this fixed-price renewable generation will offer significant benefits to
Idaho Power's ratepayers in addition to avoiding higher cost power, including:
. Low-priced solar generation. There is a limited window of opportunity for Idaho Power
to purchase low-cost solar generation before the 30olo federal investment tax credit expires
at the end of2016.
. REC sales revenues. Idaho Power will gain additional revenues from the sale of the
renewable energy credits (RECs) associated with this power, or, alternatively, from
reduced costs to comply with future regulations limiting the carbon emissions from Idaho
Power's system.
. Hedging benefits. Fixed-price power hedges against future volatility in energy market
prices.
. Lower market prices. Zero-variable-cost renewable generation will reduce energy market
prices in the West generally.
Capacity options. The solar generation will provide a new capacity option that will have
value if existing coal-fired capacity is retired earlier than expected.
. Economic development. The potential solar projects represent an investment of about
$2.7 billion in clean energy infrastructure in Idaho Power's service territory in the near
future, thus providing economic benefits associated with this new development of
modern clean energy facilities.
This testimony quantifies each of the above benefits. These significant benefits, combined
with the avoided cost pricing for the additional solar generation, mean that this generation will
offer significant net economic benefits to energy consumers in Idaho, regardless of whether this
renewable generation serves Idaho consumers or helps neighboring states to complywith their
renewable portfolio standards.
ICL and the Sierra Club also address Idaho Power's concerns with the system reliability
impacts of additional solar generation. Significant studies have been conducted in recent years of
the operational and reliability impacts of integrating high levels of wind and solar generation on
the Western Electricity Coordinating Council (WECC) grid. A much higher penetration of solar
generation is feasible in the WECC than what would result from these solar contracts. Changes in
the energy markets in the WECC already are underway to facilitate renewables integration, such
as the energy imbalance market that began operations in November 2014. By the end of 2015,
utilities that operate in all of the states that neighbor Idaho will be participating in this market.
The Commission's IRP method for setting avoided cost prices provides for regular
updates ofavoided cost prices to reflect changing loads, natural gas prices, and the need for
generation. As a result, the avoided cost prices for solar have declined as additional PURPA
generation has been added. Further updates of these prices are likely before the additional solar is
approved, which is likely to result in even lower prices. At the indicative prices for the additional
solar generation,Idaho Power will be obtaining this renewable generation at a reasonable price
compared to solar contracts elsewhere in the U.S.
Finally, ICL and Sierra Club suggest that the Commission consider changing the IRP
method to allow more frequent updates to Idaho Power's capacity position. This would produce
even more accurate avoided cost pricing in the future, and at least partially address Idaho Power's
concerns in this regard.
I. INTRODUCTION
2 Q: Please state your name, address, and business affiliation.
3 A: My name is R. Thomas Beach. I am principal consultant of the consulting firm
4 Crossborder Energy. Mybusiness address is 2560 Ninth Street, Suite 213A, Berkeley, California
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7 Q: Please describe your erqrerience and qualifications.
8 A: I have over 30 years of experience in utility analysis, resource planning, and rate design. I
9 began my career at the California Public Utilities Commission, working from 1981-1984 on the
l0 initial implementation in California of the Public Utilities Regulatory Policies Act (PURPA) of
I I 1978.Lthen served for five years as an advisor to three CPUC commissioners. Since entering
12 private practice as a consultant in 1989,I have served as an expert witness in a wide range of
13 utility proceedings before many state utility commissions. This includes sponsoring testimony on
14 PURPA-related issues in state regulatory proceedings in California, Oregon, Nevada, North
15 Carolina, and Vermont. Prior to this experience, I earned degrees in English and Physics from
l6 Dartmouth College and a Masters in Mechanical Engineering from the University of California,
17 Berkeley. My curriculum vita is attached to this testimony as Exhibit ICL/SC-301.
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19 Q: On whose behalf are you testifring in this proceeding?
20 A: I am appearing on behalf of the ldaho Conservation League (ICL) and the Sierra Club.
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22 ICL intervened in this case due to ICL's continuing interest in the development of clean,
23 indigenous energy resources in Idaho through various means, including energy sales agreements
24 between independent developers and electric utilities under PURPA. Such development can
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I ensure that Idaho's electric system provides reliable, fair-priced service that protects the clean air,
2 clean water, and stable climate that are foundational public values for Idahoans. Accordingly, ICL
3 has a strong interest in the major change the Idaho utilities propose in the terms of their PURPA
4 agreements.
5 The Sierra Club is a national, non-profit environmental and conservation organization
6 dedicated to the protection of public health and the environment. Sierra Club has joined with
7 ICL in this case on behalf of itself and nearly 2,400 Sierra Club members who live and purchase
8 utility services in Idaho. Sierra Club's Idaho members have a direct and substantial interest in this
9 proceeding as a result of its potential impact on additional solar deployment in Idaho and on the
l0 environmental, health and economic benefits that would result from the addition of this
I I renewable generation to the Idaho electric system.
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13 Q: Have you previously testified or appeared as a witness before the Idaho Public Utitity
14 Commission?
15 A: Yes,I have. I testified on behalf of ICL in Case No, IPC-E-12-27 concerning proposed
16 changes to Idaho Power's net metering service.
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18 Q: Do you have any exhibits?
19 A: Yes. Exhibit ICL/SC-301 is my curriculum vitae. Exhibit ICL/SC-302 are certain discovery
20 responses from Idaho Power. Exhibit ICL/SC-303 is a fact sheet about the new Energy Imbalance
2l Market involving PacifiCorp, the California Independent System Operator (CAISO), Puget
22 Sound Electric, and NV Energy.
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24 II. BACKGROUND ON PURPA
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Q: Idaho Power's Petition generally describes the requirements of PURPA. Do you have
anything to add to this background?
A: Yes. ICL Witness Adam Wenner provides a more detailed legal analysis. As a consultant
with over 35 years of experience in this field, I offer the following economic perspective. Congress
enacted PURPA to encourage a new, free market for the independent development of generation
from resources that would reduce our nation's dependence on fossil fuels, with the goal of
increasing the energy security and independence of the U.S. PURPA required public utilities, who
enjoyed a state-sponsored monopoly in the generation market, to purchase power from
cogeneration and small renewable power producers, collectively called "qualifring facilities" or
QFs, at prices that could not exceed the utilities' "avoided cost." In the words of the statute,
12 avoided costs are "the cost to the electric utility of the electric energy which, but for the purchase
l3 from such cogenerator or small power producer, such utilitywould generate or purchase from
14 another source."' PURPA's must-take requirement at an avoided cost price was intended to offset
l5 the monopsony power of the utility as the sole buyer of generation in its service territory.
16 Congress limited purchase price to the utility's avoided cost in order to achieve a balance between
17 the interests of ratepayers and PURPA generators, so that the price would be both 'Just and
l8 reasonable to the electric consumers of the electric utility and in the public interest" and "not
19 discriminate against qualifring cogenerators or qualifring small power producers" in comparison
20 to the utility's other supply options. The FERC and the courts have found that a price set at 100%
2l of the utility's avoided cost satisfies this dual standard and the intent of PURPA to encourage QF
22 development.2 In essence, the economic design of PURPA was to simulate the outcome of a free
1 Section 210(d) of PURPA (92 Stat. j117, t6 U.S.C. 5 2601).2 rc C.F.R. S 292.304(b)(2); American Paper Inst., Inc. v. American Elec. Power Serv. Corp., 103 S. Ct
1921 (1983).
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I and open market that would encourage QF development, if QFs could offer generation at a
2 competitive cost equal to or less than the incremental cost to the utility of procuring power from
3 other sources. PURPA generation purchased at the avoided cost price would be reasonable for
4 the consumer because it would be no more expensive than if the monopoly utility had generated
5 the power itself or purchased it from another source.
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7 Q: PURPA was enacted almost four decades ago. Have Congress and the FERC enacted
8 significant changes to PURPA since then?
9 A: Yes. PURPA was the key first step in the development of independent power generation
l0 in the U.S. The success of this new industry in many states under the PURPA framework enabled
I I the creation, in the 1990s and early 2000s, of viable and less-regulated markets for electric
12 generation in many regions of the U.S. Over time, these markets have expanded to include, in
13 some states, competition in generation at both retail and wholesale levels, as well as non-
14 discriminatory access to electric transmission through regional transmission organizations
l5 (RTOs) with independent system operators of the transmission grid. In addition, many states
16 have enacted renewable portfolio standard (RPS) programs, based on states'traditional authority
17 over utility procurement, designed to provide long-term markets for the new renewable
18 generation that previously had been developed principally through PURPA. Responding to these
19 developments, Congress enacted the Energy PoliryAct of 2005 (EPAct), which implemented a
20 new Section 210(m) of PURPA. This section allowed a utilitF to petition the FERC for relief from
2l the "must purchase" requirement of PURPA if FERC found that QFs in that utility's territory
22 have access to sufficiently competitive wholesale markets for long-term sales of capacity and
23 electric energF.
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I Q: Have utilities in other states and regions successfully petitioned the FERC under Section
2 210(m) of PURPA to end the PURPA must-purchase obligation?
3 A: Yes. However, this has occurred in states that have opened their generation market to
4 substantial competition at the wholesale level. For example, when the major California investor-
5 owned utilities (IOUs) successfully petitioned the FERC for relief from the PURPA must-
6 purchase obligation for QFs larger than 20 MW, they were able to show that California had taken
7 the following steps to provide viable long-term wholesale markets for QF generation:
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9 . A CPuC-approved program for the IOUs to conduct competitive solicitations for
10 long-term contracts with at least 3,000 MW of existing or new cogeneration QFs;
11 . A state-enacted RPS that required the California IOUs to purchase 20o/o (now 33o/o) of
12 their generation from RPS-eligible renewable generators by 2020, implemented
13 through regular competitive solicitations to procure RPS generation under long-term
14 contracts ofup to 25 years;
15 . A resource adequacy program requiring the IOUs to purchase capacity from QFs and
l6 merchant generators to meet near-term resource adequacy requirements; and
17 . Non-discriminatory access to the transmission system and to an auction-based, day-
18 ahead wholesale energy market operated by a FERC-regulated RTO, the California
l9 Independent System Operator (CAISO).3
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2l It is important to note that the PURPA must-purchase obligation remains in place in California
22 (and in most other RTO/ISO footprints) for QFs up to 20 MW in size, and that the must-
3 Pacific Gas 6 Electric et al, 135 FERC T 61,234 (issued Iune 16, 201 1).
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1 purchase obligation can be re-instated if the FERC finds that long-term wholesale markets are no
2 longer available to QFs.
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4 Q: Idaho Power's Petition, at page 33, asserts that the RTOs in which the PURPA must-
5 purchase obligation has ended do not provide markets for wholesale sales longer than three
6 years, citing the testimony of William H. Hieronymous from Case No. GNR-E-ll-03, which is
7 attached to Idaho Power's Petition. Do you agree with this argument?
8 A: No. The flaw in this argument is that the key feature necessary to end the PURPA must-
9 purchase obligation is that renewable and cogeneration resources must have access to long-term
10 power purchase agreements. These new long-term markets are based on procurement programs,
1 1 principally RPS programs, sponsored by the states under their authority over utility
12 procurement, not through the RTOs. Again, the California RPS program noted above is an
13 example of such a state-sponsored RPS program that provides long-term contracting
14 opportunities for renewable QFs in California. 29 states have RPS programs, and an additional S
15 states have less stringent renewable portfolio goals; these 37 states include virtually all of the states
16 whose utilities operate within RTOs and have deregulated wholesale markets.a
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18 Q: Has the state of Idaho or electric utilities serving Idaho taken steps that might allow it to
19 petition for relief from the PURPA must-purchase requirements.
20 A: I am not aware of any such steps that have been taken in Idaho; instead, in this docket the
2l utilities are asking the Commission to make changes that would clearly frustrate the intent of the
22 state's PURPA program. The Petition and Ms. Grow's testimonyboth mention the possibility of
23 petitioning FERC for relief from the must-purchase obligation under Section 210(m), as well as a
a See www.dsireuse.org website data on RPS programs.
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range of other changes to Idaho's PURPA program modeled on changes that have been made in
California and Texas.t However, Idaho Power is not suggesting the pursuit of any of those
options at this time.6
In my judgement, most of these steps to substantially change the PURPA program in
Idaho would require the state to adopt a successor program, such as an RPS, to provide a viable
long-term wholesale market for QF generation, and also could require broader changes in the
wholesale markets in Idaho and perhaps in the region. Furthermore, even if some of these
changes to PURPA were judged to be desirable - for example, even if Idaho enacted an RPS in
order to provide more predictable, state-regulated development of renewable resources in Idaho
- the competitive market conditions necessary for their approval by the FERC do not yet exist in
Idaho. As a result, the longstanding PURPA framework, including the must purchase
requirement, will be a feature of the energy landscape in Idaho for the foreseeable future.
m.THE TERM OF PURPA CONTRACTS
Q: What is your recommendation on the utilities'proposal to reduce from 20 years to two
years the maximum term for prospective PURPA contracts for QF projects whose size exceeds
the cap for eligibility for the published PURPA rate?
A: The proposed reduction in the maximum term for these QF contracts should be rejected,
for the reasons presented below.
s Petition, at pp. 4-5: Grow Testimony, atpp. 14- 1 5.6 Petition, at p. 5: Grow Testimony, at pp. 15- 16.
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I Q: What is the first reason why Idaho utilities should continue to make a20-year contract
2 available to QFs?
3 A: As ICL Witness Adam Wenner explains, and I agree, a contract term of this length is
4 necessary to realize PURPA's policy goal of supporting QF development. I also fully agree with
5 Idaho Power's statement on page 8 of the Petition that "the maximum contractual term for a
6 mandatory purchase under PURPA is an extremely important term and condition of the contract
7 and sale." In fact, it is decisive - in my experience, states have successfully encouraged the
8 development of QFs when they have offered long-term (15-year to 35-year) contracts at known
9 avoided cost prices. In contrast, when only short-term (5 years or less) contracts have been
10 available, very few QFs are developed. As I will discuss below, the history of QF development in
11 Idaho and other states supports this conclusion. Developers of solar projects and other renewable
12 QFs will not be able to obtain financing for their projects if all that they can show the lender is
l3 that they have a customer for the power for just the first two years of a25-year project life. In
14 addition, the current indicative pricing for levelized avoided costs for a two-year solar contract
15 are about $29 per MWh, more than 500/o below the $60 to $64 per MWh range of avoided costs
l6 for the recently-approved 2}-year solar contracts.T As a result, removing the availability of a long-
17 term contract at avoided cost prices appears likely to make uneconomic QFs that could be
18 developed at avoided cost prices with a long-term agreement. Without an RPS or other state-
19 sponsored procurement program for renewable QFs, it becomes questionable whether Idaho
20 Power's proposed two-year maximum term for PURPA contracts adequately supports QF
2l development in its service territory, as PURPA requires.
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7 Based on data in Idaho Power Response to I.R. Simplot Production Request Question No. 3.
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Q: The Petition and the testimonies of Idaho Power's witnesses Ms. Grow and Mr. Allphin
present information on the long history of the development of PURPA projects in Idaho. What
do you observe about this history?
A: Virtually all of the QF projects successfully developed in Idaho have done so under power
purchase contracts with terms of at least 20 years. This includes the small hydro projects
developed in the 1980s and 1990s, the wind projects developed in 2010-2012, and the 461 MW of
solar projects that the Commission approved in2014-2015. Figure 1 illustrates this history,
showing the number and capacity of the QFs that have been successfully developed as a function
of the available term of QF contracts.
Figure 1: ldaho Power RenewableQR by ContractTerm
700
626.2
600
500
70
60
/too
300
200
100
3
=
0(,(!*E
o
30 -t
E
z
20
1980 - 1986
(35 year contracts)
l5il
1987 - 1995
{20 year contracB)
r Capacity MW
0.6 7
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19!16 - 2001
10
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2002 - 2015
(5 year contracts) (20 year contracts)
I Number of Contracts
l0
l1
T2
The history shown in Figure 1 is not surprising - renewable energy projects have no fuel costs
(except for biomass) but are capital-intensive, and, in my decades of experience I have observed
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that long-term contracts are essential to access financing on reasonable terms. This need for long-
term assurance of capital recovery is the same for QFs as it is for a utility that proposes to build a
new power plant and seeks Commission approval for long-term recovery of the plant's costs by
including them in rate base. This history suggests that, without long-term,2}-year contracts, QFs
will not be developed in Idaho.
Q: What other states provide similar histories?
A: California offered 20- to 3O-year PURPA contracts in the 1980s, with renewable QFs
provided fixed energy and capacity prices for up to the initial ten years of the contract. About
5,000 MW of renewable QF generation was developed in the state in the late 1980s; most of this
capacity is still operating today and now is the lowest cost generation available to the state's RPS
program. This development ceased when the long-term contracts were suspended in the late
1980s, and did not revive until after the enactment of the California RPS program in 2004, which
again made available long-term contracts of up to 25 years. As another example, the recent active
development of solar QFs in North Carolina is founded upon the availability of 15-year contracts
at known, fixed prices.
Q: Can you cite a recent example where another state commission has dealt with utility
requests to reduce the term of PURPA contracts?
A: Yes. Recently, the utilities in North Carolina asked the commission in that state to shorten
the term of PURPA contracts to a maximum of 10 years, a reduction of 5 years from the
maximum of 1S-year term that in recent years has resulted in significant development of solar
QFs in that state. The North Carolina Utilities Commission rejected this request, finding that the
term of QF contracts should be long enough to enable QF projects to be financed:
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While the Commission initiated this docket to investigate the need to alter avoided costs
determinations, the evidence presented by the buyers and sellers of QF power fail to justify
altering the Commission's earlier decisions on term length and related provisions. As
discussed earlier, a QF's legal right to long-term fixed rates under Section 210 of PURPA is
well established as a result of the FERC's I.D. Wind Orders. The FERC has made clear that its
intention in Order No. 69 was to enable a QF to establish a fixed contract price for its energy
and capacity at the outset of its obligation because fixed prices were necessary for an investor
to be able to estimate with reasonable certainty the expected return on a potential investment,
and therefore its financial feasibility, before beginning the construction of a facility. In her
responses to cross-examination questions about various Duke Energy Renewables projects,
DEC/DEP witness Bowman acknowledged the foregoing by stating that PURPA does not
require the best financing, just the ability to secure it.8
The circumstances that North Carolina faced - with the utilities strenuously claiming to be
overwhelmed by solar QF development - are very similar to those in Idaho today, so this decision
is directly relevant to this case.
Q: Idaho Power's testimony hightights that it is allegedly not allowed to consider "NEED"
in acquiring PURPA resources.'Instead of the draconian step of shortening the term of QF
contracts, what other steps could Idaho take in order to allow the state greater control over its
acquisition of renewable resources?
E North Carolina Utilities Commission , Order Setting Avoided Cost Input Parameters (Docket No. E- 100
Sub-140, issued December 31,2014), atpp. 19-20. Hereafter, "North Carolina Avoided Cost Ordei'.
e Petition,atp.27.
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I A: The Idaho Legislature could enable the state to exert more control of renewable
2 development by enacting an RPS for Idaho. This would allow Idaho utilities to show the FERC
3 that the state has created a long-term wholesale market for additional renewable generation to
4 serve consumers in the state. This showing would be important if the state's utilities were to
5 petition the FERC for relief from the PURPA must-take requirement under Section 210(m), as it
6 was for the California utilities. More generally, an RPS would provide an outlet for renewable
7 development that is under direct state control by the Legislature and the Commission. In states
8 that have RPS programs, when the RPS goal in reached, renewable developers and proponents
9 need to ask the state legislature or regulatory commission to increase the program target. For
10 example, this has already occurred several times in California, as successive RPS goals have been
I I reached.ro Control over renewable development largely passes to the state, and away from the
12 federal PURPA requirements. Although a state RPS does not automatically allow a utility in that
13 state to avoid the PURPA must-purchase obligation, it would make it more difficult for a would-
14 be QF to assert to the FERC that the utility has not done enough to promote QF development, if
15 the utility was in compliance with the state's RPS program. Further, as noted above, an RPS can
16 be an integral part of a showing under Section 201(m) to end the must-purchase obligation.
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18 Finally, an RPS would allow Idaho consumers to benefit directly from the extensive
19 renewable development that has already occurred in the state, and that could continue in the
20 future. Because Idaho has no RPS, and because Idaho Power either does not acquire or sells the
'0 California's initial RPS goal, enacted in 2004, had a goal of 2oo/o renewable generation by 2017. This
goal was later advanc ed to 20o/o by 2010, and then increased to the current 33o/o by 2020. Legislation has
been introduced this year for a further increase to 50olo by 2030. California's investor-owned utilities
acquire RPS resources through regular competitive solicitations in which new renewables are procured
under the dual standards of ( 1) least-cost and (2) best-fit to the needs of the utility. Each utility s need for
RPS generation is subject to an extensive planning process oyerseen by the California Commission, similar
to Idaho's IRP process.
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I renewable energy credits (RECs) associated with the renewable resources that it purchases, Idaho
2 Power cannot and does not claim that it serves its customers with this renewable generation.tt
3 The utility s Petition compares the amount of renewables on its system to the RPS requirements
4 in other western states that have RPS programs, but these comparisons are meaningless because
5 the RECs associated with this generation are not retired. As a result, renewable development in
6 Idaho supports the RPS programs in other states but does not provide new, clean generation to
7 Idahoans or add to the amount of renewable generation in the region as a whole.
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9 IV. THE COMMISSION'S IRP METHOD IS WORKING WELL
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11 Q: Do you agree with the Commission's conclusions in its recent orders approving solar
12 contracts that the IRP method of setting avoided cost prices for these contracts is working well?
13 A: Generally, yes. The IRP method allows the fuel price and load forecasts used in calculating
14 avoided cost prices to be updated every year. The Company also is able to include previously-
l5 approved QF contracts in these updates.r2 The result of such updates is that the price in solar
16 contracts has declined as fuel and load updates have occurred and as additional contracts have
17 been added, as shown in Table 3. The table reflects that the initial solar contracts used aldy 2013
l8 capacity sufficiency year," while in the contracts submitted in October 2014, the date of
19 sufficiency had been pushed out to luly 202l.ta
" The utility's Application and testimony discusses at length the substantial renewable development that
has occurred in Idaho under PURPA, but the utility carefully footnotes its text and figures with the
revealing disclaimer that "Idaho Power cannot represent to customers that they are receiving renewable
energy from the QFs." See Allphin Testimony, at p. 8, footnote 1; also, Petition, footnote to the figure on p.
11.
12 See Order No. 32697 atp.22.
13 See Order No. 33016.la See Order No. 33159.
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Table 3z Idaho Power Solar Contract Prices 15
The even lower indicative prices for the potential solar contracts Al and A2 indicates that Idaho
Power may be using a capacity sufficiency date that is even further in the future. It is my
" Data on approved contracts are from Idaho Power Response to Idaho Irrigation Pumpers Association
Production Request No. 11. Data on the potential contracts are from Idaho Power Response to Staff
Production Request No. 9.
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Contract Date Application Submitted 2D-year Price ($/MWh)
Approved Contracts
Grand View PV Solar Two 712512014 73.41
Boise City Solar 7lzsl20t4 72.\s
Simco Solar t012012014 63.94
Murphy Flat Power r012012014 63.80
American Falls Solar t0120120t4 63.61
American Falls Solar II t012012014 62.66
Orchard Ranch Solar t012012014 62.21
Mountain Home Solar t0lt7l20t4 61.43
Pocatello Solar I t0lt7l20t4 61.33
Clark Solar 2 101t7120t4 61.03
Clark Solar 4 Lult7l20t4 60.87
Clark Solar 3 r0lt7l20t4 60.67
Clark Solar 1 r0lt7l20r4 s9.97
Potential Contracts
Project Al s2.83
Project A2 s4.10
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I understanding that the IRP methodology prices will be further revised when Idaho Power files its
2 2015 IRP on fune 30,2015. Given that indicative solar contract prices are approaching $50 per
3 MWh, which is at the low end of solar PPA prices as reported by the Lawrence Berkeley National
4 Lab (LBNL),I6 it is not clear to me that all of the 885 MW of projects will be able to be developed
5 successfully at these prices. In fact, I reviewed Idaho Power's response to Simplot discovery
6 Question 4 and observe that, of the 885 MW of possible solar projects, consisting of 48 projects,
7 the Company can cite only 14 projects that have progressed far enough to receive indicative
8 prices and only I project that has a draft sales agreement.
9
10 In my judgement, the Commission should be pleased that the IRP method is working as
I I intended. As more solar capacity has been added, the avoided cost price has fallen based on Idaho
12 Power's capacity position and future need. It is simply not true that the Commission's avoided
l3 cost methodology fails to consider the future need for new capacity - as the need for capacity is
14 pushed further out into the future, the avoided cost price falls. It is basic economic principle that,
l5 as prices fall, fewer projects will be built. And it is also true that if additional solar can be
16 developed at the new, lower prices that reflect the utility's current need, then Idaho's consumers
l7 will benefit from additional renewable generation at even lower costs. As I will discuss in detail
l8 below, there are many benefits of this new renewable generation that are not included in the
19 avoided cost price. The Commission should reject Idaho Power's proposal to turn its back on
20 these benefits by reducing the term of these PURPA contracts, a step that essentially would relieve
2l the utility from its PURPA obligations. I share the perspective of Commission staffthat was cited
22 in Order 32697:
'u Bolinger, Mark and Weaver, Samantha, Utility-scale Solar 2013: an EmpiicalEstimate of Project Cost,
Performance, and Pricing Trends in the U.S at pp.26-31and Figure 16, (LBNL, September 2014) (Hereafter
'LBNL Solar Cost Report").
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I "[t]he proper mechanism for accounting for utility need is not to relieve utilities of
2 their obligation to purchase, but instead to establish prices for capacity and energy
3 that properly recognize the utilities' need, or lack of need, for capacity and energy."r'
4
5
6 V. RATEPAYER BENEFITS FROM FIXED-PRICE PURPA GENERATION
7
8 Q: Idaho Power alleges that the continued availability of long-term contracts "inflates the
9 polver supply costs borne by customers."'8 Do you agree with this contention?
10 A: No. Not only does Idaho's IRP methodology produce reasonable avoided costs that reflect
11 the utilities'needs, as I will explain below,Idaho Power's customers will realize significant
12 additional net benefits from the utility's purchase of renewable generation under PURPA -
13 benefits that are not included in the avoided cost price. These include:
14 1. REC sales revenues, or avoided costs for reducing carbon emissions
15 2. Hedging benefits
16 3. Market price mitigation benefits
17 4. Capacity optionality
l8 5. Local economic benefits
19 Further, Idaho Power's assertions that QF generation will displace less expensive generation are
20 simply not credible.
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17 Order No. 32697 atp. 19, citing Tr. at 1090.
18 Petition, at p. 2!,also, generalli, pp. 20-25.
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Generally, it is important to remember that the prices in these contracts are set based on
the best available estimate of the utility's avoided costs, that is, the costs which the utility would
incur if it did not buy from the QF, but instead generated the power itself or purchased it from
another source. Assuming that these estimates are as accurate as possible (which we will discuss
below), then by definition these contracts will not have an adverse impact on Idaho Power's
customers, because the utility s costs will be no different than if they had not purchased this
generation. Idaho Power's Petition and testimony present numerous figures and tables showing
how the utility s PURPA expenses are increasing significantly and would be even higher with the
885 MW of proposed solar contracts.re This data is irrelevant assuming that the proposed
contracts are priced at the utility s avoided costs, because the increased PURPA expenses will be
offset by corresponding reductions in Idaho Power's costs for the other resources that the new
PURPA generation will replace. Customers will be at least indifferent to the purchase of the
PURPA generation, which is the basic tenet of PURPA.
Q: Please respond to Idaho Power's assertion that this additional PURPA generation will
displace less expensive generation, such that "the Company's overall net power supply expense,
on a dollars per MWh basis, would increase, adversely impacting customers."2o
A: Significantly, when asked for the impact of these PURPA contracts on future retail electric
rates, the utility conceded that it had not done that analysis.2'
Further, the utility s allegation of adverse ratepayer impacts is not true, because the utility
is making apples-to-oranges comparisons among its generation costs. The cost of PURPA
le Petition, at pp.22-23; Allphin Testimony, Exhibit No. 7.
20 Petition, at pp. 23-25.
'' Idaho Power Response to StaffProduction Request No. 2, included in Exhibit IPC/SC-302.
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I generation is an all-in, long-term cost that includes both the energy and capacity provided by this
2 generation. Moreover, the QF power is delivered to Idaho Power within its service territory,
3 without incurring the cost of transmission from out-of-state locations or regional markets. For
4 example, the Company compares its PURPA generation costs to Mid-Columbia (Mid-C) market
5 prices ." The Mid-C prices do not include the costs of the transmission capacity (including, in the
6 future, Boardman-to-Hemingway) necessary to deliver Mid-C power to Idaho. In addition, the
7 comparison to general Mid-C prices does not consider that, in some peak hours, this power is not
8 deliverable to Idaho due to transmission constraints; in these hours, PURPA generation can
9 displace internal Idaho Power gas-fired peaking resources that are more expensive than Mid-C
10 prices.
11
12 Similar problems exist with the comparisons to the Company's coal, natural gas, and
l3 non-PURPA purchased power expenses." In response to ICL's discovery,Idaho Power
14 responded they provided only the fuel costs for coal and gas.'n Idaho Power's comparison
15 between PURPA prices and coal costs do not include the incremental capital or O&M expenses
16 associated with the utility s coal generation, or with the transmission costs to move this power
17 into Idaho. Likewise, the natural gas expenses do not include the incremental capital, natural gas
18 pipeline reservation costs, or O&M expenses associated with the utility's gas generation.
19 Moreover, the PURPA contract costs for the solar contracts will be fixed for the 2O-year contract
20 term, while the variable costs of coal, Bffi, and other purchased power will increase significantly
2l over the next 20 years. When costs are compared on an apples-to-apples basis and measured over
22 the full expected life of these contracts, the PURPA generation is no more expensive than the
22 Petition, at pp.23-24; also Allphin Testimony, Exhibit 10.2i P etitio n, at p. 24; also Allphin T estimo ny, Exhibit 8.
" Idaho Power Response to ICL Production Request No 5, included in Exhibit IPC/SC-302.
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I marginal or avoided cost of the generation that it will displace, as required by the Commission's
2 IRP method of setting avoided cost prices. In fact, for the reasons discussed below, the solar
3 contracts will offer benefits that will result in lower power supply costs for Idaho Power's
4 customers.
5
6 i. REC revenues / avoided carbon mitigation costs
7
8 Q: What other benefits do Idaho Power's customers realize from PURPA generation?
9 A: In the absence of an RPS, Idaho Power sells the renewable energy credits (RECs)
l0 associated with the renewable resources that it purchases, and the revenues from these sales are a
11 benefit for ratepayers. Pursuant to Commission Order No. 32697, QFs who sign long-term
12 contracts with pricing under the IRP method must supply 500/o of the associated RECs to Idaho
13 Power. And it is my understanding that Idaho Power sells any RECs the Company holds and
14 returns to revenue to customers. If the Commission reduces the maximum contract length so
l5 that future QFs have no opportunity to access project financing, then it is my understanding
16 Idaho consumers would not enjoy additional revenue from future QFs.
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18 Q: Does Idaho Power receive significant revenue from these REC sales that benefit its
19 ratepayers?
20 A: Yes. These revenues for 2010-2014 are shown in the following table:
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22 Table lz Idaho Power KEC Sales
Year REC Sales (Mv{h)Revenues ($ tutl REC Price ($/MWh)
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2010 808,862 4,495,724 $s.s5
20tt 596,225 6,517,833 $10.93
20t2 445,687 3,592,782 $8.06
20r3 251,774 564,378 $2.24
20t4 598,736 3,218,529 $s.38
Average 540,257 3,675,849 $6.80
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I expect that the purchasers of these RECs use them to meet RPS compliance obligations in
neighboring states in the West. All of the other states in the WECC have RPS programs or goals,
except for Wyoming.
It is my understanding that 95%o of the ldaho-jurisdictional revenues from these REC
sales is returned to consumers in Idaho. Based on this track record, the 885 MW of additional
solar contracts could add $7.8 million per year in additional REC revenues to the benefit of Idaho
Power customers.
Q: Will Idaho Power benefit if it retains the RECs associated with this generation?
A: Yes. If the RECs are retained and retired, then Idaho Power can claim a share of the
carbon emission reductions associated with this power. Assuming that the 885 MW of potential
solar contracts displace gas-fired generation at a heat rate of 8.0 MMBtu per MWh, and using the
carbon emission costs that Idaho Power assumed in its last IRP ($t+.0+ per ton in 2018,
escalating at3o/o per year), the value of Idaho Power's 500/o share of these reductions in carbon
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I emissions is about $7.2 million per year over the life of these resources, or about $4 per MWh.:
2 In the High Carbon case in the IRP ($lS per ton in 2018, escalating atgo/o per year), the value of
3 these carbon reductions is $28 million per year or $15 per MWh. I am not aware of what steps
4 Idaho Power may take to comply with the proposed federal carbon emission regulations under
5 Section 111(d) of the Clean Air Act, but these benefits can be considered a proxy for the future
6 compliance costs that the utility may avoid by increasing its purchases of renewable generation.
7
8 ii. Hedgingbenefits
9
10 Q: Idaho Power argues that "at a time of unprecedented changes in the technological,
1 1 economic, and regulatory landscapes faced by the electric industry today," it is risky for
12 consumers to commit to long-term fixed-price contracts. Do you agree?
l3 A: No. Based on my 35 years' experience in the energy industry in the western U.S., the
14 "landscape" has always been changing, and it is difficult to tell whether the changes on the
l5 horizon today are more unprecedented than they have been in the past. With any fixed-price
16 power purchase contract - and with any significant capital investment by the utility in generation
17 or transmission - there is always a risk that the alternatives will prove to be less expensive over
l8 the long-term. This is a risk that consumers bear with PURPA contracts, with other purchases in
19 wholesale markets, and with the alternative of utility-owned fossil-fuel plants whose capital costs
20 are largely fixed once they are approved for cost recovery through rate base and whose fuel costs
2l are subject to significant market risk. Idaho Power complains that the prices or terms of QF
22 contracts cannot be modified once they are signed, yet it is also difficult to modifr the costs for
'5 To be fair, any new sources of renewable or low-variable-cost generation will produce such benefits,
including Idaho Power's hydro repowering mentioned in the Application.
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1 utility owned generation included in the rate base once they have been authorized. If it is too
2 uncertain and too risky to forecast avoided cost prices for 20 years, then it is also too risky to
3 evaluate the merits of a new utility-owned resource (such as the planned Boardman-to-
4 Hemingway transmission line), or even to make decisions based on the long-term projections in
5 an Integrated Resource Plan.
6
7 The North Carolina commission recognized this in its recent avoided cost order,
8 concluding that the uncertainties in future energy markets will impact ratepayers regardless of
9 whether the utility contracts with QFs at avoided cost or builds its own resources:
l0 Failure to calculate accurately a utility's avoided cost means ratepayers will pay for the
I I additional energy and capacity whether the utility builds the plant and places it in rate
12 base or the utility pays QFs avoided cost rates. The Commission concludes that
13 establishing avoided cost rates based upon the best information available at the time
14 and making such rates available in long-term fixed contracts, as required by Section
l5 201 of PURPA should leave the utilities' ratepayers financially indifferent between
l6 purchases of QF power versus the construction and rate basing of utility-built
I7 resources.'u
18
19 Q: Do fixed-price contracts for renewable generation provide a benefit to consumers as a
20 hedge against future uncertainty and volatility in energy and fossil fuel markets?
2l A: Yes. The alternative to the PURPA contracts is reliance on marginal utility fossil
22 generation (mostly natural gas-fired) and/or market purchases, whose prices also are influenced
23 heavily by gas prices. The value for ratepayers of hedging this exposure is simple: fixed-price
'u Supran.8, North Carolina Avoided Cost Order, atp.2l.
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generation protects against periodic spikes in natural gas prices. Such spikes have occurred
regularly over the last several decades, as shown in the plot of historical benchmark Henry Hub
gas prices in Figure Zbelow."
Figure 1: Henry Hub Market Prices
MonthlyAverage and Selected l0-Year Forward Market Prices
16.00
14.00
u.00
10.00
rMonthlyAverage
-July
3, 206
-November
2, 2009
-June
1, 2011
-June
3, 2013
*- November 3, 2014
_prilr, 2015
fI
co
oo.{/} 5.m
9999gs!!
Fixed prices also hedge against market dislocations or generation scarcity such as was experienced
throughout the West during the California energy crisis of 2000-2001 or as is occurring today
with the extreme drought in California and long-term, drier-than-normal conditions elsewhere
in the West. In 2014, the rapidly increasing output of solar projects in California made up for
27 Figure 2 based on Chicago Mercantile Exchange data.
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83olo of the reduction in hydroelectric output in the state due to the multi-year drought.28
Obviously, there is a risk that consumers may not benefit if future prices turn out to be lower
than anticipated, but, if that happens, there is the compensation that consumers will enjoy the
low prices for the portion of their needs that is not hedged. Despite this risk, hedging in a
commonly accepted practice in utility operations and regulation.
The economic literature generally finds that the fixed-price, zero-fuel-cost nature of
renewable generation provides a positive value as a hedge against future increases in fossil fuel
prices. For example, in a recent study the Lawrence Berkeley National Lab (LBNL) compared
fixed-price, long-term wind contracts to the range of expected prices for gas-fired generation,
based on the range of recent Energy Information Administration (EIA) gas cost forecasts.2e LBNL
concluded that current wind PPA prices in the range of $50 per MWh offer significant benefit as
a hedge against the expected range of future fossil fuel prices, even in today's low-price
environment for natural gas as a result of the shale gas revolution. Here is the key figure from the
LBNL study:
'8 Based on Energy Information Administration data for 2014, as reported in Stephen Lacey, As California
Loses Hydro Resources to Drought, Large-Scale Solar Fills in the Gap: New sohr generation made up for four-
fifths of Califurnia's lost hydro production in 2014 (Greentech Media, March 3l,2Ol5). Available at
http://www.greentechmedia.com/articles/read/solar-becomes-the-second-biggest-renewable-energy-
provider-in-california.
" Bolinger, Mark, Revisiting the Long-term Hedge Value of Wind Power in an Era of Low Natural Gas
Prices, LBNL-6103E, (March 2013). Available at http://emp.lbl.govisites/all/files/lbnl-6103e.pdf
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140
120
100
80
60
40
20
0
<-
of recent EIA scenarios
11 reference gas
AEO12 reference
AEO13 reference gas
HistoricalE3
={ra
(oc.E
o2
+528/MWh
Wind PPA sample includes only those signed in 20L1 or 2OL2: 36 PPAs totaling 3,678 MW
rr'(t''l'tt F Cl rl m tft l\ (,.t Fl Gl rn F (h F{ m ln N (h Fl
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Fl rl Fl Fl Fl (\l (\ hl 61 (\l (n ft't fi'l an G) tt rt stooooooo00000000000N N l\l l\l Gl ^l N (\l (\ N N N N ^l N hI (\I |\l
Figure 9. Compar{son of Recent Iltnd PPA Sub-Semple to h'oJected Renge of l{aturel
Gas hices
A number of studies have quantified these hedging benefits. In the West, Public Service of
Colorado has estimated that the long-term (20-year) hedging benefits of distributed solar
resources on its system are $6.60 per MWh.'o
In light of this well established economic theory backed up by empirical studies, it is
remarkable that Idaho Power, when asked in discovery whether "long-term, locked-in price
estimates [in PPAs] could potentiallybenefit Idaho Power in some circumstances,' the utility s
response was a flat "no.'31
iii. Market Price Mitigation
30 Xcel Energy Services, Costs and Benefi* of Distibuted Solar Generation on the Public Service Company of
Cohrado System: Study Report in Response to Colorado Public Utilities Commission Decision No. C09-1223
(May 2013), at pp. 6 ar'd 43, and Table 1. This study used the cost of options contracts in the gas futures
market to calculate the hedging benefit. Similar methods have been used in many other solar valuation
studies in other regions of the U.S.3' Idaho Power response to StaffProduction Request 18, included in Exhibit IPC/SC-302.
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Q: Will an increasing penetration of new renewable generation in Idaho and the West have
an impact on energy market prices?
Yes. This new solar generation will increase the electricity supplies available to Idaho
Power. Because this generation is must-take (and has zero variable costs), it will displace the most
expensive fossil-fired or market resources that Idaho Power would otherwise have generated or
purchased. The addition of this local generation will reduce the demand which Idaho Power
places on the regional markets for electricity and natural gas. With this reduction in demand,
there is a corresponding reduction in the price in these markets, which benefits Idaho Power
when it does buy power or natural gas in these markets. This "market price mitigation" benefit of
renewable generation is widely acknowledged, and has become highly visible in markets that now
have high penetrations of wind and solar resources. The magnitude of these benefits will depend
on the overall amount of renewables on the western grid.
Q: Are you aware of any modeling of this benefit in the West?
A: Yes. The National Renewable Energy Laboratory (NREL) and GE Consulting have
undertaken the Western Wind and Solar Integration Study (WWSIS), a major, multi-phase
modeling effort to analyze much higher penetrations of wind and solar resources in the western
U.S.32 Although this work focused on the West Connect area (basically, Arizona, Colorado, New
Mexico, Nevada, and Wyoming), the modeling has included the entire WECC grid in the U.S.,
including Idaho. For example, the WWSIS study of high penetrations of solar (25o/o penetration
in West Connect) also included l5o/o solar penetration in nearby states, including 1,000 MW of
3' The high penetration solar results from the WWSIS are reported in NREL and GE Consulting, Impact of
High Solar Penetration in theWestern Interconnection, at p. 8 and Figure 19 (December 2010). This report,
as well as all reports from the WWSIS, are available on the NREL website at:
http://www.nrel. gov/electricity/transmission/western wind.html.
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1 solar in Idaho. This modeling included analysis of the impact of increasing solar penetration on
2 market prices in the West; the results for spot prices in Arizona are shown in the figure below.
3 Generally, the high penetration solar cases (15% to 25o/o penetration) result in 10olo to 20o/o
4 reductions in spot market prices. Note that the largest reductions in market prices from a 57o
5 increase in penetration occurs at the low penetrations of solar, which is where the West is today.
6 Only in California is on-line solar penetration approaching even 5o/o today.
t{no tno frm {n0 flno 60m
[burs
m
t80
t60
g too
E reoa
E rooEs
E60
40
n
0
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Figure 19 - Arizona Spot Price Duration Curves.
The same market mitigation benefits exist on the natural gas side. Renewable generation reduces
marginal gas-fired generation, thus lowering the demand for natural gas. A study by LBNL has
estimated that the gas-related market mitigation benefits of renewable energy range from $7.50 to
$20 per MWh of renewable output.33
33 See Wiser, Ryan; Bolinger, Mark; and St. Clair, Matt, Easing the Natural Gas Cisis: Reducing Natural
Gas Prices through Increased Deployment of Renewable Energy and Energlr Efficiency, at ix (|anuary 2005),
Available at: http://eetd.lbl.gov/sites/all/files/publications/report-lbnl-56756.pdf
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I As context for how these market price reductions might benefit Idaho consumers, the utility's net
2 electric market purchase expenses in 2015-2016 are forecasted to be $9.3 million; its natural gas
3 expenses are anticipated to be $57.2 million.3n
4
5 Q: Are the fuel hedging and market price mitigation benefits that you have calculated
6 related?
7 A: They are related in that both involve energy market prices for electricity and natural gas.
8 The fuel hedging benefit for consumers results from a reduction in the volatility of these market
9 prices - in other words, in a reduced risk of periodic price spikes in these commodity markets.
l0 The market price mitigation benefit is from an overall reduction in the levels of these market
I I prices. Thus, these benefits are related but do not necessarily overlap.
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13 Q: Will some of Idaho Power's other potential future resource options also realize such
14 benefits?
l5 A: Yes. To be fair, any new sources of renewable or low-variable-cost generation will
16 produce such benefits, including Idaho Power's hydro repowering mentioned in the Petition.
17 However, historically PURPA, and the long-term contract Idaho allows, has been a major source
18 of new generation that provides these benefits.
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2l
34 DirectTestimonyofScottWright,IPC20l5-20l6PCA,CaseNo.IPC-E-I5-14,atTablesland2. Net
electric market costs are the sum of Accounts 555 (Purchased Power Non-PURPA) and 447 (Surplus
Sales). Gas costs are from Account 547 (Other Fuel).
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Q:Will these additional solar resources provide new generating capacity in Idaho Power's
service territory?
A: Yes. In developing the 2015 IRP Idaho Power assumes that solar generation will provide
annual capacity equal to about 20 - 30o/o, and peak hour capacity ,rp to 5l%o of its nameplate
capacity.3s This is based on a very conservative 900/o exceedance method. In contrast, other RTOs
and control areas in the U.S. use 70o/o or 50olo exceedance methods to assess the capacity value of
solar. Thus, the additional S85 MW of solar resources would add at least 280 MW36 and as much
as 440 MW37 of capacity. All of this capacity would be internal to Idaho Power's system, and will
not require additional out-of-state transmission capacity to be deliverable to Idaho Power's
customers.
Q: Initial results from Idaho Power's 2015 IRP show the next need for capacity is not until
2025,when the 461 MW of approved solar contracts is included in the resource stacksE Is there a
potential benefit even if the additional SS5 MW of solar capacity comes on-line before it is
eripected to be needed under the utility's current IRP?
A: Yes. Idaho Power has no immediate need for capacity based on its current IRP, and this
lack of need is priced into,the solar contracts, both those that the utility has signed recently and
those that it might sign in the near future. This assumed lack of need results in lower prices in
these contracts. However, events may occur that accelerate Idaho Power's need for capacity. One
example is the recent short-term cutback in Idaho Power's demand response programs, which
" Idaho Power presentation to the IRP Advisory Committee on October 2,2014 at page 4. Available at:
https://www.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp/2015/presentationl002l4.pdf
" The 9oolo exceedance value.3' 5\o/o of nameplate based on the on-peak capacity factor.
38 Idaho Power presentation to the IRP Advisory Committee on February 5,2015 at pages 29 - 30.
Available at:
https://www.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp/2015/presentation0205 l5.pdf
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1 resulted in a significant short-term acceleration of date of the utility's first need until the funding
2 for that program was restored.3e Another possible factor that could accelerate Idaho Power's need
3 is the retirement by 2020 of aportion of the utility's coal capacity, which could occur for a variety
4 of reasons, including the cost of additional emission controls, decisions made by Idaho Power's
5 partners to terminate their involvement in these plants, or compliance needs related to the
6 federal government's Clean Power Plan.
7
8 As a result, the possible renewable contracts provide Idaho Power essentially with a free
9 option to replace from 280 MW to 440 MW of existing capacity prior to the current date when
l0 capacity otherwise is expected to be needed. In other words, customers in Idaho will gain
11 insurance, at no cost, against events, which might threaten reliability by suddenly accelerating the
12 need for capacity. Based on the capacity costs that appear to be included in Idaho Power's IRP-
13 based indicative prices for the potential solar contracts, the value of this option is $9 million to
14 $14 million per year assuming that the capacity is needed in a year before 2022.
15
16 v. Local economic benefits
t7
18 Q: Will there be economic benefits from Idaho from additional development of the state's
19 indigenous resources?
20 A: Yes. The construction of an additional885 MW of solar generation in Idaho will
2l represent an investment of $2.7 billion in Idaho, assuming a capital cost of $3,000 per kW.no Not
22 all of this money will be spent in Idaho, of course, but there will be significant short-term
3e See Order No. 33016 at pp. l-2, and Order No. 3i084 at p. 5.* Supra r. 16, LBNL Solar Cost Report, at pp. 1 1 - 14.
IPC-E-ls-01
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30
1 employment benefits during construction as well as permanent employment operating and
2 maintaining these facilities, as well as royalties to landowners and property taxes to local
3 communities. Significantly, these facilities will be located in Idaho, so the economic benefits are
4 more likely to accrue to Idahoans than if these were out-of-state power plants, power purchases
5 from regional markets, or transmission lines that only terminate in Idaho (such as Boardman-to-
6 Hemingway).
7
8 vi. A window of opportunity to procure low-cost solar
9
10 Q: Idaho Power asserts that the PURPA contracting process generally means that QFs will
1l request long-term contracts at times when forecasts of future avoided cost prices are high. Is
12 thisconcernpresenttoday?
13 A: No. Natural gas prices today are quite low in historical terms, particularly for longer-term
14 forward contracts. Figure 2, above on page 18 also shows several examples of the 10-year forward
l5 price for natural gas at the Henry Hub in recent years. This shows that today's avoided costs are
16 relatively low. New sources of clean energF are competitive with this price. Put simply, if today's
17 independent QF developers can meet or beat this avoided cost, then it will be a good deal for
l8 ratepayers.
19
20 Q: Is this a good time to contract for new solar generation, in terms of the price for this
2l renewable generation?
22 A: Absolutely. Idahoans need energy every day and the PURPA contracts supply this energy
23 at or below the utilities' avoided costs. It is critical to recognize that the 30olo federal investment
24 tax credit (ITC) expires at the end of 2016, after which it will drop to l0olo. As a result, the
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
3l
I levelized cost of solar generation is expected to rise significantly for several years beginning in
2 2017, until cost reductions for this technology can offset the loss of this significant incentive.
3 Using a generation cost tool developed for the WECC, the drop in the federal ITC could add $15
4 to $20 per MWh (+20o/o to +25o/o) to solar contract prices after 2017.4' As a result, now is an
5 opportune moment to purchase solar generation at contract prices that may not be available for a
6 considerable period after 2016.4'Based on solar PPA prices surveyed by LBNL through mid-2014,
7 the utility-scale PPA prices at which Idaho Power has procured solar generation (and today has a
8 window of opportunity to procure more) are comparable to the solar PPAs being procured
9 elsewhere in the country, as shown in the figure below.n3
l0
s3o0
s2s0
$2oo
Figure
anararoFotroHGa(llltOOOOOClO6FHFFAAAAA&AATAAAGOOOAl!O.!nO.!O titi--
PPA Exccutbn llatc
Levelized PPA Prices by Operetional Status and PPA Execution Date
'' Based on the 2012 WECC Generation CostingTool, developed by Energy & Environmental Economics
for the WECC. Available at https://ethree.com/public-projects/renewable-energy-costing-tool.php,
assuming a $2,000 per kW utility-scale solar PV capital cost in 2017.n' This is what the California utilities concluded in 2013, even though they had largely contracted
adequate generation to reach the state's 33o/oby 2020 RPS goal. Supran.28,Lacey, Steven As California
Loses Hydro Resources to Drought, Large-Scale Solar Filk in the Gap.u' Supra n. 16, LBNL Solar Cost Report, at pp.26-3I and Figure 16.
IPC-E-ts-01
BEACH, Di
Idaho Conservation League and Sierra Club
E3-
<rl
.ltoN
o€E
AAtJJ
7t
s1s0
$1oo
ss0
$o i^
AI
G'o
Ao
16.ll
O Operatlng (5,201 MW, 60 contracts)
3 Planncd (1,292 MW,20 contracts)
32
I
2 VI. SYSTEM RELIABILITY
J
4 Q: Idaho Power is concerned that it will not be able to integrate additional intermittent
5 solar generation into its system, and that the new resources will aggravate the oversupply
6 situation that it faces at certain times of the year, principalty in the spring months when hydro
7 resources are abundant. Please comment.
8 A: First, it is my understanding that Idaho Power recently completed a solar integration
9 study and is currently expanding this study to include larger penetrations of solar power. nn Also,
10 the recent solar QF contracts in Idaho require the QF project to cover these integration costs.
11 Second, Idaho Power could reduce the oversupply issue by 15 - 29o/oby idling the Valmy coal
12 plant in 2016 and 2017.45 Third, as I explain below recent studies of the western grid conclude the
13 system can integrate high solar penetrations and that evolving market mechanisms,like the
14 Energy Imbalance Market, can facilitate this integration.
15
16 The integration of higher levels of wind and solar resources presents a challenge to
17 utilities and grid operators across the U.S., not just in the West. In recent years, significant effort
18 and numerous studies have been conducted on the operational and system reliability impacts of
19 the increasing penetration of variable renewable resources. The \ IWSIS is the most significant
20 such effiort in the WECC. As noted above, the WWSIS included a high solar penetration study
2l that considered a 25o/o solar penetration in the West Connect area, and l5olo penetration in the
22 rest of the WECC (including 1,000 MW of solar in Idaho). The WWSIS concluded that it will be
s SeeIPC-E-14-18.
as Based on data from Idaho Power Response to ICL Production Request No 6.
IPC-E-ls-01
BEACH, Di
Idaho Conservation League and Sierra Club
JJ
I feasible to operate the WECC grid at these levels of solar penetration in the WECC, provided that
2 certain operational changes are made. The key findings of the WWSIS include:
I o Increasing the size of the geographic area over which the wind and solar resources are
4 drawn substantially reduces variability.
5
6 . Scheduling generation and interchanges subhourlyreduces the need for fast reserves.
7
$ o Using wind and solar forecasts in utility operations reduces operating costs by up to l4olo.
9
10 . Existing transmission capacity can be better used. This will reduce new transmission
I I needs.
t2
13 . Demand response programs can provide flexibility that enables the electric power system
14 to more easily integrate wind and solar-and may be cheaper than alternatives.
15
16 Efforts are already underway to implement such changes. Most notably, PacifiCorp has
17 joined with the CAISO to create a new energy imbalance market (EIM) that is intended, among
l8 other benefits, to address the first two findings of the WWSIS - balancing wind and solar
19 resources over a larger geographic footprint and reducing the costs ofintegrating such resources
20 by balancing the system more efficiently on a sub-hour basis. A white paper from the FERC staff
2l explains the benefit's of an EIM for renewable integration:
22 An EIM could enhance the reliability of the bulk power system as the system
23 moves towards higher levels of variable energy resources. Balancing authorities
24 need reserves that are loaded and able to reduce output, as well as reserves that are
IPC-E-1s-01
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Idaho Conservation League and Sierra Club
34
1 unloaded and able to increase output, in order to respond to the variability from
2 variable energy resources. Without an EIM, the variability from variable energy
3 resource output in the Western Interconnection is not diversified across balancing
4 authorities. An EIM could help manage variable energy resources more reliably by
5 pooling variability over a larger area, and redispatching resources to help manage
6 imbalance energy caused by variable energy resources.nu
7 The EIM began operations on November I,2014, and achieved $6 million in savings for its
8 participants in just the first two months of operation.n' NV Energy and Puget Sound Energy will
9 be joining the EIM in October 2015 and October 2016, respectively; thus, by the end of 2015,
l0 utilities that operate in all of the states that neighbor Idaho will be participating in this market.as
I I In discovery, Idaho Power stated that it cannot join the EIM because it lacks the transmission
12 rights to do so (presumably, a lack of rights to access the CAISO balancing area).ne However, it is
l3 my understanding that utilities can participate in the EIM using Available Transmission Capacity
14 even if they do not have rights to the CAISO areato and that the EIM will be modifring its
l5 protocols to allow expansion to non-contiguous balancing areas within the WECC.st
16 Significantly, the costs of participation in the EIM are based largely on how much you use it, and
* FERC, Qualitative Assessment of Potential Reliability Benefits from a Western Energlr
Imbalance Market, at p. 17 (February 26,2013) Available at:
http://www.caiso.com/Documents/QualitativeAssessment-PotentialReliabilityBenetits-
WesternEnergylmbalanceMarket.pdf
'7 CAISO, Benefits for Participatingin EIM, at slide 3 (February 11, 2015) Available at :
E
A
//www.caiso.corn/Documents/Presentation-PacitiCorp-lSO ElMBenefitsReportQ,l 20 14.
fact sheet from PacifiCorp about the EIM is Exhibit IPC/SC-303 to this testimony. See also
https://pse.com/aboutpse/PseNewsroom/NewsReleases/Pages/PSE- to- loin-Energy-[mbalance-
Market.aspx.n' Idaho Power response to J.R. Simplot Company Production Request 16, included in Exhibit IPC/SC-
302.to For example, NV Energy plans to use Available Transmission Capacity, and not firm transmission
rights, for its EIM transfers. See CAISO, Energy Imbalance Market Year I Enhancements - Draft Final
Proposal, at p. 3 (February 11, 2015). Available at:
http://www.caiso.com/Documents/DraftFinalProposal EnergylmbalanceMarketYear I Enhancements.pdft' Ibid., atpp. l9-2r.
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
35
I participants retain dispatch authority within their control areas. In essence, the EIM promotes
2 the more granular and efficient exchange of power among the participating control areas.
J
4 Although the WWSIS study showed the ability to integrate 15 -25o/o solar penetration,
5 the rest of the West, except for California, is not close to even a 5olo level of solar penetration
6 today. Thus, today Idaho Power should be able to integrate the possible level of solar generation
7 on it system, especially if it can obtain greater access to balancing resources in the region through
8 mechanisms such as the EIM. In addition, the 461 MW of approved solar contracts will be sited
9 in or close to Idaho Power's Treasure Valley load center; I assume that the additional 885 MW
l0 will be interconnected directly to Idaho Power's system as well. Because these resources will be
1l internal to Idaho Power's system and will produce significant power during the utility's summer
12 on-peak hours, they should reduce loadings on the congested transmission paths into Idaho
13 during these summer peak periods, further increasing Idaho Power's access to regional markets.
14 Additional capacity on the transmission system serving Idaho also may become available as a
l5 result of the retirement of out-of-state coal units serving Idaho Power. This available
16 transmission capacity will expand access to the regional markets that are increasingly seen as the
17 key to successful integration of a growing penetration of renewable generation.
18
19 VII. REFINEMENTS TO THE IRP METHOD
20
21 Q: You have stated above that ICL and the Sierra Club believe that the IRP Method is
22 working well. Please elaborate.
23 A: In my judgment, the IRP method accurately predicts future avoided energy costs, and
24 captures the need for additional generation through the timing of capacity payments. As a result,
IPC-E-1s-01
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Idaho Conservation League and Sierra Club
36
I
2
aJ
4
5
6
7
8
9
10
11
t2
l3
t4
15
t6
there is no need to shorten the term of PURPA contracts out of a concern that these contracts
will be a future burden for ratepayers in Idaho. To the contrary, as discussed above, they offer
many benefits to consumers that are not captured in the avoided cost price.
Q: Are there ways in which the IRP method might be improved so that it would reflect
Idaho Power's avoided costs even more accurately?
A: Possibly. ICL and the Sierra Club recommend that the Commission consider allowing
Idaho Power to include the energy and capacity contribution of each QF with a signed contract
when calculating the avoided cost values for the next subsequent QF, instead of updating its
capacity position just once ayear.In essence, this refinement would allow more frequent updates
to Idaho Power's capacity position. This more granular calculation of avoided costs based on the
utility s up-to-date capacity position and need could further increase the accurary of the IRP
method, and at least partially address Idaho Power's concerns in this regard.
Does this conclude your direct testimony?
Yes, it does.
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Q:
A:
37
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
CASE NO. PAC-E-15-03
Idaho Conservation kague and the Sierra Club
Direct Testimony of R. Thomas Beach
Exhibit 30r
R. Thomas Beach C. V.
IPC-E-ls-01
BEACH, Di
Idaho Conservation League and Sierra Club
a
R. THOMAS BEACH
Principal Consultant Paqe I
Mr. Beach is principal consultant with the consulting firm Crossborder Energy. Crossborder
Energy provides economic consulting services and strategic advice on market and regulatory
issues concerning the natural gas and electric industries. The firm is based in Berkeley
California, and its practice focuses on the energy markets in California, the western U.S., Canada,
and Mexico.
Since 1989, Mr. Beach has participated actively in most of the major energy policy debates in
California, including renewable energy development, the restructuring of the state's gas and
electric industries, the addition of new natural gas pipeline and storage capacity, and a wide range
of issues concerning California's large independent power community. From 1981 through 1989
he served at the California Public Utilities Commission, including five years as an advisor to three
CPUC commissioners. While at the CPUC, he was a key advisor on the CPUC's restructuring of
the natural gas industry in California, and worked extensively on the state's implementation of
PURPA.
AREAS OF EXPERTISE
Renewable Energt Issues: extensive experience assisting clients with issues concerning
California's Renewable Portfolio Standard program, including the calculation of the state's
Market Price Referent for new renewable generation. He has also worked for the solar
industry on the creation of the California Solar Initiative (the Million Solar Roofs), as well
as on a wide range of solar issues in other states.
Restructuring the Natural Gas and Electric Industries: consulting and expert testimony on
numerous issues involving the restructuring of the electric industry including the 2000 -
2001 Western energy crisis.
Energy Markets: studies and consultation on the dynamics of natural gas and electric
markets, including the impacts of new pipeline capacity on natural gas prices and of
electric restructuring on wholesale electric prices.
Qualifying Facility Issues: consulting with QF clients on a broad range of issues involving
independent power facilities in the Western U.S. He is one of the leading experts in
California on the calculation of avoided cost prices. Other QF issues on which he has
worked include complex QF contract restructurings, electric transmission and
interconnection issues, property tax matters, standby rates, QF efficiency standards, and
natural gas rates for cogenerators. Crossborder Energy's QF clients include the full range
of QF technologies, both fossil-fueled and renewable.
Pricing Policy in Regulated Industries: consulting and expert testimony on natural gas
pipeline rates and on marginal cost-based rates for natural gas and electric utilities.
Crossborder Energy
a
a
a
@
rPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant Pase2
EDUCATION
Mr. Beach holds a B.A. in English and physics from Dartmouth College, and an M.E. in
mechanical engineering from the University of California at Berkeley.
ACADEMIC HONORS
Graduated from Dartmouth with high honors in physics and honors in
English. Chewon Fellowship, U.C. Berkeley, I97 8-79
PROFESSI ONAL ACCREDITATION
Registered professional engineer in the state of California.
EXPERT WITNESS TESTIMONY BEFORE THE CPUC
l.Prepared Direct Testimony on Behalf of Pacific Gas & Electric Company/Pacific Gas
Transmission (I. 88-12-027 - Iuly 15, 1989)
. Competitive and environmentalbenefits of new natural gas pipeline capacity to
California.
a. Prepared Direct Testimony on Behalf of the Canadian Producer Group(A.89-08-024- November 10, 1989)b. Prepared Rebuttal Testimony on Behalf of the Canadian Producer Group (A.
89-08-024 - November 30, 1989)
. Natural gas procurement policy; gas cost forecasting.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (R. 88-08-018 -December 7, 1989)
. Brokering of interstate pipeline capacity.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 90-08-029 -November 1, 1990)
. Natural gas procurement policy; gas cost forecasting; brokerage fees.
Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing Commission
and the Canadian Producer Group (I. 86-06-005 - December 21, 1990)
. Firm and interruptible rates for noncore natural gas users
2.
3.
4.
5.
Crossborder Energy
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant
7.
Pase 3
a. Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing
Commission (R. 88-08-018 - fanuary 25,l99l)b. Prepared Responsive Testimony on Behalf of the Alberta Petroleum Marketing
Commission (R. 88-08-018 - March 29,l99l)
. Brokeing of interstate pipeline capacity; intrastate transportation policies.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (A.
90-05-029lPhase II - April 17,, l99l)
. Natural gas brokerage and transport fees.
Prepared Direct Testimony on Behalf of LUZ Partnership Management (A. 91-01-027 -|uly 15, 1991)
. Natural gas parity rates for cogenerators and solar power plants.
Prepared Ioint Testimony of R. Thomas Beach and Dr. Robert B. Weisenmiller on Behalf
of the California Cogeneration Council (I. 89-07-004 - |uly 15, 1991)
. ,\voided cost pricing; use of published natural gas price indices to set avoided cost prices
forqualifiingfacilities. -
a. Prepared Direct Testimony on Behalf of the Indicated Expansion Shippers (A.
89-04-033 - October 28,1991)b. Prepared Rebuttal Testimony on Behalf of the Indicated Erpansion Shippers (A.
89-04-0033 - November 26,1991)
. Natural gas pipeline rate design; cost/benefit analysis of rolled-in rates.
Prepared Direct Testimony on Behalf of the Independent PetroleumAssociation of
Canada (A. 9l-04-003 - )anuary 17,1992)
. Natural gas procurement policy; prudence of past gas yturchase*
a. Prepared Direct Testimony on Behalf of the California Cogeneration Council
(I.86-06-005/Phase II - Iune 18,1992)b. Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council
(I. 86-06-005/Phase II - July 2,1992)
. Long-Run Marginal Cost (LRMC) rate design for natural gas utilities.
Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.
92-10-017 - February 19,1993)
. Performance-based ratemaking for electric utilities.
9.
10.
11.
12.
13.
Crossborder Energlt
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant
t4.
Page 4
Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-02-0141A.93-03-053 -May 21,1993)
Natural gas transportation serrice for wholesale customers.
Prepared Direct Testimony on Behalf of the CanadianAssociation of Petroleum
Producers (A.92-12-0431A. 93-03-038 - June 28, 1993)
Prepared Rebuttal Testimony of Behalf of the Canadian Association of
Petroleum Producers (A.92-12-0431A.93-03-038 - Iuly 8, 1993)
Natural gas pipeline rate design issues.
Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-05-023 -November 10, 1993)
Prepared Rebuttal Testimony on Behalf of the SEGS Projects (C. 93-05-023 -|anuary 10, 1994)
. Utility overcharges for natural gas service; cogeneration parity issues.
Prepared Direct Testimony on Behalf of the City ofVernon (A. 93-09-006/A.
93-08-0221A. 93-09-048 - Iune 17,1994)
. Natural gas rate design for wholesale customers; retail competition issues.
Prepared Direct Testimony of R. Thomas Beach on Behalf of the SEGS Projects (A.
94-01-021 - August 5, 1994)
. Natural gas rate design issues; rate parity for solar power plants.
Prepared Direct Testimony on Transition Cost Issues on Behalf of Watson Cogeneration
Company (R. 94-04-03111.94-04-032 - December 5,1994)
. Policy issues concerning the calculation, allocation, and recovery of transition costs
associated with electric industry restructuring.
Prepared Direct Testimony on Nuclear Cost Recovery Issues on Behalf of the California
Cogeneration Council (A. 93- 12-02511.94-02-002 - February 14, 1995)
. Recovery of above-market nuclear plant costs under electric restructuring.
Prepared Direct Testimony on Behalf of the Sacramento Municipal Utility Distria (A.
94-11-015 -June 16, 1995)
. Natural gas rate design; unbundled mainline transportation rates.
15 a.
b.
16. a.
b.
17.
18.
19.
20.
2t.
Crossborder Energy
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant Page 5
22. Prepared Direct Testimony on Behalf of Watson Cogeneration Company (A. 95-05-049 -September 11, 1995)
. Incremental Energy Rates; air quality compliance costs.
23. a. Prepared Direct Testimony on Behalf of the CanadianAssociation of Petroleum
Producers (A. 92 - 12 -043 I A. 9 3 -03- 03 8/A. 9 4-0s -03 5 I A. 9 4 -06 -03 4 I A.
94-09-0561A. 94-06-044- |anuary 30, 1996)b. Prepared Rebuttal Testimony on Behalf of the CanadianAssociation of Petroleum
Producers (A.92-12-0431 A.93-03-038/A. 94-05-0351A. 94-06-03 4l A. 94-09-056/A.
94-06-044 - February 28,1996)
. Natural gas market dynamics; gas pipeline rate design.
24. Prepared Direct Testimony on Behalf of the California Cogeneration Council and
Watson Cogeneration Company (A. 96-03-031 - luly 12,1996)
. Natural gas rate design: parity rates for cogenerators.
25. Prepared Direct Testimony on Behalf of the City of Vernon (A. 96-10-038 -August 6,
t997)
- Impacts of a major utility merger on competition in natural gas and electric
markets.
26. a. Prepared Direct Testimony on Behalf of the Electricity Generation Coalition
(A. 97-03-002 - December 18, 1997)b. Prepared Rebuttal Testimony on Behalf of the Electricity Generation Coalition
(A. 97-03-002 - fanuary 9, 1998)
. Natural gas rate design for gas-fired electric generators.
27. Prepared Direct Testimony on Behalf of the City of Vernon (A. 97-03-015 - fanuary 16,
1ee8)
. Natural gas service to Baja, California, Mexico.
Crossborder Energlt
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant Pase 6
a.
b.
28.Prepared Direct Testimony on Behalf of the California Cogeneration Council and
Watson Cogeneration Company (A. 98- 1 0-0 12lA. 98- 10-03 1/A. 98-07-005 -March 4,1999).
Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.
98-10-012/A. 98-01-0311A.98-07-005 - March 15, 1999).
Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.
98- 10-0 12lA. 98-0 I -03 | I A. 98-07 -00s - ltne 25, 1999) .
Natural gas cost allocation and rate design for gas-fired electric generators.
Prepared Direct Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (R. 99-ll-022 - February 11,2000).
Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (R. 99-ll-022 - March 6, 2000).
Prepared Direct Testimony on Line Loss Issues of behalf of the California
Cogeneration Council (R. 99-11-022 - April 28, 2000).
Supplemental Direct Testimony in Response to ALI Cooke's Request on behalf of
the California Cogeneration Council and Watson Cogeneration Company (R. 99-
Il-022 - April 28, 2000).
Prepared Rebuttal Testimony on Line Loss Issues on behalf of the California
Cogeneration Council (R. 99-1 l-022 - May 8, 2000).
Market-based, avoided cost pricingfor the electric output of gas-fired
cogeneration facilities in the Califurnia market; electric line losses.
Direct Testimony on behalf of the Indicated Electric Generators in Support of the
Comprehensive Gas OII Settlement Agreement for Southern California Gas
Company and San Diego Gas & Electric Company (I. 99-07-003 - May 5, 2000).
Rebuttal Testimony in Support of the Comprehensive Settlement Agreement on
behalf of the Indicated Electric Generators (I.99-07-003 - May 19,2000).
Testimony in support of a comprehensive restructuring of natural gas rates and
services on the Southern California Gas Company system. Natural gas cost
allocation and rate design for gas-fired electric generators.
Prepared Direct Testimony on the Cogeneration Gas Allowance on behalf of the
California Cogeneration Council (A. 00-04-002 - September 1, 2000).
Prepared Direct Testimony on behalf of Southern Energy California (A.
00-04-002 - September 1, 2000).
Natural gas cost allocation and rate design for gas-fired electric generators.
a.29.
b.
c.
d.
e.
30.
b.
31. a.
b.
Crossborder Energy
IPC-E-ls-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant PaseT
32. a. Prepared Direct Testimony on behalf of Watson Cogeneration Company (A.
00-06-032 - September 18,2000).b. Prepared Rebuttal Testimony on behalf of Watson Cogeneration Company (A.
00-06-032 - October 6, 2000).
. Rate design for a natural gas "peaking service."
33. a. Prepared Direct Testimony on behalf of PG&E National Energy Group &
Calpine Corporation ( I. 00- I I -002-Ap ril 25, 200 1 ).b. Prepared Rebuttal Testimony on behalf of PG&E National Energy Group &
Calpine Corporation (I. 00- 1 1 -002-May 1 5, 200 1 ).
. Terms and conditions of natural gas service to electric generators; gas curtailment
policies.
34. a. Prepared Direct Testimony on behalf of the California Cogeneration Council (R.
99 - ll -022-May 7, 2001).b. Prepared Rebuttal Testimony on behalf of the California Cogeneration Council
(R. 99-11-022-May 30, 2001).
- Avoided cost pricingfor alternative enugy producers in California.
35. a. Prepared Direct Testimony of R. Thomas Beach in Support of the Application of
Wild Goose Storage Inc. (A. 0l-06-029-lune 18,2001).b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Wild Goose
Storage (A. 01 -06-029-November 2, 2001 )
. Consumer benefits from expanded natural gas storage capacity in California.
36. Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San
Berhardino (1. 01-06-047-December 14, 2001 )
- Reasonableness review of a natural gas utility's procurement practices and
storage operations.
37. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council ( R. 0 1 - 1 0-0 24-May 3 L, 2002)b. Prepared Supplemental Testimonyof R. Thomas Beach on behalf of the California
Cogeneration Council (R. 0 1 - I 0-024-M ay 3 l, 2002)
. Electric procurement policies for Californit's electric utilities in the aftermath of the
California energy crisis.
Crossborder Energy
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant
38.
39.
40.
41.
Paee 8
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technology Association (R. 02-0 1 -0 1 l-|une 6, 2002)
"Exit fees" for direct Access customers in California.
Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San
Bernardino (A. 02-02-012 - August 5, 2002)
. General rate case issues for a natural gas utikty; reasonableness review of a
natural gas utility's procurement practices.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technology Association (A. 98-07-003 - February 7,2003)
. Recovery of past utility procurement costs from direct access customers.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council, the California Manufacturers & TechnologyAssociation,
Calpine Corporation, and Mirant Americas, Inc. (A 01-10-011 - February 28,
2003)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council, the California Manufacturers & Technology Association,
Calpine Corporation, and Mirant Americas, Inc. (A 0 1 - 10-0 1 I - March 24, 2003)
- Rate design issues for Pacrfic Gas dy EleAric's gas transmission system (Gas
Accord II).
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technology Association; Calpine Corporation; Duke
Energy North America; Mirant Americas, Inc.; Watson Cogeneration
Company; and West Coast Power, Inc. (R. 02-06-041- March 21,2003)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technology Association; Calpine Corporation; Duke Energy
North America; Mirant Americas, [nc.; Watson Cogeneration Company; and
West Coast Power, Inc. (R. 02-06-041 - April 4,2003)
. Cost allocation of above-market interstate pipeline costs for the California natural gas
utilities.
43. Prepared Direct Testimony of R. Thomas Beach and Nancy Rader on behalf of the
California Wind EnergyAssociation (R. 01-10-024- April 1,2003)
Design and implementation of a Rennvable Portfolio Standard in California.
42.
Crossborder Energy
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant Page 9
44.
45.
46.
47.
48.
b.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Coieneration Council ( R.'0 1 - I 0-0 24 - | une 23, 2003 )b. PrJpared Supplemental Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council ( R. 0 1 - I 0-024 - lune 29, 2003)
- Power procurement policies for electric utilities in California.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Indicated Commercial
Parties (02-05-004 - August 29,2003)
. Electric revenue allocation and rate design for commercial customers in southern
California.
Prepared Direct Testimony of R. Thomas Beach on behalf of Calpine
Corporation and the California Cogeneration Council (A. 04-03-021 - fuly 16,
2004)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Calpine
Corporation and the California Cogeneration Council (A. 04-03-02I -July 26,
2004)
. Policy and rate design issues for Pacific Gas 6 Electric's gas transmission system (Gas
Accord III).
Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration
Council (A. 04-04-003 - August 6,2004)
- Policy and contract issues concerning cogeneration QFs in California.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council and the California Manufacturers and Technology
Association (A. 04-07-044 - fanuary 11, 2005)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council and the California Manufacturers and Technology
Association (A. 04-07-0 44 - )anuary 28, 2005)
. Natural gas cost allocation and rate design for large transportation customers in
northern California.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technology Association and the Indicated Commercial
Parties (A. 04-06-024 - March 7, 2005)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Mairufacturers and Technolbgy Association and the Indicated Commercial
Parties (A. 04-06-024 - April 26, 2005)
. Electric marginal costs, reyenue allocation, and rate design for commercial and
industrial electric customers in northern California.
49.
Crossborder Energy
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
R. THOMAS BEACH
Principal Consultant Pase 10
50.
51.
52.
53.
54.
55.
56.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California Solar Energy
Industries Association (R. 04-03-017 - April 28, 2005)
- Cost-ffictiveness of the Million Solar Roofs Program.
Prepared Direct Testimony of R. Thomas Beach on behalf of Watson Cogeneration
Company, the Indicated Producers, and the California Manufacturing and
Technology Association (A. 04-12-004 -luly 29,2005)
. Natural gas rate design policy; integration of gas utility systems.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 04-04-003/R. 04-04-025 - August 31,2005)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 04-04-003/R. 04-04-025 - October 28,2005)
. Avoided cost rates and contracting policies for QFs in California
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technology Association and the Indicated Commercial
Parties (A. 05-05-023 - |anuary 20,2006)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technology Association and the Indicated Commercial
Parties (A.05-05-023 - February 24,2006)
- Electric marginal costs, revenue allocation, and rate design for commercial and
industrial electric customers in southern California.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Producers ( R.04-08-018 - |anuary 30,2006)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Producers ( R. 04-08-018-February2l,2006)
. Transportation and balancing issues concerning California gas production.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technology Association and the Indicated Commercial Parties (A.
06-03-005 - October 27,2006)
. Electic marginal costs, reyenue allocation, and rate design for commercial and
industrial electric customers in northern Caffirnia.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration
Council (A. 05-12-030 - March 29,2006)
- Rwiew and approval of a new contract with a gas-fired cogeneration project.
Crossborder Energlt
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
10
R. THOMAS BEACH
Principal Consultant Pase 1l
57.
58.
59.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of Watson
Cofeneration, Indicated Producers, the California Cogeneration Council, and the
California Manufacturers and TechnologyAssociation (A. 04-12-004 -July 14,
2006)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Watson
Cogeneration,Indicated Producers, the California Cogeneration Council, and the
California Manufacturers and Technology Association (A. 04- l2-0 04 - July 3 1 ,
2006)
. Restructuring of the natural gas system in southern California to include firm capacity
ights; unbundling of natural gas services; risk/reward issues for natural gas utilities.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration
Council (R. 06-02-013 - March2,2007)
. Utility procurement policies concerning gas-fired cogeneration facilities.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A.07-01-047 - August 10,2007)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A.07-01-047 - September 24,2007)
- Electric rate design issues that impact customers installing solar photovoltaic
systems.
a. Prepared Direct Testimony of R,. Thomas Beach on Behalf of Gas Transmission
Northwest Corporation (A.07-12-02I - May 15, 2008)b. Prepared Rebuttal Testimony of R,. Thomas Beach on Behalf of Gas
Transmission Northwest Corporation (A. 07-12-021- Iune 13,2008)
. Utility subscription to new natural gas pipeline capacity serving California.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A. 08-03-015 - September 12, 2008)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A. 08-03-015 - October 3,2008)
Issues concerning the design of a utility-sponsored program to install 500 MW of
utility- and indep endently-owned solar photovoltaic systems.
60.
61. a.
b.
Crossborder Energy
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
ll
R. THOMAS BEACH
Principal Consultant
62.
63.
Pase 12
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
08-03-002 - October 31,2008)
. Electic rate design issues that impact customers installing solar photovoltaic
systems.
a. Phase II Direct Testimony of R. Thomas Beach on behalf of Indicated Producers,
the California Cogeneration Council, California Manufacturers and Technology
Association, and Watson Cogeneration Company (A. 08-02-001 - December 23,
2oo8)b. Phase II Rebuttal Testimony of R. Thomas Beach on behalf of Indicated
Producers, the California Cogeneration Council, California Manufacturers and
Technology Association, and Watson Cogeneration Company (A.
64.
08-02-001 - )anuary 27,2009)
Natural gas cost allocation and rate design issues for large customers.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (A. 09-05-026 - November 4,2009)
Natural gas cost allocation and rate design issues for large customers.
Prepared Direct Testimony of R. Thomas Beach on behalf of Indicated Producers
and Watson Cogeneration Company (A. 10-03-028 - October 5, 2010)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Indicated
Producers and Watson Cogeneration Company (A. 10-03-028 - October 26,
2010)
Revisions to a program of firm backbone capacity rights on natural gas pipelines.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
10-03-014 - October 6, 2010)
. Electric rate design issues that impact customers installing solar photovoltaic
systems.
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Indicated Settling
Parties (A. 09-09-013 - October 11, 2010)
. Testimony on proposed modifications to a broad-based settlement of rate-related
issues on the Pacific Gas 6 Electic natural gas pipeline system.
65. a.
b.
66.
67-
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
t2
R. THOMAS BEACH
Principal Consultant Paee 13
68. a.
b.
Supplemental Prepared Direct Testimony of R. Thomas Beach on behalf of
Sairamento Natural Gas Storage, LLC (A. 07-04-013 - December 6, 2010)
Supplemental Prepared Rebuttal Testimony of R. Thomas Beach on behalf of
Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 13, 2010)
Supplemental Prepared Reply Testimony of R. Thomas Beach on behalf of
Sairamento Natural Gas Storage, LLC (A. 07-04-013 - December 20,2010)
Local reliability benefits of a nmv natural gas storage facility.
69.
70.
71.
72.
Prepared Direct Testimony of R. Thomas Beach on behalf of The Vote Solar Initiative
(A. 10-11-01S-June l, 2011)
. Distributed generation policies; utility distribution planning.
Prepared Reply Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
10-03-014-August 5, 201 1 )
- Electric rate design for commercial 6 industrial solar custorners.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Energy Industries
Association (A. 1 1 -06-007-Febru ary 6, 2012)
. Electric rate design for solar customers; marginal costs.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the Northern
California Indicated Producers ( R. 1 1 -02-0 1 9-f anuary 31, 2012)
b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Northern
California Indicated Producers (R. 1 1 -02-0 1 9-February 28, 2012)
. Natural gas pipeline safety policies and costs
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Energy Industries
Association (A. I 1- 10-002-June 12, 2012)
. Electric rate design for solar customers; marginal costs.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Southern
California Indicated Producers and Watson Cogeneration Company (A. 11-
11-002-June 19, 2012)
. Natural gas pipeline safety policies and costs
73.
74.
Crossborder Energy
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
13
R. THOMAS BEACH
Principal Consultant Paee 14
75.Testimony of R. Thomas Beach on behalf of the California Cogeneration
Council (R. 12-03-014-lune 25, 2012)
Reply Testimony of R. Thomas Beach on behalf of the California Cogeneration
Council (R. 1 2-03-0 l4-laly 23, 2012)
Ability of combined heat and power resources to serve local reliability needs in
southern California.
Prepared Testimony of R. Thomas Beach on behalf of the Southern California
Indicated Producers and Watson Cogeneration Company (A. 11-1 l-002, Phase
2-November 16,2012)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Southern
California Indicated Producers and Watson Cogeneration Company (A. 11-
11-002, Phase 2-December 14, 2012)
. Allocation and recovery of natural gas pipeline safety costs.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Energy Industries
Association (A. l2-12-002-May 10, 2013)
- Electric rate design for commercial6 industrial solar customers.
EXPERT WITNESS TESTIMONY BEFORE THE COLORADO PUBLIC UTITITIES COMMISSION
1. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Colorado Solar
Energy Industries Association and the Solar Alliance, (Docket No. 09AL-299E - October 2,
200e).
. Electric rate design policies to encourage the use of distributed solar generation.
2. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Vote Solar Initiative
and the Interstate Renewable Energy Council, (Docket No. 11A-418E - September 21,
2011).
. Duelopment of a community solar program for Xcel Energy.
Crossborder Energy
b.
a.76.
77.
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
l4
2.
3.
R. THOMAS BEACH
Principal Consultant Page 15
EXPERT WITNESS TESTIMONY BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
1. Direct Testimony of R. Thomas Beach on behalf of the Idaho Conservation League
(Case No. IPC-E- l2-27-May 10, 2013)
- Costs andbenfits of net energ)l meteringin ldaho.
EXPERT WITNESS TESTIMONY BEFORE THE PUBLIC SERVICE COMMISSION OF NEVADA
1.Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 97-200l-May 28,1997)
. Avoided cost pricingfor the electic output of geothermal generation facilities in
Nevada.
Pre-filed Direct Testimony on Behalf of Nevada Sun-Peak Limited Partnership (Docket
No. 97-6008-September 5, 1997)
Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 98-2002 -l:une 18, 1998)
- Market-based, avoided cost pricingfor the electric outPut of geothermal
generation facilities in Nevada.
EXPERT WITNESS TESTIMONY BEFORE THE NEW MEXICO PUBLIC REGUI.A.TION
COMMISSION
l. Direct Testimony of R. Thomas Beach on Behalf of the Interstate Renewable Energy
Council (Case No. 1 0-00086-UT-February 28, 201 l)
- Testimony on proposed standby rates for new distributed generation projects; cost-
ffictiveness of DG in New Mexico.
2. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the New Mexico
Independent Power Producers (Case No. l1-00265-UT, October 3, 2011)
. Cost cap for the Renauable Portfolio Standard program in New Mexico
Crossborder Energy
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
l5
R. THOMAS BEACH
Principal Consultant Page 16
EXPERT WITNESS TESTIMONIT BEFORE THE PUBLIC UTILITIES COMMISSION OF
OREGON
l. a. Direct Testimony of Behalf of Weyerhaeuser Company (UM ll29 -August 3,2004)b. Surrebuttal Testimony of Behalf of Weyerhaeuser Company (UM
ll29 - October 14,2004)
2. a. Direct Testimony of Behalf of Weyerhaeuser Company and the
Industrial Customers of Northwest Utilities (UM 1129 / Phase II -February 27,2006)b. Rebuttal Testimony of Behalf of Weyerhaeuser Company and the
Industrial Customers of Northwest Utilities (UM 1129 / Phase II - April
7,2006)
. Policies to promote the development of cogeneration and other qualifying
facilities in Oregon.
EXPERT WITNESS TESTIMONY BEFORE THE VIRGINIA CORPORATION COMMISSION
1. Direct Testimony and Exhibits of R. Thomas Beach on Behalf of the Maryland -
District of Columbia - Virginia Solar Energy Industries Association, (Case No. PUE-
2011-00088, October 11, 2011)
. Standby rates for net-metered solar customers, and the cost-effeaiveness of
net energ)/ metering.
EXPERT WITNESS TESTIMONY BEFORE THE MINNESOTA PUBLIC UTILITIES
COMMISSION
l. Direct and Rebuttal Testimony of R. Thomas Beach on Behalf of Geronimo Energy,
LLC. (In the Matter of the Petition of Northern States Power Company to Initiate a
Competitive Resource Acquisition Process [OAH Docket No. 8-2500-30760, MPUC
Docket No. E002/CN-12-1240, September 27 and October 18,20131)
. Testimony in support of a competitive bid from a distributed solar project in
an all-source solicitation for generating capacity.
EXPERT WITNESS TESTIMOI{Y BEFORE THE NORTH CAROLINA UTILITIES
COMMISSION
1. Direct, Response, and Rebuttal Testimony of R. Thomas Beach on Behalf of the North
Carolina Sustainable Energy Association. (In the Matter of Biennial Determination of
Avoided Cost Rates for Electric Utility Purchases from Qualifying Facilities - 2014;
Docket E-100 Sub 140; April25, May 30, and June 20,2014)
. Testimony on avoided cost issues related to solar and renervable
qualifying facilities in N orth Carolina.
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Crossborder Energr
R. THOMAS BEACH
Principal Consultant Pase 17
LITIGATION EXPERIENCE
Mr. Beach has been retained as an expert in a variety of civil litigation matters. His
work has included the preparation of reports on the following topi-s:
The calculation of damages in disputes over the pricing terms of natural gas sales
contracts (2 separate cases).
The valuation of a contract for the purchase of power produced from wind generators.
The compliance of cogeneration facilities with the policies and regulations
applicable to Qualifring Facilities (QFs) under PURPA in California.
Audit reports on the obligations of buyers and sellers under direct access electric
contracts in the California market (2 separate cases).
The valuation of interstate pipeline capacity contracts (3 separate cases).
Crossborder Energy
In several of these matters, Mr. Beach was deposed by opposing counsel. Mr. Beach has
also testified at trial in the bankruptcy of a major U.S. energy company, and has been
retained as a consultant in anti-trust litigation concerning the California natural gas market
in the period prior to and during the 2000-2001 California energy crisis.
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.
CASE NO.
CASE NO.
IPC-E-rs-0r
AVU-E-1s-01
PAC-E-1s-03
Idaho Conservation League and the Sierra Club
Direct Testimony of R. Thomas Beach
Exhibit 302
Idaho Power Responses to:
A. Commission Staff Request No. 2
B. ICL/Sierra Club Request No. 5
C. Commission StaffRequest No. 18
D. I.R. Simplot Request No. 16
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
0
REOUEST NO. 2: Idaho Power's Petition states on page 2l "The continued and
unchecked addition of extremely large amounts of intermittent wind and solar QF
generation onto Idaho Power's system at long-term fixed rate prices when the Company
has no need for additional generation inflates power supply costs borne by customers
and degrades the reliability of the system." How does Idaho Power expect the recent
addition of 461 MW of solar contracts to impact customers' retail rates? Does the
Company expect rates will have to increase once the contracted solar projects are
online and Idaho Power is purchasing the energy? If Idaho Power expects rates will
increase, has the Company estimated the approximate rate or revenue requirement
increase? Ifso, please provide the estimate.
RESPONSE TO REOUEST NO. 2: The Company expects 100 percent of the
costs associated with the additional 461 MW of solar contracts to be collected from
customers through retail rates. The extent to which retail rates would change as a
result of the referenced solar contract costs requires a modeled forecast of power
supply expenses that must include a comprehensive set of assumptions that is not
known today and is subject to debate. To date, Idaho Power has not performed such an
analysis.
The Company's request in this case is to prospectively limit the contract term for
projects above the established surrogate avoided resource ("SAR") eligibility cap and
seeks to mitigate the risk of uncertain rate impacts that exist associated with additional
generation that is not needed to satisfr any near-term capacity or energy requirements.
The response to this Request is sponsored by Mike Youngblood, Regulatory
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
1
Projects Manager, Idaho Power Company.
REQUEST NO. 5: Please reference the Direct Testimony of Mr. Aliphin Exhibit
No. 8 that shows certain FERC account expenses for the years 2010 ,2012, and 2013:
a. Do FERC Account Nos. 501 (coal) and 547 (gas) include either fixed O&M
costs, incremental capital additions, or the costs associated with the return on rate base
and associated taxes for Idaho Power-owned coal and gas plants?
b. Please provide the fixed O&M costs, incremental capital additions, and the
revenue requirements associated with the return on rate base and associated taxes for
Idaho Power-owned coal and gas plants for the years 2010,2012, and 2013. For gas
plants, please also include gas pipeline capacity or reservation costs if not included in
Account 547.
c. If available, please provide the data in Exhibit No. 8, plus the data
requested in Part (a) of this question, for the years 2011 and 20L4.
RESPONSE TO REQUEST NO. 5:
a. No. The cost items that fall within Federal Energy Regulatory Commission
('FERC') Accounts 501 (coal) and 547 (gas) are those items which fall within the FERC
Uniform System of Accounts definitions for those respective FERC accounts. [n this
case, they are fuel-related expenses for the production of steam for the generation of
electricity (FERC Account 501) and cost of fuel delivered at the station of all fuel, such as
gas, oil, kerosene, and gasoline used in other power generation (FERC Account 547).
They do not include fixed operation and maintenance ("O&M") costs, incremental
capital additions, or the costs associated with the return on rate base and associated
taxes.
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
2
b. Fixed O&M costs, incremental capital additions, and the revenue
requirements associated with the return on rate base and associated taxes for Idaho
Power-owned coal and gas plants are included as part of a comprehensive cost-of-
service study conducted in the preparation of a general rate case; they are not
determined individually or on an annual basis. As such, these items were included in
the comprehensive class cost-of-service studies filed in the Company's 2008 and 2011
general rate cases (Case Nos. IPC-E-O8-10 and IPC-E-11-08, respectively), as well as the
rate increase determination due to the inclusion of the Langley Gulch power plant (Case
No. IPC-E-12-14). These studies can be found in the documents filed by the Company
in the respective cases, which are located on the Commission's website at the following
addresses:
Year 20lG- Case No. IPC-E-08-10
http://www.puc.idaho.qov/fiteroom/cases/summary/l PCEOSI
0.htmI
Y ear 2012- Case No. IPC-E- 1 I -08
http://www.puc.idaho.qov/fi leroom/cases/summary/IPCEl I
08.html
Year2Ol3-Case No. IPC-E- 12-14
http :Ilwww.puc.idaho.gov/fileroom/cases/summary/l
PCE12l4.html
c. The information requested for 2011 is equivalent to the information for
2010. The information requested for 2Ol4 is equivalent to the information for 2013.
The response to this Request is sponsored by Mike Youngblood, Regulatory
Projects M anager,Idaho Power Company.
IPC-E-ts-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
aJ
REOUEST 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 REOUEST NO. l8: No.
The response to this Request is sponsored by Mike Youngblood, Regulatory
Projects Manager, Idaho Power Company.
IPC-E-ls-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
4
REQUEST FOR PRODUCTION NO. 16: Has the Company investigated
the impacts of Idaho Power joining the PacifiCorp-California ISO energy imbalance
market as a potential way to reduce costs associated with intermittent generation or
for any other reasons? If not, why not? Please provide all studies or analyses of the
impacts of Idaho Power joining the PacifiCorp-California ISO energy imbalance
market.
Idaho Power has not
studied participation in the PacifiCorp-CAISO energy imbalance market primarily
because Idaho Power does not have any transmission rights that would allow it to
participate in the PacifiCorp-CAISO energy imbalance market
Idaho Power is participating in the Northwest Power Pool effiorts to study the
feasibility of an intra-hour market similar to an energy imbalance market referred to
as the Security Constrained Economic Dispatch and will continue to evaluate the
PacifiCorp-CAISO energy imbalance market and other market opportunities as they
become available.
The response to this Request is sponsored by Tess Park, Director Load Serving
Operations, Idaho Power Company.
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
5
BEFORE THE IDAHO PUBLIC UTITITIES COMMISSION
CASE NO. IPC-E-15-01
CASE NO. AVU-E-Is-OI
CASE NO. PAC-E-I5-03
Idaho Conservation League and the Sierra Club
Direct Testimony of R. Thomas Beach
Exhibit 303
California ISO/NVEnergy
Energy Imbalance Market Fact Sheet
IPC-E-1s-01
BEACH, Di
Idaho Conservation League and Sierra Club 0
Exhibit 303
t# Colif-ojfig*Js-9 YlllY^*-"J..$J
Seven states participating in the Energy lmbalance Market
Ilre /SO and PacifiCorp launched into the first western reallinte energy balancing market into operation on
November 1, 2014. NV Energy has obtained approval from both the Federal Energy Regulatory Commission
(FERC) and the Public Utilities Commission of Nevada (PUCN) and will go live with the Energy lmbalance Market
lElM) in fall of 201 5 Studres conducted by both contpanies of their parltcipation in EIM sltow significant economic
and reliability benefits that accrue to customers in the NV Energy. PacifiCorp, and ISO areas Participants in the EIM
can leverage generation resoLtrces across the entire EIM region. with the added benefit of more frequent dispatching
in real time to optinize available energy supp/ies The EIM rs an imporlant tool for operators acloss the region to
facil itate increased integration of renewable resources.
Background
Ihe /SO announced a partnership with Poftland-based PacifiCorp in February 2013 to develop an EIM that would
operate across participating balancing areas. Following a robust public stakeholder process, the /SO developed a
market design that was approved by the ISO Board in November 2013. PacifiCorp began participating in the EIM in
November 2014. With NV Energy, the expanded EIM would cover seven slates and over 44 million people
Reliability benefits
The EIM strengthens grid reliability by
balancing supply and demand closer to when
electricity is consumed and by allowing sysfem
o pe rato rs re a 11 i m e v i s i b i I ity across ne i g h bo ri ng
grids. The /SO is leveraging its existing market
systems to identify fluctuations in supply and
demand, and then automatically find the best
resource to meet current needs across a larger
region. This, in turn, optimizes the
interconnected high-voltage sysfem as market
systems automatically manage congestion on
transmission lines.
Renewa b le i nteg rati on benefits
While the nation's energy supply becomes
more diverse, regional coordination and finely
tuned dispatches become more important as
ch ang i ng we athe r co nd itio ns prod uce
variability in wind and solar power generation.
An EIM improves the ability to manage
resource outptl deviations, smoothing out
power flows in real time so that renewable
energy is effectively
IPC-E-1s-01
BEACH, Di
Idaho Conservatioi.. - -.ague
Exhibit 303
I
integrated onto the grid. By combining the NV Energy, PacifiCorp, and /SO's diverse portfolio, the
seven-sfafe EIM will make it possib/e to share more variable renewable resources such as wind or solar
during times of under- or overgeneration.
Easy and economical entry and exit
Studr'es indicate that the benefits to all customers in the seven-sfate EIM footprint outweigh fhe costs of
pafticipating in the ElM. ln addition, an EIM parlicipant can choose to leave the market at any time with
no exit fees.
Preserving autonomy
EIM entities such as PacifiCorp, NV Energy and other parlicipating balancing authorities maintain
operational control over their generating resources, retain all their obligations as a balancing area, and
must still comply with all regional and national reliability standards. For example, obligations to provide
reliability compliance, ancillary servrces, physical scheduling rights and bilateral trades do not change
with ElM.
A market-based solution
Ihe iSO already operates a successfu/ reallime fifteen minute market with five-minute dispatch
capability. Ihr's rs a tried and true service thal exrsls in a similar form in twolhirds of the United Stafes,
pafticularly in the Norlheast and Midwest as well as much of Canada. This partnership signals
continuing interest from other balancing areas in joining what is already working effectively to lower
costs and at the same time expanding the pool of resources available to meet supply and demand
needs in real time. lt is a voluntary and natural step toward the more efficient management of energy
sysfems for the benefit of customers.
Governance
Ihe /SO EIM expansion requires that all entities, whether inside or outside California, are given a voice
in the decision-making process going foruvard. ln May 2014 the ISO Board of Governors appointed the
EIM Transitional Committee that is working towards the development of a long term independent
governance proposal that will go through a stakeholder process in 201 5. The Board advisory
committee is composed of 9 members who were nominated by industry stakeholders and two
representatives from PacifiCorp and NV Energy. They have committed to work in an open and
transparent manner and be inclusive of a wide range of stakeholders making the EIM a truly western
market and encourage broad parlicipation
Next sfeps
Work is undentray to integrate NV Energy into the EIM in October, 2015. The ISO began publishing in
February 2015 quafterly repofts of the actual EIM benefits based on actual operating data.
Beginning in 2014 and continuing in 2015, NV Energy will conduct a stakeholder process for
transmission cuslomers and other stakeholders to make changes to its open access tariff in order to
implement the ElM. They will then seek FERC acceptance in mid-2015.
During 2015, the /SO will complete the stakeholder process for Year 1 Enhancements to ElM, to
address FERC compliance, commitments made during the original stakeholder process, and others
identified during implementation. Continued stakeholder involvement will be criticallo the success of the
EIM by offering valuable input and supporl to expand a market that can be leveraged to more
effectively use resources in the West.
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 303
CERTIFICATE OF SERVICE
I hereby certifr that on this 22nd day of April 2015, I delivered true and correct copies of
the DIRECT TESTIMONY OF ADAM WENNER, DIRECT TESTIMONY OF R. THOMAS
BEACH, and, EXHIBITS 301 - 303 on behalf of the Idaho Conservation League and the Sierra
Club the following persons via the method of service noted:
Hand Delivery:
Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
42TW.Washington St.
Boise,ID 83702-5983
(Original and nine copies provided)
Electronic Mail:
Idaho Power
Donovan E. Walker
Regulatory Dockets
Idaho Power Company
l22l West Idaho Street
P.O. Box 70
Boise,ID 83707
[e-mail]
[e-mail]
Avista
Michael G. Andrea, Senior Counsel
Clint Kalich
Avista Corporation
l4ll E. Mission Ave, MSC-23
Spokane, WA99202
Michael. [e-mail]
Clint.kalish@avistacorp. com
Roclry Mountain Power
Daniel Solander
Ted Weston
Rocky Mountain Power
201 S. Main Street, Ste 2400
Salt Lake City, UT 841l1
Daniel. solander@pacifi corp.com
Ted. we ston@pacificorp. com
datareque st@pacificorp. com
J.R. Simplot Corp & Clearwater Paper
Peter J. Richardson
Gregory M. Adams
Richardson Adams, PLLC
515 N. 27th Street
Boise, lD 83702
[e-mail]
[e-mail]
Dr. Don Reading
6070 Hill Road
Boise,ID 83703
[e-mail]
Carol Haugen, Clearwater Paper
Carol.haugen@clearwater. com
Twin Falls Canal, Northside Canal,
American Falls Reservoir District No 2.
C. Tom Arkoosh
Arkoosh Law Offices
802 W. Bannock St Ste. 900
P.O. Box 2900
Boise,lD 83701
Tom. arkoosh@arkoo sh.com
Erin. cecil@arkoo sh. com
Intermountain Energt P artners
Dean J. Miller
McDevitt & Miller LLP
420W. Bannock Street
PO Box 2564-83701
Boise,lD 83702
j [e-mail]
Leif Elgethun, PE, LLE AP
Intermountain Energy Partners
PO Box 7354
Boise,ID 83707
leif@sitebasedenergy. com
Idaho lrrigation Pumpers Association
Eric L. Olsen
Racine, Olson, Nye, Budge & Bailey,
Chartered
P.O. Box 1391
201E. Center
Pocatello,lD 83204
[e-mail]
Anthony Yankel
29814 Lake Road
Bay Village, OH 44140
[e-mail]
Micron Technology
Richard Malmgren
Assistant General Counsel
Micron Technology Inc.
800 South Federal Way
Boise,ID 83716
[e-mail]
Frederick J Schmidt
Pamela S Howland
Holland & Hart LLP
377 S. Nevada St.
Carson City, NV 89703
fschmidt@hollandhart. com
[e-mail]
Amalgamated Sugar
Scott Dale Blickenstaff
Amalgamated Sugar Co
1651 S. Saturn Way, STE 100
Boise, Idaho 83702
[e-mail]
Ren ew able En er gy C o alitio n
Ronald L. Williams
Williams Bradbury P.C.
l0l5 W. Hays St.
Boise,Idaho 83702
[e-mail]
Irion Sanger
Sanger law, P.C.
1117 SW 53'd Avenue
Portland, OR 97215
irion@sinager-law. com
Benjamin I. Otto
TPC-E-l5-OL 2
Certificate of Service - Direct Testimony of Wenner and Beach
April22,2015