20150302Clements Direct.pdf

IN THE MATTER OF THE PETITION OF
ROCKY MOLINTAIN POWER FOR
MODIFICATION OF TERMS AND
CONDITIONS OF PURPA PURCHASE
AGREEMENTS AND FOR
MODIFICATION OF ITS AVOIDED
COST METHODOLOGY
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CASE NO. PAC.E.I5.O3
PETITION OF ROCKY MOUNTAIN
POWER
i"ii-'
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP
DIRECT TESTIMONY
OF
PAUL H. CLEMENTS
I Q. Please state your name, business address, and present position with Rocky
2 Mountain Power (the "Company"), a division of PacifiCorp.
3 A. My name is Paul H. Clements. My business address is 201 S. Main, Suite 2300,
4 Salt Lake City, Utah 84lll. My present position is Senior Originator/Power
5 Marketer for PacifiCorp Energy. PacifiCorp Energy and Rocky Mountain Power
6 are divisions of PacifiCorp.
7 Q. How long have you been in your present position?
8 A. I have been in my present position since December 2004.
9 Q. Please describe your education and business experience.
l0 A. I have a B.S. in Business Management from Brigham Young University. I have
I I been employed with PacifiCorp since 2004 as an originator/power marketer
12 responsible for negotiating qualifl,ing facility contracts, negotiating interruptible
13 retail special contracts, and managing wholesale or market-based energy and
14 capacity contracts with other utilities and power marketers. I also worked in the
15 merchant energy sector for approximately six years in pricing and structuring,
16 origination, and trading roles for Duke Energy and lllinova.
17 PURPOSE AI\[D SUMMARY OF TESTIMONY
l8 a. What is the purpose of your testimony?
19 A. The purpose of my testimony is to support and present the Company's application
20 to modiff certain terms and conditions related to contracting and pricing for non-
2l standard qualiffing facility ("QF") contracts that the Company must enter into
22 under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). The
23 Company is seeking immediate relief on one item in order to protect its customers
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in the near term. The Company is also seeking permanent implementation of two
modifications to QF contracting and pricing procedures. These changes are
necessary in order to maintain the "ratepayer indifference" standard required by
PURPA in both the immediate near term and on a perrnanent basis. Specifically,
the Company is requesting an order from the Idaho Public Utilities Commission
("Commission") directing implementation of the following:
l. Immediate reduction, on a temporary basis, of the maximum contract term
for PURPA contracts between QFs and PacifiCorp from 20 years to five
years, pending litigation of this case.
2. Permanent reduction of the maximum contract term for PURPA contracts
from 20 years to three years, to be consistent with the Company's hedging
and trading policies and practices for non-PUMA energy contracts and
more aligned with the Integrated Resource Plan ('.IRP") cycle.
3. Modification of the Company's avoided cost methodology such that
preparation of indicative prices for QFs shall reflect all active QF projects
in the pricing queue ahead of any newly proposed QF request for
indicative prices.
I provide evidence demonstrating how PacifiCorp customers could be adversely
impacted by the Commission's February 6, 2015 order in Idaho Power
Company's ("Idaho Power") Case No. IPC-E-15-01 if the Commission does not
take immediate action in this proceeding. I also describe the significant increase
the Company has experienced in PURPA contract requests in20l4 and 2015, how
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the increased activity harms customers, and why the requested modifications to
the avoided cost contracting and pricing procedures are needed.
PacifiCorp currently has 189.6 megawatts ("MW") of existing PURPA
contracts in Idaho and 275.5 MW of proposed PURPA contracts in Idaho,
together totaling 465.1 MW of nameplate capacity. The magnitude and potential
impact of this increased PURPA activity is best measured by comparing the total
amount of existing and proposed Idaho PURPA projects to PacifiCorp's Idaho
retail load. Using 2014 as an example, PacifiCorp's average total Idaho retail load
was 432 MW and its minimum total Idaho retail load was 169 MW. The 465.1
MW of existing and proposed PURPA contracts in Idaho at their nameplate
capacity would be enough to supply 108 percent of PacifiCorp's average Idaho
retail load and 275 percent of PacifiCorp's minimum retail load. Expanding the
analysis to PacifiCorp's six-state system, PacifiCorp currently has requests for
3,641 MW of new PURPA contracts system-wide, in addition to the 1,732 MW of
QF contracts that are already executed.
I explain how this material increase in the number of PURPA projects
requesting pricing in both Idaho and on PacifiCorp's system in other states will
result in proposed Idaho projects receiving and entering into purchase obligations
based upon pricing that is not reflective of the actual cost of the resource the QF
will displace under the currently effective IRP methodology. I also provide
evidence demonstrating the impact of PURPA contracts on customers' rates, and
illustrate how the required 2}-year contract term is (1) inconsistent with the
Company's hedging and resource acquisition policies and practices for non-
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PURPA energy purchases and (2) not aligned with the Company's IRP planning
cycle and action plan. Lastly, I describe how, without the requested modification
to contract term, PacifiCorp will be forced to continue to acquire long-term fixed
price PURPA contracts even though PacifiCorp's 2013 IRP Update, which was
filed with this Commission, shows that new long-term resources are not required
until2027. PacifiCorp's 2015 IRP, which is scheduled to be filed in March 2015,
will show no new resource is required until2028.
Is the application supported by other witnesses?
Yes. Company witness Mr. Brian S. Dickman describes how the current avoided
cost rate methodology does not recognize the impact of proposed QF contracts
that are not yet signed but have requested indicative avoided cost prices and are
actively pursuing a power purchase agreement ("PPA") with the Company - a
shortcoming that leads to inflated and incorrect avoided cost prices in PURPA
contracts due to QFs ability to enter into purchase obligations unilaterally. This
shortcoming is particularly impactful when there are multiple PURPA contract
requests at the same time, which is currently the case in Idaho and across
PacifiCorp's six state system.
Why are the requested modifications critical at this time?
First, the Company is seeking expedited and temporary relief based on the
following event: Within five days of the Commission's February 6,2015 Order
("Idaho Power Order"), PacifiCorp received four pricing requests totaling 130
MW from PURPA developers located in Idaho Power's service territory, who are
now planning to obtain a transmission wheel to PacifiCorp in search of a PPA
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with more favorable terms. Because of this arbitrage, which could potentially
cause immediate harm to the Company's retail customers, the Company is
seeking an expedited order temporarily lowering the Company's maximum
PURPA contract tenor from 20 years to five years.
Second, the Company seeks permanent changes to its PPA terms and
conditions in general. The Company has reviewed its PURPA contracting and
pricing procedures and believes that permanent, long-term changes to its PUttPA
contracts are critical to maintain the customer indifference standard required by
PURPA and to protect the welfare of the Company's Idaho retail customers. In
Order No. 33204, the Commission stated that utilities are in the best position to
advise the Commission when changes to PURPA contract terms and conditions
are warranted:
While we are pleased with the progression of the IRP methodologt,
avoided cost rates ore not the only terms to o PURPA contract. The
utilities are in the best position to inform the Commission if review of
additionol PURPA contract terms and conditions is watanted.l
PacifiCorp routinely reviews PURPA contract terms and conditions and avoided
cost methodologies, and recent events dictate that PacifiCorp petition this
Commission for changes at this time.
Like Idaho Power, the Company has experienced a significant increase in
QF pricing requests in Idaho and across its six-state system. Similar to Idaho
Power, the Company has no need for resources for the next decade. Also similar
to Idaho Power, the Company's hedging practices and policies are short-term in
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I Order No. 33204 at7.
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nature. The Company's hedging program was modified as a result of a series of
hedging collaborative workshops the Company held with stakeholders in 201I
and 2012 which reduced the Company's standard hedging horizon from 48
months to 36 months.
Given the magnitude of new QF requests, and considering the inherent
uncertainties in projecting avoided cost rates out 20 years or more, current Idaho
avoided cost rates are adversely impacting customers and will continue to do so
for 20 years. Thus, in addition to the temporary, immediate change noted above,
the Company also seeks two permanent changes. First, the Company requests
approval of a permanent reduction in the maximum contract term for PURPA
contracts, from 20 years to three years. Such a term would be more consistent
with the Company's hedging and trading policies and practices for non-PUMA
energy contracts and more aligned with the IRP cycle.
Second, Company witness Mr. Dickman reviewed the impact of the
Company's large QF pricing queue on avoided costs in Idaho and determined that
the currently approved methodology distorts avoided cost pricing because each
project must be priced as if it were first in the queue. Because a purchase
obligation may be created before each QF project can be re-priced to account for
other projects that have entered into an obligation around the same time, the
current methodology artificially inflates indicative avoided cost pricing for
projects lower in the queue, harms retail customers if multiple purchase
obligations are entered into based on that inaccurate pricing, and violates the
ratepayer indifference standard under PURPA.
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These events and the resulting consequences prompted the Company to
file this petition to inform the Commission that changes are warranted.
Describe the history and purpose of PURPA.
Congress enacted PURPA in response to the nationwide energy crisis of the
1970s. Its goal was to reduce the country's dependence on imported fuels by
encouraging the addition of cogeneration and small power production facilities to
the nation's electrical generating system.2 PURPA requires electric utilities to
purchase all electric energy made available by QFs at rates that (a) are just and
reasonable to electric consumers, (b) do not discriminate against QFs, and (c) do
not exceed "the incremental cost to the electric utility of alternative electric
energy."3 The incremental cost to the utility means the amount it would cost the
utility to generate or purchase the electric energy but for the purchase from the
QF.4 The incremental cost standard is intended to leave customers economically
' See, e.g.,l6 U.S.C. $ 2601 (Findings).
3 The provisions of l6 U.S.C. $ 824a-3 provide in pertinent part:
(a) Cogeneration and small power production rules
Not later than I year after November 9,1978, the Commission [FERC] shall prescribe, and from
time to time thereafter revise, such rules as it determines necessary to encourage cogeneration and
small power production, which rules require electric utilities to offer to -(l) sell electric energy to qualifring cogeneration facilities and qualifoing small power
production facilities and
(2) purchase electric energy from such facilities. . .
(b) Rates for purchases by electric utilities
The rules prescribed under subsection (a) ofthis section shall insure that, in requiring any electric
utility to offer to purchase electric energy from any qualifuing cogeneration facility or qualifoing
small power production facility, the rates for such purchase -
(1) shall be just and reasonable to the electric consumers ofthe electric utility and in the
public interest, and
(2) shall not discriminate against quali$ing cogenerators or qualifuing small power
producers.
No such rule prescribed under subsection (a) of this section shall provide for a rate which exceeds
the incremental cost to the electric utility of alternative electric energy.a The provisions of 16 U.S.C. $ S2aa-3(d) provide the following definition of "incremental cost of
alternative electric energy":
For purposes of this section, the term "incremental cost of alternative electric energy" means, with
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indifferent to the source of a utility's energy by ensuring that the cost to the utility
of purchasing power from a QF does not exceed the cost the utility would incur in
the absence of the QF purchase.s
In 1980, FERC issued rules implementing PURPA in which it adopted
what it called a utility's "avoided costs" as the standard for implementation of the
incremental cost requirement.o While the applicable statutes and rules are matters
of federal law, PURPA gives to state regulatory authorities the responsibility of
determining a utility's avoided costs as well as terms and conditions of PURPA
contracts.T
Under PURPA, are utilities or their customers intended to subsidize QFs in
order to achieve PURPA's policy goals?
Absolutely not. As this Commission and state regulators across the country have
stated time and time again, under PUMA's original intent, retail customers
should be indifferent to the purchase of QF power. This Commission stated as
early as 1987 that,
Under current FERC regulations implementing the Public Utility
Regulatory Policies Act, ratepayers are supposed to be indifferent
respect to electric energy purchased from a qualifring cogenerator or qualiSing small power
producer, the cost to the electric utility of the electric energy which, but for the purchase from
such cogenerator or small power producer, such utility would generate or purchase from another
source.t See, e.g., Armco Advanced Materials Corp. v. Pennsylvania Pub. lJtil. Comm'n, 535 Pa. 108,634 A.zd
207,209 (Pa.1993).
6 See American Paper lrat. v. American Elec. Power Serv., 461 U.S. 402, 406(1982) (stating that "the term
full 'avoided costs' used in the regulations is the equivalent of the term 'incremental cost of alternative
electric energy' used in $ 210(d) of PURPA"). FERC's definitions of terms used in implementing PURPA
are found at 18 C.F.R. $ 292.101. The term "avoided costs" is defined as "the incremental costs to an
electric utility of electric energy or capacity or both which, but for the purchase from the qualifting facility
or qualifring facilities, such utility would generate itself or purchase from another source." l8 C.F.R. $
2e2.t0t(b\(6).
'IdahoPowerCo.v. IdahoPub.Util.Comm'n.,155 Idaho780,782(2013)(IdahoPowerCo.")(citing
FERC v. Mississippi,456 U.S. 742,751 (1982)).
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or neutral as to whether they receive energy through a QF or a
regulated utility. Stated differently, the price structure should
enable utilities to integrate in a neutral and unbiased manner both
utility and non-utility owned generating facilities into the long-run
planning process and should provide similar economic criteria for
development and operation of generating facilities regardless of
facility ownership.s
FERC has likewise affirmed the need to ensure customer indifference to utility
purchases of QF power, noting that, in enacting PURPA, "[t]he intention [of
Congress] was to make ratepayers indifferent as to whether the utility used more
traditional sources of power or the newly-encouraged altematives."e
Under PURPA, then, customers must remain indifferent or unaffected by
QF contracts. Further, as this Commission has noted "avoided cost rates are not
the only terms to a PURPA contract."1o Indeed, both avoided costs and other
terms and conditions of PURPA contracts affect whether retail customers remain
indifferent to the purchase of QF power. The modifications requested by the
Company in this application are necessary to maintain this ratepayer indifference
standard and are the primary means by which the Company and the Commission
can protect customers from unnecessary price risk.
Does the Commission have discretion to determine the appropriate contract
term and avoided cost pricing methodology under PURPA?
Yes. Although PURPA's federal mandate requires utilities to purchase QF power,
PURPA's scheme of cooperative federalism gives state regulatory agencies the
8 In re Review of the ldaho Pub. Utils. Comm'n Policies Establishing Avoided Costs IJnder the Pub. Util.
Regulatory Policies Act of 1978, Case No. U-1500-170, Order No. 21249 (May 1987).
e Southern Cal. Edison Co., et al.,7l FERC n il,269 at p. 62,080 (1995), ovemrled on other grounds, Cal.
Pub. Util. Comm'n, 133 FERC .!T61,059 (2010).
to In re Application of ldaho Power Co., Case No. IPC-E-14-30, Order No. 33204 at 8 (Jan. 8, 2015).
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authority to protect retail customers from any unintended negative consequences
of these mandatory purchases by delegating to state authorities the freedom to
establish the key terms and conditions of PURPA contracts.ll In crafting their
methodologies for the details of PURPA contracts, FERC has explained its view
that "states are allowed a wide degree of latitude in establishing an
implementation plan for section 210 of PURPA, as long as such plans are
consistent with [FERC's] regulations."r2 A critical element of the utility's must-
purchase requirement under PURPA is the contract term. This is because FERC
generally requires a utility to lock in forecasted avoided cost rates for the entire
contract term.13
The contract term for PURPA contracts set by this Commission has never
been static-it has varied since PUMA's inception. Initially, the Commission set
PURPA contracts at 35 years to match the amortization period allowed for similar
utility owned facilities, making financing easier, thus encouraging QF
development.ra Later, the Commission began to recognize concerns related to the
risk and uncertainty inherent in long range forecasting and shortened the contract
length to 20 years.'u This time frame was shortened to only 5 years in 1996 and
1997 (first for QFs of I MW and larger, then for QFs under the I MW cap) in
order to align the QF contract time frame with the utilities' acquisition
" Idaho Power Co' lS5Idaho 780 at782; Exelon Wind I, LLC,766 F.3d 380 (5th Cir. 2014).
t2 Cal. Pub. Util. Comm'n,133 FERC fl 61,059 atP 24 (2010).
t3 See Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of
P U RPA, 45 Fed. Reg. 12214, 12224 (1980).
ta See, e.g. Order No. 29029 at 2 (describing the origin of PURPA regulation in ldaho).
" Order No. 21630.
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strategies.lo The Commission noted in that case that a 20 year contract obligation
did not reflect the manner in which the utilities were acquiring power to meet new
load, which at the time was through contracts with terms of five years or less, and
that "it would be nothing more than an artificial shelter to the QF industry to
provide those projects with contract terms not otherwise available in the free
market."l7
In 2002, the Commission raised the contract length back to 20 years,
expressing concerns about a scarcity of QF contracts signed since the prior
change.'8 Since then, concerns regarding the viability of QFs are no longer at the
forefront. In 2015, the key concerns about PURPA contracts are similar to those
that were present at the time of the Commission's 1996 and 1997 orders reducing
the term to five years, i.e., the current concerns flow from the magnitude of QF
power flowing onto utilities' systems without any finding of utility need and
resulting concerns about price risk, reliability, and customer indifference. As the
Commission noted in a recent press release, the Commission has approved
PURPA contracts for 400 MW of solar energy in just the past three months." But
the Commission noted, '.PURPA does not address and FERC regulations do not
adequately provide for consideration of whether the utility being forced to
16 See Order No.26576; Order No. 29029 at 5 (describing the history of PURPA regulation in Idaho).
" Order No. 26576 at 13.
18 See Order No. 29029 at 7 (stating that it "could not ignore the fact that since reducing the eligibility
threshold to I MW and contract term to 5 years, there has been only one PURPA contract signed in
Idaho.").
'e Press Release, Idaho Public Utilities Commission, PUC reduces length of some PURPA contracts to five
years (Feb. 5,2015).
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purchase QF power is actually in need of such energy."2o The Commission has
repeatedly expressed concerns about price and reliability impacts on Idaho
customers in the past year, concerns that led the Commission to lower the
approved length of PURPA contracts for Idaho Power down to five years in the
Commission's February 6 Order.2l
Can a 2}-year fixed-price contract term be considered a "subsidy" to a QF?
Yes. Given the typical contracting and hedging horizons for energy contracts in
the utility industry, which are commonly limited to less than 36 months, it is
extremely rare for a utility to voluntarily enter into a 2O-year fixed-price energy
contract without a specified energy resource need due to concerns about price
risk, market liquidity, and other risk considerations. Under the Commission's
current PURPA policies, however, any QF can obtain a Z}-year, fixed-price
energy contract at the Company's projected avoided cost, without any economic
considerations or price adjustment to account for the risk to utility customers from
this unusual long-term transaction, or to the QF to account for the price certainty
the QF enjoys from such a contract. As this Commission has noted, "avoided cost
rates are not the only terms to a PURPA contract." Contract lengths are also
PURPA contract terms, and they carry with them their own economic value. To
grant QFs access to long-term price certainty with no adjustment to the price to
account for that certainty is granting QFs something no other market participant
20 order No. 33204 at7.2t Order No. 33222.
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enjoys. For this reason, I would view a guaranteed, fixed-price, 20-year conffact
at avoided cost to be a QF subsidy.
IMPACT OF THE COMMISSIONOS IDAHO POWER ORDER: AN IMMEDIATE
INCREASE IN QF PRICING REQUESTS
a. How has the Idaho Power Order affected PacifiCorp?
A. On February 11,2015, five days after that order, PacifiCorp received four new
PURPA pricing requests in Idaho totaling 130 MW. In their requests, the
developers specifically noted that they plan to interconnect the QF to Idaho Power
Company's distribution/transmission system and wheel the power to Rocky
Mountain Power. They further specifically request proposals for a minimum
contracting term of 20 years. Their actions indicate that these developers would
not have sought to sell to PacifiCorp had the 2O-year contract term requirement
not been reduced to five years for Idaho Power. In addition to these four formal
requests, the Company has received several informal inquiries and expects to
receive additional requests from projects located in Idaho Power's service
territory. Since the current 465.1 MW of existing and proposed PURPA contracts
in Idaho at their nameplate capacity is already enough to supply 108 percent of
PacifiCorp's2014 average Idaho retail load and 275 percent of PacifiCorp's 2014
minimum ldaho retail load, immediate action must be taken.
Is it possible for projects to obtain the transmission rights required to move
energy from Idaho Power's system to PacifiCorp's system?
Yes. PacifiCorp has reviewed Idaho Power's Open Access Same Time
Information System ("OASIS") and confirmed that transmission is available.
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Is this type of wheel permitted under PURPA?
Yes. FERC's rules and orders contemplate that if a QF interconnects with one
utility and wheels power to another utility's system, the second utility is required
to purchase that power under PURPA. See, e.g., 18 CFR $292.303.
Is it just and reasonable and in the broad public interest for the Commission
to allow QFs the ability to arbitrage between the various Idaho utilities based
on different contract terms?
No. One group of Idaho customers should not be harmed by actions taken to
protect another group of Idaho customers. The customer indifference standard
should extend equally to all Idaho customers, regardless of the utility that serves
them. In this case, actions taken by the Commission to protect Idaho Power
customers may inadvertently result in harm to Rocky Mountain Power customers.
In a prior case brought before this Commission to address a similar
situation in 1996 and 1997, Commission Staff stated its belief that "rules
regarding contract length for PURPA contracts should be the same for all
regulated electric utilities in Idaho to avoid disparate treatment."22 The
Commission ultimately agreed with the Staffls position in that case and
incorporated their position in its order. In today's situation, similar to what
occurred when found in these same circumstances in the past, Rocky Mountain
Power customers should be afforded the same protections provided to other Idaho
customers.
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" Case No. UPL-E-97-4, Order No.27213.
I Q. Notwithstanding the consequences you describe above that resulted from the
2 ldaho Power Order, is there other evidence that supports PacifiCorp's
3 requested modifications?
4 A. Yes. The Company will present substantial and compelling evidence
5 demonstrating why the Company's requested modifications are necessary in order
6 to maintain the "ratepayer indifference" standard. The consequences of the Idaho
7 Power Order support the need for immediate relief but are not the sole reason the
8 immediate and permanent changes are warranted at this time.
9 SIGNIFICAI\IT INCREASE IN PURPA CONTRACT REQUESTS
10 a. Has PacifiCorp executed a significant number of PURPA contracts in recent
I I years in response to its federal obligation?
12 A. Yes. PacifiCorp currently manages l4l PURPA contracts totaling 1,732 MW of
13 nameplate capacity across its six state system. Of this total, 97 projects totaling
14 1,553 MW (90 percent of the total PURPA MWs under contract) have online
15 dates of 2007 or later, demonstrating that significant activity has occurred in the
16 last seven to eight years. Of this total,47 projects totaling 885 MW (slightly more
17 than half of the total PURPA MWs under contract) have online dates of 2014 or
l8 later, further demonstrating the exponential increase in PURPA contract requests
19 and resulting contracts that have occurred in the last two years. In Idaho, four
20 projects totaling 164.7 MW came online in 2011 and 2012. Those four tdaho
21 projects alone are close in nameplate capacity to PacifiCorp's minimum Idaho
22 retail load in20l4 of 169 MW.
23 This dramatic increase in PURPA contract executions and pricing requests
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in Idaho and system-wide in the last several years demonstrates that additional
review of contract and pricing methodology for non-standard Idaho QFs is
warranted at this time and could not have been anticipated when the Commission
reviewed the issue of contract term in previous cases.
Please describe the current queue of pricing requests for PURPA contracts in
Idaho and across PacifiCorp's system.
In ldaho, the Company currently has 12 project requests totaling 275.5 MW of
nameplate capacity. The Company currently has requests from 89 projects
totaling 3,641 MW of nameplate capacity system-wide. Table I shows the
number of project requests and the total MWs by resource type for each of
PacifiCorp's six states:
Table 1
Exhibit No. I provides detailed information on the pricing queue, including each
project location (state), size (nameplate capacity), Upe (i.e. solar, wind), and
proposed online date. Project names have been withheld to maintain
confidentiality of the customer information.
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Stite Wind Solar O ther Totrl
Projects MVYs Projects MWs Proje cts MWs Proj e cts MWs
Celifornie
Idaho I1.0 271.0 1.0 4.5 12.0 275.5
Oregon 25.0 312.4 1.0 3.5 26.0 315.9
Utah 5.0 3 54.0 38.0 2,075.6 43.0 2,429.6
Washington
Wyoming 8.0 620.0 8.0 620.0
IOTAL r3.0 974.0 74.0 2,659.0 2.0 8.0 89.0 3,641.0
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a.How does the number of executed Idaho PURPA contracts and proposed
Idaho PURPA contracts compare to PacifiCorp's typical Idaho load
requirements?
PacifiCorp has 189.6 MW of existing PURPA contracts in Idaho and 275.5 MW
of proposed PURPA contracts in ldaho, together totaling 465.1 MW of nameplate
capacity. Using 2014 as an example, PacifiCorp's maximum total retail load in
Idaho was 818 MW, its minimum load was 169 MW, and its average load was
432 MW. The 465.1 MW of existing and proposed PURPA contracts in Idaho at
their nameplate capacity would be enough to supply 108 percent of PacifiCorp's
average Idaho retail load and 275 percent of PacifiCorp's minimum Idaho retail
load.
How does the number of executed PURPA contracts and proposed PURPA
contracts across PacifiCorp's system compare to PacifiCorp's typical six
state system load requirements?
PacifiCorp has 1,732 MW of existing PURPA contracts and 3,641 MW of
proposed PURPA contracts, together totaling 5,373 MW of nameplate capacity.
Using 2014 as an example, PacifiCorp's maximum total retail load across its six
state system was 10,314 MW, its minimum load was 4,967 MW, and its average
load was 6,844 MW. The 5,373 MW of existing and proposed PURPA contracts
at their nameplate capacity would be enough to supply 79 percent of PacifiCorp's
average retail load and 108 percent of PacifiCorp's minimum retail load.
Clements, Di - 17
Rocky Mountain Power
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DISTORTION OF INDICATIVE AVOIDED COST PRICING DUE TO
INCREASE IN PURPA CONTRACT PRICING QUEUE
a. How is indicative pricing calculated if you have multiple proposed PURPA
contracts in the pricing queue?
A. Each proposed QF project is provided an indicative price assuming the project
requesting pricing is at the top of the pricing queue, meaning the existence of
other proposed or queued QF projects is not factored into the indicative price.
Therefore, each project is provided an indicative price based on the Company's
highest marginal or avoided resource costs. For example, assuming PacifiCorp's
highest marginal or avoidable cost for a given time period is a 25 MW market
purchase at $35 per megawatt-hour ("MWh"), and the next highest marginal or
avoidable cost for the same time period is a second 25 MW market purchase at
$30 per MWh. Under the current approved methodology, a proposed 20 MW QF
would receive an indicative price based on avoiding 20 MW of the 25 MW
purchase at $35 per MWh. If the Company were to receive a second 20 MW
pricing request for a different PURPA project, it too would receive an indicative
price based on the assumption that it avoids 20 MW of the 25 MW purchase at
$35 per MWh, because the current methodology does not allow the Company to
account for the existence of the first proposed project when providing pricing for
the second proposed project. If both parties were to unequivocally commit
themselves to sell to PacifiCorp at around the same time, PacifiCorp could not re-
price the second project to reflect the fact that the first project already "avoided"
the same resource. In my hypothetical example, both 20 MW projects, or 40 MW
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total, would be priced as if they were avoiding the single 25 MW resource at $35
per MWh. In reality, if considered together they would be avoiding 25 MW of the
$35 per MWh resource and 15 MW of the $30 per MWh resource. In this
example, the inability to account for the first proposed contract when providing
pricing for the second proposed contract results in customers paying a QF $35 per
MWh for l5 MW when the actual cost of the l5 MW being avoided by that QF is
only $30 per MWh. This $5 per MWh difference violates the ratepayer
indifference standard.
What is the impact of a very large pricing queue (i.e. multiple proposed
PURPA projects requesting contracts) on indicative pricing?
A very large pricing queue results in indicative pricing being provided to
proposed PURPA projects that is far in excess of actual avoided costs if all
queued projects are considered. The larger the queue, the greater the problem. In
my example above, I described how two hypothetical 20 MW projects received
pricing based on the single highest cost resource, but one of them actually avoided
a lower cost resource when considered together. The result was an avoided cost
that was $5 per MWh too high. If the queue has dozens of PURPA projects
requesting pricing, as is currently the case, this issue is exacerbated. Multiple
projects may receive indicative pricing based on the highest cost resource, but
when the dozens of projects are considered together, the projects at the bottom of
the queue are likely avoiding much lower cost resources. This results in payments
to QFs that exceed the cost of the resource that is being avoided. This increases
costs to customers and is not consistent with the ratepayer indifference standard
Clements, Di - l9
Rocky Mountain Power
I mandated by PURPA. Company witness Brian Dickman provides additional
2 evidence and supporting testimony regarding the impact of the existing pricing
3 queue on avoided cost pricing. In his testimony, he describes how the difference
4 in avoided costs from the top to the bottom of a pricing queue with approximately
5 3,000 MW, or 641 MW less than the current PacifiCorp pricing queue of 3,641
6 MW, is approximately $18 per MWh - meaning indicative pricing for the last
7 project request received could be as much as $18 per MWh higher than avoided
8 costs if all the project requests ahead of it in the 3,000 MW queue enter into
9 purchase obligations.
IO THE COMPAIIY'S IDAHO PURPA CONTRACTS WILL RESULT IN ITIGHER
11 CUSTOMER RATES, IN CONFLICT WITH THE RATEPAYER
12 INDIFFERENCESTAITDARI)
l3 a. What impact should PURPA contracts have on customer rates?
14 A. PURPA contracts should have no impact on customer rates. As this Commission
15 and state regulators across the country have stated time and time again, retail
16 customers should be indifferent to the purchase of QF power. As FERC has noted,
17 in enacting PURPA, "[t]he intention [of Congress] was to make ratepayers
18 indifferent as to whetherthe utility used more traditional sources of power orthe
19 newly-encouraged alternatives." Southern CaL Edison Co., San Diego Gas &
20 Elec. Co.,7l FERC n 61,269 at p. 62,080 (1995).
2l In short, customers must remain indifferent or unaffected by PURPA
22 contracts. The modifications requested by the Company in this application are
23 necessary to maintain this indifference standard.
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a. Why is it critical to make needed modifications to pricing and contracting
procedures quickly once they have been identified?
A. As mentioned earlier in my testimony, PacifiCorp currently has 189.6 MW of
existing PURPA contracts in Idaho and 275.5 MW of proposed PURPA contracts
in ldaho, together totaling 465.1 MW of nameplate capacity. The Company has
l4l existing (executed) PURPA contracts totaling 1,732 MW of nameplate
capacity across its six state system. Under PacifiCorp's multi-state jurisdictional
cost allocation model, PURPA contracts are considered system resources and are
allocated to each of the six states based on the System Generation allocation
factor. Idaho's allocated share is typically around six percent. The expected
system wide costs (payments to QFs) over the next ten years from PacifiCorp's
executed PURPA contracts is $2.6 billion. In 2015 alone, the projected payment
to QFs is $170.5 million, with Idaho's allocated share at $10.2 million." If these
projects had been priced incorrectly by just l0 percent, it would create a $1.0
million impact in 2015 for Idaho customers. That l0 percent impact would grow
to a total of $15.5 million in additional costs to Idaho customers over the ten year
period starting in 2015. With a pricing queue that currently totals 3,641 MW, or
more than double (in MW) the size of the $2.6 billion worth of current PURPA
contracts to which the Company is already obligated, it is imperative that the
indicative pricing provided to prospective PURPA projects be accurate and
reflective of the Company's actual projected avoided costs. Failure to implement
the modifications proposed by the Company in this case will result in significant
Clements, Di - 21
Rocky Mountain Power
23 Assuming an allocation factor of 6 percent.
I irreversible harm to customers in the form of higher retail rates than what would
2 otherwise occur without the PURPA contracts.
3 20 YEAR PURPA CONTRACTS ARE INCONSISTENT WITH CURRENT
4 HEDGING PRACTICES AND RISK POLICIES AI\D REQUIRE CUSTOMERS
5 TO BEAR AII INAPPROPRIATE AND UNNECESSARY LEVEL OF PRICE
6 RISK
7 Q. When the Company considers purchasing power from a third party, does the
8 Company first review the proposed purchase from a resource need and a
9 risk-management perspective?
l0 A. Yes. The Commission expects the Company to serve its customers with least-cost,
I I least-risk resources. For that reason, the Company has integrated resource
12 planning processes and risk-management policies it applies to evaluate any
13 proposed energy contracts, to ensure the contracts are reasonable and prudent.
14 a. Does the Company apply its integrated resource planning process and
l5 internal risk management policies to PURPA contracts?
16 A. No, not in the same way as it does for non-PURPA contracts. The Company
17 cannot refuse to execute PURPA contracts based on the price or the contract term,
18 or based on other transaction parameters that it would normally not accept for
19 non-PURPA contracts. Under PURPA, the Company must purchase QF energy
20 and capacity regardless of whether the Company needs the power, on terms and
2l conditions established by its state commissions.
22 a. How does the Company manage PURPA contract risk?
23 A. While the Company has some limited ability to negotiate PURPA contract terms
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and conditions, and while the Company uses its non-QF resources to integrate QF
power into its system as efficiently and reliably as possible, PURPA requires the
Company to rely primarily on its state regulatory commissions to regulate
customer exposure to risk through the establishment of terms and conditions of its
PURPA contracts.
PURPA contracts aside, please generally describe the current electricity and
natural gas hedging practices and policies at PacifiCorp.
The Company modified its hedging horizon for natural gas and power from 48
months to 36 months as a result of hedging collaborative workshops it held with
stakeholders in 201I and 2012. The Company's trading policies and procedures
are outlined in the PacifiCorp Energy Commercial & Trading Risk Management
Policy. That policy sets forth how the Company identifies, assesses, monitors,
reports, manages and mitigates each of the various types of commercial risk
associated with energy trading. Energy commodities include, but are not limited
to, physical and financial transactions of electricity and natural gas, #2 fuel oil,
unleaded gasoline, renewable energy credits, SO2 emission allowances, and
greenhouse gas allowances. PacifiCorp's commercial & trading organization
within PacifiCorp Energy manages the energy commodity position and utilizes
PacifiCorp's assets and liabilities (loads, generating resources, contractual rights,
and obligations) to (i) ensure reliable sources of electric power are available to
meet PacifiCorp's customers' needs and (ii) reduce volatility of net power costs
for PacifiCorp's customers.
PacifiCorp's commodity risks are managed through a control and
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structure that defines the maximum levels of market risk and credit capacity
permissible for commercial & trading to engage in trading and risk management
activities. Compliance with this policy is mandatory.
PacifiCorp's current practice is to actively manage electricity and natural
gas short and long positions that are 36 months out and nearer, meaning up to
three years from today. Traders have risk limits that they must maintain in order
to limit customer price exposure to the Company's open position over this three
year time horizon. This trading practice ensures reliable sources of electric power
are available to meet PacifiCorp customers' needs and reduces volatility of net
power costs.
Do PacifiCorp traders actively manage or hedge positions beyond the prompt
36 months?
No. The Company's practice since it completed the hedging collaborative
workshops in 2012 has been to limit hedges to 36 months or less unless
stakeholders express interest for longer term hedges. There has been no such
expressed interest for electricity hedges beyond 36 months since that time. The
Company's risk management metrics are also limited to 36 months.
Why are these risk management and hedging policies and requirements not
applicable to the Company's PURPA contracts?
The Company is obligated by law to purchase electricity from QFs at prices and
terms set forth by the appropriate state commissions. In this sense, the Company's
primary vehicle for risk management review of PURPA contracts are the policy
decisions made by each state commission.
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What process would PacifiCorp undertake when contemplating a non-
PURPA transaction that exceeds the typical36-month time horizon?
Non-PUMA transactions that exceed 36 months in effective transaction period
require extensive analysis and progressively higher level of management review.
The analysis includes a review of the need for the transaction, a comparison of the
contemplated transaction to other available transactions that meet the same need,
a thorough economic analysis to demonstrate that the transaction is the least-cost,
least-risk way to meet the identified need, and an extensive review of credit terms
and contract terms. Typically the level of detail, documentation, and review
increases commensurate with the size and duration of the transaction, which also
increases the level of management approval that is required.
The Company primarily enters into long-term transactions (those that
exceed 36 months) only when there is a clearly identified long-term resource need
in its IRP. Long-term resource needs are typically identified in the IRP only after
lower-cost, lower-risk short-term resource opportunities are exhausted such that a
long-term resource is required to meet customer load requirements.
When the Company enters into a long-term transaction as a result of the IRP
action plan, what additional steps are taken to protect customers?
The Company typically utilizes a rigorous request for proposal ("RFP") process to
acquire any long-term transaction or resource need directed by the IRP action
plan. This process often involves extensive input from regulators in the drafting
and management of the RFP. In fact, the process often includes independent
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evaluatofa review of the process and ultimate results. This robust process ensures
the Company acquires only what is needed and results in a long-term transaction
at the lowest cost possible. In addition to the extensive RFP process, any long-
term transaction goes through the analysis and review process I described in
conjunction with the PacifiCorp Energy Commercial & Trading Risk
Management Policy.
Do these same steps occur prior to entering into a PURPA contract?
No. PURPA contracts do not go through the same extensive IRP process to
determine if they are needed. PURPA contracts do not go through the same
competitive bid RFP process including oversight by an independent evaluator to
ensure they are lowest cost. PURPA contract executions are not limited to the size
of the resource need in the IRP action plan. And, PURPA contracts do not receive
the same upper management review and analysis because upper management does
not have the discretion to refuse the mandatory purchase obligation and the 20
year contract term established by the Commission. The Company is asking the
Commission to use its discretion to implement the changes necessary to protect
customers.
Why is such a rigorous review process necessarT when entering into long-
term transactions, and why does the Company generally limit trading and
hedging activities to the prompt 36 months?
The primary reason is long-term fixed price energy contracts carry significant
2o An independent evaluator is a third party who is appointed by PacifiCorp's regulators to oversee the RFP
process to ensure fairness throughout the process and to ensure the bids are accurately evaluated.
Clements, Di - 26
Rocky Mountain Power
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price risk. The market becomes more and more uncertain as you move further into
the future, and it is difficult to forecast with reasonable certainty what prices will
be far out into the future. Long-term fixed price transactions often move in or out
of the money over time as the forward price curve changes. For these reasons,
unless the Company has a demonstrated need for resources in its integrated
resource plan, it does not pursue long-term transactions.
Is there additional market and industry evidence that supports the
Company's 36 month trading and hedging horizon?
Yes. In the unregulated wholesale energy marketplace, very few transactions
occur beyond a six year time horizon and the highest volume is within one year.
When the Company has entered into long-term, non-QF transactions in the past
several years it is the result of a specific need for a resource identified in the IRP
and the contracts are typically backed by an identified firm resource (i.e. a utility
has load growth, generating unit retirements, or expiring contracts and needs a
resource, so it contracts to buy the output from a certain generator). Most of these
long-term transactions occur through a rigorous, transparent, and competitive
request for proposals processes.
Further evidence of the industry preference for shorter term fixed price
contracts is found in the practices of most of PacifiCorp's combined heat and
power (CHP) QFs. CHP QFs generally do not need long-term contracts for
financing purposes (most use balance sheet financing), so these types of QFs
evaluate a desired contract term from a risk management perspective. Like most
utilities, CHP QFs typically elect short term contracts with PacifiCorp even when
Clements, Di - 27
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20year terms are available. In fact, most elect annual contracts that are renewed
each year at the then-current avoided costs. These CHP QF customers have told
PacifiCorp that they are not energy traders and therefore prefer to take the spot or
near term avoided cost price in order to eliminate the price risk that comes from
long-term fixed price contracts.
Can you provide an example of the price risk associated with a long-term
fixed price contract?
Yes. The electricity and natural gas markets have fallen dramatically in the past
year as oil prices have also declined. On August 1,2014, a ten year fixed price
contract for a seven day by 24 hour electricity product at the Mid-Columbia
("Mid-C") wholesale power market trading hub was priced at $45.87 per MWh.
On February 2,20l5,just six months later, that same ten year contract was priced
at $38.11 per MWh. The 10 year electricity market declined 17 percent in just six
months. Hypothetically, had the Company purchased 100 MW of this ten year
fixed price electricity on August I , 2014 at $45.87 per MWh, just six months later
the Company would have a mark-to-market loss of $68.0 million on the contract.
By comparison to this 100 MW ten-year example, PacifiCorp currently
has 275.5 MW of proposed PURPA contracts in ldaho seeking 20 year fixed price
contracts. The price risk associated with this large number of proposed long-term
fixed price contracts is substantial and should not be borne by customers.
How do you respond to the argument that market prices are currently "low"
and therefore PacifiCorp should lock in as much energy as possible?
Locking in a price because you are speculating that the price is "low" is not
Clements, Di - 28
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hedging - it is speculative trading. PacifiCorp customers are not commodity
traders. PacifiCorp customers expect the Company to provide safe and reliable
energy while employing the "least cost least risk" principle. Taking a long-term
fixed price position in a commodity does not follow this principle.
Has this long-term price risk been evidenced in the Company's existing
PURPA contracts?
Yes. The Company currently has 141 PURPA contracts totaling 1,732 MW of
nameplate capacity across its six state system. As I mentioned above, Idaho's
allocated share of these contract costs averages approximately 6 percent. Over the
next ten years, the Company is under contract to purchase 38.9 million MWhs
under its PURPA contract obligations at an average price of $66.32 per MWh.
The average forward price curve for Mid-C over this same ten years is $38.11 per
MWh25, or a difference of $28.21 per MWh.
Under current policies and QF pricing methods, can the Company protect
customers from long-term price risk when entering into PURPA contracts?
No. Unlike a need based long-term transaction, a mandatory purchase under a
PURPA long-term fixed price contract must be executed regardless of need.
Consequently, these long-term contracts unnecessarily expose customers to price
risk that is not reflected in the contract price.
2s Based on a February 2,2015 forward price curve for a7x24 (flat) electricity product.
Clements, Di - 29
Rocky Mountain Power
1 LONG-TERM RESOURCE PLAI\INING: PACIFICORP,S IRP PROCESS AI\D
2 CURRENT RESOURCE NEEDS
3 Q. How does the Company determine its long-term resource needs?
4 A. The Company's long-term planning and resource decisions are thoroughly
5 evaluated through the Company's IRP process. PacifiCorp's IRP is developed
6 with participation from public stakeholders, including regulatory staff, advocacy
7 groups, and other interested parties. The planning process entails: (l) developing
8 an assessment of resource need via a load and resource balance, reflecting current
9 load growth forecasts and existing resources and contracts over a twenty year
l0 planning horizon; (2) producing a range of different resource ponfolios that could
I I be used to meet the projected resource need; and (3) evaluating the comparative
12 cost and risks of each resource portfolio, taking into consideration a wide range of
13 planning uncertainties, in order to identify the least cost and least risk preferred
14 portfolio. Once a preferred portfolio is selected, an action plan is developed that
15 identifies the specific resource actions the Company will take over the next two to
16 four years to implement its resource plan.
17 a. How does the IRP influence the types of long-term transactions entered into
18 by the Company?
19 A. The Company would not plan to enter into long-term transactions unless a long-
20 term resource need is identified in the IRP prefened portfolio. As noted above,
2l long-term resource needs are typically identified in the tRP only after lower-cost,
22 lower-risk short-term resource opportunities are exhausted such that a long-term
23 resource is required to meet customer load requirements. If the IRP identifies the
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need for a long-term resource in the near-term, an IRP action item would speciff
the Company's plans to acquire the resource, which might include issuance of a
request for proposal.
What long-term transactions have been included in recent and current IRP
action plans?
The 2013 IRP, which is the reference for current avoided costs in Idaho, included
a combined cycle combustion turbine ("CCCT") gas plant in 2024. Due to the
timing of the identified need for this resource, the 2013 IRP action plan did not
include any action items to procure this long-terTn resource. The 2013 IRP
Update, filed with the Commission in March 2014, pushed the CCCT out to 2027.
Again, due to the timing of this identified need, the Company has not developed
an action item to procure this long-terrn resource. The Company is in the process
of preparing its 2015 IRP, which will be filed with the Commission in March
2015. The 2015 IRP draft preferred portfolio pushes the CCCT out even further to
2028. As in the 2013 IRP and the 2013 IRP Update, the 2015 IRP draft action
plan does not include any action items to procure this long-tern resource.
What conclusion can you draw from the draft 2015 IRP preferred portfolio
and associated draft action plan?
The Company does not have a need for a new long-term resource until 2028, and
due to the timing of this need, the Company will not have any action items to
procure a new long-term resource in the next two to four years.
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Rocky Mountain Power
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How is the Company's proposal to limit QF contract terms to three years in
length aligned with the IRP planning process?
The full IRP is published every other year, with an update published in the off
years. As described earlier in my testimony, the IRP process includes a rigorous
review of the Company's resource needs by evaluating its load and resource
balance and establishing a least cost, least risk resource plan through
comprehensive and rigorous modeling of numerous resource alternatives. The
planning environment is constantly changing. This is evidenced by changes in the
Company's load and resource balance, state and federal environmental policies,
wholesale power and natural gas prices, market products, market rules and
contracting practices, and cost and performance of new generating technologies,
to name a few. While the Company's planning process is robust and designed to
reasonably capture a wide range of uncertainties, the magnitude of the various
planning uncertainties grows as you get further out into the IRP 2}-year planning
horizon. [t is for this very reason that IRP action items focus on the front two to
four years of the planning period and that the IRP planning process is repeated
every two years with updates in the off years. Even within these biannual
planning cycles, material changes in Company's resource needs have been
observed from one IRP to the next. The Company's proposal to limit QF contract
terms to three years in length is more aligned with the two year IRP planning
cycle, and the associated two to four year action plan period. Aligning a QF
contract term limit to the tRP planning cycle will ensure avoided cost pricing
remains consistent with the most up-to-date information regarding the Company's
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resource needs and limit long-term price risk.
Please summarize your testimony and the Company's requested relief.
The Company is seeking immediate relief on one item and permanent
implementation of two modifications to QF contracting and pricing procedures.
These changes are necessary in order to maintain the ratepayer indifference
standard required by PURPA and to protect Idaho customers. Specifically, the
Company is requesting an order from the Commission directing implementation
of the following:
L Immediate reduction, on a temporary basis, of the maximum contract term
for PURPA contracts between QFs and PacifiCorp from 20 years to five
years, pending litigation of this case.
2. Permanent reduction of the maximum contract term for PURPA contracts
from 20 years to three years, to be consistent with the Company's hedging
and trading policies and practices for non-PURPA energy contracts and
more aligned with the IRP cycle.
3. Modification of the Company's avoided cost methodology such that
preparation of indicative prices for QFs shall reflect all active QF projects
in the pricing queue ahead of any newly proposed QF requests for
indicative prices.
The immediate short-term relief is necessary to protect Rocky Mountain Power
customers from being adversely impacted by the Idaho Power Order. The
Company has received 130 MW of pricing requests from proposed QFs who now
intend to wheel power to PacifiCorp to obtain PURPA contracts with a 2}-year
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term. This action, if allowed to continue, will result in disparate treatment of
Rocky Mountain Power's customers, an unfair result that is inconsistent with the
Commission's historical treatment of utilities in similar circumstances.26
In addition to seeking immediate, temporary relief, the Company is
seeking longer-term relief as a result of a significant increase in PURPA contract
requests received in2014 and 2015, activity that Rocky Mountain Power believes
will harm customers unless the Commission directs permanent modifications to
the Company's current Idaho avoided cost contracting and pricing procedures. As
noted, PacifiCorp currently has pending requests for 275.5 MW of new PURPA
contracts in Idaho, in addition to the 189.6 MW of existing contracts. By
comparison, Rocky Mountain Power's minimum retail load in Idaho in 2014 was
169 MW. Across its six-state system, PacifiCorp currently has 3,641 MW of new
PURPA contract requests, in addition to the 1,732 MWs of PURPA power already
under contract. This striking increase in new QF activity exposes customers to
higher price risk due to the sheer volume of power that may become locked in at a
fixed price for decades under current Commission contract terms.
Given this exponential increase in QF contracting activity, it is critical to
quickly adjust pricing and contracting procedures now that problems with those
procedures have been identified. The current Commission-approved PURPA
contract length puts retail customers at risk of harm due to significant and
unnecessary exposure to long-term price risk, a level of risk the Commission
would not accept in the context of a non-PURPA transaction. The Company has
Clements, Di - 34
Rocky Mountain Power
26 See CaseNo. UPL-E-97-4, Order No .27213.
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no control over this price risk; it must purchase essentially an unlimited quantity
of QF power under terms and conditions the Commission controls. Under
PURPA, only the Commission can mitigate this price risk to customers.
The Company can mitigate the risk to customers of other long-term
transactions. When the Company considers non-PUMA transactions, the
Company first reviews the proposed purchase from a risk-management
perspective. The Company's practice since it completed the hedging collaborative
workshops in 2012 has been to limit hedges to 36 months or less unless
stakeholders express interest for longer term hedges. As explained above,
transactions that exceed 36 months require extensive analysis and progressively
higher level of management review. The primary reason that such a rigorous
review process is necessary when entering into long-term transactions, and the
reason the Company generally limits trading and hedging activities to the prompt
36 months, is that long-term fixed price energy contracts carry significant price
risk. The market becomes more and more uncertain as you move further into the
future, and it is difficult to forecast with reasonable certainty what prices will be
far out into the future. Moreover, the Company does not typically enter into long-
term transactions unless those transactions have been identified as least cost, least
risk transactions through the IRP process. Even then, the Company typically
utilizes a rigorous RFP process to acquire any long-tenn resource identified by the
IRP action plan. At this point in time, the Company does not have a need for a
new long-terrn resource until 2028, and due to the timing of this need, the
Clements, Di - 35
Rocky Mountain Power
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Company will not have any action items to procure a new long-term resource in
the next two to four years.
The situation facing the Company and its Idaho customers is one that they
have experienced in the past: significant industry changes, low gas prices, surplus
of energy and capacity, and the primary use of short-term purchases to meet load.
In proceedings in 1996 and 1997, the Commission appropriately responded to this
precise situation by reducing PURPA contract terms from 20 years to five years:
Significant changes have swept through the electric industry since
we last examined the issue of contract length. The FERC has
mandated open access to the transmission system, thermal
technologies have improved, gas prices are low, there is a
considerable surplus of energy available in this region resulting in
very low spot market prices for electricity and, finally, even the
continued existence of PURPA is being called into question. We
find that as the industry as a whole continues to transform to a
more free market model, we cannot justifu obligating utilities to
2}-year contracts for PURPA power. As the utilities in this case
note. such an oblisation does not reflect the manner in which they
are currently acquiring power to meet new load: through short-
term (five years or less) purchases. Consequently. it would be
nothing more than an artificial shelter to the OF industry to provide
those projects with contract terms not otherwise available in the
free market. We can find no justification for insisting that ldaho's
investor-owned utilities and their ratepayers assume such an
oblieation simply to foster one particular segment of an
increasingly competitive industry. We find, therefore, that Idaho's
investor-owned utilities shall not be required to offer contracts to
QFs in excess of five years until further action is taken by this
Commission. This ruling, however, does not prevent utilities from
offering for approval QF contracts with terms that exceed five
years should the utilities believe that such contracts are in the best
interests of their ratepayers.
See Case No. IPC-E-95-9, Order No. 26576; Case No. IPC-E-97-9, Order No. 271 I l;
Case No. WWP-E-97-8, Order No.27212; Case No. UPL-E-97-4, Order No.27213
(emphasis added). The Company requests that the Commission respond to the current
Clements, Di - 36
Rocky Mountain Power
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situation as it did in the 1996 and 1997 proceedings: by reducing the maximum
PURPA contract term; in this case, from 20 years to three years.
Moreover, the current, Commission-approved methodology allows QFs to
lock in long-term contracts with pricing that is above the Company's incremental cost
ofenergy and capacity because projects that are in the pricing queue ahead ofthe next
proposed project are not considered and included in the calculation of indicative
pricing. Brian Dickman describes how this impact can be as much as $18 per MWh
for a queue that includes approximately 3,000 MW of queued QF power, or 641 MW
less than the current queue. Given the magnitude of new QF requests, this one-way
error is becoming progressively more harmful to retail customers. Therefore, the
Company requests the Commission direct that preparation of indicative prices for
QFs reflect all active QF projects in the pricing queue ahead of any newly proposed
QF request for indicative prices.
The requested temporary relief and the permanent modifications to the
Company's current Idaho avoided cost contracting and pricing procedures are
required at this time to maintain the ratepayer indifference standard required by
PURPA and to protect Idaho customers from near-term and ongoing harm.
Does this conclude your direct testimony?
Yes.
Clements, Di - 37
Rocky Mountain Power
Case No. PAC-E-I5-03
Exhibit No. I
Witness: Paul H. Clements
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Paul H. Clements
February 2015
Rocky Mountain Power
Exhibit No. 1 Page 1 of 3
Case No. PAC-E-15-03
Witness: Paul H. Clements
Location Type Size (MW)Proposed Online Date
ldaho Gas 4.5 08101/20 5
Idaho Solar 40.0 08t0U20 6
Idaho Solar 20.0 0810120 6
Idaho Solar 20.0 08t0U20 6
ldaho Solar 50.0 08101/20 6
Idaho Solar 20.0 0t31t20 6
Idaho Solar 20.0 013,/20 6
daho Solar 21.0 2t31/20 6
daho Solar 20.0 213U20 6
daho Solar 20.0 2t3120 6
daho Solar 20.0 2t3U20 6
daho Solar 20.0 2/3v20 6
Oregon Geothermal 3.5 0510y20 4
Oregon Solar r0.0 213U20 5
Oregon Solar 0.8 213U20 5
Oregon Solar 10.0 2/31/20 6
Oregon Solar 10.0 2/3U20 6
Oregon Solar 7.s 2/3U20 6
Oregon Solar 0.0 2/31/20 6
Oregon Solar 0.0 2t31/20 6
Oregon Solar 0.0 2l3t/20 6
Oregon Solar 0.0 2t3r/20 6
Oregon Solar 0.0 2131/20 6
Oregon Solar 8.0 213U20 6
Oregon Solar 9.9 2t3U20 6
Oregon Solar 9.9 2t3U20 6
Oregon Solar 9.9 2t3t/20 6
Oregon Solar 10.0 213U20 6
Oregon Solar 10.0 2t3U20 6
Oregon Solar 9.9 213t/20 6
Oregon Solar 7.5 2t3U20 6
Oregon Solar 10.0 213,720 6
Oregon Solar 10.0 2t3U20 6
Rocky Mountain Power
Exhibit No. 1 Page 2 of 3
Case No. PAC-E-15-03
VMtness: Paul H. Clements
Location Type Size (MW)Proposed Online Date
Oregon Solar 9.9 12t3U20 6
Oregon Solar 9.9 t2t3U20 6
Oregon Solar 45.0 1213U20 6
Oregon Solar 20.0 t2t3U20 6
Oregon Solar 44.2 0U0y20 7
Utah Solar 50.0 08t3u20 5
Utah Wind 80.0 t0l0U20 5
Utah Wind 45.0 tt/01/20 5
Utah Solar 50.4 12/01/20 5
Utah Solar 65.6 t2lt5l20 5
Utah Solar 50.4 12n5/20 5
Utah Solar 10.0 t2t3y20 5
Utah Solar 80.0 t2l3l20 5
Utah Solar 80.0 t2l3U20 5
Utah Solar 80.0 t2t3U20 5
Utah Solar 5.0 t2t3U20 5
Utah Solar 21.0 0U0U20 6
Utah Solar 80.0 0U0v20 6
Utah Solar 1.0 04103120 6
Utah Solar 80.0 06t0 t20 6
Utah Solar 80.0 06/0 t20 6
Utah Solar 80.0 0610 t20 6
Utah Solar 80.0 0610 120 6
Utah Solar 80.0 0610 120 6
Utah Solar 80.0 06/0 120 6
Utah Solar 80.0 0/0 t20 6
Utah Solar 20.0 0/0 /20 6
Utah Solar 80.0 U0 12016
Utah Solar 80.0 U0 t2016
Utah Solar 80.0 U0 12016
Utah Solar 80.0 U0 12016
Utah Solar 1.0 213 12016
Utah Solar 20.0 2t3 t2016
Utah Solar 40.0 213 t20r6
Utah Solar 50.0 2t3 t2016
Utah Solar 15.0 213 /2016
Utah Solar 14.5 2/3 12016
Rocky Mountain Power
Exhibit No. 1 Page 3 of 3
Case No. PAC-E-15-03
\Mtness: Paul H. Clements
Location Type Size (MW)Proposed Online Date
Utah Solar 7.5 12t31/20 6
Utah Solar 50.0 t213v20 6
Utah Solar 80.0 12/31/20 6
Utah Solar 80.0 r2l3t/20 6
Utah Solar 6.0 t2/3y20 6
Utah Wind 69.0 t2/31120 6
Utah Solar 78.2 t2t3y20 6
Utah Solar 80.0 0U0U20 8
Utah Solar 80.0 0l/0 t20 8
Utah Wind 80.0 0r/0 t20 8
Utah Wind 80.0 0l/0 /20 8
Wyoming Wind 80.0 07t3 120 5
Wyoming Wind 80.0 t2l0 t20 5
Wyoming Wind 80.0 01/0 120 6
Wyoming Wind 60.0 0l/0 120 6
Wyoming Wind 80.0 t2t3 /20 7
Wyoming Wind 80.0 t2/3 t20 7
Wyoming Wind 80.0 t2l3U20 7
Wyoming Wind 80.0 t2l3U20 7