20150611Allphin Rebuttal.pdf

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An IDACORP Companv
DONOVAN E. WALKER
Lead Gounsel
dwal ker@i dahopower.com
June 11,2015
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VIA HAND DELIVERY
Jean D. Jewell, Secretary
ldaho Public Utilities Commission
472 West Washington Street
Boise, Idaho 83702
Re: Gase Nos. IPC-E-15-01 , AVU-E-15-01 , and PAC-E-15-03
Modify Terms and Conditions of PURPA Purchase Agreements - ldaho
Power Co m pany's Rebuttal Testi mony of Randy Al I ph i n
Dear Ms. Jewell:
Enclosed for filing in the above matterc please find an original and nine (9)
copies of the Rebuttal Testimony of Randy Allphin. One copy of Mr. Allphin's testimony
has been designated as the "Reporter's Copy." !n addition, a disk containing a Wod
version of Mr. Allphin's testimony is enclosed for the Reporter.
DEW:csb
Enclosures
1221 W. ldaho 5t. (83702)
PO. Box 70
Boise, lD 83707
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^rli li ,, t I r:.,1 t.. t o:J,'..JU,i ir I ii H. lU
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY
TERMS AND CONDITIONS OE PURPA
PURCHASE AGREEMENTS
IN THE MATTER OF AVISTA
CORPORATION'S PETITION TO
MODIFY TERMS AND CONDITIONS OE
PURPA PURCHASE AGREEMENTS
IN THE MATTER OF ROCKY MOUNTAIN
POh]ER COMPANY'S PETITION TO
MODIEY TERMS AND CONDITIONS OF
PURPA PURCHASE AGREEMENTS
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
CASE NO. PAC-E-15_03
IDAHO POWER COMPANY
REBUTTAL TESTIMONY
OF
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O. Please state your name and business address.
A. My name is Randy A1lphin. My business address
is 1227 West fdaho Street, Boise, Idaho 83702
a. By whom are you employed and in what capacity?
A. I am employed by ldaho Power Company ("Idaho
Power" or "Company") as the Energy Contracts Coordinator
Leader.
O. Are you the same Randy Allphin that prevj-ousIy
provided direct testimony for Idaho Power in this matter?
A.
o.
testimony?
Yes.
What is the purpose of your rebuttal
A.My rebuttal testimony wiJ-I provide Idaho
Power's response and rebuttal- to the test j-mony of fered by
the other parties in this proceeding.
O. Have you had the opportunity to review the
pre-fiIed direct and rebuttal testj-mony of the other
parties to this proceeding, incl-uding the Idaho
Conservatj-on League and the Sierra Club's witnesses R.
Thomas Beach and Adam Wenner; the Idaho Publ-ic Utilities
Commission ("Commissi-on") Staff's ("Staff") witnesses Rick
Sterling and Yao Yin; J. R. Simplot Company ("Simp1ot") and
Cl-earwater Paper Corporation's ("Clearwater") witness Mr.
Don Reading; Intermountain Energy Partners, LLC's wj-tness
Mark Van Gulik; Renewabl-e Energy Coalition's witness John
ALLPHIN, REB 1
Idaho Power Company
1 R. Lowe; Snake Ri-ver Alliance's witness Ken Mil-Ier; and the
2 Idaho Irrigation Pumpers Association, Inc.'s (*IIPA")
3 witness Anthony ,J. Yankel?
4 A. Yes, I have. I have also reviewed the
5 testimony offered by the other utilities, Avj-sta
6 Corporati-on and Rocky Mountain Power, d/b/a PacifiCorp.
1 Q. Please summarize what your rebuttal- testimony
8 wil-1 address.
9 A. Commission Staff supported the Company's
10 request to reduce the maximum contract term, but suggests a
11 maximum term of fj-ve yearsr EIS opposed to Idaho Power's
L2 requested maximum term of two years. IIPA also supported
13 Idaho Power's request to reduce the maximum contract term
74 to two years. In general, the remaining parties opposed
15 Idaho Power's request. Several Intervenors questj-on the
16 Commission's authority to reduce the maximum contract term,
L7 present argument that a shorter term will prevent
18 Qualifying Facility (*QE") financing for new projects, and
79 argue that granting a shorter term for QF contracts would
20 result in unequal treatment between QFs and utility-owned
27 resources, along with several other arguments. Various
22 Intervenors proposed, as an alternatj-ve, a 20-year contract
23 term with a fixed-prj-ce portj-on of the 2l-year term and the
24 remaining term having some type of price adjustment. I
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will address many of these issues in this rebuttal
testimony.
O. Do the parties that oppose reduction in the
contract term address the issues raised by Idaho Power
related to no current need for additional generation
resources?
A.No. None of the parties opposi-ng the
requested reduction in maximum authorized contract term
have addressed the larger issues related to need for
additional generation resources and the disproportionate
amount of risk that long-term, fixed-rate, unchangeable QF
contracts place upon Idaho Power's customers without the
benefit of the Commission's or the public's scrutiny of its
acquisition, like Company-owned resources must endure.
O. Staff references in its rebuttal- testimony the
fact that various witnesses have suggested there is unequal
treatment between QFs and utility-owned resources, and Mr.
Reading, on page 9 of his direct testimony, states,
"Treating PURPA resources on an equal footing with utility-
owned resources woul-d mandate they al-so should receive
longer-term contracts." What is Idaho Power's position and
response on this issue?
A.Idaho Power generally agrees with the
statements and position of Staff, which acknowledges that
QEs and utility-owned resources are aot treated the same.
ALLPHIN, REB 3
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The other parties make the erroneous assumption that QFs
are to be treated exactly the same as utility-owned
resources. However, Staff points out that QFs are treated
differently primarily because of the unlque requirements of
the Public Utility Regulatory Policies Act of 7978
(*PURPA") and that this different treatment is very much to
the benefit, rather than to the detriment, of the QF.
Idaho Power submits that if a QF were subjected to the same
regulatory standards and its acquisition and cost was
scrutinized 1n the same manner as a utility-owned resource,
then it could expect simil-ar treatment. However, that is
not the present reality. A utility-owned resource is only
considered in the first instance if there is a aeed for the
acquisition of additional generatj-on resources to reliably
serve customers. Presently, a QF project would fail this
initial standard and thus would not be purchased.
Additionally, beyond an initial identification of need,
utility-owned resources are subjected to further
evaluations of selecting the appropriate type of resource.
The operational characteristics, re1iabi11ty, costs, and
other reLevant aspects of whether any particular resource
is the most appropriate resource must be determined before
seeking Commission approval to construct such resource.
Even further, once constructed, the utility-owned resource
is subjected to further Commission and public scrutiny in a
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proceeding to pl-ace it into the utility's rate base, and on
an on-going, annual basj-s with regard to the fuel and
variable cost, which are subject to annual- adjustment
through the Power Cost Adjustment. Consequently, the
argument that the QF is somehow entitled to the same type
of capital cost recovery as a utility-owned resource simply
does not logically make sense.
o.Are there other examples of the parties'
inappropriate comparison of QF resources to utility-owned
resources?
A.Yes. Mr. Reading, on pages 24 through 26 of
PURPAhis direct testimony, attempts to argue that because
projects get paid only when they supply power to the
utility, they are somehow a better value and "risk hedge"
than a util-ity-owned resource. This may seem to make sense
on the surface, but Mr. Reading leaves out an important
aspect of the operational differences between a PURPA
project and a utility-owned resource, which makes a1I the
difference. Utility-owned resources are economically
dispatched, or only run when they are less costly that
other alternatives or when they can be sold at a profit.
However, a PURPA generator w1II run as much, and as often,
as it can to maximize its profits-without regard to whether
it is needed and without regard to the avail-ability of
other lower-cost resources. Utility-owned resources are
ALLPHIN, REB 5
Idaho Power Company
1 only constructed and operated to serve the public interest,
2 a factor that is closely monitored, regulated, and
3 controlled by the Commissj-on. QF resources are constructed
4 and operated so1eIy to make a profit for its
5 owners/investors, with no constraint or obligation to serve
6 in the public interest. Because of PURPA's must-purchase
7 obligation-and because the QF is motivated to maxi-mize its
8 profits and not concerned with meeting need on a least-
9 cost, reliable basis-the utility must accept the QF
10 generation if , when, and j-n whatever amounts the QE decj-des
11 to put to the utility. This can result in the utility
L2 foregoJ-ng the operation of its l-ower-cost resources,
13 acquj-red after careful- Commission scrutiny to serve the
L4 publi-c, j-n order to take the power that is put to it by the
15 QF. This situation can only grow in magnitude as more
16 must-take PURPA is forced onto the system at a time when
t7 the utility's Integrated Resource Plan (*IRP") shows no
18 need for additional generation resources to meet need/load.
19 0. Mr. Reading attempts to make a cost comparison
20 of PURPA resources and Idaho Power's thermal generatj-on
2L resources on pages 74 and 15 of his direct testimony. Has
22 Idaho Power reviewed Chart 1 on page 15 of Mr. Readi-ng's
23 direct testimony?
24 A. Yes.
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ALLPHIN, REB 6
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O. Was Idaho Power able to replicate al-1 of the
values presented by Mr. Reading in that chart?
A.No, not al-l of them. Idaho Power was able to
replicate all of the values except the value presented for
the Bennett Mountain generation unj-t. Mr. Reading's Chart
1 presents a cost per megawatt-hour ("MV{h") for the Bennett
Mountain generation unit of $253.87. He cites the sources
of the numbers as being from the Company's 20L3 Federal-
Energy Regulatory Commission ("FERC") Eorm 1 as wel-I as
some Company responses to Simplot's production requests.
Using those same resources, Idaho Power was able to
validate all of the other numbers in Chart L, but for the
Bennett Mountain generation unit. Using the same
assumptions as Mr. Readi-ng, Idaho Power calculated a cost
per MWh of $L7L.28
a. What is Mr. Reading attempting to demonstrate
with the numbers shown in Chart 1 of his testj-mony?
A. Mr. Reading is responding to Exhibit No. 10 of
my direct testimony, which is a graphical depiction of the
average actual cost per MWh of PURPA energy purchases and
Mid-C market prices through year-end 2074 and the same two
values forecasted through 2030. f provided Exhibit No. 10
as support for the statement that if the Company is
required to purchase PURPA generation when it is not
needed, the Company may be required to curtail other less
ALLPHIN, REB 1
Idaho Power Company
1 expensive sources of generation or market purchases in
2 order to continue purchasing PURPA generation at a higher
3 cost. A11phin, DI p. 14. Exhibit No. 10 shows that the
4 average PURPA price is greater than the Mid-C Index in all
5 years, both historj-ca11y and forecasted.
6 Q. Does Mr. Reading agree with the Company's
7 conclusion?
8 A. No. Mr. Reading claims that the Company is
9 only "te11ing half of the story." Mr. Reading does not
10 dispute the j-nformation provided in Exhibit No. 10, which
11 shows that historical Mid-C prices have been lower than
72 PURPA prices since 2002 to the present and are projected by
13 Idaho Power to be lower over the next 20 years. However,
14 Mr. Reading cl-aims that is just the first hal-f of the
15 story. He claims this comparison fails to recognj-ze that
76 capital costs are included in the per MWh prJ-ce of PURPA,
l7 and suggests that Mid-C prices are market prj-ces and are
18 more reasonably related to the variable running costs of
t9 existing generati-ng resources that do not contain capital
20 costs.
2L O. [ilhat does Mr. Reading believe is the
22 appropriate comparison to PURPA prices?
23 A. Mr. Reading bel-ieves a more approprj-ate
24 analysis woul-d be comparlng PURPA rates to what he cl-aims
25 customers pay for in the Company's own generation
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facilities, by including rate-based capi-tal costs along
with fj-xed and variable operating costs.
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Is this an approprj-ate comparison?
No, not at aIl-. Mr. Reading is attempting to
mislead the Commission by using an inappropriate comparison
of the cost for the must-take.PURPA energy on a cost per
MWh basis compared to all- of the Company's thermal
generating resources, regardless if they provide baseload
generation or are a peaking resource, which are only used
when needed to meet system load and/or are economi-ca11y
viable to run. Mr. Reading provides his Chart 1 (including
the erroneous Bennett Mountaj-n calculation) to try and
demonstrate his assertion that if you include the capital
costs of the Company's thermal resources, it wou1d show
PURPA is lower cost than many of the Company's generating
resources. However, the Company's peaking resources were
planned to operate only on an as-needed basis, dt times
when it is necessary to meet the Company's system peak
and/or they are economically viabl-e to run. Consequently,
when you include the capital costs of a peaking resource
with the variabl-e costs of running the plant, divided by
the net generatj-on for the pIant, the average cost per MWh
for the peaking resource wiII be greater than other
resources with greater MWh of output.
ALLPHIN, REB 9
Idaho Power Company
1 The peaking resources were specifically built to meet
2 capacity, rather than energy needs.
3 O. Does Mr. Reading discuss the various processes
4 undertaken by the Company in determining the need for an
5 additional- generation resource or the type of resource
6 needed?
7 A. No. Mr. Reading completely ignores the fact
8 that, unlike PURPA resources, the Company's generation
9 resources, like the peaking plants I just described, were
10 determined to be needed prior to being buil-t and endured
11 significant public scrutiny through the required IRP
12 planning process, as well- as achieving regulatory approval
13 through a Certificate of Public Convenience and Necessity
74 (CPCN) hearing that determined the need for that resource
15 at the time it was built. Further, before being placed
16 into rates, Idaho Power has to prove before the Commissj-on
l7 that the expenditures in these plants were prudently
18 incurred. As I referenced earl-j-er in my testimony, PURPA
19 projects are not subject to this same scrutiny and
20 determination of need.
2L O. Does Mr. Reading's comparj-son appropriately
22 reflect the potential customer impact of Idaho Power's
23 forced purchase of unneeded PURPA generation?
24 A. No. My testimony and this filing address the
25 future impact to customers' rates, and the undue j-nflation
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of those rates if the Company is forced to purchase energy
it does not need at prices higher than those of alternative
resources. The capj-taI costs for existing resources that
Mr. Reading includes in his analysis are j-nappropriate
given current operating conditions, and distort potential-
customer impacts in a manner that inaccurately depicts
PURPA as a relatively Iow-cost option.
Please explain.
The capital costs associated with Idaho
Power's existing generation facil-ities are already embedded
in rates and, as described above, were only authorized for
recovery after thorough regulatory review and scrutiny by
the Commission, the public, and intervening parties. These
facilities were ultimately determined to be in the public
interest, and currently operate to reliably meet Idaho
Power's load requirements 24 hours a day, 7 days a week,
365 days a year.
On a going forward basisr dS identified in Idaho
Power's recent draft of its 201-5 fRP just rel-eased on the
Company's website, the IRP anal-ysis has identified for the
preferred portfolio no need for additional- generation
resources in the near term. The first year a capacity
deficiency exists is in 2025, whil-e the first energy
defj-cient perj-od is in 2026. Therefore, the true impact to
customers' bills over that time period will reflect how
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Idaho Power utilj-zes exj-sting generation resources
(Company-owned, existing PURPA, market purchases) to meet
customer need, as weII as any additional PURPA generation
it is requi-red to purchase. An accurate cost comparison
should reflect current operating conditj-ons and the reality
of these circumstancesr dn area in which Mr. Reading's
analysis fails.
By including capi-taI costs associated with pJ-ants
that are already meeting customer need, Mr. Reading's
analysis distorts the potential impact to customers by
inappropriately combining embedded capital costs associated
with existing facilities and incremental costs associated
with new unneeded PURPA resources. In doing sor the
resultant prices do not indicate the lowest-cost future
course of action, because they include construction costs
associated with resources that have already been
constructed, and compare them to incremental costs that
have yet to be incurred. When evaluating future customer
impacts, embedded costs should not be compared to
incremental costsr Ers they do not reflect cost increases
customers will face if Idaho Power is forced to purchase
unneeded PURPA generatj-on.
O. Why should the figures in your Exhibit No. 10
table be relied upon by the Commission rather than Mr.
Reading's analysj-s?
ALLPHIN, REB 12
Idaho Power Company
1 A. Unlike Mr. Reading's figures, the cost
2 comparison provided in Exhibit No. 10 reflects a realistic
3 expectation of the future impact to customers. Given the
4 lack of need for new capital resources in the next l-0
5 years, the cost to serve customers over that time perj-od
6 will reflect how Idaho Power operates existing Company-
7 owned resources in conjunction with must-take PURPA and
8 market purchases. For comparison purposes, Idaho Power
9 provides historical- and forecast prj-ces for the Mid-C
10 market, which is frequently utilized by Idaho Power for
11 off-system market purchases. On a going forward basis,
12 these figures provide a real-istic estimation of the costs
13 Idaho Power woul-d incur to serve customers absent
L4 additional 2}-year, fixed-price PURPA contracts, and can be
15 relied upon by the Commission as an expectation and
16 approxj-mation of the future impact to customers.
1,7 O. Several of the opposing partj-es argue that QE
18 projects will not be able to obtain financing with a
L9 reductj-on of the maximum contract term to two years. Does
20 Idaho Power agree?
2t A. I do not think the term reduction will
22 absol-ute1y prevent any kind of financing for QF projects.
23 Certainly, the same type of financi-ng, and the terms of the
24 flnancing, will- 1ike1y be different than today where QF
25 projects are able to finance a risk-free guarantee of a 20-
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year stream of prices and income. However, the argument of
the parties that PURPA and FERC require the Commissj-on to
provide QF projects with a contract that enabl-es risk-free
financing for their projects is j-ncorrect. Everyone knows
that one purpose and intent of PURPA is to promote the
development of additional cogeneration and small- power
production. However, PURPA also requires that the
utj-lity's retail customers, who pay for PURPA purchases, be
held neutral as to whether that generation was acquired
from PURPA or otherwise provided by the utility. The
promotion of the development of additional cogeneration and
sma11 power production QFs required by PURPA is
accomplished by use of the mandatory purchase obligation.
Promotion is not to be provided with the rates, terms, and
financing available for QF projects. PURPA directs that
the purchase price is not to exceed the utility's avoided
cost, and must be just and reasonable to the utility's
customers. This determination was given to the state
Commission to establish. The Commission recognj-zed this
concept in its order from Phase II of the previous generic
avoided cost and PURPA contracting case, Case No. GNR-E-11-
01. The Commission found:
Avoided cost rates are to be just
and reasonable to the utility's
ratepayers. PURPA entitles QFs to arate equivalent to the utility's
avoided cost, a rate that hol-ds
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utility customers harmless not a
rate at which a project may beviable. If we allow the current
trend to continue, customers may beforced to pay for resources at aninflated rate and, potentially,
before the energy is actually needed
by the utility to serve itscustomers. This is clearly not in
the public interest.
Order No. 32262, p. 8 (internal cj-tations omitted) . Idaho
Power's position is that the must-take obligation of PURPA
does not require a proposed QF project be provided with
risk-free financj-ng by the Company and its customers.
The must-take, or mandatory purchase, obligation of
PURPA is the way PURPA was designed to promote the
development of additional- cogeneration and sma11 power
production facilities. This mandatory purchase obligation
does not go away with the expiration of a contract term,
and, once the contract term expi-res, the QF project can
then enter into a new contract with the utj-lity; the
utility is still obligated to purchase. However, in order
to protect customers from paying infl-ated, outdated costs
that exceed avolded cost t ox from shouldering the entire
risk of such which is associated with a long-term, fixed-
prj-ce contract, the best viable alternative is to set a
shorter maxj-mum contract term. It is in this way that the
Commission can assure an updated avoided cost rate is
implemented for individual projects. The Company has
ALLPHIN, REB 15
Idaho Power Company
1 proposed a two-year contract term, the same time frame used
2 by the Company in its determination of the need for
3 additional resources carri-ed out through the IRP process.
4 Q. Some of the parties have proposed to retain
5 long term, 2O-year contracts but to have a portion of the
6 term with fixed prices and the remaj-ning term with an
7 adjustable rate portion of the long-term contracts. What
8 is Idaho Power's position with regard to these proposals?
9 A. Such arrangements have been implemented to
10 some extent in the past, where different mechanisms were
11 j-mplemented that provided some portion of adjustable rates
12 in a PURPA contract. The Company believes this to be
13 slightly better than the current implementatj-on where the
14 entire 2l-year contract term is at fixed rates, with Idaho
15 Power's customers shouldering the entire risk. However,
L6 this solution has at least two major problems associated
1,7 with it. First of all, from the past arguments put forth
18 by many QF parties, the ability to adjust prices in a PURPA
79 contract, once that contract is executed, approved, and put
20 into pIace, is questionable. The Commissj-on and the
21, Company have both faced substantial opposition to the
22 legality of any kind of "contract reopener" that would
23 adjust the avoided cost rate during the term of a contract.
24 Whether a contract that contained adjustabl-e avoided cost
25 rates would be considered valj-d is questionable, ds EERC
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has opj-ned that once the rates are established in the
contract, they cannot be changed, even in the face of
direct evidence that they are grossly out of sync with the
utility's avoided costs in the future. As referenced
above, a short-term contract would not abrogate the
utility's must-purchase obligation. Once the current
contract term expired, the utility would be required to
enter into a new contract-but at the current calculation of
its avoided costs. In this wdy, the Commj-ssion could
mitigate the long-term risk shouldered by customers, and
assure that the rates are refreshed to current rates at
Ieast every two years, which is consistent with both the
Company's IRP process as well as its Commission-approved
Risk Management Policy for power purchases.
Secondly, retention of a long-term contract, even
with an adjustable portion of the rate, if such were
determined to be Iegal, would sti11 expose the Company's
customers to unreasonable risk. Moreover, given the
mandatory purchase requirement of PURPA, j-s rea11y
unnecessary. Additionally, if there was a legislative
change in PURPA affecting the mandatory purchase
obligation, or if a viabl-e RTO, ISO, or other PURPA exempt
market developed in Idaho Power's service territory,
customers would be locked into long-term contracts, and
potentially not able to benefit from these changes for the
ALLPHIN, REB L7
Idaho Power Company
1 next 20 years. Retention of a long-term obligation on
2 customers would continue to allocate a disproportionate and
3 harmful amount of risk to Idaho Power customers.
4 Q. The testimony of Mr. Wenner on behalf of the
5 Sierra Club and the Idaho Conservation League states his
6 legal opinion that a two-year contract term'tdoes not
7 satisfy the FERC's regulations and is inconsistent with
8 PURPA." Wenner, DI p. 2. Have you reviewed Mr. Wenner's
9 testimony?
10 A. Yes, I have.
11 O. Does Idaho Power have any response to Mr.
72 Wenner's testj-mony?
13 A. Yes. Mr. Wenner's testj-mony is somewhat odd
14 in that Mr. Wenner, as an attorD€y, appears to provj-de his
15 own Iega1 opinion, argument, and analysis regarding an
16 argument that FERC somehow has prescrj-bed or j-ntended long-
L7 term contracts to be j-n excess of 10 years and that two
18 year contracts would be iI1ega1. Although Idaho Power
79 intends to ask the Commission to stri-ke Mr. Wenner's
20 testimony as improper, it is important to note that even
2l Mr. [rf,ennerr oD page 5 of his direct testi-mony, acknowledges
22 that there is no EERC regulation specifying the number of
23 years or required term for a contractual or 1egaI1y
24 enforceable obligation by which QFs are entitled to receive
25 avoided cost rates.
ALLPHIN, REB 18
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Mr. Reading al-so argues that FERC's regulations
require long-term contracts. These arguments attempt to
create something that simply is not there. As acknowledged
by Mr. Wenner, and stated by Mr. Sterling on behalf of
Staff beginning on page 10 of his dlrect testlmony, EERC's
regulations implementing PURPA are silent on contract
length. The parties' attempts to create a required long-
term contract length where none exj-sts is unpersuasive.
The Commission has from tj-me-to-time adjusted the maximum
contract term available to QEs in the state of fdaho. The
Commj-ssion approves and/or directs the use of many
different contractual terms and conditions contained in the
Energy Sales Agreement contracts that are individually
approved or rejected on a case-by-case basis in PURPA
purchases. In doing so, the Commission balances the
protection of utility customers and the promotion of smaIl
power production and cogeneration facilities. However, as
discussed above, the Commlssion has recognized that the
promotion of QF projects through PURPA is accomplished by
the mandatory purchase obligation, not a promotional rate
and/or promotional terms and financing arrangements. Sma11
generators, partj-cularIy renewabl-e generators, have other
avenues outside of PURPA designed to promote development.
O. Some partj-es, such as Mr. Reading and Mr.
Yankel on behal-f of Simplot/Clearwater and the IIPA,
ALLPHIN, REB 19
fdaho Power Company
1 respecti-veIy, have offered criticism of your Exhibit No. 6.
2 Does Idaho Power have a response?
3 A. Yes. Mr. Reading, in particular, argues that
4 the information can be configured or re-displayed in
5 different ways to make it look different, or appear that it
6 is the Company's resources contributing more to over-
7 generation events than PURPA projects. However, no matter
8 how the information is di-sp1ayed, Idaho Power does not
9 dispute the fact that over-generation occurs, even with its
10 own must-run resources, just as with the must-take PURPA
11 generation. That was not the point. One point and purpose
t2 for the information in this exhibit is to provj-de evj-dence
13 of instances in which the Company must manage through over-
t4 generation events on its system. Typically, the Company's
15 resource planning, the IRP process, looks at peak hour
16 capacj-ty and energy deficits to make sure the Company
17 adequately plans to meet its obligation to reliably serve
18 all l-oad on its system. This exhibit provides valuable
19 information about system operations and resource
20 sufficiency for other times of the day and year, somewhat
2t on the other end of the spectrum from the typical IRP
22 analysis.
23 Exhibit No. 6 shows the frequency with which Idaho
24 Power's system, when in a state where it cannot be backed
25 down any further (onIy must-run and must-take generation is
ALLPHIN, REB 20
Idaho Power Company
1 running) , wil-l- have generatj-on resources in excess of its
2 system Ioad. As discussed in my direct testimony starting
3 on page 8, this puts the system into an imbalanced, over-
4 generation state that requires remedial action to balance
5 the system. The addition of more must-take PURPA
6 generation will exacerbate the problem and increase the
7 number of over-generation events that Idaho Power must
8 manage, as can be seen on the summary page of Exhj-bit No. 6
9 (ranging from a 29 to 40 percent increase). Additionally,
10 Idaho Power will have no ability to dispatch these must-
11 take PURPA QF resources; thus, the management of this
72 increased number of over-generation events will- have to be
13 absorbed and managed by existing Idaho Power generation
14 resources. This can result in more costly and less
15 efficj-ent operations of the Company's resources, and
1,6 increased costs passed on to Idaho Power customers.
L7 O. Commj-ssion Staff supported the Company's
18 request to reduce the maxj-mum contract term, but suggests a
19 maximum term of five yearsr ErS opposed to ldaho Power's
20 requested maximum term of two years. What is fdaho Power's
21 response?
22 A. Idaho Power appreciates and agrees wj-th
23 Staff's analysis and recommendations. The Company is very
24 cognizant of the fact that the Commission has utilized a
25 maximum PURPA contract term of five years in the past, but
ALLPHIN, REB 27
Idaho Power Company
l-
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the Company maintains j-ts request for a two-year maximum
term. A two-year term is consistent. with the Commission's
existing determinatj-on of reasonable risk exposure to
customers in both the IRP process and the Company's Rlsk
Management Policy. As stated in the Company's Petition and
direct testimony, the IRP is updated with a new planning
document that is filed with the Commission every two years.
In like manner, under the Commission-approved Risk
Management Po1icy, which governs the Company's purchase and
sales of generatj-on, typical transactions do not exceed 18
months, and any transactions longer than two years require
specific Commission approval-. The Commission has
determined that two years is the reasonabl-e and prudent
period of tj-me in which to update forecasts and to not
expose customers to undue market and transactional risk
associated with the purchase of generation. This should
al-so be applied to the undue risk and burden placed upon
customers with the must-take PURPA obligation.
o.Do you have any summary or concluding
statements for the Company's rebuttal- testimony?
A.Yes. As stated in the Company' s Petj-tion and
direct testimony, Idaho Power continues to believe the
continued creation of 2)-year, fixed-prlce contracts places
undue ri-sk on customers at a time when fdaho Power has
sufficient resources to meet customer demands. The
ALLPHIN, REB 22
Idaho Power Company
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L4
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L7
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L9
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Company's required IRP process is filed and updated every
two years. Non-PURPA purchase and sales transactions are
limi-ted to less than two years pursuant to the approved
Risk Management Policy. Avoided cost rates are updated at
Ieast every year. Idaho Power has no current identifiable
need to acquire any addi-tional generatj-on resources through
202L, and 1ike1y out to at least 2025r ds noted in the
upcoming 20!5 IRP. The requirements for acquiring
additional generation resources, particularly that of
establishing need for the resource and meeting that need in
the least cost, most reliable manner, are absent in the
mandatory PURPA QF purchase. The further constraint
imposed by PURPA that eliminates the ability to modify,
adjustr or change the prices that are locked into a PURPA
contract for the duration of its term-regardless of whether
all costs were i-ncluded or whether actual costs and
conditions changed or varj-ed-makes long-term, 20-year
contract terms risky and harmful to Idaho Power customers.
The Commissj-on should reduce the maximum term to two years
to match the determination of prudent updates and rj-sk
exposure that have been established for the IRP and non-
PURPA purchases.
o.
A.
Does this concl-ude your testimony?
Yes.
ALLPHIN, REB 23
Idaho Power Company
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STATE OE IDAHO
County of Ada
SUBSCRIBED AND
June 2015.
ATTESTATION OE TESIIIONY
SV{ORN to before me this 11th day of
Notary Publid for Idaho
Residing at:
)
)
)
ss.
I, Randy A11phin, having been duly sworn to testify
truthfully, and based upon my personal knowledge, state the
following:
I am employed by Idaho Power Company as the Energy
Contracts Coordinator Leader in the Load Serving Operations
Group and am competent to be a witness in this proceeding.
I declare under penalty of perjury of the laws of
the state of Idaho that the foregoing pre-fi1ed testimony
is true and correct to the best of my information and
belief.
DATED this 11th day of June 2015.
ALLPHIN, REB 24
Idaho Power Company
tI
My commissiori
CERTIFICATE OF SERVICE
I HEREBY CERTTFY that on the 11h day of June 2015 I served a true and
correct copy of the REBUTTAL TESTIMONY OF RANDY ALLPHIN upon the following
named parties by the method indicated below, and addressed to the following:
P.O. Box 83720
Boise, ldaho 83720-007 4
J. R. Simplot Gompany and Clearwater Paper _Hand Delivered
Corporation
Peter J. Richardson
Gregory M. Adams
RICHARDSON ADAMS, PLLC
515 North 27h Street (83702)
P.O. Box 7218
Boise, ldaho 83707
Dr. Don Reading
6070 Hill Road
Boise, ldaho 83703
Commission Staff
Donald L. Howell, ll
Daphne Huang
Deputy Attomeys General
ldaho Public Utilities Commission
472 West Washington (83702)
Clearwater Paper Corporation
ELECTRONIC MAIL ONLY
Carol Haugen
Clearwater Paper Corporation
Hand Delivered
U.S. Mail
Overnight Mail
FAXX Email [e-mail]
daphne. huano@puc. idaho.oov
_U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
o reo@richardsonadams. com
Hand Delivered
U.S. Mai!
Overnight Mail
FAXX Email [e-mail]
_Hand Delivered
U.S. Mail
Ovemight Mail
FAXX Email [e-mail]
lntermountain Energy Partners, LLG; _Hand Delivered
AgPower DCD, LLC; and AgPower Jerome, _U.S. MailLLC Ovemight Mail
Dean J. Miller _FAX
McDEVITT & MILLER, LLP X Email [e-mail]
420 West Bannock Street (83702) [e-mail]
P.O. Box 2564
Boise, ldaho 83701
CERTIFICATE OF SERVICE . 1
lntermountain Energy Partners, LLC
Leif EIgethun, PE, LEED AP
lntermountain Energy Partners, LLC
P.O. Box 7354
Boise, ldaho 83707
AgPower DCD, LLC, and AgPower Jerome,
LLC
Andrew Jackura
Gamco Clean Energy
9360 Station Street, Suite 375
Lone Tree, Colorado 80124
ldaho Gonservation League and Sierra Club
Benjamin J. Otto
ldaho Conservation League
710 North 6h Street (m702)
P.O. Box 844
Boise, ldaho 83701
Sierra Club
Matt Vespa
Siena Club
85 Second Street, Second Floor
San Francisco, Califomia 94105
Snake River Alliance
Kelsey Jae Nunez
Snake River Alliance
223 North 6h Street, Suite 317
P.O. Box 1731
Boise, ldaho 83701
ELECTRONIC MAIL ONLY
Ken Miller
Snake River Alliance
PacifiGorp d/b/a Rocky Mountain Power
Daniel E. Solander
Yvonne R. Hogle
Rocky Mountain Power
201 South Main Street, Suite 24OO
Salt Lake City, Utah 84111
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U.S. Mail
Ovemight Mail
FAX
Emai! [e-mail]
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_Ovemight Mai!_FAXX Email [e-mail]
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FAXX Email kn u nez@sna kerivera I I ia nce. o ro
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_Hand Delivered_U.S. Mail
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FAX
Email [e-mail]
wo n ne. hoq le@ pacifi co rp. co m
CERTIFICATE OF SERVICE - 2
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FAXX Email [e-mail]
_Hand Delivered_U.S. Mail
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Twin Falls Canal Company, North Side Canal _Hand Delivered
Company, and American Falls Reservoir _U.S. Mail
District No. 2 Ovemight Mail
C. Tom Arkoosh FAXX Email [e-mail]
Ted Weston
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
ELECTRONIC MAIL ONLY
Data Request Response Center
PacifiCorp
ARKOOSH LAW OFFICES
802 West Bannock Street, Suite 900 (83702)
P.O. Box 2900
Boise, ldaho 83701
ELECTRONIC MAIL ONLY
Erin Cecil
ARKOOSH LAW OFFICES
Avista Corporation
Michael G. Andrea
Avista Corporation
1411 East Mission Avenue, MSC-23
Spokane, Washingto n 99202
Clint Kalich
Avista Corporation
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U.S. Mail
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FAXX Email [e-mail]
_Hand Delivered_U.S. Mail
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FAXX Email [e-mail]
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U.S. Mail
1411 East Mission Avenue, MSC-7 _Ovemight Mai!
Spokane, Washington992O2 _FAXX Email [e-mail]
I i nda. oervais@avistaco rp. com
Idaho Irrigation Pumpers Association, lnc. _Hand Delivered
Eric L. Olsen _U.S. Mail
RACINE, OLSON, NYE, BUDGE & BAILEY Ovemight MailCHARTERED
-FAX201 East Center X Email [e-mail]
P.O. Box 1391
Pocatello, ldaho 83204-1 391
CERTIFICATE OF SERVICE . 3
Anthony Yankel
29814 Lake Road
Bay Village, Ohio 44140
Renewable Energy Coalition
Ronald L. Williams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, ldaho 83702
lrion Sanger
SANGER LAW, P.C.
1117 SW 53'd Avenue
Portland, Oregon 97215
The Amalgamated Sugar Gompany
Scott Dale Blickenstaff
The Amalgamated Sugar Company, LLC
1951 South Satum Way, Suite 100
Boise, Idaho 83709
Micron Technology, lnc.
Richard E. Malmgren
Micron Technology, lnc.
800 South FederalWay
Boise, ldaho 83716
Frederick J. Schmidt
Pamela S. Howland
HOLLAND & HART, LLP
377 South Nevada Street
Carson City, Nevada 89703
Ecoptexus, lnc.
John R. Hammond, Jr.
FISHER PUSCH LLP
U.S. Bank Plaza, Seventh Floor
101 South Capitol Boulevard, Suite 7O1 (83702)
P.O. Box 1308
Boise, ldaho 83701
Hand Delivered
U.S. Mail
Overnight Mail
X Email [e-mail]
_Hand Delivered
U.S. Mall
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FAXX Email [e-mail]
_Hand Delivered
U.S. Mai!
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phowland@holland hart.com
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CERTIFICATE OF SERVICE - 4
John Gorman
Ecoplexus, lnc.
650 Townsend Street, Suite 310
San Francisco, Califomia 94103
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_FAXX Email [e-mail]
CERTIFICATE OF SERVICE . 5