20150204White Direct.pdf

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UT ILlTl IS C(ii,1 i,'i l -i jlC;i
BEEORE THE IDAHO PUBLIC UTILITIES COMMTSSION
IN THE MATTER OF IDAHO POtf,ER )
COMPANY' S APPLTCATION FOR )
APPROVAL OF NEW TARIFF SCHEDULE ) CASE NO. IPC-E-15-03
82, A COMMERCIAL AND INDUSTRIAL )
DEMAND RESPONSE PROGRAM (FLEX )
PEAK PROGRAM). )
IDAHO POWER COMPANY
DIRECT TESTIMONY OE
TAMI Vf,HITE
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0.
A.
O. Please state your name and business address.
A. My name is Tami White and my business address
is L22L West Idaho Street, Boise, Idaho 83102.
O. By whom are you employed and in what capacity?
A. I am employed by Idaho Power Company ("Idaho
Power" or "Company") as the Senior Manager of Rate Design
in the Regulatory Affairs Department.
Please describe your educatj-onal background.
I earned a Bachelor of Business Administration
degree in Accounting from California State University,
Stanislaus. I have attended various electric utility
courses, including "Electric Utility System OperatJ-onr " a
course offered through Professional Training Systems, Inc.,
and "Overview of System Operations" presented by the
Western Electricity Coordinating Council. In 20L4, I
attended the Utility Executive Course at the University of
Idaho.
O. Pl-ease descrlbe your work experience with
Idaho Power.
A. I began my employment with Idaho Power in 7999
as a Financial Analyst in the Company's Delivery Finance
Support area where I provided accounting and financial
support services to the Delivery Business Unit. In 2005, T
was promoted to Finance Team Leader where I was responsible
for leading a group of Financial Analysts, Accountants, and
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Idaho Power Company
I Accounting Speci-alists in providing accounting and
2 financj-a1 support services to the Operations Business Unit.
3 I was responsible for all aspects of the monthly accounting
4 closing process for the Operations Busj-ness Unit and for
5 the monthly billing and settlements processes for
6 transmission sales and purchases, wholesale energy
7 transactions, Public Utility Regulatory Policj-es Act of
8 1978 (PURPA) transactj-ons, large specj-aI contracts, and
9 )oint use transactions. While working in Operations
10 Finance Support, f was invol-ved in the development of the
11 Company's Federal Energy Regulatory Commission (*FERC")
t2 Open Access Transmissj-on Tariff ('OATT") formula rate for
1-3 transmission services.
L4 In October of 2070, after 11 years in finance, I
15 accepted a posi-tion as Manager of FERC and Regional Affairs
16 in the Regulatory Affairs Department. In this position, I
l1 was responsible for managing reguJ-atory activities such as
18 the preparation and filing of Idaho Power's OATT rates for
L9 transmission service, supervising participation and
20 settl-ement negotiations in Bonneville Power Administration
2L rate cases, and creating analyses that form the basis for
22 Idaho Power's EERC regulatory strategy.
23 In January of 2012, T was promoted to Senior Manager
24 of Rate Design. As Senior Manager of Rate Design, I
25 oversee the Company's rate design acti-vities such as
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Idaho Power Company
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1 regulatory ratemaking and compliance filings, tarj-ff
2 administration, and the development of varj-ous pricing
3 strategies and policies.
O. What is the Company requesting in this
5 proceeding?
A. Idaho Power is requesting that the Idaho
7 Publ-ic Utilities Commission ("Commission") approve a new
8 tariff schedule that provides for the j-mplementation of an
9 optional internal-Iy managed demand response program for the
10 commercial- and industrj-aI ("C&I") customer classes1, and
11 authorize the Company to continue recovering the C&I demand
L2 response program expenses in the manner it currently does.
13 A similar program has historically been managed by a
74 third party, and has been referred to as the F1exPeak
15 Management program; however, for the remainder of my
!6 testimony I will refer to the historical program as the
l1 "third-party program. " The Company's j-nternal-1y-managed
18 program wil-I be referred to as the El-ex Peak Program
79 ("Program").
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O. How is the Company's case organized?
A. Idaho Power is filing an application for a
22 Commission order authorizing the Company to implement an
23 optional Schedule 82, FIex Peak Program, and to continue to
' The proposed program will be available to CeI customers
taking servj-ce under Schedules 9, 19 or a Special Contract.
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recover expenses associated with the Flex Peak Program in a
manner consistent with the current recovery approach. In
support of this application, the Company is filing my
testimony and the test j-mony of Mr. Quent j-n Nesbitt who is
the Energy Efficiency Program Leader responsible for
overseeing Idaho Power's C&I and irrigation demand-side
management ('DSM") programs.
My testimony along with the testimony of Mr.
Nesbitt, will inform the Commission as to why it is
appropriate and in the best interest of customers for fdaho
Power to transition from a third-party operated demand
response program to the Company-operated Flex Peak Program.
O. Please provide a summary of your testimony.
A. My testimony is organj-zed into three sections.
The first section will provide the history of the third-
party program. The second section will describe
stakeholder input received to date. Eina11y, in the third
section I will discuss program cost-effectiveness and how
the Company plans to recover program expenses.
I. EISTORY OF THE C&I DEI'AND RESPO}ISE PROGR.BU
o.
A.
What is the Elex Peak Program?
The Fl-ex Peak Program is a voluntary demand
response program for the Company's C&I customers who are
willing and able to reduce their electrical- energy loads
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for short periods of time from mid-June through mid-August
when el-ectrical- loads on Idaho Power's system are high.
O. When was the third-party program initiatly
offered to fdaho Power's C&I customers?
A. The Company filed an application on March 2,
2009, seeking Commission approval of an agreement ("third-
party Agreement") with a contractor, EnerNOC, Inc.
("EnerNOC"), to implement and manage the third-party
program beginning in the summer of 2009. The Commissi-on
approved the third-party Agreement in Order No. 30805,
issued on May 15, 2009. EnerNOC solicited participants and
the third-party program was available for the 2009 summer
season.
0.How did Idaho Power select EnerNOC to manage
the third-party program?
A.EnerNOC was selected by Idaho Power through
a competitive request for proposal ('RFP") process to
implement and manage the program. Through that process,
EnerNOC demonstrated it had successfully implemented
simil-ar programs for other util-ities throughout the
country.
a.What were EnerNOC's responsibilities under
the third-party Agreement?
A. Once notified by ldaho Power of a demand
response event, EnerNOC was responsible for supplying a
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committed load reduction to Idaho Power's system. Eurther,
EnerNOC was responsible for developing and implementing all-
marketing p1ans, securing all- participants, installing and
maintaj-ning all equi-pment beyond Idaho Power's meter
necessary to reduce demand, tracking participation, and
reporti-ng resul-ts to Idaho Power.
O.Please explain the Company's 2009 request for
Commission approval of the third-party Agreement.
A.The third-party Agreement included a five-
year term with demand reduction targets to be achieved
during each of those five years. The initial targets for
years 2009 through 2073 ranged from two megawatts ("MW") of
demand reduction during the 2009 program year up to 50 MW
of demand reduction during the 2073 program year.
0.Did the Company request Commission approval
for any modifications to the third-party Agreement?
A. Yes. On Eebruary 26, 2010, the Company
requested approval for an amendment to the third-party
Agreement which primarily sought to: (1) clarl-fy conditions
under which ldaho Power would be charged "energy payments"
during demand reduction events, (2) adjust the calculation
of the "Day-of-Load Adjustmentr" (3) decrease the penalty
EnerNOC would incur for failing to commit to a demand
reduction, and (4) add a non-solicitation cl-ause. This
fj-rst amendment was approved by the Commission in Order No.
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Idaho Power Company
1- 31098, issued on June 2, 201,0. The Company later filed two
2 other amendments as described below.
O. Did Idaho Power request suspension of its
4 Company-managed demand response programs in 2072?
A. Yes. In December of 2012, in response to
6 the l-ack of near-term peak-hour deficits identified in the
7 Load and Resource Balance analysis prepared for the 20L3
I Integrated Resource PIan ('IRP"), Idaho Power filed a
9 request (Docket No. TPC-E-1,2-29) with the Commission for
10 authority to temporarily suspend two of its three demand
11 response programs (A/C CooI Credit and Irrigation Peak
t2 Rewards). The Commission authorized the suspension of the
13 A/C CooI Credit and Irrigation Peak Rewards demand response
1,4 programs in Order No. 32'716, issued on April 2, 20L3.
15 O. Was the third-party program or the third-
!6 party Agreement impacted by the suspension of Company-
tl managed demand response programs?
18 A. Yes. On March 'l , 20L3, following the
79 Company's request to suspend its other two demand response
20 programs in Case No. TPC-E-L2-29 described above, the
2! Company filed a petition requesting the Commission approve
22 a second amendment to the third-party Agreement. The
23 second amendment reduced the weekly MW of nominated demand
24 reduction obligations to a range of 20 MW to 35 MW to
25 ensure that the then-current participati-on l-evel-s were
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sustainable while limlting future program costs associated
with higher demand reduction levels that the Company's IRP
indicated it did not need at the time. This second
amendment was approved by the Commission j-n Order No.
32805, issued on May 9, 2013.
o.Was the third-party Agreement impacted by
the Company's Demand Response Programs Settlement Agreement
("Sett1ement Agreement") entered into and approved by the
Commission in Case No. IPC-E-L3-74?
A.Yes. On March 'l , 2074, subsequent to the
Commission's approval of the Settlement Agreement, the
Company filed a petition seeking approval of a third
amendment to the third-party Agreement. This amendment
modified the third-party Agreement to comply with terms of
the Settl-ement Agreement and sought to extend the contract
terminatj-on date through December 20L4. This third
amendment was approved by the Commission in Order No.
33035, issued on May 7, 2014. The Settlement Agreement is
attached as Exhibit No. 1 to my testimony.
0.Did the Settlement Agreement specifically
address the C&I demand response program?
A.Yes. Signing parties to the Settlement
Agreement reached agreement on the design of each of the
Company's demand response programs, specifically addressing
the C&I demand response program in Section 9 of the
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Idaho Power Company
1 Settlement Agreement which describes parameters surrounding
2 paxticipation, program design, and the incentive structure.
O. What are the parameters surrounding
4 participation and program design?
A. The signing parties agreed in Section 9.a.
6 that the Company woul-d not actively seek to expand the
7 capacity of the C&I demand response program.
The signing parties also agreed in Section 9.b. that
9 the program will be available from June 15 through August
10 15, Monday through Eriday, from 2:00 p.m. B:00 p.m. ,
11 excluding holidays. Each dispatch event will last up to
72 four hours per participant within the avail-able program
13 hours. Dispatch events will not occur more than 60 hours
14 per season. Idaho Power will conduct a minimum of three
15 dispatch events per season. There will be two hours
76 advance notice to participants. In the event of a system
1,7 emergency, participants may be called to voluntarily reduce
18 their l-oad.
19 0. What parameters did the signing parties agree
20 to regarding the incentj-ve structure?
2I A. The signing parties agreed in Section 9.c.
22 that a fixed and variable incentive structure may be
23 appropriate, as long as the varj-able portion is 1ow enough
24 that it does not prevent the program from being dispatched.
25 If a fixed and variable incentive structure is used, a
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minimum of three dispatch events will- be included in the
fixed incentive. The variable incentive will be paid to
participants if Idaho Power conducts dispatch events during
the program season for more than the three minimum dispatch
events.
o.Does the Settlement Agreement contain any
other requirements with which Idaho Power must comply with
when offering its demand response programs?
A. Yes. The Settlement Agreement discusses six
overarching concepts that are to guide Idaho Power in the
implementation of its demand response programs. These
high-1evel concepts are l-isted in Section 4.a of the
Settl-ement Agreement and include the concept that Idaho
Power will provide demand response program offerings for
al-l three customer classes (residential,
commercial/industrial, and irrigation). The signing
parties also agreed on the annual value of Idaho Power's
demand response portfolio as set forth in Section 6 of the
Settlement Agreement.
O. Does the Settlement Agreement identify a term
during which Idaho Power has agreed to offer its demand
response programs?
A.Yes. Section 3 discusses the term, stating in
[T] he Settlement Agreement shal1 be ineffect beginning on the date it is approved
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by the Commission and sha1l apply to the
Company's demand response programs for 2074
and beyond until a change occurs in the
Company's system operations or cost-
effectiveness of a demand response program
that would warrant reevaluation of the
Settlement Agreement' s term.
0. Was demand response incl-uded in the 201,3 IRP?
A. Yes. The preferred portfolio of the 20\3 IRP
accepted for filing by the Commission in Order No. 32980
assumes a demand response capacity of 50 MW is available
beginning in 2024 and steps up to approximately 370 MW by
2032 -
o.WiIl demand response be j-ncl-uded in the 2015
IRP to be filed with the Commission in June 20L5?
A.Yes. Idaho Power considers demand response a
committed resource and 390 MW2 (including the C&I program)
of demand response will be included in each portfolio that
j-s analyzed as part of the 2075 IRP process.
o.Did the Company consider continuj-ng with
third-party management of the C&I demand response program
beyond the December 2074 expiration date of the third-party
Agreement?
2Based on the Settl-ement Agreement and the 2074 actual
enroll-ment of demand response, the Company incl-uded a
committed resource of 390 MWs of demand response in the
20L5 IRP. The Commission acknowledged the Company's
anticipated level- of demand response of 403 MWs for the
201-4 summer season in Order No. 33084, issued on July 30,
2014.
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o.
A.
A.Yes. In anticipation of the third-party
Agreement expiring in December 2074, the Company issued an
RFP during the summer of 20L4 seeking assistance operating
a C&I demand response program by a third party beyond 20L4.
How were the responses evaluated?
Idaho Power compared the proposals received
to a Company-operated program that served as a benchmark.
o.Was there a successful bidder?
A. No.
o.What prevented Idaho Power from pursuing a
contract with either bidder?
A.The primary concern that prevented Idaho
Power from pursuing either bid was the Company's conclusj-on
that cost savings for customers could be achieved by the
Company managing the program itself rather than through a
thj-rd party.
II. STAKEHOIDER INPUT
o.Did the Company solicit input from the
Energy Efficiency Advisory Group ('EEAG") to discuss the
Company's conclusions regarding the third-party bids and
the alternate proposal to operate an internally-managed C&I
demand response program?
A.Yes. The Company held a webinar with its
EEAG membership on Frj-day, January 9, 20!5, to solicit
EEAG's preference and support for either renewing the
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contract with EnerNOC or having the Company administer the
program.
o.
A.
o.
A.
Did you participate in this webj-nar?
Yes.
Did the EEAG offer a recommendation?
Yes. My impression is that the majority of
EEAG members are cautiously supportive of an Idaho Power-
managed program. One EEAG member expressed a neutral
position and one EEAG member recommended the Company retain
EnerNOC as the third-party manager of the program.
a.Why do you think the EEAG was cautious about
its support for Idaho Power managj-ng the program?
A.EEAG members expressed concerns regarding
how the Company would handle less certaj-n nomination
Ievels, concerns about how the Company would ensure that it
does not pay for l-oad reduction that is not achieved, and
concerns about the aggressive time1lne required to have a
program deslgned, approved, and operating prior to the June
15th start of the demand response program season, among
others.
O. Can the Company address the concerns
expressed by EEAG members?
A. Yes. Mr. Nesbitt, who will oversee the
Company-managed El-ex Peak Program wiII address the concerns
I identified in his testimony.
wHrTE, DI 13
Idaho Power Company
1 III. PROGRA}T COST-EFFECTTVEIIESS A}ID COST RECOVERY
O. Will the Flex Peak Program be cost-effective?
A. Yes, I believe the Program will be cost-
4 effective because it has historically been cost-effective,
5 and fdaho Power will be able to operate the Program at a
6 lower cost per MW of load reduction.
1 Q. How wil-l the cost-effectiveness of the El-ex
8 Peak Program be measured and reported?
9 A. According to the previously described
10 Settlement Agreement, the annual value of Idaho Power's
11 demand response portfolio is equal to the levelized annual-
72 cost of the minimum size deferred resource, which was
13 calculated to be approximately $16.7 mi11lon. In 2074, the
t4 cost of operating the Company's entire demand response
15 portfolio was $10.6 m1IIion, well- under the $16.7 millioh
16 dollar threshold. If all three programs were dispatched
Ll for the maximum allowable number of hours, the total costs
18 would have been approximately $13.8 million.
19 O. Did the Company compare the costs of
20 managing the Program internal-Iy versus the historical costs
2t of the third-party managed program?
22 A. Yes. The Company looked at the average
23 historical- total program costs over the course of the 6
24 years the third-party program has been in pIace. The total
25 program costs averaged approximately $2.0 million annually
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for nominated reductions at generation-level ranging
between 8.5 MV{s and 39.3 MWs annua11y.
Based on the Company's proposed Program design, the
Company anticipates total- Program costs to range from
approximately $1.1 million annually with no variabLe
payments up to approximately $1.4 million if the Program
has 35 MW of nominated reductions and was dispatched for
the maximum number of hours a1J-owed, which is 60.
o.Is the Company proposing a change to customer
rates associated with the ongoing funding of the Program?
A.No, not at this time. The Company bel-ieves
that the current level and method of recovery will
adequately fund the ongoing operati-on of the Program for
the f oreseeabl-e future.
o.Pl-ease explain how Idaho Power currently
recovers the third-party program costs.
A. On December 30, 20L1,, the Commission issued
Order No. 32426 approving $11.3 million of normal or "base
level" demand response incentive payment costs to become
part of base rates effective January L, 2072. Of that base
level- amount, approximately $2.0 mill-j-on was associated
with the C&I demand response program costs. The demand
response cost recovery method approved by Order No. 32426
authorized the Company to move demand response j-ncentive
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payment costs into base rates and track them as part of the
annual Power Cost Adjustment ("PCA") mechanism.
Annual1y, ds part of the PCA, the forecasted level
of demand response incentj-ve palrments woul-d be compared to
the normal leve1 included i-n base rates to determine the
level of demand response incentive payment cost recovery or
credi-t to be incl-uded in the PCA f orecast. One hundred
percent of any deviations between actual demand response
incentive payment costs and forecasted costs would be
incl-uded j-n the followj-ng year's PCA true-up. It should
also be noted that the demand response costs recovered in
base rates and tracked through the PCA woul-d include only
the incentives paid to customers for demand reduction or
the total amounts paid to third-party demand-aggregator
contractors for demand reduction; Idaho Power labor and
expenses associated with administration of the demand
response programs would continue to be recovered through
the Energy Efficiency Rider.
O. How will- the current regulatory treatment of
demand response cost recovery apply to the FIex Peak
Program?
A. Under the current regulatory treatment of
demand response cost recovery, Idaho Power would recover
Program incentive payment costs through base rates with
deviations from the base level tracked through the PCA
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mechanism. The Company woul-d continue to recover Program
l-abor and other administratlve expenses through the Energy
Efficiency Rider.
The current 1evel of. CcI demand response program
costs recovered through base rates j-s the same level
approved by Order No. 32426, approximately $2.0 mil-lion a
year. If approved, the Company anticipates incentive
payment costs from an Idaho Power-managed program to range
from approximately $0.9 million annually with no variable
payments up to approximately $1.21 million if the program
has 35 MWs of nominated reductions and is dispatched for
the maximum number of hours a11owed.
Continuing the use of the PCA mechanism to track
deviations between actual Program incentive payment costs
and those recovered in base rates will a1low 100 percent of
any annual Program cost savings to flow to customers by
June of the following year.
Idaho Power will report in its DSM Annua1 Report on
all- activities associated with the Flex Peak Program
incl-uding how it impacts the Energy Efficiency Riderr ds
well as detail-ing the incentives to be included in the PCA
calculation.
0.
A.
Does this conclude your testimony?
Yes, it does.
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STATE OF
County of
IDAHO
Ada
SUBSCRIBED AND SWORN
Eebruary 2075.
ATTESTATIOII OF TESTIIIONT
to before me this 4th day of
Residj-ng at:
My commission expi
ss.
I, Tami White, having been duly sworn to testify
truthfully, and based upon my personal knowledge, state the
following:
I am employed by Idaho Power Company as a Senior
Manager in the Regulatory Affairs Department and am
competent to be a witness in this proceedj-ng.
I declare under penalty of perjury of the laws of
the state of Idaho that the foregoing pre-fi1ed testimony
and exhibit are true and correct to the best of my
information and be]ief .
DATED this Ath day of Eebruary 2075.
wHrTE, Dr 18
Idaho Power Company
Tami White
c for Idaho
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-15-03
IDAHO POWER GOMPANY
wHlTE, Dl
TESTIMONY
EXHIBIT NO. 1
DEMAND RESPONSE PROGRAMS
SETTLEMENT AGREEMENT
This settlement agreement ("Settlement Agreement" or "Agreement") is entered into by
and among the following participants to the demand response workshops: Idaho Power
Company ("Idaho Power" or "Company"), the Staff of the Idaho Public Utilities Commission
("Staff"), the ldaho lrrigation Pumpers Association, Inc. ("IIPA"), the Idaho Conservation
League ('lCL"), the Snake River Alliance ("SRA"), EnerNOC, [nc. ("EnerNOC"), and Mike
Seaman. These entities and individuals are collectively referred to as the "Partier,," arrrd
individually as a "Party," to the Agreement.
WHEREAT whery in late 2012, the Load and Resource Balance Analysis performed
during the development of Idaho Power's 2013Integrated Resource Plan showed no peak-hour
capacity deficit until 2015, Idaho Power filed for changes to its A/C Cool Credit program,
Irrigation Peak Rewards program, and FlexPeak Management program (collectively "DR
Programs") in Docket Nos. IPC-E-72-29 and IPC-E-13-04;
WHEREAT following the temporary suspension of the A/C Cool Credit program and
Irrigation Peak Rewards program in 2013 and contract changes for the FlexPeak Management
program, the Parties attended a series of five workshops ("DR Workshops") for all interested
parties and stakeholders to discuss how the Company includes demand response ("DR") in its
Integrated Resource Plan ("[RP"), how it calculates cost-effectiveness of D& the purpose of D&
Idaho Power's DR Programs and desigru and settlement options for Idaho Power's DR
Programs n 2074and beyond;
SETTLEMENT AGREEMENT
Page 1 of 11 Exhibit No. 1
Case No. IPC-E-15-03
T. Wtite, IPC
Page I of 17
WHEREAS, these DR Workshops occurred in Case No. IPC-E-'I3-14, were noticed in
Docket UM 1553, and were attended by parties to both dockets, as well as members of the
public and other stakeholders;
WHEREAS, UM 1653 followed the workshop process in Case No. IPC-E-1$14 in an
effort to allow all interested Idaho and Oregon parties and stakeholders to collectively provide
input and agree upon Idaho Power's DR Program details; and
WHEREAS, tfuoughout the course of the DR Workshops, the Parties reached agreement
on certain aspects of Idaho Power's DR Programs.
NOW THEREFORE, in consideration of the mutual promises set forth herein, the
sufficiency of which is hereby acknowledged the Parties agree as follows:
l. Recitals. The above-stated recitals are incorporated and made a part of this
agreement to the same extent as if the recitals were set forth in full at this point.
2. Public.Interest. This Agreement is a fair, just, and reasonable compromise of
contested issues and its acceptance by the Idaho Public Utilities Commission ("IPUC" or
"Commission") would be in the public interest. The Agreement and its acceptance by the
Commission will reasonably resolve the issues related to Idaho Power's DR Programs.
Therefore, the Parties recommend that the Commission approve the Agreement and all of its
terms and conditions without material change or condition pursuant to IPUC P& 274-
3. Ienn. This Agreement shall be in effect beginning on the date it is approved by
the Commission and shall apply to ldaho Power's DR Programs for 2014 and beyond until a
change occurs in Idaho Power's system operations or cost-effectiveness of a DR Program that
would warrant reevaluation of the Agreement's terms. In such event Idaho Power will consult
SETTLEMENT ACREEMENT
Page 2 of 11 Exhibit No. 1
Case No. IPC-E-15-03
T. \A/hite, IPC
Page2 of 17
its Energy Efficiency Advisory Group ('EEAG") and then make an appropriate filing at the
Commission. Similarly, a party to this Agreement, may petition the Commission to open a
docket to reevaluate the terms of this Agteement if Idaho Power experiences a change in system
operations or the cost-effectiveness of a DR Program so warrants.
4. Concepts. The Parties and workshop participants agreed that the following
overarching demand response concepts should guide ldaho Power's implementation of its DR
Programs:
a. The Company must:
i. Use existing demand response resources when possible. This
includes using, to the extent possible, current demand response equipment owned or available
to ldaho Power and participating demand response customers, which currently represents
approximately a00 megawatts ("MW") of potential demand response capacity.
ii. lnclude demand response offerings for all three customer classes
(residential, commerciaUindustrial, and irrigation).
iii. Keep costs as low as possible.
iv. Reevaluate the value calculation as the IRP changes.
v. Take a long-term outlook. In order to have viable demand
response programs in the long term, the programs must continue in the short term.
vi. Calculate the avoided cost used for demand response by using the
avoided capacity cost of a 170 M!{ single cycle combustion turbine ("SCC?') multiplied by the
effective load carrying capacity ("ELCC"), measured over 20 years, plus the corresponding
deferred energy savings for 60 program hours.
SETTLEMENT AGREEMENT
Page 3 of 11 Exhibit No. 1
Case No. IPC-E-'15-03
T. White, IPC
Page 3 of 17
lrll.Strive for consistenry in dispatch requirements across DR
Programs.
b. Uses for demand response beyond reducing peak loads may be: load
following, non-spinning operating reserves, improved reliability during emergenry situations,
and flexibility to address delays in building new supply-side peaking resources. The workshop
participants broke into small groups and discussed the possibilities of load following and
reserves. Based upon these workgroup findings, Idaho Power will investigate the feasibility of
using demand response as operating reserves and make a determination on feasibility by the
end of the 3'd quarter of 2014. If Idaho Power determines that a pilot is feasible, it will create a
proposal and work with Staff and other interested stakeholders to develop a pilot program.
c. This Agreement applies only to Idaho Power's Demand Response
Prograrns, and the concepts are not applicable to any of the Company's other DSM Programs.
5- Resource Size. The minimum size of the deferred resource used for the value
calculation is 170 MW. It is appropriate for Idaho Power to incur and recover costs based on
deferring this resource.
6. Value. The annual value of demand response is equal to the levelized annual
cost of the minimum size deferred resource, measured over a period of 20 years, plus the
corresponding deferred energy savings for 60 program hours. As of the date of this Agreement
the calculation leads to an annual value of $1"6.7 million dollars for the entire DR Program
portfolio. The demand response value calculation shall include this value even in years when
the IRP shows no peak-hour capacity deficit. The annual value calculation will be updated with
SETTLEMENT AGREEMENT
Page 4 of 11 Exhibit No. 1
Case No. IPC-E-15-03
T. \A/hite, IPC
Page 4 of 17
each IRP based on changes that include, but are not Iimited to need, capital cosf or financial
assumptions.
7, AIC Cool Credit Program. Idaho Power will implement the A/C Cool Credit
program in a manner consistent with the tariff Schedule 81. A true and correct copy of the tariff
is attached to this Agreement as Attachment 1 and is incorporated herein as if set forth in full at
this point.
a. Participants. Participants are residential customers who are presently
enrolled in the program and have a load control device installed. All paging devices installed at
current participants' residences will be replaced with AMl-compatible devices, with the goal of
completing replacement in time for the 2074 program season. Idaho Power will not actively
promote the A/C Cool Credit program to solicit new participants through marketing tactics, but
will accept new participants in this program who request to participate, regardless of whether
they were previously participants in the program. In order to use existing equipment, Idaho
Power will contact and attempt to recruit customers who move into a home that already has a
load control device installed. If a customer enrolls in the A/C Cool Credit program at a
residence that has a paging device, the load control device will be replaced with an AMI-
compatible device. Idaho Power will also attempt to recruit participants who change residences
to a location that does not have a load control device. An AIC Cool Credit program load control
device will remain in place unless a customer requests the load control device be removed.
b. Program Details. The A/C Cool Credit program will be available from
]une 15 through August 15, Monday through Friday, excluding holidays. Each dispatch event
will last no longer than four hours for each participant. Dispatch events will not occur more
SETTLEMENT AGREEMENT
Page 5 of 11 Exhibit No. 1
Case No. IPC-E-15-03
T. White, IPC
Page 5 of 17
than L5 hours per week or 60 hours per season. ln the event of a system emergency, demand
response capacity from the A/C Cool Credit program will be available for immediate dispatch.
Idaho Power will conduct a minimum of three dispatch events per season. No advanced notice
to participants is required prior to executing each dispatch event. Participants, with advance
notice, may opt out of two events per season.
c. Incentive. Participants will receive a fixed incentive of $15 for the season,
which will be issued as a credit on one or more of the participanfs monthly bills for the
program months.
d. Program Size. If participation in the A/C Cool Credit Program changes,
Parties to this Agreement may file an application to modify the program as set forth in Section
3.
8. Irrigation Peak Rewards Program. Idaho Power will implement the Irrigation
Peak Rewards program in a manner consistent with the tariff Schedule 23. A true and correct
copy of the tariff is attached to this Agreement as Attachment 2 and is incorporated herein as if
set fbrth in full at this point.
Participanlq. Participation is limited to past lrrigation Peak Rewards
service locations where an active, working load control device exists as described in more detail
in Attachment 2. The Company will not actively market the Irrigation Peak Rewards program
as described in more detail in Attadrment 2.
b. Program Details. The Irrigation Peak Rewards program will be available
from June 15 through August 15, Monday through Saturday, from 1:00 p.m.-9:00 p.m.,
excluding holidays. Each dispatch event will Iast no longer than four hours for each
SETTLEMENTAGREEMENT
Page 5 of 11 Exhibit No. 1
Case No.lPC-E-15-03
T. White, IPC
Page 6 of 17
participant. Dispatch events will not occur more than fifteen (15) hours per week or sixty (60)
hours per season. In the event of a system emergency, demand response capacity from the
Irrigation Peak Rewards program will be available for immediate dispatch. [daho Power will
conduct a minimum of three dispatch events per season. Participants with Interruption Option
3 will be given at least four hours advanced notification. There will be no notification required
for participants with Intermption Options I and 2. Participants may opt out of an event. An
opt-out fee of S5.00 per kilowatt ("kW") per event will apply for the first three events and $1.00
per kW per event for subsequent events. The opt-out fee will not exceed the total bill credit for
the program season.
c. lncentive. Participants will receive a fixed incentive in the form of a
demand and energy component which is approximately $16 per kW per season, as set forth in
more detail in Attachment 2. The fixed incentive shall include the above-mentioned three
minimum dispatch events. If Idaho Power conducts dispatch events in the Irrigafion Peak
Rewards program in addition to the tfuee minimum dispatch events, Participants will receive a
variable incentive of $0.148 (or $0.198 for the 9:00 p.m. option) per kWh as set forth in more
detail in Attachment 2, which, with the realization rate included, results in a cost to Idaho
Power of approximately $0.22 per kWh.
9. FlexPeak Management Program. Idaho Power will implement the Flex Peak
Management program using the following design parameters.
a. Participants. Idaho Power will not actively seek to expand the capacity of
the FlexPeak Program. Participants are industrial and large commercial customers.
SETTLEMENT AGREEMENT
PageT ofll Exhibit No. 1
Case No. IPC-E-15-03
T. White, IPC
PageT ot 17
b. Pro&ram Details. The FlexPeak Management program will be available
from fune 15 through August 15, Monday through Friday, from 2:00 p.m.-8:@ p.m., excluding
holidays. Each dispatch event will last up to four hours per participant within the available
program hours. Dispatch events will not occur more than 60 hours per season. In the event of a
system emergency, demand response capacity from the FlexPeak Management program will be
available. Idaho Power will conduct a minimum of three dispatch events per seasn. There will
be two hours advanced notice to participants.
Incentive A fixed and variable incentive structure may be appropriate,
as long as the variable portion is low enough that it does not prevent the program from being
dispatched. If a variable and fixed incentive structure is used, a minimum of three dispatch
events will be included in the fixed incentive. The variable incentive witl be paid to participants
if Idaho Power conducts dispatch events in the FlexPeak Management program for more than
the three minimum dispatch events.
10. Confidentiali8. As provided in I<P 272, other than any testimony filed in
support of the approval of this Agreement and except to the extent necessary for a Party to
explain before the IPUC its own statements and positions with respect to the Agreement all
statements made and positions taken in negotiations relating to this Agrcement shall be
confidential and will not be admissible as evidence in this or any other proceeding.
L7. Commission Procedurs. The obligations of the Parties under this Agreement are
subject to the Commission's approval of this Agreement in accordance with its terms and
conditions and upon zuch approval being upheld on appeal by a court of competent
jurisdiction. The Parties will submit this Settlement Agreement to the Commission and
SETTLEMENT AGREEMENT
Page 8 of 11 Exhibit No. 1
Case No.lPC-E-15-03
T. White, IPC
Page 8 of 17
recorunend approval in its entirety pursuant to RP 274. Parttes shall support this Agreement
before the Commission, and no Party shall appeal a Commission order approving the
Agreement or an issue resolved by the Agreement. If this Agreement is challenged by any
person not a party to the Agreement, the Parties to this Agreement reserve the right to file
testimonp cross-exarnine witresset and put on zuch case as they deem appropriate to respond
fully to the issues presented, including the right to raise issues that are incorporated in the
settlements embodied in this Agreement. Notwithstanding this reservation of rights, the Parties
to this Agreement agree that they will continue to support the adoption of the terms of this
Agreement.
If the Commission rejects any part or all of this Agreement, or imposes any additional
material conditions on approval of this Agreement, each Party reserves the right upon written
notice to the Commission and the other Parties to this proceeding, within L4 days of the date of
such action by the Commission, to withdraw from this Agreement. In such case, no Party shall
be bound or prejudiced by the terms of this Agreement, and each Party shall be entitled to seek
reconsideration of an IPUC Order, file testimony as it chooses, cross-examine witresses, and do
all other things necessary to put on such case as it deems appropriate.
No Party shall be deemed to have agreed that any method, ttreory, or principle of
regulation or cost recovery employed in arriving at this Agreement is appropriate for resolving
any issues i, *y other proceeding in the future.
L2. Entire Agreement. This Agreement and its attachments constitute the entire
agreement between the Parties regarding the subject matter hereof. There are no oral or written
SET'ILEMENT ACREEMENT
Page 9 of 11 Exhibit No. 1
Case No. IPC-E-15-03
T. White, IPC
Page 9 of 17
understandings, representations, or commitnents of any kind, express or implied, which are
not expressly described in this Agreement.
13. Severability. If, after Commission approval of this entire Agteement without
modification, any immaterial term or provision of this agreement that is found to be voi4
prohibited, or unenforceable by local, state, or federal law shall be ineffective only to the extent
of such prohibition or unenforceability without invalidating the remaining provisions of this
Agreement. Upon a determination that any material term or provision is void, prohibited, or
unenforceable by local, state, or federal law, the Parties shall negotiate in good faith to modify
this Agreement to maintain the original intent of the Parties without such material provision.
14. No Third-Party Beneficiaries. No right or obligation contained in this
Agreement shall inure to the benefit of any person or entity not a Party or successor or assign of
a Party.
15. Counteryarts. This Agreement may be executed in counterparts and each signed
counterpart shall constitute an original document.
[signature page follows]
SETTLEMENTAGREEMENT
Page 10 of 11 Exhibit No. 1
Case No. IPC-E-15-03
T. \Mrite, IPC
Page 10 of 17
DATED this
-day
of September 2013.
Idaho Power Company ldaho Public
Staff
Utilities Commission
By.
Customer Relations & Energy Efficiency
Manager
Kad Klein
Deputy Attomey General
ldaho lrrigation Pumpers Association, ldaho Gonservation League
lnc.
By.By
Sid Enrin
Vice President of llPA
Ken Miller
Clean Energy Program Director
Benjamin J. Otto
Attomey for ldaho Conservation
League
EnerNOC, lnc.
Melanie Gillette
Director, Regulatory Affairs
Snake River Alliance
By By
By
Mike Seaman
ldaho Power Customer
SETTLEMENT AGREEMENT
Page 11 of 1L Exhibit No. 1
Case No. IPC-E-15-03
T. White, IPC
Page11of17
DATF,D tfris lnHy of Septernber 2013.
ldaho Power Company
Theresa Drake
Customer Relations & Energy Efficiency
Manager
ldaho lrrigation Pumpers Association,
lnc.
ldaho Public Utilities Commiesion
Staff
ldaho Conservation League
By
By.By.
ByBy
Sid Erwin
Vice President of llPA
Snake River Alliance
Benjamin J. Otto
Attorney for ldaho Conservation
League
EnerNOC, lnc.
Melanie Gillotte
Di rector, Reg ulatory Affairs
Ken Miller
Clean Energy Program Director
By.
Mike Seaman
ldaho Power Customer
SiJ'TTLIiMEN'T AGREEMENT
Page 11 of 11
Exhibit No. 1
Case No. IPC-E-15-03
T. White, IPC
Page 12 ot'17
Deputy Attorney General
Oct OA 13 O4:4Oa
DATED this-day of September2013.
ldaho Power Company
Theresa Drake
Gustomer Relatlcns & Energy Efficiency
Manager
p.1
ldaho Public tltilites Gommission
Staff
By
Karl Klein
DeputyAttomey General
By
ldaho lrrlgation Pumpers Assoclatlon, ldaho Conservation League
lnc.
By.
Snake River Alliance
Ken Miller
Clean Energy Program Director
Benjamin J. Otto
Attomey for ldaho Conservation
League
EnerNOC, lnc.
By.
Melanie Gillette
Director, Regulatory Affairs
By.
By
Mike Seaman
ldaho Power Customer
SETTLEMENT AGREEMENT
Page 11 of 11 Exhibit No. 1
Case No. IPC-E-15-03
T. White, IPC
Page 13 of 17
Vice President of llPA
DATED T*"dLrof september 201 3.
ldaho Power Company Public Utilities Commission
Theresa Drake Karl Klein
Customer Relations & Energy Efficiency Deputy Attorney General
Manager
lrrigation Pumperc Association, ldaho Gonseruation League
By.
ldaho
Staff
By**
ldaho
lnc.
By-
Sid Erwin
Vice President of IIPA
,/?
By fu,? k-
Benjamin J. Otto
Attorney for ldaho Conservation
League
EnerNOC, lnc.Snake River Alliance
ByBy
By
Ken Miller Melanie Gillette
Clean Energy Program Director Director, Regulatory Affairs
Mike Seaman
ldaho Power Customer
SETTLEMENT AGREEMENT
Page 11 of 11
Exhibit No. 1
Case No. IPC-E-15-03
T. \A/hite, IPC
Page'14 of 17
---l
I
i
DATEDthis dnvofSeoErnber2013.
kbhs_P-A11-e10_qmpa-ty ldaho- Public Utila{qp Com.mission
Staff
_By*_
fhereea Drake l&d (le1s
Customer Rqlgtions & Enerqy_Eftiele-rcy Deouty Altorney General
IvlAOaSeI
lda ho lrrigation PraBEeSL3gegCLalieS- ICS hg_C- eI setue ti g-E_LBgUe-
lnc-
$id EMin
Mce President of llPA
Bv -_
-Bsnjamin.t. otto
Aitornev for l4aho . Conservation
tpague
Bv
Snake River Alliancq ' EnerNOC, lnc,
i - -'-',
Melanie Gitlette
Clean EnergyP_r_Sgfan_DjlectgI Direstor, RequlatofyJfiats
irtike SeamaLr
ldaho Power Customer
SBTTLEMENTAGREEMENT
Page 11of11
Exhibit No. 1
Case No. IPC-E-15-03
T. Write, IPC
Page 15 of 17
DATED this
-day
of September 2013.
ldaho Powercompany
Theresa Drake
Customer Relations & Energy Efiiciency
Manager
ldaho lrrigation Pumpers Association,
lnc.
Utillties Gommissionldaho Public
Statr
ByBy
By.By
By.
Karl Klein
Deputy Attomey General
ldaho Conservation League
Sid Erwin
Vice President of llPA
Benjamin J. Otto
Attomey for ldaho Conservation
League
EnerNOC,lnc.Snake River Alliance
Ken Miller
Clean Energy Program Director
av fi, oo,-,, ytfuf r*+zr
Itlelaiie Gillette
Director, Regulatory Afiairs
By.
Mike Seaman
ldaho Power Customer
SETTLEMENT AGREEMENT
Page 11 of 11
Exhibit No. 1
Case No. IPC-E-15-03
T. \Mite,IPC
Page 16 of 17
DATED this
-day
of September 2013.
ldaho Power Gompany
By
Theresa Drake
Customer Relations & Energy Efficiency
Manager
ldaho lrrigation Pumpers Association,
lnc.
Utllltles Gommissionldaho Public
Staff
By
KarlKlein
Deputy Attomey General
ldaho Conservatlon League
By,
Ken Miller
Clean Energy Program Director
By
Benjamin J. Otto
Attorney for ldaho Conservation
League
EnerNOC, lnc.
By
Melanie Gillette
Director, Regulatory Affairs
Sid Erwin
Vice President of llPA
Snake River Alliance
By
By,lsl Mikc Soeman
Mike Seaman
ldaho Power Customer
SETTLEMENT ACREEMENT
Page 11 of 11 Exhibit No. 1
Case No. IPC-E-15-03
T. White, IPC
Page 17 of 17