20120828Volume IV.pdf

ORIGINAL
. 'flI7AUr27 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
1J H IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT ) CASE NO.
PROVISIONS INCLUDING THE ) GNR-E-11-03
SURROGATE AVOIDED RESOURCE (SAR)
AND INTEGRATED RESOURCE PLANNING
(IRP) METHODOLOGIES FOR
CALCULATING PUBLISHED AVOIDED
COST RATES.
TECHNICAL
HEARING
12* 44
S C
HEARING BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER PAUL KJELLANDER
PLACE: Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE: August 7, 2012
VOLUME IV - Pages 440 - 678
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HEDRICK
COURT REPORTING
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
4a/emwa4 1978
APPEARANCES
For the Staff:
For Idaho Power Company:
For Avista Corporation:
For PacifiCorp dba Rocky
Mountain Power:
For Idaho Conservation
League:
For Idaho Wind Partners I,
LLC:
For The Northwest and
Intermountain Power
Producers Coalition;
Grand View Solar II;
The Board of County
Commissioners of Adams
County, Idaho; J. R. Simplot
Company; Exergy Development
Group of Idaho, LLC; and
Clearwater Paper Corporation:
For Renewable Northwest
Project; Idaho Windfarms,
LLC; and Ridgeline Energy,
LLC:
KRISTINE A. SASSER, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83702
DONOVAN E. WALKER, Esq.
and JASON B. WILLIAMS, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
MICHAEL G. ANDREA, Esq.
Avista Corporation
1411 East Mission Avenue
Spokane, Washington 99202
DANIEL E. SOLANDER, Esq.
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
BENJAMIN J. OTTO, Esq.
Idaho Conservation League
710 North Sixth Street
Boise, Idaho 83702
GIVENS PURSLEY, LLP
by DEBORAH E. NELSON, Esq.
601 West Bannock Street
Boise, Idaho 83702
RICHARDSON & O'LEARY, PLLC
by PETER J. RICHARDSON, Esq.
and GREGORY M. ADAMS, Esq.
Post Office Box 7218
Boise, Idaho 83707
McDEVITT & MILLER, LLP
by DEAN J. MILLER, Esq.
420 West Bannock Street
Boise, Idaho 83702
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HEDRICK COURT REPORTING APPEARANCES
P. 0. BOX 578, BOISE, ID 83701
For Mountain Air Projects, UDA LAW FIRM, PC
LLC: by Michael J. Uda, Esq.
7 West Sixth Avenue, Suite 4E
Helena, Montana 59601
For Renewable Energy WILLIAMS BRADBURY, PC
Coalition and Dynamis by RONALD L. WILLIAMS, Esq.
Energy, LLC: 1015 West Hays Street
Boise, Idaho 83702
For Twin Falls Canal Company, CAPITOL LAW GROUP, PLLC
North Side Canal Company, by C. THOMAS ARKOOSH, Esq.
Big Wood Canal Company, and 205 North Tenth Street,
American Falls Reservoir Fourth Floor
District No. 2: Boise, Idaho 83702
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HEDRICK COURT REPORTING
APPEARANCES
P. 0. BOX 578, BOISE, ID 83701
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INDEX
WITNESS EXAMINATION BY PAGE
Mark Stokes Mr. Walker (Direct) 440
(Idaho Power) Prefiled Direct 443
Prefiled Rebuttal 490
Mr. Richardson (Cross) 538
Mr. R. Williams (Cross) 564
Mr. Arkoosh (Cross) 572
Ms. Sasser (Cross) 588
Tessia Park Mr. J. Williams (Direct) 596
(Idaho Power) Prefiled Direct 598
Prefiled Rebuttal 624
Mr. R. Williams (Cross) 639
Mr. Otto (Cross) 661
Ms. Nelson (Cross) 669
Ms. Sasser (Cross) 676
EXHIBITS
NUMBER PAGE
For Idaho Power Company:
1 PURPA QF Projects as of 12/31/11, 3 pgs Premark
Admit 538
2 Idaho Power Company PURPA Expense Premark
Admit 538
3 12/15/11 Workshop Presentation, 47 pgs Premark
Admit 538
4 Policy and Procedure for Curtailment Premark
of Certain PURPA QFs, 2 pgs Admit 639
5 Schedule 74, 2 pgs Premark
Admit 639
9 Idaho Power Hourly Incremental Cost Premark
Methodology Admit 538
HEDRICK COURT REPORTING INDEX
P. 0. BOX 578, BOISE, ID 83701 EXHIBITS
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3
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7
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10
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12
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10 Schedule 73, 6 pgs Premark
Admit 538
11 Rocky Mountain Power Electric Service Premark
Schedule No. 38, 9 pgs Admit 538
For Clearwater Paper Corporation, et al:
516 "Farming the Wind Near the Oregon Mark 543
Trail," 2 pgs
517 Idaho Power Company 2011 IRP, Pg 33 Mark 547
518 Request for Production No. 66 Mark 550
519 IPUC Order No. 31034, 5 pgs Mark 552
520 IPUC Case No. IPC-E-10-22 Comments Mark 556
of the Commission Staff, 6 pgs
For Dynamis:
1002 Firm Energy Sales Agreement, Dynamis Mark 647
Ada County Landfill Project, Pgs 1,
14-15, and 45-46, 5 pgs
HEDRICK COURT REPORTING EXHIBITS
P. 0. BOX 578, BOISE, ID 83701
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0 1 1 BOISE, IDAHO, TUESDAY, AUGUST 7, 2012
DIRECT EXAMINATION
BY MR. WALKER:
Q. Could you please state your name and spell your
last name for the record?
A. Yes. My name is M. Mark Stokes, and the last
name is spelled S-T-O-K-E--S.
Q. And by whom are you employed and in what
capacity?
A. I am employed by Idaho Power Company as the
manager of power supply planning.
Q. And did you previously cause to be filed your --
prefiled your written direct and rebuttal testimony, as well as
440
COMMISSIONER SMITH: So, Mr. Walker, I think
we're ready for your next witness, perhaps.
MR. WALKER: Thank you, Madam Chair. Idaho Power
calls Mark Stokes as its next witness.
MARK STOKES,
produced as a witness at the instance of Idaho Power Company,
being first duly sworn, was examined and testified as follows:
HEDRICK COURT REPORTING STOKES (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
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exhibit Exhibit No. 1 through 3 of your direct, and Exhibit
No. 9, 10, and 11 to your rebuttal?
A. Yes, I did.
Q. Do you have any changes or corrections to either
your direct, your rebuttal, or your exhibits?
A. I do have a couple of corrections:
In my direct testimony on page 5, at the bottom
of that page, there's a series of three tables that highlight
the amount of PURPA development that Utilities in the region
have contracted for, and I've got a correction in the upper
table for Northwestern Energy's number. For their Montana
number there, in my direct testimony, it's shown as 351. That
should actually be 163.
And, correspondingly, in the bottom table, the
47.9 percent should actually be 22.2 percent.
COMMISSIONER SMITH: This would also change the
total. Correct?
THE WITNESS: Yes, that's correct, yeah, the
total column in the upper table would be different also.
COMMISSIONER SMITH: And on the lower.
THE WITNESS: And the total column under the
percentage as well.
And then the other correction I have is on --
near the top of page 14. There is a reference to a State of
Oregon PUC case number where there's a blank in my testimony
441
HEDRICK COURT REPORTING STOKES (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power

1 for that case number, and that should read UM 1575.
2
Q. Do you have any other changes or corrections to

3 your direct, rebuttal, or exhibits?
A. No, I do not.

5 Q. If I were to ask you the questions set out in
6 your direct and rebuttal testimony, would your answers be the

7 same here today?

8 A. Yes, they would.

9 MR. WALKER: Madam Chair, I move to have the

10 direct and rebuttal and exhibits of Mark Stokes spread upon the

11 record as if read.
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COMMISSIONER SMITH: If there's no objection, we
will spread the prefiled testimony, direct and rebuttal, of
Mr. Stokes upon the record as if read in full, and Exhibits 1
through 3 and 9 through 11 will be admitted.
(The following prefiled direct and
rebuttal testimony of Mr. Stokes is spread upon the record.)
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442
HEDRICK COURT REPORTING STOKES (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
1 Q. Please state your name and business address.
2 A. My name is M. Mark Stokes and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q. By whom are you employed and in what capacity?
5 A. I am employed by Idaho Power Company ("Idaho
6 Power" or "Company") as the Manager of Power Supply
7 Planning.
8 Q. Please describe your educational background
9 and work experience with Idaho Power.
10 A. I am a graduate of the University of Idaho
11 with a Bachelor of Science Degree in Civil Engineering. I
12 also hold a Masters Degree in Business Administration from
. 13 Northwest Nazarene University and am a registered
14 Professional Engineer in the state of Idaho.
15 I joined Idaho Power in 1991 as a member of the
16 construction management team responsible for the
17 construction of the Milner Hydroelectric Project. In 1992,
18 I joined the Generation Engineering Department where I was
19 responsible for dam safety and regulatory compliance for
20 Idaho Power's 17 hydroelectric projects. In 1996, I began
21 working with Idaho Power's Hydro Services Group, a new
22 business initiative within the Power Production Department,
23 where I was responsible for business development and
24 marketing. In 1999, I returned to my previous position
• 25
STOKES, DI
Idaho Power Company
1 within the Power Production Department to administer Idaho
2 Power's dam safety program.
3 In 2004, I accepted a position as the President of
4 Ida-West Energy Company, a subsidiary of IDACORP. In this
5 role, I was responsible for managing the overall operation
6 of the company as well as the operation and maintenance of
7 nine hydroelectric projects with qualifying facility
8 status. In 2006, I rejoined Idaho Power's Power Supply
9 business unit as the Manager of Power Supply Planning. The
10 Power Supply Planning Department is responsible for
11 resource planning, load forecasting, and cogeneration and
12 small power production contract management.
S 13 Q. What is the purpose of your testimony in this
14 matter?
15 A. The purpose of my testimony is to provide
16 direct testimony for Idaho Power in response to the Idaho
17 Public Utilities Commission's ("Commission") Order Nos.
18 32352 and 32388. My testimony will describe the current
19 status of Public Utility Regulatory Policies Act of 1978
20 ("PURPA") Qualifying Facility ("QF") projects on Idaho
21 Power's system, as well as the current implementation of
22 both the Surrogate Avoided Resource- ("SAR") and Integrated
23 Resource Plan- ("IRP") based avoided cost methodologies in
24 Idaho. I will address issues related to risk and harm to • 25 Idaho Power customers through the implementation of PURPA,
444
STOKES, DI 2
Idaho Power Company
1 the Company's proposal for the Commission to set the
2 eligibility cap for published rates at 100 kilowatts ("kW")
3 for all QF resources, and to utilize the IRP-based
4 methodology for establishing the avoided cost for all PURPA
5 QF projects. My testimony also includes a recommendation
6 that the Commission establish a procedure that will
7 formalize negotiation of PURPA contracts. I will also
8 discuss the Company's request to lower the maximum
9 authorized contract term of PURPA QF power purchase
10 agreements.
11 I. SUMMARY OF RECOMNDATIONS
12 Q. Could you please summarize the recommendations
. 13 of your testimony?
14 A. Yes. My testimony will discuss and recommend:
15 1. That the Commission set the eligibility
16 cap for published avoided cost rates at 100 kW for all QF
17 resource types;
18 2. That the Commission authorize Idaho
19 Power to utilize the IRP-based methodology for establishing
20 avoided cost rates, for both published and negotiated
21 rates, for all PURPA QFs;
22 3. That the Commission establish an
23 authorized negotiation process and procedure by which a
24 PURPA QF can obtain a power purchase agreement with Idaho
. 25 Power; and
445
STOKES, DI 3
Idaho Power Company
1 4. That the Commission reduce the maximum
2 authorized PURPA QF power purchase agreement contract term
3 from the current 20 years to a maximum term of five years.
4 II. CURRENT STATUS OF PURPA QFS ON IDAHO POWER'S SYSTEM
5 Q. Could you please describe the current status
6 of PURPA QF development on Idaho Power's system?
7 A. Yes. Idaho Power has a very large amount of
8 PURPA QF generation both currently operating on its system,
9 and under contract to come on-line in the near term. In
10 fact, Idaho Power has more PURPA QF generation on its
11 system than any other utility, of any size, in the
12 northwest region of the United States. When this is
. 13 considered in proportion to Idaho Power's load, both peak
14 and minimum, it is even more extreme and concerning.
15 As of December 31, 2011, Idaho Power had 119 PURPA
16 QF projects under contract with an estimated nameplate
17 rating of 989 megawatts ("MW") . Of those projects, 96 (606
18 MW) are currently on-line, and an additional 23 projects
19 (383 MW) are scheduled to come on-line between now and
20 early 2014. The majority of QF projects that are under
21 contract, but not yet operational, are estimated to be on-
22 line by the end of 2012. Additional information about
23 Idaho Power's QF projects is provided in Exhibit No. 1.
24 Q. How does this compare to other regional
. 25 utilities?
446
STOKES, DI 4
Idaho Power Company
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1 A. Idaho Power researched PURPA activity in the
2 region, and has summarized it in the table below. This
3 table contains the PURPA QF nameplate rating, 2011 annual
4 average utility customer load, and PURPA nameplate rating
5 as a percentage of load, reported by utility and by state.
6 As shown in the table below, the amount of PURPA QF
7 development on Idaho Power's system significantly exceeds
8 the QF development of any other Northwest utility.
PURPA Nameplate by State and Utility (MW)
ID OR MT UT WA WY CA Total
Idaho Power 940 28 21 989
PacifiCorp 65 167 179 6 378 20 815
Avista 7 95 102
Northwestern Ene 351 351
Portland General 14
Puget Sound Energy
_
44 1
2011 Annual Average Load by State and Utility (a MW)
ID OR MT UT WA WY CA Total
Idaho Power 1,771 87 1,858
PacifiCorp 386 1,526 2,735 468 1,133 94 6,342
Avista 382 714 1,096
Northwestern Energy 733
Portland General Electric 2,403 1 2,403
Puget Sound Energy 2,507 1 2,507
PURPA Percentage of Average Load by State and Utility
ID OR MT UT WA WY CA Total
Idaho Power 53.1% 32.2% 53.2%
PacifiCorp 16.8% 10.9% 6.5% 1.3% 33.4% 21.3% 12.9%
Avista 1.8% 13.3% 9.3%
Northwestern Energy 47.9% 47.9%
Portland General Electric 0.6% 1 0.6%
Puget Sound Energy 1.8% 1.8%
The table above highlights that Idaho Power with
1,858 average megawatts ("aMW") of 'average annual load has
447
STOKES, DI 5
Idaho Power Company
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1 989 MW of PURPA contracts. In comparison, PacifiCorp with
2 6,342 aMW of load in its six state service territory
3 (almost three and a half times more load than Idaho Power)
4 only has 815 MW of PURPA QF resources. Other comparisons
5 from the table are just as striking with Puget Sound Energy
6 having 2,507 aMW of load and only 44 MW of PURPA and
7 Portland General Electric with 2,403 aMW of load and only
8 14 MW of PURPA.
9 Q. How does the amount of PURPA QF generation
10 Idaho Power has under contract compare to the federal
11 renewable electricity standard ("RES") Idaho Power assumes
12 in its IRP and other state renewable portfolio standards
13 ("RPS") requirements?
14 A. Idaho Power's 2011 IRP assumes a federal RES
15 requirement will be implemented in the near future that
16 will require 15 percent of generation be renewable starting
17 in 2020. The figure below shows how the current level of
18 PURPA QF generation added to Idaho Power's other eligible
19 renewable resources in 2014 compares to the assumed RES
20 requirement (in 2020) and to other regional state RPS
21 requirements. It is important to note that the assumed
22 federal RES requirement also includes subtracting
23 hydroelectric generation from the sales base used to
24 calculate the requirement, which has been proposed in past • 25 draft legislation.
448
STOKES, DI 6
Idaho Power Company
.
Idaho Power Compared to Regional RPS Standards
30%
25%
20%
15%
10%
5%
0%

Idaho Power Assumed WARPS WARPS WARPS ORRP52011ORRPS2015ORRPS20200RRP52025 MTRPS MTRPS
2014 Federal RES 2012 2016 2020 2010 2015
2020
Note: Federal RES includes subtracting hydro generation from the sales base in the calculated requirement.
1
2 As shown in the figure above, with just the current
3 level of PURPA generation Idaho Power has under contract
4 coupled with Idaho Power's other qualifying long-term power
5 purchase agreements, the Company would meet the assumed
6 federal RES standard by nearly three times, six years ahead
7 of schedule. This comparison is done only to show the
8 magnitude of QF development compared to various mandatory
9 RPS requirements. Because Idaho Power does not receive the
10 renewable energy certificates ("REC") from most of its QF
11 generation, PURPA generation cannot be used to meet any
12 potential RPS requirements and Idaho Power cannot represent
13 to customers they are receiving renewable energy from the
14 Us for which it does not receive the RECs.
449
STOKES, DI 7
Idaho Power Company
1 In comparison to other state RPS requirements, in
2 2014, Idaho Power will exceed the state of Washington's 15
3 percent requirement in 2020, the state of Oregon's 15
4 percent requirement in 2015, and the state of Montana's 15
5 percent requirement in 2015. In addition, in 2014 Idaho
6 Power would be just shy of meeting the state of Oregon's 20
7 percent requirement in 2020.
8 Q. What does this large amount of PURPA
9 generation cost Idaho Power customers?
10 A. Through October 2011, Idaho Power customers
11 have incurred a cost of a little over $1.1 billion for all
12 PURPA projects that have come on-line since 1982, when the
. 13 first PURPA project began delivering energy to Idaho Power.
14 The future cost of the current 119 PURPA projects under
15 contract with Idaho Power is estimated to cost Idaho Power
16 customers an additional $3.6 billion over the remaining
17 life of the contracts for a total historical and estimated
18 future cost of $4.7 billion. Details of these costs are
19 presented in Exhibit No. 2.
20 Q. How are the costs of PURPA paid for?
21 A. PURPA costs are paid for by Idaho Power's
22 customers as a power supply expense that runs through the
23 annual Power Cost Adjustment ("PCA") mechanism. Each year
24 100 percent of the power supply expense related to PURPA
. 25 QFs is passed through the PCA, and collected from Idaho
450
STOKES, DI 8
Idaho Power Company
1 Power's customers. The increase in PURPA costs will result
2 in a direct increase to each customer's monthly bill to pay
3 for the power produced by these projects.
4 Q. Is there a trend with the power supply
5 expense related to PURPA?
6 A. Absolutely. PURPA expenses are growing at a
7 very rapid pace and becoming quite large. The figure below
8 shows the historical and projected increase in PURPA QF
9 power supply expense from 2004 through 2020, and includes
10 only the contracts approved by the Commission as of
11 December 31, 2011. Details of these costs are also
12 included in Exhibit No. 2.
~ Is
200
180
160
140
120
100
1J
80
60
40
20
Idaho Power PURPA Payments
2004-2020

Ln N CO O 0 '-I M t M W N CO 0i 0 0 -1 - I . _l .4 .4 N 8 8 8 8 e 0 0 0 0 0 N N N N N N N (N N N N N N N N N N 13
14 As shown in the figure above, annual PURPA power
15 supply expenses in 2004 were approximately $40 million. It
.
16 took over 20 years of accumulation of PURPA contracts to
451 STOKES, DI 9
Idaho Power Company
reach the $40 million in costs seen in 2004. Five years
later, in 2009, that amount grew by 50 percent to
approximately $60 million. Just three years later, in
2012, that $60 million will double to $120 million of
annual PURPA power supply costs. That number increases to
$167 million by 2014 and by 2026, it will be $186 million
annually, an approximate 465 percent increase in costs from
2004.
Q. How do these large increases in PURPA power
supply expenses affect customer rates?
A. As stated earlier, PURPA power supply costs
are paid for by Idaho Power's customers through the PCA
mechanism. Each year 100 percent of the power supply
expense related to PURPA QFs is passed through the PCA, and
collected from Idaho Power's customers. The dramatic
increases discussed above in annual PURPA power supply
costs have a corresponding and equally dramatic impact on
customers' bills. As shown in the figure below, the effect
of the increase in PURPA power supply costs alone will
increase the annual PCA rate from the $62.9 million
currently approved in base rates to $78.4 million, with
three months of the PCA year still remaining.
1
2
3
4
6
7
8
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[1 13
14
15
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452 STOKES, DI 10
Idaho Power Company
~ 0 $90,000,000
$&,000,000
$70,000,000
$60,000,000
$50,000,000
$40,000,000
$30,000,000
$20,000,000
$10,000,000
Idaho Power PURPA Expense by PA Year

,, ,, , I I I I NQ Q111
' ' c"' (' c(;" ç(' '
,, '- 01 01 .
ro,0c~' ? ' - ,1- c c
1
2 The level of increase in near term PURPA power
3 supply expense, through 2014, results in dramatic annual
• 4 increases in customers' bills. The average Schedule 19,
5 Large Power Service, customer's bill will increase by
6 approximately $138,000 annually. The average residential
7 customer will see an increase of just under $100 per year.
8 Annual increases to the Company's largest customers, the
9 Special Contract customers, will range from just over $1
10 million to more than $3.6 million annually. This price
11 impact is not speculation. It is based entirely upon the
12 projected cost of the currently existing PURPA QF
13 generation, along with the QF projects that have executed
14 power purchase agreements approved by the Commission. If
15 Idaho Power never acquires another kilowatt of PURPA QF
16 generation, these increases will still take place based
is
453 STOKES, DI 11
Idaho Power Company
10 1
2
3
4
5
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7
upon the current QF projects and approved contracts the
Company has now.
Q. Is there a corresponding trend with the
amount of generation provided by QF5?
A. Yes. The amount of generation provided, and
projected to be provided by QFs to Idaho Power increases in
a similar fashion, as shown in the figure below:

Idaho Power PURPA Contract Nameplate Capacity
1982-2014
19
8
9
10
11
12
13
14
15
16
.
In summary, over the 10 years between 2004 and 2014,
the number of Idaho Power PURPA projects on-line since 2004
has increased by 95 percent (61 projects in 2004 to 119
projects currently under contract), total nameplate
capacity has increased 530 percent (157 MW in 2004 to 989
MW currently under contract) and total estimated cost has
increased 318 percent ($40 million in 2004 to a projected
cost in 2014 of $167 million) .
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STOKES, DI 12
Idaho Power Company
1 Even if no additional PURPA project contracted with
2 Idaho Power, the amount of energy and financial impact of
3 the existing projects under contract is dramatic. However,
4 PURPA project development within the Idaho Power service
5 territory continues. In October 2011, a new 20 MW solar
6 project contract was submitted and approved by the
7 Commission, in November 2011 a 22 MW biomass project and a
8 40 MW wind project were submitted for Commission approval,
9 and in December 2011 a 1.27 MW hydro project was submitted
10 for approval. In addition to these projects, Idaho Power
11 continues to receive numerous inquiries from potential
12 PURPA projects of all types.
. 13 In fact, over a recent three-day period (January 25,
14 26, and 27, 2012) the Company received nine new requests
15 for published rate contracts from QFs in its Oregon service
16 territory. These requests are for projects 10 MW and under
17 with rates determined by the SAR avoided cost methodology.
18 The Company additionally has three other QFs located in
19 Idaho attempting to wheel their output to the Company's
20 Oregon jurisdiction to obtain published SAR-based avoided
21 cost rates. In contrast to the current requests from 12
22 QFs representing approximately 90 MW, Idaho Power currently
23 has six QF projects providing approximately 28 MW located
24 in its Oregon jurisdiction. Idaho Power has requested
• 25 authorization from the Public Utility Commission of Oregon
455
STOKES, DI 13
Idaho Power Company
1 to utilize the IRP avoided cost methodology for all
2 projects over 100 kW. Advice No. 12-02 and Case No. UM
3 filed on January 27, 2012. Additionally, Idaho Power
4 has requested the Idaho Commission to exercise its
5 jurisdiction over three proposed QF projects that have
6 requested Oregon QF contracts, but have points of delivery
7 in Idaho.
8 Q. Does the recent increase in PURPA projects
9 mean Idaho Power can avoid building any new resources for
10 some time?
11 A. No. Because a vast majority of the new
12 PURPA contracts are for wind projects, Idaho Power will . 13 still have to build new resources in order to meet
14 projected growth in peak-hour demand. Wind resources
15 provide less than 5 percent of capacity on peak and
16 therefore do little to meet Idaho Power customers' growing
17 summertime peaking needs.
18 III. HARM TO CUSTOMERS
19 Q. What effect does the very large and dramatic
20 increase in PURPA power supply expenses that you have set
21 forth above have on Idaho Power customers?
22 A. The effect is that customers are harmed by the
23 QF transactions that the Company is legally required to
24 enter into. Customers will pay much more for QF generation • 25 than they would otherwise pay for Idaho Power to either
456 STOKES, DI 14
Idaho Power Company
1 generate the same amount of electricity from its own
2 generation resources or to purchase that same amount of
3 electricity from the wholesale market. This is directly
4 contrary to the federal definition of avoided cost. It is
5 also directly contrary to the requirement that customers be
6 held indifferent to whether the Company purchased
7 electricity from the QF or otherwise acquired it.
8 Q. It is clear that customers are paying a lot of
9 money for QF generation, and that this amount will increase
10 substantially. Is this increase acceptable because the
11 amount of generation received from PURPA QFs will also
12 increase substantially?
' 13 A. No. If the greatly increased amount of QF
14 generation coming onto the system were priced properly, and
15 if that generation were bringing adequate value to the
16 system, then Idaho Power customers might be indifferent.
17 However, PURPA generation is not currently bringing
18 adequate value to the system and, in fact, is providing a
19 very large amount of generation at times when it is not
20 needed, at a price that exceeds the cost to Idaho Power to
21 generate using its own resources, and at a cost that
22 exceeds what Idaho Power can get for it at market. This is
23 extremely harmful to customers.
24 Q. How can one determine the value that QF
25 purchases bring to the system?
STOKES, DI 15
Idaho Power Company
1
2
3
4
5
6
7
.1
A. One approach to determine the value of QF
purchases is to compare PURPA contract rates to historical
and forward market prices. Investigation reveals that
there has been a significant difference between the
historical prices paid to PURPA resources and the Mid-C
index and, on a forward looking basis, there continues to
be a significant difference between PURPA prices and the
Mid-C forward market prices. This difference is
illustrated in the following figure:
Average PURPA Price Compared to Mid-C Index
2002-2022 90
80
70
-c
40
20
A
---;
60
50
30 iI1II
10
0 0 o 0 0 0 0 0 0 0 0 0 0 0 (N (N (N (N (N (N (N (N (N (N (N (N (N
—Average Mid-C Index - PURPA Price - - Est. PURPA Price - - Mid-C Forwards
In 2005 and 2008, the average price paid to PURPA
projects was reasonably close to the Mid-C index price;
however, the Mid-C index was down significantly in 2009 and
2010, and dropped further in 2011, yet the price paid to
PURPA projects remained relatively constant. And, as
458
10
11
12
13
14
15
.
STOKES, DI 16
Idaho Power Company
1 illustrated above, there continues to be a significant gap
2 between PURPA prices and Mid-C forwards out past 2022.
3 Q. Does Idaho Power need PURPA generation?
4 A. There are limited times when Idaho Power
5 utilizes this generation to serve load, and the Company
6 reflects such use in its IRP planning process. However,
7 Idaho Power is currently purchasing large amounts of PURPA
8 generation that exceeds the needs of its customers. For
9 example, the figure below shows Idaho Power's projected
10 monthly surplus/deficit position in 2014 and the only
11 monthly energy deficit is projected to occur in July.
12 Idaho Power is in a surplus position in all months of the
. 13 year except July, and does not have a need for any
14 additional QF generation outside of that month. Overall,
15 the projected annual average surplus on the Company's
16 system is 526 aMW and this projected surplus includes 284
17 aMW of PURPA generation. If all of the PURPA generation is
18 removed, the portfolio still has an average surplus of 242
19 aMW.
20
21
22
23
24
25
STOKES, DI 17
Idaho Power Company
.
Idaho Power 2014 Surplus/Deficit
December 2011 OP Plan
1,000
800
600
400 €5
200
0
-200
-400
I.
.
:1-
2 The net result is that Idaho Power is buying a
3 significant amount of energy that its customers do not
4 need, at above market prices, and, in many instances, the
5 Company will end up selling that energy back into the
6 market at a significant loss. This is very harmful to
7 customers, as it works to inflate the power supply expenses
8 they must bear.
9 Q. Could you explain?
10 A. Yes. To illustrate the significance of this
11 issue, the differential between what Idaho Power will pay
12 for PURPA generation in 2012 and the amount it would pay to
13 purchase the same amount of generation as a "firm" product
14 in the Mid-C market is on the order of $69 million - that
15 is an overpayment of $69 million dollars in one year. For
16 2013, the differential in QF purchase price and market
17 price results in an overpayment to the QFs of $80 million.
18 For the 10-year period between 2012 and 2021, this
460 STOKES, DI 18
Idaho Power Company
1 differential results in an average overpayment of $67
2 million per year, totaling $670 million. The present value
3 of this overpayment is close to half a billion dollars
4 ($493,000,000)
5 That is only part of the harm to customers. There
6 is an additional cost associated with moving unneeded QF
7 generation to market when it is not needed to serve
8 customers. Not only are customers overpaying for
9 generation the system does not need, but when the QF
10 generation cannot be used to serve Idaho Power's load (11
11 months where it is surplus), it must be moved to market.
12 To move this QF generation to market at Mid-C, the Company • 13 will have to sell it as a standard "firm" product.
14 Additionally, transmission expenses are incurred to
15 move energy to the Mid-C market. Non-firm energy typically
16 trades at a discount to a firm energy product - this
17 discount may be as much as $5 per megawatt-hour ("MWh")
18 So, if on average, Idaho Power incurs an additional $3 per
19 MWh to firm the energy and an additional $3 per MWh in
20 transmission costs plus transmission losses of $1.50 per
21 MWh, with PURPA generation projected to exceed 2.4 million
22 MWh per year beginning in 2013, this adds an additional $18
23 million per year. This increases the $67 million loss to
24 $85 million per year. While these are just estimates, they
25
461 STOKES, DI 19
Idaho Power Company
1 illustrate the type of additional costs that will be
2 incurred to get PURPA generation to the market.
3 Q. Are there any other costs that are unaccounted
4 for in the current avoided cost methodologies that harm
5 customers?
6 A. Yes. There are a number of additional costs
7 that Idaho Power and its customers may incur as a result of
8 the amount of intermittent PURPA resources currently under
9 contract. Although difficult to quantify, additional costs
10 may be incurred in the following areas:
11 1. New Resources. It may be necessary for
12 Idaho Power to add additional utility-owned generation
. 13 resources to assist with integration of variable QF
14 resources;
15 2. Maintenance Costs. As a result of
16 operating its existing resource portfolio differently,
17 Idaho Power may incur additional maintenance costs if, for
18 example, thermal units are cycled more frequently to assist
19 with integration of variable QF resources;
20 3. Imputed Debt. Idaho Power's borrowing
21 costs may increase if Idaho Power's credit ratings are
22 impacted by the amount debt rating agencies impute on Idaho
23 Power's balance sheet. The amount of imputed debt will
24 depend on the magnitude of the PURPA obligations and the
25
462
STOKES, DI 20
Idaho Power Company
1 agency's assessment of the likelihood that Idaho Power will
2 be able to recover these costs.
3 The current indications are that Idaho Power's
4 customers are paying above-market prices for significant
5 amounts of energy that the system does not need, and they
6 will continue to do so at substantial harm well into the
7 future.
8 Q. Most of the Company's data is based on
9 nameplate capacity numbers of the various QFs, but QFs do
10 not typically generate at nameplate capacity do they?
11 A. No, not all the time. However, sometimes they
12 do and when they do, Idaho Power must have the . 13 infrastructure and ability to handle the generation as it
14 is delivered to the electric system. There are several
15 times when QF generation has and will generate at or close
16 to nameplate capacity. For example, on December 21, 2011,
17 Idaho Power received a large amount of energy from its QF
18 wind resources. On this day Idaho Power received 7,028 MWh
19 (293 aMW) from the 20 PURPA wind projects on-line
20 (nameplate rating of 398 MW). Based on an average energy
21 price contained in those contracts, Idaho Power incurred a
22 power purchase expense of approximately $535,000 for the
23 day for the wind generation ($76.12 per MWh). On that same
24 day, the short-term, daily average Mid-C market price was • 25 $29.75 per MWh. If Idaho Power had purchased the same
463
STOKES, DI 21
Idaho Power Company
1 amount of energy as provided by the PURPA wind projects on
2 that day, Idaho Power would have only incurred a power
3 purchase expense of approximately $209,000. Thus on
4 December 21, 2011, the PURPA wind energy power purchase
5 expenses were $326,000 greater than alternative market
6 purchases. This additional cost will be included in the
7 annual PCA and collected directly from Idaho Power's
8 customers. If this example were an isolated incident, the
9 Company might not be so concerned. However, these
10 circumstances occur frequently enough to suggest a thorough
11 examination is warranted, as is the purpose of this case.
12 The December 21, 2011, example is not only a good
13 example of QF generation operating at or near nameplate
14 capacity but also a good example of what is wrong with the
15 current avoided cost methodology employed in Idaho.
16 Avoided cost is supposed to mean the incremental cost to
17 Idaho Power of electric energy or capacity or both which,
18 but for the purchase from the QF, Idaho Power would
19 generate itself or purchase from another source. 18 C.F.R.
20 § 292.101(b) (6). When customers must pay more for QF
21 generation than what that generation can be sold at market
22 at times when it cannot be used to serve load, customers
23 are no longer being held indifferent to the QF transaction.
24 This is discussed further by Company witness Karl
• 25 Bokenkamp. Mr. Bokenkamp's testimony will propose
464
STOKES, DI 22
Idaho Power Company
1 adjustments to the current IRP-based avoided cost
2 methodology to more properly align the methodology with the
3 definition of avoided cost.
4 Q. Is wind generation the main concern of Idaho
5 Power with regard to QF generation?
6 A. Wind generation is a major concern because of
7 the extremely large quantity that is currently operating on
8 the Company's system, the additional projects that have
9 approved, long-term power purchase agreements and are
10 scheduled to come on-line in the near future, and the
11 continued interest from QF developers in developing new
12 wind projects and forcing the Company to purchase the
S 13 output through PURPA. However, the main concern of Idaho
14 Power in this case is not limited to concerns over wind
15 alone, and extends to all PURPA QF projects regardless of
16 the generation technology or motive force.
17 Q. What is the significance of large amounts of
18 intermittent and variable QF energy being inconsistent with
19 the Company's least cost, long-term IRP process?
20 A. As a public utility, Idaho Power is obligated
21 to engage in a planning process that ensures it prudently
22 acquires resources accounting for cost, risk, and
23 environmental concerns. Diversity in generation resources
24 (e.g., thermal, hydro, renewable, etc.) is consistent with
25 good utility planning practices. However, wind generation
465
STOKES, DI 23
Idaho Power Company
1 is by far the largest form of intermittent and variable
2 generation on Idaho Power's system, and more is being
3 proposed by QF developers. From an operational perspective
4 (policy and legal arguments aside), it is neither good
5 utility practice nor prudent for Idaho Power to be
6 acquiring such large amounts of wind generation such as
7 that which is currently scheduled to come onto its system.
8 In fact, the preferred portfolio in Idaho Power's 2011 IRP
9 does not include any new wind resources for the next twenty
10 years.
11 The 2011 IRP Advisory Council and members of the
12 public participating in the IRP process have been in • 13 general agreement for some time that significant amounts of
14 wind generation is not a good choice for Idaho Power for
15 the following reasons: (1) it does very little to meet
16 Idaho Power's peak-hour needs, i.e., less than 5 percent on
17 peak; (2) its intermittent and variable nature, requiring
18 regulating reserves and providing unreliable energy
19 deliveries; and (3) it creates a substantial amount of
20 surplus energy during times when Idaho Power's customers'
21 demand is low.
22 Q. How has the IRP planning process been
23 frustrated or circumvented by PURPA?
24 A. The IRP process was established in order to • 25 evaluate different resource types and allow informed
466
STOKES, DI 24
Idaho Power Company
1 decisions regarding future generation resources based on
2 cost, risk, and environmental concerns. The IRP planning
3 process involves input from the public during the creation
4 of the plan through monthly meetings with the IRP Advisory
5 Council and following the completion of the plan by way of
6 the Commission's public comment period.
7 A new IRP is created every two years and it is
8 common for a resource to be evaluated in two or three IRP
9 cycles before it reaches the point of being considered a
10 "committed" resource. In addition, before building a new
11 resource, an application is filed with the Commission
12 requesting a Certificate of Public Convenience and
13 Necessity ("CPCN"). During this process, the proposed
14 resource is again scrutinized by the Commission and the
15 public is allowed to provide comments.
16 In the case of Langley Gulch, a 300 MW combined
17 cycle combustion turbine ("CCCT"), the need for this new
18 resource was identified as early as Idaho Power's 2004 IRP.
19 In the 2004 and 2006 IRPs, this resource was identified as
20 a coal plant, and it was not until 2007 that it was changed
21 to a natural gas CCCT. Between the IRP and CPCN processes,
22 Langley Gulch was evaluated and scrutinized for over five
23 years before the CPCN was granted for the addition of this
24 300 MW resource.
25
467
STOKES, DI 25
Idaho Power Company
1 In contrast, Idaho Power was obligated to sign PURPA
2 wind contracts totaling 294 MW during a two-month period in
3 late 2010 without any evaluation or thought given to
4 whether these wind resources were needed, or how they would
5 impact customer rates or the reliable operation of Idaho
6 Power's electrical system. In addition, the only
7 opportunity for the public to comment was during the
8 Commission approval process for the power purchase
9 agreements, which primarily focuses on whether the
10 established rules and prior Commission orders regarding
11 PURPA were followed.
12 IV. CURRENT APPLICATION OF THE SAR AND IRP METHODOLOGIES ' 13 Q. Could you describe the methods currently
14 utilized in Idaho to establish avoided cost rates?
15 A. Yes. The Commission currently utilizes two
16 methodologies for determining avoided cost: the SAR- and
17 IRP-based methodologies.
18 Q. What determines a QF's eligibility for rates
19 determined by the two different methodologies?
20 A. The determination of which methodology is used
21 has historically been based on the size of the QF project,
22 and has recently been further differentiated by not only
23 size but also resource type. Until recently, all QF
24 projects that generated up to 10 aMW monthly were eligible • 25 for published rates established by the SAR methodology.
468
STOKES, DI 26
Idaho Power Company
1 Correspondingly, all QF projects over 10 aMW were only
2 eligible for negotiated rates based upon the IRP
3 methodology.
4 In Order No. 32262 from Phase II of this proceeding,
5 the Commission determined that the eligibility cap for
6 published rates based on the SAR methodology for wind and
7 solar QFs remain at 100 kW. Consequently, the IRP-based
8 methodology is currently applicable to all QFs over 10 aMW
9 and all wind and solar QFs over 100 M.
10 A. SR Methodology.
11 Q. Could you describe the SAR methodology?
12 A. Yes. As its name implies, the SAR methodology
13 estimates avoided cost by estimating the cost of a
14 surrogate avoided resource which, at present, the
15 Commission has determined is a natural gas-fired CCCT. The
16 SAR methodology uses that cost to set published, or
17 standard, avoided cost rates. Published, or standard,
18 rates are required by Federal Energy Regulatory Commission
19 ("FERC") for projects up to 100 kW.
20 The SAR methodology consists of two primary cost
21 components: (1) the fuel cost component and (2) the non-
22 fuel variable cost components. The fuel cost component
23 simply utilizes the long-term natural gas price forecast
24 produced by the Northwest Power and Conservation Council
25 ("NPCC") . The avoided cost prices established by the SAR
469 STOKES, DI 27
Idaho Power Company
1 model are adjusted by the Commission whenever the NPCC
2 revises its long-term natural gas price forecast.
3 The non-fuel variable components of the SAR
4 methodology include the capital cost component of the CCCT,
5 other fixed and variable operating costs, and escalation
6 rates that are applied over time. The non-fuel variables
7 are further divided into two general categories: (1)
8 utility-specific variables and (2) generic variables.
9 Utility-specific variables relate to each utility's cost of
10 capital. Because they are a direct outcome of qeneral rate
11 cases, they are updated after a utility rate case with a
12 resulting change in the utility's cost of capital.
0 13 The other generic variables are updated periodically
14 and were most recently examined and updated in 2009, Case
15 No. GNR-E-08-02. In that case, the Commission approved a
16 stipulation between the utilities, Commission Staff, and
17 several QF developers as to a revision of the non-fuel
18 variables in the SAR methodology. The generic non-fuel
19 variables, or the non-fuel related SAR costs, are: heat
20 rate, equivalent availability factor, capital cost,
21 variable operations and maintenance ("O&M"), O&M escalation
22 rate, SAR escalation rate, fixed O&M, and general
23 inflation.
24 The SAR methodology produces two different sets of
25 avoided cost rates, one for "fueled" projects that utilize
470 STOKES, DI 28
Idaho Power Company
1 fossil fuels, and one for "non-fueled" projects that apply
2 for all other resource types. The avoided cost rates for
3 "fueled" projects are adjusted annually based on the
4 average monthly gas price during the previous calendar
5 year. Therefore, the rates change each year and track with
6 natural gas prices. The "non-fueled" rates are based on an
7 initial price from the NPCC's most recent medium gas price
8 forecast, which is then escalated at a uniform rate
9 throughout the term of the contract. Under this method,
10 the avoided cost rate for the entire term of the contract
11 is known at the time the contract is signed.
12 B. IRP Methodology. . 13 Q. Could you please describe the current IRP
14 methodology?
15 A. Yes. On December 15, 2011, as part of the
16 present proceeding, the three utilities gave a presentation
17 for the parties to this case at the Commission regarding
18 the present application of the IRP methodology. The
19 components of the methodology were described, and the
20 methodology was demonstrated on four example QF resources
21 to produce sample avoided cost rate calculations. Idaho
22 Power's December 15, 2011, presentation is attached as
23 Exhibit No. 3.
24 The IRP methodology consists of three components: • 25 (1) the avoided cost of energy, (2) the avoided cost of
471
STOKES, DI 29
Idaho Power Company
1 capacity, and (3) an integration cost for variable and
2 intermittent resources. The avoided cost of energy is
3 calculated using the AURORA electric market model, which is
4 also used to make future resource decisions in the IRP.
5 The total portfolio cost of a "Base Case," which includes
6 the preferred resource portfolio from the IRP, is compared
7 to a "Study Case," which includes the same IRP preferred
8 portfolio with the PURPA resource added. The difference in
9 the total portfolio cost of these two cases, on a monthly
10 basis, is divided by the MWh of generation from the PURPA
11 resource to establish an avoided cost of energy in dollars
12 per MWh. This establishes the avoided cost of energy
S 13 component.
14 Q. How is the avoided cost of capacity calculated
15 in the IRP methodology?
16 A. To determine the avoided cost of capacity, the
17 capital or fixed cost of a CCCT (taken from the IRP) is
18 used as the surrogate resource that Idaho Power would avoid
19 building. The cost in dollars per kilowatt-month for the
20 CCCT is first multiplied by the nameplate capacity of the
21 PURPA resource and then converted to an annual cost by
22 multiplying by 12. This cost is then multiplied by the
23 peak-hour capacity factor of the PURPA resource to account
24 for the amount of capacity the PURPA resource will provide • 25 during Idaho Power's peak-hour load period between 3:00
472
STOKES, DI 30
Idaho Power Company
1 p.m. and 7:00 p.m. in July. Due to the uncertain and
2 variable nature of intermittent resources, a 90 percent
3 exceedance capacity factor calculated from representative
4 projects in Idaho Power's service territory is used as a
5 benchmark. If the peak-hour generation of the PURPA
6 resource exceeds the generation of the benchmark resource
7 for that period, the PURPA resource will receive a
8 proportionally higher peak-hour capacity factor that is
9 used to calculate the avoided cost of capacity. Likewise,
10 if the PURPA resource provides less generation than the
11 benchmark resource during the peak-hour period, the PURPA
12 resource will receive a proportionally lower peak-hour
13 capacity factor.
14 While baseload resources such as biomass and
15 geothermal may be capable of producing 100 percent of
16 nameplate during the peak-hour period, forced outages
17 remain a possibility. Therefore, applicable forced outage
18 rates taken from the NPCC's Sixth Power Plan are used to
19 derive the peak-hour capacity factor for these types of
20 resources in calculating the avoided cost of capacity. For
21 all resource types, the resulting avoided cost of capacity
22 is held constant for all months of the year in the
23 analysis.
24 The avoided cost of energy and the avoided cost of • 25 capacity are then added together to get a monthly avoided
473
STOKES, DI 31
Idaho Power Company
1 cost rate. However, the avoided cost of capacity is
2 excluded until the first month Idaho Power's load and
3 resource balance shows a peak-hour deficit based on
4 existing and committed resources as identified in the IRP.
5 Also, for wind and solar PURPA resources, a deduction to
6 the avoided cost of energy is applied to account for the
7 cost of integrating these variable and intermittent
8 resources.
9 Q. Do you have current examples of the rates
10 calculated using the IRP methodology?
11 A. Yes. As part of the December 15, 2011,
12 presentation, Idaho Power evaluated four sample QF projects
' 13 using the IRP methodology. Details of the evaluation and
14 the results are presented in Exhibit No. 3. The avoided
15 cost rates were calculated for 10 aMW generation resources
16 consisting of: (1) base load (geothermal, biomass,
17 anaerobic digesters, and co-generation), (2) canal drop
18 hydro, (3) fixed photovoltaic ("PV") solar, and (4) wind.
19 As can be seen in Exhibit No. 3 the resulting 20-
20 year, levelized avoided cost rate in dollars per MWh for
21 each resource is: (1) base load (geothermal, biomass,
22 anaerobic digesters, and co-generation) - $65.00, (2) canal
23 drop hydro - $80.31, (3) fixed PV solar - $75.60, and (4)
24 wind - $43.08.
•25
474 STOKES, DI 32
Idaho Power Company
1 Q. What assumptions were used in the AURORA model
2 to determine the avoided cost of energy for the sample
3 projects?
4 A. Prior to preparing each IRP, Idaho Power
5 updates and calibrates the AURORA model. The sample
6 avoided cost of energy calculations were performed using
7 the same AURORA model setup used for the Company's latest
8 planning document, the 2011 IRP, with three exceptions.
9 First, Idaho Power prepares a load forecast on an
10 annual basis which is typically finalized in September of
11 each year. Because the load forecast is one of the
12 earliest items required in the preparation of the IRP, the
' 13 load forecast used in the 2011 IRP was completed in
14 September of 2010. In September of 2011, the Company
15 prepared a new load forecast as is typically done for the
16 IRP process. The updated load forecast provides current
17 expectations of future load growth which have been in a
18 state of flux due to the economic recession over the past
19 few years. Because the updated load forecast is based on
20 the most current information, Idaho Power believes it
21 should be used in any evaluation and analysis work the
22 Company does, including the calculation of avoided cost
23 rates. Therefore, the avoided cost of energy in the sample
24 calculations were performed with the AURORA model using the
25 most current load forecast.
STOKES, DI 33
Idaho Power Company
1 Second, the forecast of natural gas prices must also
2 be determined early in the preparation of the IRP. The
3 natural gas price forecast used in the 2011 IRP was
4 finalized in August of 2010, and since that time natural
5 gas prices and forecast future prices have dropped
6 considerably. Therefore, the Company used the most current
7 natural gas price forecast prepared by the NPCC in the
8 AURORA model to calculate the avoided cost of energy for
9 the sample projects.
10 Third, a carbon adder is used in the AURORA model
11 for the IRP analysis to evaluate the risk, impact, and
12 costs of various levels of carbon regulation. Because of
S 13 the uncertainty in what future carbon costs may be, if any,
14 Idaho Power does not believe it is appropriate to include
15 these costs in the AURORA model for the purpose of
16 calculating the avoided cost of energy. While appropriate
17 for purposes of evaluating future resource acquisitions in
18 the IRP process, these potential carbon costs do not exist
19 today, and would be inappropriate to include in the avoided
20 cost analysis. Therefore, no carbon adder was used in the
21 AURORA model to calculate the avoided cost of energy for
22 the sample calculations.
23
24
25
476 STOKES, DI 34
Idaho Power Company
. 1 V. THE IRP BASED-METHODOLOGY SHOULD BE USED
2 FOR ALL AVOIDED COST RATES
3 Q. Does the Company have a recommendation for the
4 Commission with regard to the continued use of the SAR
5 methodology?
6 A. Yes. The Company recommends that the
7 Commission abandon the use of the SAR methodology to
8 determine a utility's avoided cost and instead use the IRP-
9 based avoided cost methodology for all QF projects, and for
10 published as well as negotiated rates.
11 Q. Is this position consistent with Idaho Power's
12 submissions in Phase I, GNR-E-10-04, and Phase II, GNR-E-
13 11-01?
14 A. Yes. In both to this prior phases proceeding,
15 Idaho Power has asked for the IRP methodology to be applied
16 to the avoided cost calculation for all QF generation.
17 Idaho Power has stressed and reiterated the severe problems
18 with the current SAR methodology and 10 aMW published rate
19 eligibility in the Joint Petition of the three utilities,
20 in Idaho Power's Comments, and in its Reply Comments in
21 Case No. GNR-E-10-04, all of which are incorporated herein
22 by this reference. Those problems and issues are also
23 discussed in my Direct and Rebuttal Testimony as submitted
24 in Case No. GNR-E--11-01, which are also incorporated herein
25 by this reference. These problems have not gone away, and
. 77 STOKES, DI 35
Idaho Power Company
1 continue to have a substantial negative impact on
2 customers. Those problems include:
3 1. The continuing and unchecked
4 requirement for the Company to acquire QF generation,
5 pursuant to avoided cost rates, with no regard for the
6 Company's need for additional generation on its system, nor
7 the availability of other lower cost resources, and in a
8 manner inconsistent with the definition of avoided cost;
9 2. Circumvention of the Company's required
10 IRP planning process and a continuing requirement to
11 acquire generation outside of that established process that
12 inflates customers' power supply costs;
. 13 3. System reliability and other
14 operational issues caused by a rapid and large scale
15 increase in intermittent and unreliable generation sources;
16 and
17 4. Most importantly, a dramatic increase
18 in the price that Idaho Power's customers must pay for
19 their energy needs as a direct result of the large
20 quantities of additional QF generation at prices in excess
21 of the Company's avoided cost, and beyond that which would
22 otherwise be considered prudent.
23 Q. What does the Company mean by "beyond that
24 which would otherwise be considered prudent"?
25
478
STOKES, DI 36
Idaho Power Company
1 A. The addition of large quantities of QF
2 generation such as those currently facing the Company, the
3 majority of which are variable and intermittent in nature,
4 is inconsistent with its least-cost IRP planning process,
5 and it creates operational and reliability issues. It also
6 forces the Company to make uneconomic decisions, or to
7 engage in negative economic transactions.
8 It is good utility practice to have diversity among
9 generation resources, but too much of any single resource
10 creates challenges. From an operational perspective, Idaho
11 Power has reached or is nearing a saturation point with
12 adding intermittent, variable generation to its resource
. 13 portfolio. This and other operational issues are discussed
14 further in the testimony of Company witness Tessia Park.
15 Q. Do you believe the SAR Methodology calculates
16 an accurate avoided cost rate?
17 A. No. A utility-owned CCCT will be economically
18 dispatched and will only be run when needed for system
19 reliability or when the market price of energy is more than
20 the variable operating cost of the plant. On the other
21 hand, a PURPA project is incented to generate as much
22 electricity as possible because the avoided cost rate
23 calculated by the SAR methodology will almost always be
24 higher than the variable cost of operating the plant.
•25
STOKES, DI 37
Idaho Power Company
1 The SAR methodology assumes the PUPRA resource will
2 have a 90 percent annual capacity factor, while Idaho
3 Power's new Langley Gulch CCCT is expected to have an
4 annual capacity factor of about 60 percent. This results
5 in the PURPA resource generating substantial additional
6 amounts of energy, all at times when a utility-owned CCCT
7 would not be dispatched because of economics.
8 Q. Can you provide a comparison of the cost of a
9 utility-owned CCCT to the avoided cost rate calculated by
10 the SAR methodology?
11 A. Yes. The Company has prepared a comparison of
12 the expected cost of the Langley Gulch CCCT to the current
. 13 avoided cost rates calculated with the SAR methodology.
14 As previously stated in my testimony, an important
15 input into the levelized cost of production calculation for
16 a generation resource is the assumed level of annual
17 capacity utilization or capacity factor over the life of
18 the resource. A capacity factor of 50 percent would
19 suggest that over a project's lifetime, it would be
20 expected to produce 50 percent of the output that it could
21 have produced if it had operated every hour at its rated
22 capacity. Therefore, at a higher capacity factor, the
23 levelized cost will be less because the plant would
24 generate more MWh over which to spread the fixed costs.
•25
480 STOKES, DI 38
Idaho Power Company
1 Conversely, lower capacity factor assumptions reduce the
2 MWh and the levelized cost is higher.
3 For PURPA QF projects, the published avoided cost
4 rate determined by the SAR methodology is based on the
5 levelized cost of a CCCT (the same type of plant as Langley
6 Gulch) at an assumed capacity factor of 90 percent. The
7 current 20-year, levelized published avoided cost rate for
8 a QF project coming on-line in 2013 is $70.92 per MWh.
9 The estimated 20-year, levelized cost of Langley
10 Gulch is $68.55 per MWh using a 90 percent capacity factor
11 assumption (to be consistent with the SAR capacity factor
12 assumption), and Idaho Power's current natural gas price . 13 forecast. This comparison indicates the current SAR
14 published avoided cost rate is $2.37 per MWh higher than
15 Langley Gulch. In other words, over the next 20 years,
16 Idaho Power's customers will be paying $2.37 per MWh more
17 for PURPA QF generation than what it would cost Idaho Power
18 to produce at Langley Gulch.
19 In addition, Idaho Power's customers will be paying
20 $2.37 per MWh more for resources that provide little if any
21 capacity during peak-hour summer load periods. Langley
22 Gulch on the other hand will be fully available to serve
23 customer needs during these times.
24 Langley Gulch will also only be run when Idaho Power • 25 needs the energy to serve load or when it is economical to
481 STOKES, DI 39
Idaho Power Company
1 make surplus sales in the market. Idaho Power has the
2 ability to operate Langley Gulch in this fashion because it
3 is dispatchable. QF resources on the other hand are not
4 dispatchable and are incented to provide as much energy as
5 possible at the published avoided cost rate, much of which
6 will have to be sold at a loss. Therefore, the total cost
7 of the PURPA resource is much greater than the total cost
8 of a utility-owned CCCT.
9
Q. What do you think is the root cause of the
10 problems with using the SAR methodology to set avoided cost
11 rates?
12 A. First, the SAR Methodology does not correctly
0
13 model the operation of a PURPA resource because it assumes
14 the resource is operated at a very high annual capacity
15 factor. However, this is much different than the way a
16 utility would economically dispatch a CCCT. The fact that
17 PURPA resources are not dispatchable creates a large
18 difference in the value or total cost.
19 Second, seasonal and heavy/light load pricing
20 adjustments have been made in recent PURPA contracts to try
21 to incent PURPA resources to deliver energy at times when
22 it is more valuable. However, the SAR methodology does not
23 value the energy at the times it is delivered to the
24 utility.
.
25
482
STOKES, DI 40
Idaho Power Company
1 Third, resources are not interchangeable. Wind
2 turbines are not equal to combined cycle combustion
3 turbines. Different types of generation resources have
4 different operating characteristics and the differences in
5 operational characteristics have different values to a
6 utility. Some characteristics may permit the utility to
7 avoid certain costs while the characteristics of other
8 resources may actually burden the utility with additional
9 costs.
10 Fourth, the SAR methodology is static and only
11 updated periodically, and the published avoided cost rate
12 does not change as resources are added to the utility's • 13 portfolio.
14 Q. Why should the IRP methodology be used for
15 setting all avoided cost rates?
16 A. The primary reason the IRP methodology is
17 better than the SAR methodology is that the IRP methodology
18 places a more appropriate value on the energy a QF project
19 delivers based on the time it is delivered to the utility.
20 Solar resources tend to receive higher overall pricing
21 because energy is primarily delivered during the heavy load
22 hours of the day when energy prices and load are typically
23 higher. Resources that deliver more energy during light
24 load hours (nighttime, Sundays, and holidays) will see
25 reduced avoided cost rates that account for the lower value •
483 STOKES, DI 41
Idaho Power Company
1 of the energy that is delivered during these periods. In
2 addition, the IRP methodology is able to assign pricing
3 down to a much smaller time frame, which allows a better
4 estimate of the actual value of the energy.
5 The IRP methodology is also significantly more
6 flexible than the SAR methodology and can be updated more
7 frequently as conditions and assumptions change. As
8 utilities prepare IRPs every two years, the models used to
9 calculate energy prices in the IRP methodology are also
10 updated to account for the most current forecasts of load,
11 natural gas prices, and other factors that influence the
12 market value of energy. The IRP methodology also allows . 13 for the model to be updated as each incremental resource is
14 added to a utility's generation portfolio.
15 Q. From an administrative ease perspective, would
16 it be better to continue to use the SAR methodology to set
17 published avoided cost rates?
18 A. No. When viewing the proposals in my
19 testimony in aggregate, it is evident that continuing to
20 use the SAR methodology actually creates additional
21 administrative burden. One only has to review the case
22 history regarding the application of the SAR methodology
23 and disputes over updating the inputs used in the
24 methodology to realize it would create a burden to continue • 25 using the SAR methodology with its only purpose being to
484
STOKES, DI 42
Idaho Power Company
1 set published rates. Published avoided cost rates could be
2 set using the IRP methodology in the same manner Idaho
3 Power is proposing to establish negotiated rates for QF
4 contracts.
5 Q. How are you proposing the IRP methodology be
6 used to set published avoided cost rates?
7 A. As each utility prepares an IRP every two
8 years, the IRP methodology could be used to calculate
9 avoided cost rates for sample projects as was done for the
10 parties in this case and presented on December 15, 2011.
11 These rates would then become the published rate for each
12 type of resource for the next two years until the next IRP
13 was completed.
14 Q. Does your proposal also include a
15 recommendation regarding the eligibility cap for published
16 avoided cost rates?
17 A. Yes. In Phase II of these proceedings
18 (GNR-E-11-01), the Commission maintained the eligibility
19 cap for wind and solar QF resources at 100 kW, while
20 published rates remained available to all other QF resource
21 types up to 10 aNW. Idaho Power's recommendation is that
22 the eligibility cap for all QF resources be set at 100 kW.
23 Q. Why do you think it is important to set the
24 eligibility cap at 100 kW for all QF resources?
25
485 STOKES, DI 43
Idaho Power Company
1 A. If the IRP methodology is used to establish
2 both published rates and rates for negotiated contracts,
3 the rates should remain similar as long as the assumptions
4 and forecasts used for the IRP remain valid. For
5 negotiated contracts (projects larger than the eligibility
6 cap), the utility would have the ability to update the
7 assumptions or forecasts as warranted. However, for the
8 published rate, a correction may not be possible until the
9 next IRP is completed, which could be as long as two years.
10 Therefore, setting the eligibility cap at 100 kW for all
11 resource types would minimize the risk to customers of
12 paying higher than avoided cost rates due to unforeseen
0 13 circumstances or events.
14 VI. RECOMMENDATION TO ESTABLISH AN AUTHORIZED
15 NEGOTIATION PROCESS AND PROCEDURE
16
17 Q. Does Idaho Power have a recommendation
18 regarding the establishment of an authorized negotiation
19 process and procedure by which a PURPA QF can obtain a
20 power purchase agreement with Idaho Power?
21 A. Yes. In the recent past there have been
22 numerous issues surrounding a QF developer's
23 "grandfathered" rights to published avoided cost rates that
24 have been superseded in the normal course of updating the
25 rate. Even more recently, issues regarding a determination
26 of the point in time when a utility has a legally
486
STOKES, DI 44
Idaho Power Company
1 enforceable obligation as to price and other terms in a QF
2 contract have been disputed.
3 In order to resolve these issues and disputes going
4 forward, Idaho Power recommends the Commission establish
5 formal processes and procedures that will eliminate any
6 future questions surrounding these issues. Idaho Power
7 recommends that this be done through the development and
8 implementation of a PURPA QF contraction process and
9 negotiation tariff schedule.
10 VII. CONTRACT TERM
11 Q. Does Idaho Power have a recommendation for the
12 Commission with regard to the maximum authorized contract
13 term for a PURPA QF power purchase agreement?
14 A. Yes. The Company recommends that the
15 presently authorized maximum contract term of 20 years be
16 reduced to 5 years. A contract term of 20 years containing
17 a fixed price schedule shifts market price risk from the
18 project developer/owner entirely onto Idaho Power's
19 customers. By locking in a single fixed price or a
20 schedule of fixed prices, PURPA projects are hedging the
21 variable market value of the energy for the fixed prices
22 contained in the contract, at the expense of Idaho Power's
23 customers. While there is a need to provide a schedule of
24 fixed prices in the contract, 20 years is simply too long
25 given the amount of change that can take place and the
487 STOKES, DI 45
Idaho Power Company
1 amount of risk this brings to customers. This is further
2 addressed in the direct testimony of witness William
3 Hieronymus.
4 Q. Do you have any concluding remarks?
5 A. Idaho Power respectfully urges the
6 Commission to set the published rate eligibility cap at 100
7 kW for all QF resource types and allow both published
8 avoided cost rates and negotiated avoided cost rates to be
9 determined using the IRP methodology as described
10 previously in my testimony and with the modifications
11 proposed by Company witness Bokenkamp.
12 While the application of the IRP methodology with
. 13 the proposed modifications appears complicated at first,
14 Idaho Power believes it is the best method for determining
15 avoided cost rates that are aligned with the Federal Energy
16 Regulatory Commission's definition of a utility's avoided
17 cost. Prior to proposing the continued use of the IRP
18 methodology with modifications, Idaho Power has thoroughly
19 tested the methodology and found it to actually be less of
20 an administrative burden than the current application of
21 the IRP methodology.
22 Idaho Power also urges the Commission to establish
23 an authorized negotiation process and procedure that will
24 govern the contract negotiation process. This will
25 eliminate future disputes over issues regarding
488 STOKES, DI 46
Idaho Power Company
1 "grandfathering," the determination of when a legally
2 enforceable obligation exists, and the applicable stream of
3 prices that should be included in any contract.
4 Finally, in order to limit the risk customers are
5 exposed to through longer-term contracts, Idaho Power urges
6 the Commission to reduce the standard contract term from 20
7 years to five years. Idaho Power believes all of these
8 proposed changes will resolve several problems that exist
9 with the current implementation of PURPA in the state of
10 Idaho, and protect utility customers from further harm.
11 Q. Does this conclude your testimony?
12 A. Yes.
15
16
17
18
19
20
21
22
23
24
. 25
489 STOKES, DI 47
Idaho Power Company
1 Q. Please state your name and business address.
2 A. My name is M. Mark Stokes and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q. Are you the same M. Mark Stokes that submitted
5 direct testimony in this proceeding?
6 A. Yes, I am.
7 Q. What is the purpose of your rebuttal
8 testimony?
9 A. In my rebuttal testimony, I will address the
10 following items:
11 1. I will respond to recommendations to
12 change the source of the natural gas price forecast used to
13 set avoided cost rates. In addition, I will discuss the
14 sensitivity of each of the avoided cost methodologies to
15 changes in natural gas prices.
16 2. I will respond to statements made by
17 others in direct testimony supporting the continued use of
18 the Surrogate Avoided Resource ("SAR") methodology and
19 provide additional information supporting my recommendation
20 to abandon the use of the SAR methodology.
21 3. I will respond to questions raised by
22 others in direct testimony regarding Idaho Power Company's
23 ("Idaho Power" or "Company") proposed Hourly Incremental
24 Cost methodology and provide additional support for the • 25 adoption of this methodology to set avoided cost rates.
490
STOKES, REB
Idaho Power Company
1 4. I will also respond to recommendations
2 made by others regarding contract term, the published rate
3 eligibility cap, the avoided cost of capacity and energy,
4 the use of a carbon adder in avoided cost rate
5 calculations, the security deposit for liquidated damages,
6 and the need to litigate Integrated Resource Plans ("IRP")
7 5. I will describe why the electric
8 utilities that purchase energy from a Qualifying Facility
9 ("QF") should also receive the associated environmental
10 attributes and/or Renewable Energy Credits ("RECs")
11 associated with the purchase of that energy.
12 6. Finally, I will present Idaho Power's
13 proposed Schedule 73 to address the QF contracting process.
14 I. NATURAL GAS PRICE FORECAST
15 Q. Several parties have filed testimony in
16 support of using a natural gas price forecast developed by
17 the Energy Information Administration ("EIA") in the
18 calculation of avoided cost rates. Do you support this
19 recommendation?
20 A. Yes. I believe using the EIA forecast and
21 updating it annually in July of each year is a step in the
22 right direction. However, it does not resolve the
23 underlying problem that the natural gas price forecast
24 assumption has too significant of an impact on the avoided • 25 cost rates produced by the SAR methodology.
491
STOKES, REB 2
Idaho Power Company
1 In addition, current and near-term market prices for
2 natural gas are approximately half of the EIA forecast
3 presented in Exhibit No. 301 of the Direct Testimony of
4 Idaho Public Utilities Commission Staff ("Staff") witness
5 Cathleen McHugh. This EIA forecast was released in January
6 2012 and is already off by approximately 50 percent in the
7 near term. This highlights the underlying problem that the
8 avoided cost rates can become out of date rather quickly
9 and, further, avoided cost rates determined using the SAR
10 methodology compound this problem because they are overly
11 sensitive to the natural gas price assumption used in the
12 model. In addition to establishing a better, more accurate
13 source for the natural gas price forecast, I believe it
14 would be of greater benefit to adopt an avoided cost
15 methodology that is less sensitive to the natural gas price
16 assumption, such as the Hourly Incremental Cost methodology
17 proposed by Idaho Power.
18 Q. Do you have any proposed modifications to
19 Staff's recommendation to use the EIA gas forecast and
20 update it annually in July of each year?
21 A. Yes. EIA releases an annual natural gas price
22 forecast in the spring of each year. In addition, during
23 the interim months between EIA's annual forecast, EIA
24 releases a short-term forecast. Idaho Power recommends • 25 that the short-term forecast also be adopted. This will
492 STOKES, REB 3
Idaho Power Company
1 help to somewhat address the problem identified earlier in
2 my testimony where I describe how the EIA annual forecast
3 can rapidly become outdated and inaccurate in a rapidly
4 shifting natural gas market. As previously noted, the EIA
5 gas forecast released in January 2012 is already more than
6 50 percent off in the near term. By incorporating EIA's
7 monthly updates, this inaccuracy can be somewhat mitigated
8 on a monthly basis, rather than allowing an entire year to
9 pass with the corresponding inaccuracy transferred to
10 avoided cost rates.
11 Q. Is the Hourly Incremental Cost methodology
12 proposed by Idaho Power in this case less sensitive to . 13 changes in the natural gas price forecast than the SAR
14 methodology?
15 A. Yes, it is. Idaho Power has compared the gas
16 price sensitivity of the SAR methodology and Idaho Power's
17 Hourly Incremental Cost methodology. Both methodologies
18 were used to calculate avoided cost rates for a base load
19 resource using Idaho Power's 2011 IRP natural gas price
20 forecast (August 2010), the Northwest Power and
21 Conservation Council's updated forecast (August 2011), the
22 EIA forecast (January 2012), and current NYMEX forward
23 prices. This series of natural gas price forecasts
24 occurred over a time period where prices were falling and • 25 are shown in the following figure.
493
STOKES, REB 4
Idaho Power Company
S
CD $500
0
80 $4.00
$3.00
$8.00
$7.00
$6.00
$2.00
$1.00
Gas Price Forecasts (Sumas)
r
$oo0 r-r
1 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
2 The results of this comparison are provided in the
3 figure below and show the 20-year, levelized avoided cost
4 rates from the SAR methodology vary from $80.43 to $62.18
5 (23 percent) and the Hourly Incremental Cost methodology
6 varies from $52.42 to $42.88 (18 percent)
Natural Gas Price Sensitivity Analysis
I $80.43
$80 4-
$79 -_$6Loo........$67.n .................................................................................... -
$62.18
$60
$52.42
5".78 $42.88
tJ $iio -- -.. -
- - --..-
$10 -i---- - - -
$0 ... ........... ............I.......- ...--
2011 IRP NPCC Updated EIA 2012 Early IPC Forwards 2011 . IRP NPCC Updated
.
E1A2012 Early IPC Forwards
I Expected Case Forecast (Aug Release USIngNYMEX Expected Case Forecast(Aug Release USIngNYMEX
2011) (M"--) 2011) (M"2022)
SAR Hourly Incremental Cost Methodology
Notes: SAR model run using Surnas natural gas forecast
7 t Hourly Incremental Cost Methodology using April 2012 load forecast and no carbon
494
STOKES, REB 5
Idaho Power Company
1 These results show that the SAR methodology is more
2 sensitive to the natural gas price assumption than Idaho
3 Power's proposed Hourly Incremental Cost methodology.
4 Natural gas prices have historically been the most volatile
5 of all the inputs used to set avoided cost rates. Using a
6 methodology that is less sensitive to the gas price
7 forecast will likewise reduce the volatility of avoided
8 cost rates.
9 II. SR METHODOLOGY
10 Q. Do you agree with the statement made by Dr.
11 Don Reading that avoided cost rates calculated using the
12 SAR methodology "have been remarkably accurate in
. 13 hindsight." (Reading Direct, p. 7, 1. 8.)
14 A. No, I do not. As I stated in my direct
15 testimony, historically there has been a significant
16 difference between the prices paid to QF resources on Idaho
17 Power's system and the Mid-C market index to the direct and
18 substantial detriment of Idaho Power's customers and, on a
19 forward looking basis, there continues to be a significant
20 difference between QF prices and the Mid-C forward market
21 price. This difference is illustrated in the following
22 figure:
23
24
•25
495
STOKES, REB 6
Idaho Power Company
lu
1
Average PURPA Price Compared to Mid-C Index
2002-2022
90
80
70
60
50 -c
40
30
20
10
0
8 o 8 8 8 r1 r.l (N (N
-Average Mid-C Index
00 0 (N 00 0 (N
0 0 0 0 0 0 0 0 0 (N (N (N (N (N (N (N (N (N
- PURPA Price - - Est. PURPA Price - - Mid-C Forwards
~ 0
r L
2 While the Mid-C index does not represent an avoided
3 cost rate, it does highlight the harm done to Idaho Power's
4 customers when Idaho Power has excess QF energy which must
5 be sold into the market at a substantial loss.
6 Q. Why do you believe avoided cost rates
7 determined by the SAR methodology are not accurate?
8 A. The concerns I have are not limited to the SAR
9 methodology, but any proxy method, which is why I believe
10 the SAR methodology should be abandoned and not just
11 modified, as recommended by others in this proceeding.
12 The SAR methodology is currently based on the
13 estimated cost of a utility building, owning, and operating
14 a combined-cycle combustion turbine ("CCCT"), and does not
15 account for all of the unique characteristics of the
16 various types of QF resources, including the availability
496
STOKES, REB 7
Idaho Power Company
1 of generation during system peak loads. In addition, the
2 methodology does not take into consideration that QF
3 resources are not economically dispatched in the same
4 fashion as utility-owned resources as under the Public
5 Utility Regulatory Policies Act of 1978 ("PURPA"), Idaho
6 Power has a "must purchase" obligation. For these reasons,
7 the product a QF resource delivers is very different from
8 the product produced by a utility-owned resource such as a
9 CCCT, and is not as valuable to the utility with its
10 obligation to serve load in a least-cost, reliable manner.
11 The high rates produced by the SAR methodology and
12 the subsidies available to many QF developers in the form . 13 of investment and production tax credits as well as
14 renewable energy certificates are the primary drivers in
15 why Idaho Power has recently seen a landslide in QF
16 development. While the Idaho Public Utilities Commission
17 ("Commission") cannot control state and federal subsidies
18 and tax incentives, it can remove some of the financial
19 incentive which is harming Idaho Power customers, and was
20 never the purpose nor intent of PURPA, by abandoning the
21 SAR methodology completely.
22 Q. Do you have any other basis for Idaho Power's
23 recommendation that the SAR methodology be abandoned for
24 the purposes of calculating Idaho Power's avoided cost • 25 rates paid to PURPA QFs?
497
STOKES, REB 8
Idaho Power Company
1 A. Yes. Based upon Idaho Power's direct
2 testimony, and its March 12, 2012, Motion for a Temporary
3 Stay of its Obligation to Enter into New Power Purchase
4 Agreements with Qualifying Facilities filed in this matter,
5 the Commission made findings "that the methodologies
6 previously approved by this Commission, as utilized and
7 applied by Idaho Power, do not currently produce rates that
8 reflect Idaho Power's avoided cost and are not just and
9 reasonable, nor in the public interest." Order No. 32498.
10 Idaho Power believes that based upon its system
11 configuration, costs, and operations - including the large
12 amount of PURPA generation that currently exists on its
13 system - that the SAR methodology is no longer capable of
14 providing rates that are just and reasonable, nor in the
15 public interest. The resulting rates from the SAR
16 methodology do not result in rates that hold Idaho Power's
17 customers indifferent as to whether they are paying for
18 power generated by a QF or that which is otherwise
19 generated or acquired by the Company. While it may, or may
20 not, be appropriate to continue the use of the SAR
21 methodology for Idaho's other investor-owned utilities, it
22 is no longer appropriate to continue its use for Idaho
23 Power for the reasons set forth by Idaho Power in this
24 proceeding.
25
498
STOKES, REB 9
Idaho Power Company
1 Q. Several witnesses in this case have filed
2 testimony advocating the continued use of the SAR
3 methodology because of its transparency and simplicity. Do
4 you agree with this?
5 A. No, I do not. I believe these statements were
6 made only because the SAR methodology has been used for a
7 long period of time in Idaho and people have become
8 familiar with it. Just because the SAR methodology has
9 been used in Idaho for a number of years does not
10 necessarily mean that the methodology is transparent or
11 simple. In a recent Public Utility Commission of Oregon
12 case involving avoided cost rates, Public Utility
. 13 Commission of Oregon staff rejected the SAR methodology on
14 the basis of its complexity and lack of transparency,
15 particularly the tilting rate capital calculation contained
16 in the model.
17 Q. On page 8 of his direct testimony, Dr. Reading
18 references a National Economic Research Associates ("NERA")
19 survey that is mentioned in the Direct Testimony of Idaho
20 Power witness William Hieronymus. What conclusion does Dr.
21 Reading make regarding this survey?
22 A. Dr. Reading points out that the survey results
23 showed 14 states out of 49 surveyed used some form of the
24 proxy method. Dr. Reading's conclusion from this data is
25
STOKES, REB 10
Idaho Power Company
0
.
1 that it "indicates the SAR method is widely accepted as
2 valid method [sic] for determining avoided cost rates."
3 Q. Do you agree with Dr. Reading's conclusion?

4 A. No, for two primary reasons. First, the
5 survey was regarding the use of a proxy method, not the
6 specific SAR methodology as it has been used in Idaho. Dr.
7 Reading makes a big leap to get to his conclusion that the
8 SAR methodology is somehow valid because a few states use
9 some form of a proxy method. Second, while the survey does
10 indicate some states use a form of the proxy method (14 out
11 of 49 or 29 percent), it can also be stated that 35 out of
12 49 states (or 71 percent) have chosen other methodologies
13 for determining avoided cost rates. Dr. Reading chooses to
14 ignore this conclusion, which is in fact compelling data to
15 suggest that a proxy method is not the best way to
16 calculate a utility's avoided costs.

17 III. HOURLY INCREM ENTAL COST METHODOLOGY

18 Q. Do you believe that levelized avoided cost
19 rates available to QF5 should be the same or very similar
20 to the per megawatt-hour ("NWh") production cost of a
21 utility-owned resource as Dr. Reading suggests?

22 A. No, I do not. There are many reasons that I
23 will elaborate upon in my testimony as to why the two cost
24 figures would not match or even be close, the most
25 important of which is that a utility-owned resource will be
500
STOKES, REB 11
Idaho Power Company
9 1 dispatched based upon need, system reliability, and
2 economics while, currently, a QF resource is incented to
3 generate as much as possible in all months of the year
4 regardless of need, cost, or economic considerations
5 because the electric utility has a "must purchase"
6 obligation under PURPA.
7 Throughout his direct testimony, Dr. Reading is
8 critical of any changes to avoided cost rate calculations
9 proposed by parties to this case on the grounds that a
10 proposed change "does not put the QF on an equal cost
11 footing with the utility's own resources." (Reading Direct,
12 p. 13, 1. 2). Furthermore, on page 5 of his direct
I 13 testimony, Dr. Reading quotes the following passage from
14 Commission Order No. 15746 (1980)
15 This Commission endorses the policy
16 of having each utility pay its full
17 avoided cost when purchasing power
18 from cogenerators and small power
19 producers. Such a price will bring
20 about the equilibrium solution
21 typical of a competitive market
22 where the marginal cost of all firms
23 producing a like product is equal.
24 Anything less will fail to bring
25 about the condition of a free,
26 competitive market and will leave
27 the utility, as the sole buyer, in a
28 position to dictate price as it sees
29 fit. (Emphasis added.)
30 I have added the emphasis in the passage above
31 because I do not believe QF generation and utility-owned
32 generation are "like products" because they are not bound
501
STOKES, REB 12
Idaho Power Company
1 by the same economic constraints. In addition, I do not
2 believe the SAR methodology is capable of capturing these
3 differences.
4 Further, the definition of avoided cost is "the
5 incremental costs to an electric utility of electric energy
6 or capacity or both which, but for the purchase from the
7 qualifying facility or qualifying facilities, such utility
8 would generate itself or purchase from another source." 18
9 C.F.R. § 292.101(b) (6). Avoided cost must additionally
10 leave a utility's customers neutral or indifferent as to
11 whether the electricity was generated by the utility or the
12 QF. Order No. 32262, 18 C.F.R. § 292.304. Customers are
13 not being held indifferent and are paying much more for QF
14 generation under the SAR avoided cost rates than other
15 available power the Company could generate itself or
16 otherwise acquire.
17 Q. On page 34 of Dr. Reading's testimony, he
18 provides a chart showing four different levelized costs.
19 He goes on to describe the costs as being dramatically
20 different, and questions whether Idaho Power's proposed
21 Hourly Incremental Cost methodology produces a realistic
22 estimate of avoided cost. Do you agree with Dr. Reading's
23 assessment?
24 A. No, I believe the differences between the • 25 levelized costs reported by Dr. Reading can be easily
502
STOKES, REB 13
Idaho Power Company
1 explained and serve to highlight some of the differences
2 between a QF and a utility-owned resource. Specifically, I
3 am going to focus on the difference between Idaho Power's
4 2011 IRP estimated levelized cost of $98 per MWh for a
5 utility-owned and operated CCCT and the Hourly Incremental
6 Cost methodology's avoided cost rate of $47.40 per MWh for
7 a base load QF resource. An explanation of the factors and
8 assumptions behind these levelized cost estimates
9 demonstrates the avoided cost rates calculated under the
10 Hourly Incremental Cost methodology are not dramatically
11 different from estimated utility costs to build and operate
12 a resource, after taking into account characteristics of
. 13 the utility-owned resource relative to the QF resource.
14 Q. Please explain further the differences between
15 the levelized costs of a QF resource and one which is
16 utility-owned and operated.
17 A. A key difference between these cost estimates
18 is the assumed annual capacity factor for the two
19 resources. The 2011 IRP estimate assumes a 270 megawatt
20 ("NW") CCCT economically dispatched at a 65 percent annual
21 capacity factor, while the Hourly Incremental Cost
22 methodology base load resource example assumes a QF
23 resource operating at a 92 percent annual capacity factor.
24 With a much higher capacity factor, the QF delivers energy
. 25 during a considerable number of hours during which the
503
STOKES, REB 14
Idaho Power Company
• 1 Company's costs to operate its existing resources are
2 relatively low. Consequently, the costs the QF allows
3 Idaho Power to avoid during these hours are also relatively
4 low. If the QF were dispatchable and only operated when
5 economical and in the same manner the utility would operate
6 its own resources (65 percent annual capacity factor), the
7 Hourly Incremental Cost methodology's levelized rate would
8 increase by approximately $13 per MWh.
9 A second difference relates to the period over which
10 the cost is levelized. The 2011 IRP cost is levelized over
11 a 30-year period, while the $47.40 per MWh calculated under
12 the Hourly Incremental Cost methodology is levelized over a
• 13 20-year period. Extending the Hourly Incremental Cost
14 methodology analysis to 30 years and then leveling the
15 costs over an additional 10 years increases the proposed
16 methodology's estimate by approximately $6 per MWh.
17 Another factor explaining the difference between the
18 cost estimates involves the natural gas price forecast used
19 for each. Operating costs for a CCCT in the 2011 IRP are
20 based on earlier forecasts of nominal natural gas prices at
21 Sumas reaching approximately $13 per MMBtu by 2030. By
22 comparison, the more recent August 2011 Northwest Power and
23 Conservation Council fuel price forecast used in the Hourly
24 Incremental Cost methodology has nominal Sumas prices
• 25 reaching only about $9 per MMBtu by 2030. While part of
504
STOKES, REB 15
Idaho Power Company
1 the Hourly Incremental Cost methodology's appeal is its
2 lower sensitivity to changes in natural gas prices, the use
3 of the higher 2011 IRP natural gas forecast in the proposed
4 methodology still produces an increase of approximately $5
5 per NWh in the estimated levelized cost.
6 It is also important to note that the Hourly
7 Incremental Cost methodology defers avoided capacity costs
8 until the Boardman to Hemingway transmission line is
9 operational in 2016. In contrast, the 2011 IRP estimate
10 for a CCCT begins accounting for capacity costs when the
11 plant is placed in-service. For the sake of comparison, if
12 the avoided capacity costs in the Hourly Incremental Cost
13 methodology were assumed to begin in 2013, the proposed
14 methodology would yield an estimated levelized cost about
15 $3 per MWh higher.
16 Q. Are there other differences between a utility-
17 owned CCCT and a QF resource that differentiate the value
18 each type of resource provides?
19 A. Yes, there are other differences between a
20 utility-owned resource and a QF resource; however, they are
21 more qualitative. First, a utility-owned CCCT is able to
22 provide operating reserves necessary for the reliable
23 operation of the electrical system. This is particularly
24 important for Idaho Power because of the increasing amounts
25 of variable and intermittent generation being added to the
505 STOKES, REB 16
Idaho Power Company
1 system. An intermittent QF generator, on the other hand,
2 increases the amount of operating reserves a utility must
3 have available.
4 Second, a utility-owned CCCT can be undesignated as
5 a network resource and utilized to source firm, off-system
6 sales, when economical, which benefits customers by
7 offsetting other power supply costs. The ability to
8 provide operating reserves and source firm, off-system
9 sales are directly related to the fact that a utility-owned
10 CCCT is dispatchable, while a QF resource is not.
11 Finally, new utility-owned resources are scrutinized
12 during public regulatory processes for the development and
. 13 acknowledgment of the Company's IRP and filing for a
14 Certificate of Public Convenience and Necessity ("CPCN")
15 where it must be demonstrated to regulators, customers, and
16 other stakeholders that the new resource will be not only
17 used and useful but also least cost. This helps to ensure
18 that any new resource selected is well suited to the
19 electrical system and customer needs. For example, the
20 need for a resource in 2012 like Langley Gulch power plant
21 was first introduced and vetted in the Company's 2004 IRP,
22 and subsequently in the Company's 2006, 2009, and 2011
23 IRPs. In addition, it was subject to a fully contested
24 CPCN proceeding at the Commission in Case No. IPC-E-09-03.
• 25 In contrast, Idaho Power is forced to take whatever QF
506
STOKES, REB 17
Idaho Power Company
1 generation is proposed to it with no regard to customer
2 need, the QF's impact on the reliable operation of Idaho
3 Power's system, or the cost that QF generation imposes on
4 Idaho Power's customers. Idaho Power was obligated to sign
5 294 MW of QF wind contracts during a two-month period in
6 late 2010 without any evaluation or scrutiny given to
7 whether those resources were needed, or how they would
8 impact customer rates or the reliable operation of Idaho
9 Power's electrical system.
10 Q. Based on your review, what do you conclude
11 from the cost comparison chart shown on page 34 of Dr.
12 Reading's testimony? • 13 A. Dr. Reading asserts that the magnitude of the
14 difference in the levelized costs "calls into question the
15 claims that the proposed method is a realistic estimate of
16 the Company's avoided cost." (Reading Direct, p. 34, 1.
17 4.) Based on review of the levelized costs presented, and
18 the inputs and assumptions used for each, I believe the
19 differences in the costs can be easily explained and
20 highlight why a QF resource does not provide the same value
21 as a utility-owned resource. It is for these same reasons
22 that the SAR methodology, or any other proxy method, is
23 incapable of accounting for all the differences in resource
24 characteristics and is therefore not able to produce • 25 accurate, or appropriate, avoided cost rates.
507
STOKES, REB 18
Idaho Power Company
1 Q. Would you characterize Idaho Power's proposed
2 Hourly Incremental Cost methodology as transparent and
3 simple?
4 A. Yes, I would. In the Hourly Incremental Cost
5 methodology, the AURORA model is used to determine the
6 dispatch of utility-owned resources; beyond that, all other
7 information and calculations are done in an Excel
8 spreadsheet, which I believe is very transparent. The main
9 Excel worksheet is large, but only because it performs the
10 same calculation for every hour of the contract term.
11 As far as simplicity, I have had the opportunity to
12 become familiar with the spreadsheet and the methodology
13
over the past few months and believe it is simpler and more
14 transparent than the SAR model. Others likely do not share
15 this view because they have not yet spent much time working
16 with it. While I was not involved with avoided cost rates
17 when the SAR methodology was implemented, my guess is
18 similar feelings were also expressed at that time because
19 it was new to everyone.
20 Q. Do you believe Staff has thoroughly reviewed
21 the Hourly Incremental Cost methodology and spreadsheet?
22 A. Yes, I do. In fact, based on the discovery
23 questions Idaho Power received from Staff, I would say
24 Staff did a very thorough review of the methodology and • 25 supporting data submitted by Idaho Power.
508
STOKES, REB 19
Idaho Power Company

•1

Q. After reviewing the Hourly Incremental Cost
2 methodology, is Staff supportive of the method Idaho Power
3 is proposing?

4 A. Yes, they are. Beginning on page 8 and
5 continuing through page 13 of his direct testimony, Staff
6 witness Sterling discusses various aspects of the Hourly
7 Incremental Cost methodology proposed by Idaho Power. The
8 following statements are taken from Mr. Sterling's
9 testimony and are representative of the support expressed
10 for the proposed methodology:

11 I believe that Idaho Power has

12 properly focused on the incremental

13 costs that the utility would incur

14 as the basis for determining avoided
S 15 costs. (Sterling Direct, p. 10, 1.

16 21.)

17 I believe that the IRP methodology

18 as proposed by Idaho Power conforms

19 more closely with FERC's definition

20 of avoided cost than the way in

21 which Idaho Power has employed the

22 methodology in the past. (Sterling

23 Direct, p. 11, 1. 1.)

24 I believe that the methodology as

25 proposed by Idaho Power is

26 acceptable, and as I stated

27 previously, an improvement over the

28 currently-accepted methodology.

29 (Sterling Direct, p. 13, 1. 8.)

30 Q. Although supportive of the Hourly Incremental
31 Cost methodology proposed by Idaho Power, Staff is still
32 recommending the SAR model be used to establish published

0 33 rates. Do you agree with this?
509
STOKES, REB 20
Idaho Power Company
1 A. No, I do not. There are many reasons for
2 abandoning the SAR methodology that I expound on in both my
3 direct and rebuttal testimony, and I will not reiterate
4 them all here. However, I would like to emphasize that I
5 believe it would be an unnecessary administrative burden to
6 continue to use the SAR methodology for published rates
7 when a single method could be adopted and used to set both
8 published and negotiated avoided cost rates.
9 Q. Does the Company have any changes or updates
10 to the Hourly Incremental Cost methodology or pricing that
11 it would like to submit?
12 A. Idaho Power has no proposed changes to the
13 methodology itself as such is proposed in the Direct
14 Testimony of Karl Bokenkamp. However, the Company does
15 have updated current avoided cost prices derived from the
16 Hourly Incremental Cost methodology. Submitted as Exhibit
17 No. 9 to my rebuttal testimony are updated current prices
18 for the four representative QF generation types that
19 coincide with and replace the current prices reflected in
20 Corrected Exhibit No. 8 previously submitted with witness
21 Bokenkamp's pre-filed direct testimony. The updated
22 current prices in my Exhibit No. 9 were derived using the
23 EIA natural gas forecast recommended by Commission Staff
24 and Idaho Power's updated April 2012 load forecast. The • 25 updated pricing takes into account recent events, such as
510 STOKES, REB 21
Idaho Power Company
1 the removal of loads associated with Hoku Materials, Inc.,
2 as well as other updated adjustments.
3 IV. SPR METHODOLOGY MODIFICATIONS
4 Q. Although you propose abandoning the SAR
5 methodology in favor of Idaho Power's Hourly Incremental
6 Cost methodology for both published and negotiated rates,
7 do you have any comments on the modifications to the SAR
8 methodology proposed by other witnesses?
9 A. Yes, I do. As an initial matter, I must
10 reiterate that Idaho Power believes the Commission should
11 completely abandon the use of the SAR methodology for
12 determining avoided cost rates. For all the reasons ' 13 explained in my direct testimony and elsewhere in my
14 rebuttal testimony, the Company believes the Hourly
15 Incremental Cost methodology is a better, more accurate
16 manner in which to determine avoided costs. That said, if
17 the Commission elects to retain the SAR methodology, I
18 would recommend a number of changes to that methodology,
19 including updating the index used to determine natural gas
20 prices. As I previously stated, several witnesses support
21 using the EIA natural gas price forecast and updating it on
22 an annual basis. Because of the frequency of updates, I
23 believe this would be better than continuing to rely on the
24 Northwest Power and Conservation Council forecast; however, • 25 it still does not resolve the primary problem of the SAR
511
STOKES, REB 22
Idaho Power Company
1 methodology being overly sensitive to changes in the
2 natural gas price assumption.
3 Q. In his direct testimony, Staff witness
4 Sterling agrees with your proposal to use a simple-cycle
5 combustion turbine ("SCCT") to determine the avoided cost
6 of capacity for all QF resource types. (Sterling Direct,
7 p. 16, 1. 24.) Could an SCCT be used in the SAR
8 methodology as well?
9 A. Yes, I believe it could be if just the capital
10 and fixed costs of an SCCT were used to determine the
11 capacity portion of the avoided cost rate. The energy
12 component would still require using the heat rate and other
S 13 variable operations and maintenance assumptions appropriate
14 for a CCCT.
15 Q. In her direct testimony, Staff witness McHugh
16 proposes to apply the "first deficit year" concept to both
17 the capacity and energy components of avoided cost rates
18 (McHugh Direct, p. 9, 1. 10). Do you agree with her
19 proposal?
20 A. Yes, with one recommended change. As I
21 understand the proposal, capacity payments would be removed
22 from the avoided cost rate until the month the first
23 uncommitted resource is identified in each utility's IRP.
24 For the avoided cost of energy payments, deductions from • 25 the rate would be made to account for transmission wheeling
512
STOKES, REB 23
Idaho Power Company
1 costs and losses until the first month an energy deficit
2 occurs in each utility's IRP. In general, I support this
3 proposal because I believe this treatment of capacity costs
4 is an appropriate way to account for the ability of a QF to
5 come on-line at any time irrespective of a utility's need.
6 For the energy component, transmission wheeling and losses
7 are real costs that result from having to sell surplus
8 energy into the market and, therefore, I am also supportive
9 of this concept with one modification.
10 Q. What is your recommended modification to
11 Staff's proposal with regard to avoided cost of energy
12 payments?
S 13 A. Energy surplus/deficit positions are
14 determined on a monthly basis in the IRP. Therefore, I
• 15 propose that deductions for wheeling and losses be made for
16 any month the utility is surplus throughout the term of the
17 QF contract, not just until the first deficit month is
18 reached. A utility factors in wheeling and transmission
19 loss costs as part of making the decision of whether to
20 dispatch a utility-owned resource. Because a QF resource
21 is incented to deliver as much energy as it can to the
22 utility during all months of the year, I believe it would
23 be appropriate to account for these costs for any month the
24 utility is surplus throughout the term of the contract.
25
513
STOKES, REB 24
Idaho Power Company
1 Q. Canal company witness Schoenbeck proposes
2 numerous changes to the SAR methodology beginning on page
3 16 of his direct testimony. Can you summarize his
4 recommendations?
5 A. Yes, I can. Mr. Schoenbeck's recommended
6 changes to the SAR methodology are fairly extensive and
7 include:
~ 0
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
The SAR method could employ an
exogenously determined market price,
either hourly or monthly by on and
off peak period . . . . (Schoenbeck
Direct, p. 16, 1. 18.)
Determining four different sets of
published prices based on the four
different QF delivery patterns
applied to the cost stream would
recognize the delivery
characteristics of each resource
type just as Idaho Power is
proposing . . . . (Schoenbeck
Direct, p. 17, 1. 2.)
By requiring annual updates to the
gas prices and the corresponding
market prices, the SAR method will
not be static between integrated
resource plan publications.
(Schoenbeck Direct, p. 17, 1. 7.)
Mr. Schoenbeck goes on to state, "The only item that
32 cannot be directly addressed by these modifications is how
33 additional QF5 that commence delivering generation to Idaho
34 Power might impact Idaho's published avoided costs, if at
35 all." (Schoenbeck Direct, p. 17, 1. 10).
[1
514
STOKES, REB 25
Idaho Power Company
1 Q. Do you have any comments regarding Mr.
2 Schoenbeck's recommended changes to the SAR methodology?
3 A. Yes, but only a general comment. As I read
4 through the recommended changes, it began to sound more
5 like an endorsement of the IRP methodology or the Hourly
6 Incremental Cost methodology proposed by Idaho Power. I am
7 not sure if it would even be feasible to implement the
8 changes Mr. Schoenbeck is recommending to the current SAR
9 model. At the very least, with his recommended changes I
10 think it would be difficult to still consider the SAR model
11 a proxy method for determining avoided cost rates.
12 V. AVOIDED COST OF CAPACITY
S 13 Q. The Staff and the utilities in this case are
14 recommending the avoided cost of capacity be removed from
15 the avoided cost rate until the first deficit year appears
16 in the IRP. Why do you believe this is appropriate?
17 A. As I have previously stated, utility-owned
18 resources are identified in the IRP based on need and are
19 only constructed or acquired when the need exists. From
20 this standpoint, utilities and QF5 would be treated the
21 same as a utility would not be able to place a resource
22 into rates until it was used and useful and a QF would not
23 receive capacity payments until there was an identified
24 need.
25
515
STOKES, REB 26
Idaho Power Company
1 Q. On page 14 of his direct testimony, Dr.
2 Reading states "the denial of capacity payments during a
3 period of claimed surplus does not put a QF facility and a
4 company owned generating plant on an equal footing." Do
5 you have any evidence to the contrary?
6 A. Yes, I do. In the 1980s, Idaho Power faced a
7 surplus capacity situation at the same time that the
8 Company attempted to place the Valmy II generating unit
9 into rate base. The Idaho Public Utilities Commission
10 determined that the Valmy II plant was not used and useful
11 because Idaho Power was in a surplus situation, meaning
12 that in the load and resource balance, resources exceeded
. 13 load. The exact words of the Commission were:
14 We find as a fact that Idaho Power's
15 share of the Valmy II generating
16 plant is not used and useful in the
17 service of its Idaho ratepayers.
18 Power's, Schneider's, and Miller's
19 evidence on this point is
20 overwhelming and uncontroverted.
21 The Company's own load and resources
22 plan demonstrates that Valmy II is
23 surplus capacity until approximately
24 1993. In the interim, the Company's
25 limited dispatches from Valmy II
26 could be reliably replaced, at a
27 fraction of that plant's fully
28 distributed cost, by generation from
29 Idaho Power's other plants and
30 purchases from the surplus market.
31 (Idaho Public Utilities Commission
32 Case U-1006-265, Order No. 20610, p.
33 103.)
.

516
STOKES, REB 27
Idaho Power Company
1 The final result of this case was that Idaho Power
2 was not allowed a rate of return on this resource until
3 1989, four years after the resource was constructed and
4 operational.
5 Q. Beginning on page 9 of his direct testimony,
6 Dr. Reading includes a lengthy discussion of long-run and
7 short-run marginal costs based on the NERA "Grey Books"
8 that were published prior to the passage of PURPA.
9 Specifically on page 12, Dr. Reading states "Unless QFs are
10 credited for long-run capacity costs they will never by
11 [sic] compensated on an equal basis relative to what the
12 utilities receive in rates to build plant." Does the • 13 Hourly Incremental Cost methodology proposed by Idaho Power
14 compensate QF developers based on Idaho Power's long-run
15 capacity cost?
16 A. Yes, the Hourly Incremental Cost methodology
17 compensates QF resources for the capacity they provide
18 based on the estimated long-term cost to add generation
19 capacity to Idaho Power's system. Idaho Power has proposed
20 using the capital costs from an SCCT as the generation
21 resource that determines the capacity credit for QF
22 generation. Using the capital cost from a SCCT insures
23 that a QF resource receives equal treatment to utility-
24 owned resources. In fact, the Hourly Incremental Cost • 25 methodology is consistent with the recommendation from the
517
STOKES, REB 28
Idaho Power Company
1 NERA Grey Books to use the "long-run marginal costs of
2 generating capacity" that Dr. Reading highlights in his
3 testimony.
4 Dr. Reading argues that QF resources would not be
5 compensated based on long-run marginal costs because they
6 would not receive capacity payments until the first deficit
7 year identified in the IRP. What this is ultimately saying
8 is that QF developers should receive preferential treatment
9 and be compensated for capacity regardless of a utility's
10 need for the capacity.
11 Compensation for capacity based long-run marginal
12 costs is also impacted by the five-year contract term Idaho
. 13 Power has proposed. QF developers have rightly argued that
14 it is unrealistic for them to recover the capital cost of
15 their projects in a five-year term. While a utility
16 typically does have generation assets recovered in rates
17 past a five-year period, it is important to point out that
18 PURPA's obligation, and, thus Idaho Power's obligation to
19 contract, lasts past the Company's proposed five-year
20 contract term. Accordingly, as a QF project continues to
21 sign new five-year contracts, it would continue to be
22 compensated for capacity long after a utility-owned
23 resource had been fully depreciated.
24 Q. On page 31 of his direct testimony, canal
• 25 company witness Schoenbeck proposes using loss of load
518
STOKES, REB 29
Idaho Power Company
1 analysis results to determine when QF resources should
2 begin being compensated for capacity. Do you agree with
3 this?
4 A. No, I do not agree for at least two reasons.
5 First, the loss of load expectation analysis Idaho Power
6 performs as part of the IRP is done after a preferred
7 portfolio has been identified and is only done to verify
8 that the selected portfolio provides a reasonable level of
9 assurance that projected loads can be met. Second, a loss
10 of load expectation (or probability) study is complex and
11 difficult to explain to anyone not familiar with the
12 concepts. It would be hard to imagine any of the
' 13 intervenors in this case that are proponents of simple and
14 transparent processes being supportive of this
15 recommendation.
16 Q. Mr. Schoenbeck supports his proposal because
17 it produces earlier capacity payments for QF resources, and
18 then goes on to discuss "the game that can be played," by
19 utilities in basing the start of capacity payments on the
20 first deficit month in the IRP load and resource balance.
21 (Schoenbeck Direct, p. 31, 1. 13.) To support this
22 statement, Mr. Schoenbeck references Idaho Power's Boardman
23 to Hemingway transmission project and its scheduled on-line
24 date of 2016. Do you agree that Idaho Power was "playing a
25
519
STOKES, REB 30
Idaho Power Company
1 game" with the scheduled on-line date for the Boardman to
2 Hemingway transmission project?
3 A. No, I do not. Late in the process of
4 preparing Idaho Power's 2011 IRP, it was determined that
5 delays in permitting were going to cause the scheduled
6 operational date of the project to slip from 2015 to 2016.
7 Therefore, the IRP load and resource balance showed a
8 deficit in 2015, which was eliminated with an "east-side"
9 purchase for the summer months. Idaho Power has relied on
10 short-term purchases from the east side of its system in
11 the past when necessary; however, it is not the preferred
12 choice for market purchases or something the Company wants
13 to rely on long term due to low market liquidity and
14 typically higher prices.
15 I believe Mr. Schoenbeck's "gaming" concerns could
16 be addressed simply by clarifying how the first deficit
17 year is determined. The way Idaho Power has applied it in
18 the case of the Boardman to Hemingway project mentioned
19 above is based on when the next planned resource is to come
20 on-line. This methodology is based on the utility resource
21 that is potentially being "avoided" due to any new QF
22 resources. The other method that could be used would be to
23 strictly rely on the first deficit year identified in each
24 utility's load and resource balance, which would address
• 25 Mr. Schoenbeck's concern.
520
STOKES, REB 31
Idaho Power Company
S iVI. AVOIDED COST OF ENERGY
2 Q. In his direct testimony, Dr. Reading comments
3 on Idaho Power's proposed Hourly Incremental Cost
4 methodology by stating, "the approach incorrectly assumes
5 avoided costs should be based on a very short-run hourly
6 basis." (Reading Direct, p. 29, 1. 10) . Do you agree with
7 Dr. Reading's assessment?
8 A. No, I do not. Dr. Reading assumes that
9 because the avoided cost of energy is calculated on an
10 hourly basis, the calculation is only focused on the
11 "short-run." The avoided cost of energy calculation in the
12 Hourly Incremental Cost methodology is in fact very
S 13 "granular" in that every hour for the QF contract term is
14 analyzed. This does not suggest that the methodology is
15 only focused on the "short-run" because the calculation is
16 done for each and every hour throughout the entire contract
17 term.
18 VII. CONTRACT TERN
19 Q. In his direct testimony, canal company witness
20 Schoenbeck states "The five-year term is unfair and
21 inappropriate because it creates a mismatch between the
22 maximum contract term allowed a QF versus the economic life
23 used or assumed for a comparable utility-owned resource."
24 (Schoenbeck Direct, p. 9, 1. 1.) Do you believe this is
25 true?
521
STOKES, REB 32
Idaho Power Company
•
1 A. No. What Mr. Schoenbeck does not point out is
2 that a QF resource could simply continue to sign new five-
3 year contracts and ultimately receive capacity payments
4 long after a utility-owned resource was fully depreciated.
5 I believe Mr. Schoenbeck's statement is based on the
6 expectation that the QF would have to pay off any debt
7 associated with the project during the first five-year
8 contract. While I have no firsthand knowledge of whether
9 project financing would become more difficult for QF
10 developers, I do not believe this assumption supports the
11 statement that a five-year contract term is "unfair and
12 inappropriate."
. 13 Q. Mr. Schoenbeck goes on to state that "locking
14 into fixed price arrangements reduces Idaho Power's
15 exposure to market price movements." (Schoenbeck Direct, p.
16 13, 1. 13.) Do you agree with this?
17 A. No. In fact, it has the opposite effect of
18 putting all of the risk on Idaho Power customers and giving
19 the QF5 a hedge against potential unfavorable market
20 shifts. History indicates that avoided cost rates exceed
21 market prices and that QFs predominantly insist upon
22 contracts only when contractual prices exceed market rates.
23 See the chart on page 7 of my rebuttal testimony. This
24 chart clearly shows that over the past 10 years Idaho Power
25 has paid substantially more for QF energy compared to
522
STOKES, REB 33
Idaho Power Company
1 market rates. Although it is true in theory that actual
2 prices can go up or down relative to the forecast or
3 contract price, if the price is favorable to the QF, they
4 will insist upon a long-term contract, develop the project,
5 and continue to generate. On the other hand, if the price
6 is not favorable, or no longer favorable, the QF has the
7 options of not contracting, contracting but not developing,
8 or bringing the project on-line, not generating or
9 generating less, or ultimately ceasing operations and
10 walking away from the project and contract. The point
11 being that it is a hedge, or an option that the QF can
12 exercise with customers taking all the downside price risk
. 13 and hit, and rarely if ever seeing any upside.
14 Q. Does Staff agree with Idaho Power's views
15 regarding this risk that is shouldered by customers?
16 A. Yes. Staff witness Sterling also supports
17 this view in his direct testimony regarding fuel price
18 risk.
19 Prices established at the start of a
20 long-term contract could prove to be
21 too high or too low compared to
22 other alternatives or to market
23 prices in effect throughout the term
24 of the contract. A long-term
25 contract locks in those prices,
26 regardless of what happens with
27 market prices. Because 100 percent
28 of PURPA costs are passed on to
29 customers through PCAs, ratepayers
30 are fully exposed to the risk that
31 PURPA rates may prove to be too
32
33
high. (Sterling Direct, p. 30, 1.
25.)
523
STOKES, REB 34
Idaho Power Company
1 I believe what Mr. Sterling states is the exact
2 situation Idaho Power's customers are currently in due to
3 avoided cost rates that have historically been set too high
4 using the SAR methodology.
5 Q. Staff witness Sterling proposes that a five-
6 year contract term only apply to QF projects larger than
7 the published rate cap. Do you agree with this?
8 A. While Idaho Power appreciates Staff's
9 agreement that the maximum contract term for all QF
10 contracts under the Hourly Incremental Cost methodology be
11 set at five years, Idaho Power recommends that the five-
12 year contract term apply to all PURPA QF power sale . 13 contracts. Staff's recommendation that contracts for all
14 other QF resources under the SAR methodology be entitled to
15 20-year contracts would only be acceptable to the Company
16 if the published rates based upon the SAR methodology were
17 to remain available only to QFs with a nameplate capacity
18 below 100 kilowatts ("W). If the Commission reduces the
19 published rate cap to 100 kW for all QF resource types as
20 the Company has recommended, then most of the risk
21 customers face due to longer-term contracts will be
22 minimized. However, if longer-term contracts are available
23 for published rates for larger QFs up to 10 MW or 10
24 average megawatts, then all of the problems associated with • 25 price risk described above, and by Staff and the Company in
524
STOKES, REB 35
Idaho Power Company
1 direct testimony, will continue to exist, and continue to
2 harm customers.
3 As stated earlier, the shorter maximum contract term
4 is a safeguard for customers to ensure that the very large
5 risk of locking in prices for the entire duration of the
6 contract is not allowed to continue to inflict substantial
7 financial harm to customers. Because Federal Energy
8 Regulatory Commission ("FERC") regulations allow a QF to
9 unilaterally elect to have the prices in its contract set
10 for the entire duration of the contract based upon price
11 estimates at the time of contracting - as opposed to prices
12 at the time the energy is delivered - the Company, and the . 13 Commission, have no means to bring prices back to reality
14 should a large deviation in prices materialize to the
15 detriment of customers, as Idaho Power has demonstrated in
16 its direct testimony in the current case. This is
17 exacerbated by FERC's prohibitions regarding certain price
18 "reopeners" in the QF power sales agreements.
19 Consequently, the only real tool left for the Commission to
20 assure that the Company and its customers are not saddled
21 with substantial long-term harm from price projections that
22 end up deviating substantially from actual prices is to
23 shorten the term of the contract. The obligation to
24 purchase will remain, and the QF can enter into a new • 25 contract for the years past year five, or the maximum term
525
STOKES, REB 36
Idaho Power Company
1 of the contract. The Commission and the utility customers
2 can then be assured that even should the price estimates
3 that are established in the contract become harmful and
4 deviate substantially from reality, that they will be
5 looked at anew and refreshed with the new contract, once
6 the maximum term expires.
7 VIII. PUBLISHED RATE CAP
8 Q. Canal company witness Schoenbeck recommends
9 setting the published rate cap at 10 MW of nameplate
10 capacity for all resource types (Schoenbeck Direct, p. 14,
11 1. 10) . Do you have any concerns regarding this proposal?
12 A. Yes, I do. Regardless of what avoided cost
. 13 methodology the Commission decides to use to set rates,
14 published rates could remain stagnant for one to two years.
15 Past experience shows much can change in the energy
16 industry during this time frame, and in order to protect
17 customers from the risk associated with changed conditions,
18 I believe the published rate cap should be set at the
19 minimum FERC required level of 100 kW for all resource
20 types.
21 As I have proposed previously, if published rates
22 are set using the Hourly Incremental Cost methodology for
23 the various resource types, published rates and negotiated
24 rates for each resource type will remain virtually
. 25 identical as long as the assumptions made in the IRP remain
526
STOKES, REB 37
Idaho Power Company
1 valid. If any of the assumptions do change, the utilities
2 will be able to update the inputs used in the methodology
3 in order to calculate a current and accurate avoided cost
4 rate. This idea on how to implement and apply published
5 and negotiated rates also has the advantage of no longer
6 needing to rely on the SAR methodology, which I do not
7 believe calculates accurate avoided cost rates.
8 IX. CARBON ADDER
9 Q. On page 24 of his direct testimony, canal
10 company witness Schoenbeck advocates for including
11 potential carbon costs in the avoided cost of energy.
12 Witness Looper also discusses the addition of carbon tax
. 13 costs on page 7 of his direct testimony. Do you agree with
14 their statements?
15 A. No, I do not. Estimates of future carbon
16 costs are used in the IRP process to evaluate the relative
17 difference between the cost of various resource portfolios.
18 None of these costs are currently real nor are they
19 included in customer rates.
20 Idaho Power has addressed the carbon adder issue in
21 every IRP it has prepared since at least the 2004 IRP, and
22 used high and low cases for risk analysis purposes. During
23 the IRP cycle, the cost and potential implementation date
24 of a carbon adder are discussed with stakeholders, and
. 25 today there is just as much uncertainty of these
527
STOKES, REB 38
Idaho Power Company
1 projections as there was in 2004. While appropriate for
2 purposes of evaluating the relative difference between
3 future resource acquisitions in the IRP process, these
4 potential carbon costs do not exist today, and it would be
5 inappropriate to include them in any avoided cost rate.
6 X. IRP LITIGATION
7 Q. On page 18 of his direct testimony, Dr.
8 Reading proposes that utility IRPs should "be subject [sic]
9 greater scrutiny and subjected to a litigated hearing and
10 ultimately approval by the Commission." (Reading Direct, p.
11 18, 1. 2.) In leading up to this recommendation, Dr.
12 Reading states, "I would agree if the utilities IRPs were,
. 13 in fact, subject to significant oversight in their
14 development and submission." (Reading Direct, p. 17, 1. 1.)
15 Do you agree with Dr. Reading's opinion concerning the
16 level of oversight in the IRP process?
17 A. No, I do not. It takes Idaho Power
18 approximately one year to prepare an IRP, and during that
19 time, the Company conducts monthly meetings with the IRP
20 Advisory Council. Members of the council include
21 political, environmental, and customer representatives,
22 Commission Staff representatives, and representatives of
23 other public-interest groups. In addition, the meetings
24 are open to the public and are typically well attended by
. 25 other stakeholders and interested individuals. The primary
528
STOKES, REB 39
Idaho Power Company
1 purpose of the meetings is to discuss issues related to the
2 IRP and to solicit input on the assumptions that go into
3 the plan.
4 Following the completion of the IRP and subsequent
5 filing with the Commission, additional public meetings are
6 conducted to present the plan to the public. During this
7 same time, the Commission also solicits public comments.
B As the person ultimately responsible for the
9 preparation of Idaho Power's IRP, I can say that there is a
10 significant amount of oversight in the process of preparing
11 the plan.
12 Q. Are there specific reasons the Commission • 13 should not make the IRP a "litigated process"?
14 A. Yes, there are at least three reasons. First,
15 IRPs are intentionally "accepted" and not "approved" by the
16 Commission so there is no inference of approval of any of
17 the action items contained in the plan. Any new generation
18 resources identified in the plan must still go through a
19 CPCN process, which is fully litigated.
20 Second, the Commission, utilities, and others
21 recognize that things can change within the two-year period
22 between IRP filings. Having the IRP accepted and not
23 approved provides flexibility for the utilities to react to
24 these changes, without having to go through a protracted • 25 legal proceeding.
529
STOKES, REB 40
Idaho Power Company
1 Finally, as I stated previously, it takes
2 approximately one year to prepare an IRP. The regulatory
3 process as it exists today typically takes an additional
4 six months and shortly after that internal preparations
5 begin for the next IRP. If the IRP were to be fully
6 litigated, I do not believe the two-year cycle would allow
7 time for the Commission to issue an order before the next
8 plan would be underway.
9 XI. ENVIRONMENTAL ATTRIBUTES
10 Q. Did Idaho Power make any specific requests of
11 the Commission with regard to Environmental Attributes or
12 REC5 of QF generation in its direct testimony in this case?
S 13 A. No. In Lisa Grow's direct testimony, Idaho
14 Power acknowledged that RECs were listed by the Commission
15 as one of the issues to be examined in this proceeding in
16 Order No. 32352; however, the Company stated that it had no
17 specific request of the Commission in this regard at the
18 time that direct testimony was filed (January 31, 2012).
19 Q. Did the Company make any other statements
20 regarding the issue of RECs in its direct testimony?
21 A. Yes. Witness Grow stated:
22 Issues related to PURPA QF5 and
23 RECs are currently being litigated
24 by the Company before the
25 Commission in Case No. IPC-E-11-15.
26 The Commission has had proceedings
27 in the past regarding issues
S 28 related to the ownership of REC5
530
STOKES, REB 41
Idaho Power Company
S ibetween PURPA QFs and the
2 purchasing utility, but the issue
3 of ownership of RECs in the state
4 of Idaho remains an unsettled
5 issue. Idaho Power understands
6 that the Idaho Legislature, which
7 is currently in session, may be
8 considering proposed legislation
9 that would address the ownership of
10 RECs from PURPA QF projects, and
11 thus the Company has no specific
12 request of the Commission in this
13 regard at this time.
14
15 Grow Direct, p. 13, 1. 22 through p. 14, 1. 8.
16 Q. Has anything changed with regard to the
17 pending Commission cases regarding QF RECs or with the
18 Idaho Legislature since January 31, 2012?
19 A. Yes, with regard to both. The Idaho
20 Legislature ended its 2012 session without taking any
21 action with regard to the ownership of RECs and utility
22 purchased QF generation. Additionally, the Commission
23 recently issued Order No. 32580 in Case No. IPC-E-11-15
24 denying a QF's motion for summary judgment regarding its
25 request to require the utility to disclaim ownership of
26 RECs in a QF power purchase agreement.
27 Q. Does Idaho Power have any specific requests of
28 the Commission with regard to RECs from utility-purchased
29 QF generation at this time?
30 A. Yes. Idaho Power, similar to other parties to
31 this docket, requests that the Commission specifically find
32 that the Environmental Attributes or REC5 from utility
531
STOKES, REB 42
Idaho Power Company
1 purchased QF generation are owned by the purchasing
2 utility.
3 Q. Have other parties to this docket asked the
4 Commission to make similar findings?
5 A. Yes. Witness Paul Clements on behalf of Rocky
6 Mountain Power, and witness Rick Sterling on behalf of
7 Commission Staff have recommended that the Commission find
8 that the purchasing utilities should be determined the
9 owners of the RECs from PURPA projects that sell their
10 generation to the utility.
11 Q. What basis do you have for this
12 recommendation?
13 A. First of all, Idaho Power agrees with witness
14 Sterling's conclusion that FERC has clearly determined that
15 REC ownership with regard to QF generation is a matter for
16 the states to decide. Citing, American Ref-Fuel Company,
17 105 FERC ¶ 61,004 (2003). Additionally, this was confirmed
18 by the Commission in Order No. 32580, Case No. IPC-E-11--15
19 (June 21, 2012) . The Commission in that Order denied a
20 QF's motion for summary judgment requesting that the
21 Commission order the utility to disclaim ownership of the
22 RECs in its QF power purchase agreement. The Commission
23 confirmed that the decision regarding ownership of RECs
24 from QF generation is a decision that lies with the states, • 25 and that such a decision has not yet been made in the state
532
STOKES, REB 43
Idaho Power Company
1 of Idaho. The Commission stated, quoting FERC, "States, in
2 creating RECs, have the power to determine who owns the
3 RECs in the initial instance, and how they may be sold or
4 traded; it is not an issue controlled by PURPA." Order No.
5 32580, p. 5 (citations omitted). The Commission found, "no
6 specific federal or state laws governing the ownership of
7 RECS" and rejected the QF's arguments that other facts
8 supported the QF's contention that it owned the RECs from
9 the PURPA power sale. Order No. 32580, pp. 9-13. The
10 Commission also verifies that its past orders regarding QF
11 REC issues did not address the ownership of those RECs in
12 the initial instance (Id., at pp. 10-11) and that the issue . 13 of QF REC ownership in the state of Idaho remains an
14 undecided issue, "Grand View cannot assert a Commerce
15 Clause violation when the ownership of REC5 has not been
16 decided." Id., p. 16.
17 Q. Have any of the QF parties to this docket
18 acknowledged the Commission's authority to decide the issue
19 of QF REC ownership?
20 A. Yes. Clearwater Paper Corporation, J.R.
21 Simplot Company, and Exergy Development Group of Idaho,
22 LLC, through their witness, Dr. Reading, have asked the
23 Commission to make a decision "as soon as possible"
24 regarding the ownership of environmental attributes. • 25 Reading Direct, p. 60. In addition, Grand View Solar II, a
533
STOKES, REB 44
Idaho Power Company
1 party to this case, is the QF referenced above in Order No.
2 32580 that filed its Complaint asking the Commission to
3 order Idaho Power to disclaim ownership of the RECs in its
4 proposed QF power sales agreement, which the Commission
5 denied.
6 Q. Does Idaho Power agree with Rocky Mountain
7 Power witness Clements' recommendations that the Commission
8 determine that the utility owns the Environmental
9 Attributes of the QF generation it purchases pursuant to
10 PURPA with no additional compensation beyond what is
11 already paid for the QF generation?
12 A. Yes. Idaho Power agrees with the position and • 13 statements of Rocky Mountain Power in the Direct Testimony
14 of Paul Clements Direct, p. 6, 1. 22 through p. 10, 1. 13,
15 and by this reference adopts and supports the same.
16 Q. Does Idaho Power agree with Staff witness Rick
17 Sterling's recommendations to the Commission with regard to
18 the ownership of RECs from utility purchased QF generation?
19 A. Yes. Idaho Power agrees with witness
20 Sterling's recommendation that the Commission find that the
21 utility owns the RECs from utility purchased QF generation.
22 However, the Company disagrees with his recommendation that
23 the utility be required to pay any amount over the avoided
24 cost rate for rates determined under the SAR avoided cost • 25 methodology. The Company, and its customers, in such an
534
STOKES, REB 45
Idaho Power Company
1 instance would be paying twice for what it had all ready
2 purchased from the QF, and paying above the avoided cost.
3 XII. LIQUIDATED DAMAGES
4 Q. Several witnesses discuss liquidated damages
5 and the current Commission-approved requirement to post
6 delay damage security with the current PURPA power sales
7 agreements. Does Idaho Power have a position in this
8 regard?
9 A. Yes. Idaho Power is in favor of and supports
10 the Commission's requirements to post delay damage security
11 with all PURPA power sales agreements in the amount of $45
12 per kW of nameplate capacity. This has been specifically
S 13 addressed in numerous Commission cases and numerous
14 different power sales agreements with various QF projects.
15 The Commission has specifically found this requirement to
16 be in the public interest and a just and reasonable
17 requirement of the contracting process. With regard to the
18 reasonableness of liquidated damages, some witnesses, such
19 as Dr. Reading, focus only upon the comparison to the cost
20 of replacement power should the QF not bring its project
21 on-line when it commits itself to a Scheduled Operation
22 Date that it chooses in the contract. This highlights an
23 important part of Idaho Power's case that it provided much
24 evidence of in its direct testimony, and that is typically
• 25 the Company can acquire replacement power from other
535

STOKES, REB 46
Idaho Power Company
1 available sources at a cost that is below the contract
2 price in the PURPA contract. This, however, is not the
3 only measure of harm and damages. In addition to the
4 system operation and planning problems that failure to
5 bring generation units on-line in a timely manner and when
6 they are scheduled to come on-line, there is the
7 substantial value that the QF gets by locking in a price,
8 and a pricing stream with its contract. If a QF is allowed
9 to come on-line, or not, at its choosing with no
10 consequences and no liability for the value of that option,
11 then customers are left in a financially disadvantaged
12 position and uncompensated for the price lock and option
S 13 they extended to the QF project. There are financial
14 instruments that can be purchased that would allow a
15 utility to lock in a 20-year, or long-term, stream of
16 prices, and have the option to not execute on that option
17 at a date certain in the future. Such products are very
18 costly, and could be as much as $5 per MWh of power. The
19 $45 per kW of nameplate capacity is very small in
20 comparison, but at least provides an agreed upon valuation
21 of an assessment of risk that the customers are bearing
22 associated with whether a QF generator brings its project
23 on-line when it commits that it will.
24
25
536
STOKES, REB 47
Idaho Power Company
1 XIII. SCHEDULE 73
2 Q. The Company stated in its direct testimony
3 that one of the items it seeks from the Commission is
4 "Establishment of a Commission-authorized negotiation
5 process and procedure by which a PURPA QF can obtain a PPA
6 with Idaho Power." Grow Direct, p. 14. Does Idaho Power
7 have any further details regarding this request?
8 A. Yes. Upon Idaho Power's review of Rocky
9 Mountain Power's proposed Tariff Schedule 38, provided as
10 Exhibit No. 202 to Rocky Mountain Power witness Clements'
11 testimony, Idaho Power has drafted its proposed Tariff
12 Schedule No. 73, which sets forth a similar process for QFs • 13 proposing to contract with Idaho Power. I submit Idaho
14 Power's proposed Tariff Schedule No. 73 as Exhibit No. 10
15 to this rebuttal testimony. Additionally, submitted as
16 Exhibit No. 11 herewith is a red-lined version of Rocky
17 Mountain Power's proposed Schedule 38, which shows in red-
18 line format the substantive changes between Schedule 38 and
19 Idaho Power's proposed Schedule 73.
20 Q. Does this conclude your rebuttal testimony in
21 this case?
22 A. Yes, it does.
23
24
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537
STOKES, REB 48
Idaho Power Company
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1 (The following proceedings were had in
open hearing.)
(Idaho Power Company Exhibit Nos. 1-3 and
9-11, having been premarked for identification, were admitted
into evidence.)
MR. WALKER: The witness is available for
cross-examination.
COMMISSIONER SMITH: Any questions?
MR. ANDREA: No questions.
COMMISSIONER SMITH: Mr. Solander, any questions?
MR. SOLANDER: No questions.
COMMISSIONER SMITH: Mr. Otto, do you have
questions?
MR. OTTO: No questions, Madam Chairwoman.
COMMISSIONER SMITH: Ms. Nelson.
COMMISSIONER NELSON: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you, Madam Chair.
CROSS-EXAMINATION
BY MR. RICHARDSON:
Q. Good afternoon, Mr. Stokes.
A. Mr. Richardson.
Q. Let's start at the bottom of page 24 of your
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direct testimony. Beginning on the bottom of page 24 of your

2
direct testimony, you are asked how the IRP process has been

3
frustrated and circumvented by PURPA. Do you see that?
LIM A. Yes, I do.

5 Q. Then you answer that question in four full
6 paragraphs beginning on the bottom of page 24, all the way over

7 to the middle of page 26. In the first paragraph of your

8 answer, you state that the IRP process -- planning process

9
involves input from the public. Do you see that?

10 A. Yes, I do.

11 Q. Can you tell me who is on the I- -- we've already

12 established who's on the IRP committee. The exhibit that we
.
13 handed out, is it still current?

14 A. It is still current until we have our first IRP
15 advisory council meeting for our next IRP, which is scheduled

16 for next Thursday, Thursday of next week.

17
Q. And are there new members selected and vested

18 in?

19 A. There's a handful of changes to that list, you

20 know, once it is in place, and it's routine for us to have some
PIPS M turnover from IRP to IRP.

22
Q. And the second paragraph of your answer, you note
23 that new resources get evaluated sometimes in even two or three

24 IRP cycles?

25 A. That's correct.
L
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HEDRICK COURT REPORTING STOKES (X)
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1 Q. And the fourth place -- the fourth paragraph is
2 the only place in your answer where PURPA is actually mentioned
3 regarding how it is frustrating and circumventing the IRP

4 process. Correct?
5 A. Yes, as far as the 294 megawatts of wind
6 contracts, PURPA wind contracts that got signed in a two-month

7 period in late 2010.

8 Q. And in that paragraph, you state that Idaho Power
9 had to sign 294 megawatts of wind PURPA contracts without

10 evaluation or thought.

11 So is it that lack of evaluation or thought that

12 causes the frustration and circumvents the IRP process?
.
13 A. No, in my opinion, what circumvents the IRP
EU process -- well, one and what I'm talking about in my direct

15 testimony -- is the fact that there's very little scrutiny
16 given to the types of resources that happen under PURPA, again

17 because as the Utility, we have the obligation to purchase the

18 output.

19 The other side of that is that, you know, Idaho

20 Power's needs for new generation resources for a long time now
21 have been summertime capacity needs. And we have discussed

22 this with our IRP advisory council and I think there's general

23 agreement that this is definitely the case, that wind is just

24 not a good resource for Idaho Power to be adding. Wind only
25 provides a five percent capacity factor during the summertime
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peak. The numbers I've been using lately in comparison to our
new Langley Gulch plant, which is a 300-megawatt combined cycle
combustion turbine, it would take 6,000 megawatts of wind
generation to give us the same amount of capacity as we're
getting out of Langley Gulch.
So from that standpoint, I think PURPA is
definitely frustrating the IRP process from the standpoint of
it's designed to identify the best resources that we should be
building in the future.
Q. So going back to your answer is that with no
evaluation or thought given to whether these wind resources
were needed or how they would impact customer rates, it's lack
of evaluation and thoughtfulness, according to your answer?
A. Yes, uh-huh.
Q. So, I assume someone at Idaho Power has reviewed
wind resource maps for Southern Idaho?
A. I have seen probably several myself.
Q. And has Idaho Power ever looked at wind resource
studies or data showing the potential -- the potential for wind
development in Southern Idaho?
A. I mean, I'm generally aware of it myself.
Southern Idaho, as a wind resource, is not too bad. It's not
as good of a location as Wyoming or the Columbia Gorge area.
But, again, because of PURPA and the avoided cost rates, we've
seen a tremendous amount of development in Southern Idaho.
541
HEDRICK COURT REPORTING STOKES (X)
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.
1
Q. But there are some pretty good wind sites in

2 Southern Idaho?

3 A. I would call them modestly good.

4 Q. But -- and, certainly, the Idaho Power personnel,
5 presumably, even though it's working with the IRP team, knew

6 what the avoided cost rates were in 2010. Right?

7 A. We don't really get into any kind of a discussion

8 over avoided cost rates in the IRP planning process.

9
Q. But the Idaho Power personnel know what the

10 avoided cost rates are?

11 A. Some of them probably do. I, myself, am familiar

12 with them.

13
Q. And, certainly, Idaho Power personnel also knew

14 about the favorable tax and depreciation treatment that the

15
federal government was making available to wind projects.

16 Right?

17 A. We're aware of the production tax credit and the

18
investment tax credits that have been available.

19 Q. So it wasn't just that the economics were

20
favorable in 2010, that the resource was available in 2010, and

21 that there were developers eager to capitalize on those very

22
favorable conditions. The political environment was very

23 welcoming in 2010, wasn't it?

24 A. "Political" from the standpoint of the tax

25 1 incentives?
542
HEDRICK COURT REPORTING STOKES (X)
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Q. For wind developers, for encouraging wind
developers to come to the state of Idaho.
A. I believe it was a combination of the tax
incentives that were available and the high avoided cost rates.
MR. RICHARDSON: May we approach the witness,
Madam Chair?
COMMISSIONER SMITH: You may.
MR. RICHARDSON: Madam Chair, I'm handing out
what I will ask to be marked Exhibit 516, a press release
entitled Farming the Wind Near the Oregon Trail: Idaho's
Governor, GE and Partners Launch State's Largest Wind Power
Project.
(Clearwater Paper Corporation, et al,
Exhibit No. 516 was marked for identification.)
Q. BY MR. RICHARDSON: I'd asked earlier if the
political climate was favorable for encouraging wind to come to
the state. Would you read into the record the fourth paragraph
of this press release that is on GE Financial?
MR. WALKER: Madam Chair, I'm going to object to
this attempt to introduce new evidence into the record in this
manner. Mr. Richardson had the opportunity through both direct
and rebuttal to submit whatever he wanted in his case rather
than now trying to make a new case manufactured upon his
cross-examination.
COMMISSIONER SMITH: Mr. Richardson.
543
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MR. RICHARDSON: Madam Chair, I guess I'd respond
that I restrained myself when I saw Mr. Stokes' rebuttal
testimony that rebuts no one. And I'm not going to move to
have it stricken from the record because it is, indeed, new
information.
What I'm introducing this exhibit for is to
demonstrate the political climate in Idaho was very favorable
for wind development and nothing else.
COMMISSIONER SMITH: And I don't think he
disagreed with you. So if you're not trying to impeach him or
anything, I'm just wondering if -- he already agreed with you.
MR. RICHARDSON: There is a touch of that coming
down the road, Madam Chair, if you would indulge me.
COMMISSIONER SMITH: Okay, just for a little
while.
MR. RICHARDSON: Thank you.
Q. BY MR. RICHARDSON: Would you read that fourth
paragraph into the record, please?
A. "'The renewable energy industry is breathing new
life into the Idaho frontier,' said Governor Otter. 'We're
aggressively harnessing our abundant natural resources for
growth because that helps our economy, generating not only
electricity but career opportunities right here at home.'"
Q. Thank you. Couldn't someone on the IRP team have
put two and two together and made the not so far-fetched
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conclusion that there's probably going to be a lot of wind
projects built in Idaho Power's service territory in 2010?
A. Well, I think it's important to consider the time
frame that all of these things happened. This press release
came out in August of 2010. Because of the ad campaigns and
other things in this case, a lot of people think Idaho Power is
antiwind. We're not. As late as 2009, we had an RFP on the
street for up to 150 megawatts of wind, because at that time we
believed there was a certain amount of wind that we should have
on our system that made sense.
These projects, this dedication, happened August
of 2010. The piece out of the top of page 26 on my testimony
talks about in late 2010, when we have 294 megawatts of PURPA
wind that came to us, and it literally got to the point where
it was way too much that it just didn't make sense, and we were
paying and ultimately our customers were paying way too much
for it.
Q. Are there any wind developers on the IRP team?
A. Specifically that's their line of profession, I
don't believe so. Now, whether any of them have any type of
financial interest in it, I couldn't speak to.
Q. Can you tell me any more specifically, other than
the assertions we just discussed that this wind wasn't
evaluated or thought out, how the IRP process has been
frustrated and circumvented? Do you have any more specific
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HEDRICK COURT REPORTING STOKES (X)
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than the top of page 26?
A. Well, I guess another example I could give you is
that under PURPA, part of the point of QF projects coming
online is that they would defer potential Utility projects.
Again, wind, because of its low capacity factor, is doing very
little to defer future resources that we'll need to build for
Idaho Power's customers.
Q. Right. And I want to kind of stay on how this is
disrupting the IRP process.
MR. RICHARDSON: Madam Chair, may we approach?
COMMISSIONER SMITH: You may.
Q. BY MR. RICHARDSON: Mr. Stokes, I'm handing out
page 33 from your current 2011 IRP in case you don't have that
at your ready disposal, and I'll ask that it be marked as
Exhibit 517.
THE COURT REPORTER: Commissioner Smith, we don'tI
have a 515.
COMMISSIONER SMITH: I think this would be a good
time for us to take a break. Let's come back at 2:45.
(Recess.)
COMMISSIONER SMITH: All right, let's go back on
the record. All right, on the exhibit numbers, we have decided
for the clarity of the record there will be no Exhibit 514?
THE COURT REPORTER: Fifteen.
COMMISSIONER SMITH: 515. And we will resume
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with 516 and 517, so we'll keep those numbers straight.
MR. RICHARDSON: Thank you, Madam Chairman. I
apologize for that mishap.
COMMISSIONER SMITH: I should have kept better
track.
(Clearwater Paper Corporation, et al,
Exhibit No. 517 was marked for identification.)
MR. RICHARDSON: Ready?
COMMISSIONER SMITH: Yes.
MR. RICHARDSON: Thank you.
Q. BY MR. RICHARDSON: Mr. Stokes, before the break,
we were discussing how the addition of this 294 megawatts of
wind contracts in 2010 was disruptive to the IRP process. Do
you recall that discussion?
A. Yes, I do.
Q. And then I handed out what's marked as
Exhibit 517, and I'll ask you now if you recognize that.
A. Yes. It appears to be a page out of our 2011
IRP.
Q. And do you see a section on Exhibit 517 entitled
Public Utility Regulatory Policies Act?
A. Yes, I do.
Q. And in the second paragraph of that section is a
paragraph that begins "Generation from PURPA contracts." Would
you please read the second and third sentences into the record
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from that paragraph?
Into the record, please.
A. I'm just trying to see exactly what's in the
paragraph. I'd rather read the whole paragraph into the
record.
Q. That would be fine.
A. "Generation from PURPA contracts has to be
forecasted early in the IRP planning process to update the load
and resource balance. The forecast used in the 2011 IRP was
completed in September 2010 and did not include approximately
500 megawatts of wind contracts that were signed in late 2010.
Because Idaho Power's future resource needs are driven by
capacity requirements and not energy, the exclusion of these
new contracts does not have a material impact on the 2011 IRP.
At the five percent peak hour capacity factor used for wind
resources for planning purposes, the 500 megawatts of PURPA
wind contracts represent only 25 megawatts of capacity for peak
hour planning."
Q. Thank you, Mr. Stokes. Is the 294 megawatts of
unannounced wind a subset of that 500 megawatts?
A. Yes, I believe that it would be a part of that.
Q. So your testimony here is that 294 megawatts of
unannounced wind is frustrating and circumventing the IRP
process is all for naught, isn't it, if 500 megawatts is deemed
to have no material impact on your IRP?
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A. No material impact from the standpoint of it's
not displacing any Utility resources, or a very, very small
amount of capacity that's needed in the summertime. That's the
purpose of the last sentence there: The 500 megawatts of PURPA
wind contracts represent only 25 megawatts of capacity for peak
hour planning.
That's the purpose of my statement that it's
frustrating the process, that even with all of this wind, we
still have to go out and build other resources.
Q. But you didn't -- I'm confused. 500 megawatts is
immaterial where 294 megawatts is significant enough to
frustrate the whole process?
A. I think I'm talking about the same thing. It's
just in the point in my direct testimony is that in a two-month
window, there was 294. The batch in -- that's being talked
about here in the IRP is over a little bit broader time frame,
but the same thing is going on there.
Q. On page 46 of your rebuttal testimony, there on
line 15 in discussing the $45 delay damage security, you state
that, quote: The Commission has specifically found that --
this requirement to be in the public interest, and a just and
reasonable requirement of the contracting practice.
Do you see that?
COMMISSIONER SMITH: "Process."
THE WITNESS: Process.
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Q. BY MR. RICHARDSON: Practice. Did I say
"process"?
MS. SASSER: Process.
THE WITNESS: "Process" is the last word of that
sentence.
Q. BY MR. RICHARDSON: I apologize, but do you see
that with that correction?
A. Yes, I do.
MR. RICHARDSON: Madam Chair, may we approach?
COMMISSIONER SMITH: You may.
MR. RICHARDSON: Thank you.
Q. BY MR. RICHARDSON: Now, Mr. Stokes, we asked the
discovery question of the Company as to what you relied on when
you made that statement, and that would be Exergy Development
Group Request for Production Number 66, and I'm handing out as
Exhibit No. 518 a copy of your Response.
(Clearwater Paper Corporation, et al,
Exhibit No. 518 was marked for identification.)
Q. BY MR. RICHARDSON: And in your Response, you
actually refer us to Idaho Power's legal brief. And in that
Answer, at the very bottom, after a long series of case number
citations, there's a sentence that begins "In approving the
change." Could you read that into the record for us, please?
A. Yes: In approving the change in the amount of
delay damage security that is acceptable for such contracts
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S :1- from 20 to $45 per kilowatt of nameplate capacity, the
2 Commission specifically found such delay security to be
3 reasonable, necessary, and not to be punitive. Order No.
4 31034.
MR. RICHARDSON: Madam Chair, may we approach?
COMMISSIONER SMITH: (Indicating.)
MR. RICHARDSON: Madam Chair, I'm handing out
exhibit number -- Order No. 31034 and ask that it be marked as
Exhibit No. 519.
MR. WALKER: Madam Chair.
COMMISSIONER SMITH: Mr. Walker.
MR. WALKER: I would object to this. He's citing
a Discovery Response that is quoting Idaho Power's legal brief,
and now he's admitting an Order that was cited by that legal
brief which is cited in the discovery, and he's really -- I
don't know if he's asking a question or if he's doing oral
argument from the legal briefs, and I object to this tactic.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Madam Chair, I'm not engaged in
oral argument. I'm cross-examining this witness on a statement
he makes in his testimony to the effect that the Commission has
specifically found this requirement to be in the public
interest and a just and reasonable requirement of the
contracting process. And in discovery, we asked this witness
or the Company to identify the source of that document. They
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referred us to Idaho Power's legal brief. They did not refer
us to the Commission's Order. They didn't answer the
Production Request because they said they cited as authority
Idaho Power's legal brief. So, I want to get into the
authority that he relied on and see what it says.
COMMISSIONER SMITH: Well, just remember that
Commission Orders speak for themselves, so what different
people's interpretations are may or may not be relevant.
MR. WALKER: It's irrelevant, Madam Chair,
whether he agrees with Mr. Stokes or not. And like you said,
the Commission Order speaks for itself. And I think the
Commission is the best body to determine what that Order says
and what it means.
MR. RICHARDSON: Well then, Madam Chair, I would
move to have the sentence stricken from the witness's testimony
if he's not prepared to be examined on it.
COMMISSIONER SMITH: Well, I think,
Mr. Richardson, you may ask your question, but just remember
that the Commission's Order speaks for itself, and your
characterization of it or his characterization of it may be
neither here nor there.
MR. RICHARDSON: Thank you, Madam Chair.
(Clearwater Paper Corporation, et al,
Exhibit No. 519 was marked for identification.)
Q. BY MR. RICHARDSON: Mr. Stokes, would you point
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to me in Exhibit 519 where the Commission made a specific
finding that the liquidated damages deposit is not a penalty?
A. I may have to read the whole thing here to find
it.
I assume are you interested in the Commission
Decision and Findings?
Q. That's where it will be, yes.
A. Again, do I need to read a Commission Order that
it's my understanding that it stands on its own?
Q. That's a sufficient answer, Mr. Stokes.
Have you had a chance to review Dr. Reading's
testimony?
A. I did read through it a while back.
Q. I'm going to refer you to page 38 of
Dr. Reading's direct testimony. We'll make a copy available to
you.
A. Okay, yeah, I'll need a copy.
Q. You don't?
A. I don't have it with me, no.
Q. Okay, we'll bring you one.
MR. SOLANDER: I'm sorry, did you say his direct
or his rebuttal?
MR. RICHARDSON: His direct.
Q. BY MR. RICHARDSON: Do you have that in front of
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A. Yeah, page 38 is what it's opened to.
Q. And there on page 38, rather than going through
the exercise of introducing another Order and trying the
Commission's patience, I'll ask you to read what the Commission
declared, as quoted in Dr. Reading's testimony, of Order No.
30608, page 3. Could you read that into the record, please?
A. The quoted paragraph near the top?
Q. Correct.
A. Okay. From Dr. Reading's testimony:
The Commission declared: Therefore, the
Commission finds that such provisions calling for delay
security should not be punitive in nature. Rather, the amount
of delay security ultimately provided in this case, as well as
future energy sales agreements with other PURPA suppliers,
should constitute a fair and reasonable offset of a regulated
Utility's estimated increase in power supply costs attributable
to the PURPA supplier's failure to meet its contractually
scheduled operation date.
Q. Do you agree that a liquidated security provision
should not be punitive?
A. Yes. The whole intent is to keep Idaho Power
customers whole.
Q. And do you agree that a liquidated security
provision should be a reasonable offset of your increased power
supply costs caused by a QF'S delay in coming online?
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A. In general terms, yes.
Q. But isn't it true that the $45 liquid security
you recommend in this case doesn't even purport to be related
to any of your increased power supply costs, does it?
A. From my -- I believe it's in my rebuttal
testimony on page 47, and I assume this is what you're
referring to and I'll go ahead and just read from that,
starting the bottom of page 46, in the section on liquidated
damages:
This highlights an important part of Idaho
Power's case that it provided much evidence of in its direct
testimony, and that is, typically the Company can acquire
replacement power from other available sources at a cost that
is below the contract price in the PURPA contract. This,
however, is not the only measure of harm and damages. In
addition to the system operation and planning problems that the
failure to bring generation units online in a timely manner and
when they are scheduled to come online, there is a substantial
value that the QF gets by locking in a price, and a pricing
stream with its contract. If a QF is allowed to come online,
or not, at its choosing with no consequences and no liability
for the value of that option, then customers are left in a
financially-disadvantaged position and uncompensated for the
price lock and option they extended to the QF.
MR. RICHARDSON: Madam Chair, I promise, this is
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the last time. May we approach?
COMMISSIONER SMITH: You may.
MR. RICHARDSON: Thank you. I'm handing out what
is marked -- what I'd like marked as Exhibit 520 for
identification purposes, comments of the Commission Staff dated
July 10, 2012, in Case No. IPC-E-10-22.
(Clearwater Paper Corporation, et al,
Exhibit No. 520 was marked for identification.)
Q. BY MR. RICHARDSON: Would you turn to page 5 of
these comments. So these comments were filed by the Commission
Staff in July of this year, just about one month ago. So,
presumably, the Staff of the PUC would have had the benefit of
your viewpoint on liquidated damages when it wrote these
comments, don't you think?
A. I can't speak to that.
MS. SASSER: I'm going to object to the question
as to whether Mr. Stokes, a witness for Idaho Power, would have
any idea what Staff knew or didn't know when we filed these
comments.
MR. RICHARDSON: I'll withdraw the question,
Madam Chair.
COMMISSIONER SMITH: Thank you.
Q. BY MR. RICHARDSON: On page 47 of your testimony,
of your rebuttal testimony, you state that Idaho Power's
disadvantaged if a QF is allowed to come online, or not, at its
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1 choosing with no consequences and no liability for the value of
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that option. And since you're not a lawyer, you probably don't
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know what liabilities and consequences a QF could suffer at the
hands of the Utility if it breached its contract to deliver
power, do you?
A. You're asking me what liability a QF faces?
Q. I'm asking if you are opining on what liabilities
and consequences a QF could suffer if it breached its contract
to deliver power.
A. No, I would not have an opinion on that or any
knowledge of it.
Q. And then on Exhibit 520, if you would turn to
page 5?
A. Which exhibit was that?
Q. The one that was just handed to you, Staff's
comments.
A. The Staff comments.
Q. Would you read that paragraph that begins with
the word "nonetheless" into the record?
A. "Nonetheless, the proposed settlement eliminates
the uncertainty in additional cost and resources necessary to
litigate the termination of the agreement and validity of the
delay liquidated damages. While Staff would normally be
reluctant to recommend approval of a settlement that appears
inconsistent with the express terms of the contract, Staff
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recognizes that the current circumstances may support
acceptance of the proposed settlement. Currently, electric
market prices are far below the avoided cost rates specified in
the contract. Consequently, the actual damages to Idaho Power
as a result of contract default are likely minimal, and, in
fact, Idaho Power could arguably be better off because
Yellowstone has defaulted. The terms of the proposed
settlement acknowledge some liability for Yellowstone's default
while also acknowledging some uncertainty about the actual
amount of damages to Idaho Power. Approval of the proposed
settlement will also avoid litigation. Consequently, Staff
believes that the proposed settlement is in the public
interest."
Q. Thank you. Back in your direct testimony at
page 45, you recommended the Commission establish a formal
process and procedure to eliminate problems with the contract
negotiation process and procedure. Do you recall that,
generally?
A. Yes, I do.
Q. But you did not recommend such a process or a
procedure in your direct testimony, did you?
A. Not in direct, but in rebuttal I did.
Q. And in your rebuttal, you introduced proposed
Schedule 73, patterned after PacifiCorp's Schedule 38.
Correct?
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A. Yes, I believe that's the number of it.
Q. So whose testimony are you rebutting with the
presentation of this proposed schedule?
A. Basically, showing -- well, part of the exhibit
is a red-lined version of the Rocky Mountain Power proposal
that was submitted in direct, which is what we did as a part of
creating our proposed Schedule 73.
Q. And are you aware that by filing this as rebuttal
testimony, you have precluded the parties from reviewing your
recommendation and providing their experts' opinions on its
merits or lack thereof?
A. That was not my intent. At the time I filed
direct, we simply didn't have -- have a draft proposal put
together.
Q. Do you think that's fair to the other parties?
A. I can't comment on that. It's, in essence, the
same thing that Rocky Mountain Power proposed in their direct,
so from that standpoint, I don't think it's unfair.
Q. So when you put this together, did you get Idaho
Power legal review of the document?
A. Yes, our legal department reviewed it.
Q. And would you turn to your exhibit,
Schedule 73 -- I forget what exhibit number it is -- Exhibit
No. 11, in the section marked I.- -- it's on page 5 of nine --
-B.7., which is actually on page 6 of nine?
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1 A. Okay, Paragraph B.7.
2 Q. Yeah, I.B.7. says Procedures, paren, continued.
3 Do you see that?
A. Yes, I do.
Q. And in that Procedures section, it says at the
very last sentence: Prices and other terms and conditions in
the power purchase agreement shall not be final and binding
until the power purchase agreement has been executed by both
parties and the Idaho Public Utilities Commission approves the
agreement.
Do you see that?
A. Yes, I do.
Q. And did your lawyer specifically look at that and
tell you it was current state of the law, it was legal?
MR. WALKER: Objection, your Honor: That's
attorney-client privilege and improper for him to examine upon.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: I'll withdraw the question,
Madam Chair.
Q. BY MR. RICHARDSON: And in Section 7, beginning
with the words "The Company reserves the right to condition" --
where did I find that?
COMMISSIONER SMITH: Second sentence.
Q. BY MR. RICHARDSON: Oh, never mind. I got ahead
of myself.
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Given Schedule 73's recitation of the FERC
separation of functions in Part II, why would you make a power
purchase agreement contingent upon the execution of an
interconnection agreement?
A. Is there a paragraph here you're referencing
or --
Q. In your Schedule 73, you reference that a
condition of the power purchase agreement is the execution of
an interconnection agreement, and I'm asking you if you have
any understanding of the interplay between the power side and
the transmission side, and why the two meet in this power --
this process for obtaining a power purchase agreement.
A. Yeah, I don't know that I can accurately comment
on that. I mean, the group that I manage has been responsible
for the contract negotiations with the firm energy sales
agreements, but myself have not been involved with the
generator interconnection agreement process.
Q. But with this, you will be now?
A. Well, actually not, because that's not -- the
contracting process is not in my group anymore, so
Q. Okay. Well, that's a good answer.
In Section III -- and that would be on page 9 of
nine -- is a prohibition against either party from filing a
complaint at the Commission until 60 calendar days after a
notice is given that the two parties can't reach agreement on a
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1 specific term. Is that a holdover from this tariff schedule

2 you marked up, or is that a new process you're actually
3 recommending? Did you mean to delete that or did you really

4 want to leave that in there?

5 A. I think our intent was to leave it in there, and

6 again, I believe it was in Rocky Mountain Power's proposed

7 Schedule 38 that they filed with direct testimony.

8
Q. So if we get in a dispute with Idaho Power, we're
9 precluded from going to the Commission for help for 60 days?

10 A. That's how I would read that, at least from

11 filing a complaint.
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Q. And then the very last sentence in that section
says: This includes, but is not limited to, any disputes that
are not resolved through the procedures set forth in Part
Do you see that?
A. Yes, I see that sentence.
Q. And if we turn to I.B.6., which is on page 5 -
and I read through it and you can certainly take the time to do
it, but all I find here on dispute resolution is a reference
back to Part III, so it seems to be circular. And that's at
sub (E) at the very bottom of the page.
COMMISSIONER SMITH: So is there a question
there, Mr. Richardson?
Q. BY MR. RICHARDSON: The question is isn't it
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A. Well, this -- I guess my take on this -- this
section is that as the parties are passing back and forth the
terms of the contract, if there are any disputes, Part E at the
bottom directs you to the -- that last Section III at the
end --
Q. Right, and all that Section --
A. -- which is to file a complaint.
Q. -- III does is say you can't go to the
Commission.
A. No, it says you can go to the Commission.
Q. Well, you have to wait 60 days.
A. Doesn't say you can't go to the Commission
though.
Q. But you can't file a complaint. Typically when
you go to the Commission to force a Utility to do something,
don't you have to file a complaint?
A. That's the typical method.
Q. So given that your Schedule 73 seems to have
been -- forgive the characterization -- an afterthought because
you filed it as rebuttal, don't you think it might be
reasonable for the Commission to not rule on the process and
procedures, but give the parties a chance to either engage in a
new proceeding to look at it, or perhaps convene workshops or
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collaboratives or something to see if the parties can work
these out?
A. By including this in my rebuttal, it's basically
Idaho Power's comments on what was proposed by Rocky Mountain
Power in their direct testimony.
Q. Thank you, Mr. Stokes.
MR. RICHARDSON: Madam Chair, that's all I have.
COMMISSIONER SMITH: Mr. Miller.
MR. MILLER: No, ma'am.
COMMISSIONER SMITH: Mr. Uda.
MR. UDA: I have no questions, Madam.
COMMISSIONER SMITH: Mr. Williams.
MR. R. WILLIAMS: Yes, Madam Chair, I have a few
questions.
CROSS-EXAMINATION
BY MR. R. WILLIAMS:
Q. Good afternoon, Mr. Stokes.
A. Good afternoon.
Q. You mentioned earlier that -- correct me if I got
it right (sic) -- 6,000 megawatts of wind would equal the
capacity of Langley Gulch. Did I get that correct?
A. Yes. The five percent capacity factor applied to
6,000 megawatts of wind would give you 300 megawatts of
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reliable capacity.
Q. How many megawatts of wind does Langley Gulch
allow you to integrate?
A. Oh, that's difficult, if not impossible, to say,
because integration is such a complex topic. It's going to
vary by time of year, it's going to vary depending on what kind
of water we have for the hydro system, what loads are.
Q. Have you heard of the computer model PLEXOS?
A. Yes, I have.
Q. Okay. And what is -- well, isn't -- didn't WECC
just run PLEXOS on a Western regional basis to determine the
ability of all of the balancing authorities, including Idaho
Power, to assimilate variable generation?
A. I'm not familiar with that work that WECC may or
may not have done.
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16 Q. Are you familiar with the proposal for a Western
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lean on each other on a less-than-one-hour basis to help each
19 other out with capacity to support variable generation?
20 A. I'm familiar with it. I'm not overly
21 knowledgeable about it. Idaho Power witness Tess Park might be
22 better suited to answer that question, where she's in our
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respect to what the market is supposed to do.
MR. R. WILLIAMS: Okay. Thank you, Madam Chair.
As we go into that, I realize the State Commissions have
probably more -- as much leadership in this as the Utilities
do, so I will save my questions then for Ms. Park.
Q. BY MR. R. WILLIAMS: Now, Mr. Stokes, you're the
witness that proposes and supports the Company's proposal that
PURPA contracts be limited to five-year terms. Correct?
A. Yes, I am.
Q. Okay. And on Idaho Power -- in Idaho Power's
brief, they reference three states that had in the past -- and
this includes Idaho -- limited PURPA contracts to five years,
and the other two states references including Oregon and
California. Do you recall that?
A. You're saying that was in our Company's legal
brief?
Q. That was in your brief, that's correct.
A. I vaguely recall it.
Q. I could read it to you, but it might help us go
faster if you accept my representations of that.
So, do you know if -- we know what -- obviously,
where Idaho is. Do you know, is either Oregon or California
currently restricting PURPA contracts to five-year terms?
A. Not to my knowledge, they aren't. Again, we have
with our Oregon -- small Oregon service territory, we have a
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few PURPA contracts in Oregon and obviously in Idaho.
Q. But your Oregon contracts are not five-year
3 contracts. Correct?
A. No, they are not.
Q. And also in the legal brief, there's a
representation made that five-year contracts -- and I quote
direct -- I use these words that -- will not fatally inhibit QF
financing. I assume you agree with that statement?
A. I don't know that I can comment on that myself.
I mean, I've never had to go out and get financing for a
project.
Q. Now, Idaho Power has a subsidiary company called
Ida-West?
A. Yes, they do. IDACORP has a subsidiary.
Q. IDACORP. And they own PURPA contracts, they have
projects, or partly own four of -- they own four in Idaho and
five in California?
A. That's correct.
Q. And you were, at one point in your career, the
CEO of Ida-West. Is that correct?
A. President of the company.
Q. President. You were the head guy there?
A. Yes, I was.
Q. With the nine PURPA projects that Ida-West owns
that you managed, were they all project financed?
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A. They all were or had been. I believe there were
a couple of them that had been paid off.
Q. But originally, well, as an alternative, they
were not financed using the equity of the balance sheet of the
parent company IDACORP; they were financed by Ida-West on a
project finance basis where you went out and placed a debt on
each project. Correct?
A. They were, yes.
Q. And do you know what the debt service terms were
for let's just pick the four projects in Idaho?
A. Oh, that's been long enough ago, I just don't
recall.
Q. Do you recall the contract lengths for those fourl
A. I know they were at least 20 years. I think some
of the earlier ones may have been longer than that. Again,
when I went over there, in the short time I was there, I was
there basically to manage the operating portion of the company
and was not involved directly in any kind of financing
activities.
Q. Sure.
A. All of the financing had previously been set up
for all of the projects.
Q. And what about the five PURPA projects in
California, do you recall what the length of the contract terms
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1 for those, or the financing?
2 A. No, I do not, Mr. Williams. It's -- again, it
3 was 2006 when I left over there. I just don't recall any of
4 the details.
Q. So, Mr. Stokes, on page 33 of your rebuttal
testimony -- let's turn to that. And it caught my eye. On
line 8, you say you have no firsthand knowledge on whether
project financing would become more difficult for QF
developers.
You are the one unique witness for Idaho Power
that actually worked in the QF independent power industry, yet
you have no knowledge of project financing or what would be
required -- or, you would have no firsthand knowledge on what
it would take to put together a financing for a PURPA project?
A. No. Again, like I previously stated, when I went
over to Ida-West, the company was no longer looking at actively
developing any new projects. The extent of my involvement with
the banks was basically making the required debt payments on
whatever basis or terms were in the financing arrangement that
had all been set up prior to my going over there.
Q. Now, switching topics a little bit, you're the
sponsor of Exhibit 73 -- or, Schedule No. 73, and I know
Mr. Richardson went through this with you a little bit, but the
Idaho Power legal brief argues or makes the statements that --
two statements: There's no material significant objections to
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Schedule 73 raised, and then, secondly, that Schedule 73 is
ripe for Commission approval.
If Schedule 73 came in on -- attached to your
rebuttal testimony, when would any of your parties have had the
opportunity to object to it?
MR. WALKER: Objection, Madam Chair. This is the
exact same question that Mr. Richardson previously asked.
COMMISSIONER SMITH: Mr. Williams.
MR. R. WILLIAMS: Then I will consider it
answered as well.
COMMISSIONER SMITH: Sorry about this buzzing.
MR. R. WILLIAMS: That's okay.
Q. BY MR. R. WILLIAMS: Idaho Power proposes that
the IRP pricing be updated when a new QF comes in and requests
a power purchase agreement. Correct? I know that's in
Mr. Bokenkamp's testimony. You're familiar with that?
A. Yes, it is in Mr. Bokenkamp's testimony that that
is proposed.
Q. And we can generally accept that you have roughly
119 contracts under signature?
A. As of the end of last year when we did direct
testimony, that was the number of contracts at that time.
Q. And you have some number of projects that are in
the queue at this point. Is that correct?
A. Yes, there is some number in various stages.
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Q. Can you give me a ballpark of what the number
might be of those in the queue?
A. I couldn't really. Again, since back in about
February, the contracting side of PURPA contracts is no longer
within the group that I manage.
Q. Sure. Do you think it's more than 50?
A. No, I don't believe it's more than 50.
There is a spot in my testimony -- or, actually,
if you go back to the stay of -- the request for a stay, and I
don't have that in front of me, but we had the numbers in there
at that time as of like March of this last spring, and I
believe it was 27 projects at that time, if I remember.
Q. Okay. Now, Idaho Power's brief says that the
contracts will remain in the queue until the Company has
received a withdrawal request from the QF.
Have you ever received a withdrawal request from
a QF, that they no longer want to be considered in a queue?
A. In the queue as far as the transmission or the
interconnection queue?
Q. Let's get away from the use of the word "queue."
Let's just say that of all of the world of requests for
contracts, some of them come true, some of them don't. How
many developers have given you the courtesy in a written format
to say, "Don't count on me anymore. Take me off your list."
A. Oh, I mean, I'd be speculating on that, because
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I'm not the one that has dealt with them firsthand. It
wouldn't be a large number, but I know there have been some
that have done that.
Q. Could be a few nice guys like me that would just
write you and say, "We're dead," but --
A. Yeah.
Q. -- most people probably would just go away.
Right?/
A. Yeah, it's hard to say whether they would
actually just go away or there may be various things. I mean,
they do typically, I think, communicate something to us at some
point. Sometimes, that takes a long time to happen, but --
MR. R. WILLIAMS: I have no further questions.
COMMISSIONER SMITH: Thank you.
Mr. Arkoosh.
MR. ARKOOSH: Thank you, ma'am.
CROSS-EXAMINATION
BY MR. ARKOOSH:
Q. Mr. Stokes, I'd like to follow up on a question
that was asked Ms. Grow, and I don't know if you know the
answer or not. Ms. Grow testified that the price of QF power
is passed through to the ratepayers, and that's your concern in
the hearing. Do you know what happens to the income that you
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receive from the RECs that you sell?
A. Yes. The RECs that the Company sells and for
some time now also passes through the PCA at I believe 100
percent as well, so the benefit of that goes back to customers.
Q. And is it divided among the states you service as
well?
A. That, I'm not positive. That would be a more of
a rate-related question. My guess is that it's all Idaho, but
I'm not positive.
Q. Would you look at page 16 of your testimony,
please, Mr. Stokes, and you have a chart?
A. Direct?
Q. Page 16.
A. Of direct testimony or rebuttal?
Q. Yes, direct, sir.
Have you found that?
A. Yes, I have.
Q. And there is a chart, and on it, on the
right-hand side of the horizontal bar, you have estimated PURPA
price and Mid-C forwards. Do you see those two dotted lines?
A. Yes, I do.
Q. And they're both in an upward market. Correct?
A. They are both increasing, yes.
Q. And it looks like the way you anticipate things
are we're sort of at a nadir today in terms of energy price.
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Is that right?
A. We're what again?
Q. We're low, low as we can go?
A. Oh, yes. Yeah, definitely, as Mr. Kalich
testified earlier, there is a kind of an oversupply of
resources in the Northwest. That, coupled with low gas prices,
has really depressed energy market prices.
Q. I guess gas prices are phenomenally low right
now. Is that correct?
A. Yeah, I think that would be a fair statement.
Q. You advocate a five-year contract because you say
on page 46 a 20-year contract shifts market price risk from the
project developer/owner entirely onto Idaho Power's customers.
Is that your position?
A. Is this in direct?
Q. Yes, sir, page 46.
A. And what -- can you reference a line there --
Q. No, I can't.
A. -- where 46 primarily contains my concluding
remarks.
Q. I might have the wrong page. Notwithstanding
that, is that your position, that a 20-year contract -- and
listen to the sentence in my question -- a 20-year contract
shifts market price risk from the project developer/owner
entirely onto Idaho Power's customers?
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1 COMMISSIONER SMITH: It's on page 45.
2 MR. ARKOOSH: Thank you, Madam Chairman.
3 COMMISSIONER SMITH: Lines 16 and 17.
4 THE WITNESS: Yes, that is correct, and in my
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direct testimony.
Q. BY MR. ARKOOSH: And then you also say that
hedging the variable market value of the energy for fixed
prices contained in the contract -- you say that PURPA projects
are hedging the variable market value of energy for fixed
prices contained in the contract. Do you recall that?
A. Yes, they, by signing the contract and getting
the fixed prices, they basically lock that in. And they
have -- it's back to the whole option issue that was discussed
earlier.
Q. Correct, an option versus a contract?
A. Yep, exactly.
Q. Mr. Stokes, if you are a buyer of product and you
are in a low market, isn't that the buyer that hedges forward
into an anticipated higher market and the buyer has the benefit
of the hedge, not the seller?
A. Let's see. Well, for -- from a -- the QF
developer standpoint, if they lock in a price that is, you
know, substantially higher than a market rate, they have the
option of either performing on that contract and getting that
rate; or if rates were to go higher, they have the option of
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not performing on that and getting a higher price, potentially.
Q. Well, my point is this; you said that the QFs are
hedging, and my point to you is this: If you think you're
going to need shoelaces into the future and shoelaces are a
penny today and you think they're going to be a dime into the
future, wouldn't you want to hedge against that and buy an
extra shoelace today?
A. You could.
Q. Wouldn't the rational investor want to, given
these low gas prices?
A. I think so, but the point of that is that the
hedge would not be a free hedge. That would come at a cost.
Q. Well, any kind of energy capacity comes at a
cost. "Energy capacity," I didn't mean to say. Any kind of
capacity comes at a cost?
A. Certainly.
Q. So that I didn't quite get it and I don't know if
the question was asked of you directly, but do you know what
the economic life of these -- most of these QF projects are,
small hydro, for instance? They're a lot more than five years,
aren't they?
A. Oh, I would certainly expect so. I mean, it's
going to vary by resource type.
Wind I think is hard to say right now because so
many of the turbines are so new.
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Small hydro, you know, as long as it's
maintained, should last for a long time.
Q. So if you -- these five-year contracts are not
going to last long enough. If the Commission orders five-year
contracts, it's not going to last long enough to meet the or
equal the useful life of the project. Do you agree with that?
A. That the five-year contract would expire prior to
the --
Q. -- expiration of the useful life.
A. Certainly for some or most projects I would
expect that, but then they have the option of signing up for
another five-year contract.
Q. Well, let's just stick with the one five-year
contract for a minute, and I do understand your theory about
serial five-year contracts.
The one five-year contract wouldn't allow for
cost recovery on the useful life of the project ordinarily?
A. Ordinarily, I don't think it would.
Q. Okay. And that would make financing very
difficult, would it not?
A. Again, I don't -- I'm not a banker and I don't
have any direct experience in the financing arena.
Q. The projects in your IR? have a useful life of a
30-year plant life, don't they?
A. That's the typical life that we assume. Again,
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if you're going to compare resource -- Utility-owned resources
in the IRP versus QF resources, in my mind, they're not the
same thing.
Q. I grant you they're not the same thing, nor are
they treated the same legally, but you do finance yours over
longer than five years, do you not, or if you know?
A. We typically do, I believe.
Q. How long?
A. Oh, that, I couldn't tell you what the typical
term would be.
Q. Longer than 20 years, generally?
A. Most likely, but again, I can't comment
specifically on that.
Q. Okay. Let me -- have you read Mr. Sterling's
testimony?
A. I did, yes.
Q. Okay. Mr. Sterling testified at page 28 of his
testimony, and this was the question:
But won't a five-year limit on maximum contract
length, if approved, severely limit the ability of projects to
obtain financing, thus making extensive project development
unlikely?
And he answered in the first sentence, and this
isn't all of the answer:
I agree that development would likely slow
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considerably, at least under PURPA.
Do you recall having read that?
A. It sounds familiar.
Q. Do you agree with that?
A. I guess in general. Again, I don't have any
experience in financing or what the impact of that might be.
Q. And you know the command of PURPA is to
encourage, not discourage, cogeneration and small power
development?
A. I do, but it's my understanding that the
encouragement comes in the form of the Utility having the
obligation to purchase it, not in providing any sort of terms
or pricing that makes it happen.
Q. If you have a series of five-year contracts, as I
understand, what would happen is the first five-year contract
would go into your plan, the capacity for that one would go
into your plan, for a period of five years only. Is that
right?
A. When you say "plan," are you talking about the
IRP?
Q. Yes, sir.
A. Yeah, that would be how we would handle that
where -- the typical practice is to include signed and approved
contracts in our load and resource balance that we use for the
IRP.
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Q. And then at year five that contract, under what
you would anticipate, would be replaced, and it would go then
another five years' capacity would show up in your IRP. Is
that correct?
A. I guess that would all depend on the actions of
the QF developer, if they had started the process of getting a
new contract in line, and how that fell in with the timing of
when we're doing the IRP as to whether it would or wouldn't be
accounted for, I guess.
Q. So what would really happen between year one and
five, the capacity, the 20 or 30 years of capacity that plant
could provide that ordinarily would be in your IRP in a 20- or
30-year contract, would be displaced by newer capacity
developed either by the Utility or others. Is that correct?
A. Yeah, potentially, outside that five-year window,
I guess.
Q. You read some language for Mr. Richardson from
your rebuttal testimony about a developer receiving a benefit
from locking in a long-term price, and if you didn't have a
liquidated damage provision it was unfair for them to receive
that benefit without a liquidated damage provision. Do you
recall having read that from your rebuttal?
A. Yeah, let me go back to that. I believe that was
about page 46 of my rebuttal.
Yeah, the bulk of what I read was kind of at the
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top of page 47.
Q. Was that a fair paraphrase of it?
A. Can you state it again?
Q. That the developer would receive the benefit of
having levelized -- have a levelized price, and if he didn't
step up to the plate he should pay liquidated damages, because
it was unfair for him to receive that benefit then back away?
A. Well, I think in what you're talking about,
there's kind of two things going on. One is the kind of the
put option that's been discussed.
The other one related to the liquidated damages
has to do also with the fact that if we're planning on a QF
resource coming online, we've got that factored into our
medium-range planning process and we are buying and selling
energy on a 18-month-ahead basis, up to 18 months, counting on
that QF energy being there. So to the degree at the last bend
if it doesn't show up, there's potentially an impact on our
customers from having to go out and acquire that at a late
date.
Q. I'm going to go back and read the language. It's
at page 47, line 6. I'm going to start in the middle of the
sentence. It says:
There is the substantial value that the QF gets
by locking in a price, and a pricing stream with its contract.
If a QF is allowed to come online, or not, at its choosing with
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no consequences and no liability for the value of that option,
then the customers are left in a financially-disadvantaged
position and uncompensated for the price lock and option they
extend to the QF.
Do you see that language?
A. Yes.
Q. Is that what you're talking about?
A. Yes, and that's the option piece that we
discussed.
Q. Okay. But there's no option under a contract.
You either show up with power or pay damages, don't you?
A. Yeah, in essence, the QF developer is getting a
free option. There's nothing contractual about it, but it is
what happens.
Q. Well, Idaho Power has sued people for
nonperformance, has it not?
A. Oh, certainly in the past, we've tried to.
Again, the issue I think with QF developers is that most, if
not all, of these companies are LLCs that don't have a balance
sheet, so it's almost pointless to try to pursue that.
Q. You have suggested an eligibility cap of 100
kilowatts for all resource types because it would minimize a
risk to customers of paying higher than avoided cost rates due
to unforeseen circumstances or events. Is that your position?
A. It is, and that --
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Q. Well, Mr. Stokes, we'll get into it in just a
minute if that is your position.
A. Yes.
Q. Okay.
A. We believe that the eligibility cap should be set
at 100 kilowatts for all resource types.
Q. And are there other -- and so the idea is to
protect your customers from paying higher than avoided cost
rates. Is that right?
A. Yes, ultimately, through any kind of changed
condition that might happen.
Q. So -- but there are other pricing mechanisms to
accomplish the purpose, are there not?
A. I suppose so. I mean, I believe what Idaho Power
has proposed in this case is a good way to calculate avoided
cost rates.
Q. Well, one of them is set the avoided cost rate
right, isn't it?
A. That's our intent is to set an accurate avoided
cost rate.
Q. By "right," "accurate" is a better word, thank
you, Mr. Stokes.
And you agree with Mr. Schoenbeck that this low
cap will make virtually all QF projects negotiated rather than
scheduled?
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A. It would potentially make most of them. There
are some smaller than 100 kilowatts that are out there, but
most of them are larger.
Q. So almost all of the projects then, fair enough.
Almost all of the projects will have to come to Idaho Power to
negotiate rather than have a scheduled rate?
A. Yes, in general.
Q. And it will add to the up-front transactional
costs for the project, for the Commission, and, frankly, for
the Utility as well, will it not?
A. I don't see it that way. Again, to me, the
beauty of lowering the cap to that amount in the methodology
the way we proposed it, if you set published rates with the
same methodology, those rates will stay the same as a
negotiated rate. As long as all of the assumptions that went
into it, be it from the IRP or whatever else, as long as those
conditions don't change, the published rates and the negotiated
rates are going to be virtually identical.
Q. Mr. Stokes, do you see the irony of that? If
they're going to be the same, then it is equally beneficial
without the transactional costs of negotiation is to set
scheduled rates and have a ten megawatt eligibility cap if the
rates are going to be the same. Don't you agree?
A. No, I don't, because, again, the intent of
setting that cap low is that in the event there is any kind of
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a changed condition, that you can actually make changes in the
avoided cost calculation, and that will protect the customers
from any kind of a higher avoided cost rate that may not be
appropriate.
Q. Well, you're going to look at these rates every
two years with the IRP planning. Is that right?
A. That's what we proposed, that it would be tied to
the IRP cycle.
Q. So let me understand this correctly. This IRP
process, as it was discussed earlier, is a process where a
group of people get together and put together a resource plan
and present it to the Commission for acceptance but not
approval. Is that right?
A. I think that's a fair characterization of it.
Q. So if I had a project, there's not necessarily a
hearing process that accompanies that?
A. The IRP?
Q. Yes, sir.
A. No, the IRP, once it's filed, is usually handled
through modified procedure, but certainly, I mean, that's not
to say that there isn't a whole lot of scrutiny that goes on.
Again, with the IRP advisory council, we meet
with that group once a month as we're preparing the plan. All
of the assumptions and inputs that go into it get thoroughly
vetted with that group, which includes Idaho and Oregon PUC
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Staff representatives. Once we file the plan, it gets posted
and it's open for public comment, we do public meetings
throughout our service territory, and we go through the whole
modified procedure process. So, in my mind, it gets a lot of
Well, here's my concern, and you tell me if I'm
What the Company wants is a low eligibility cap -- what I
what that will do to financing. And then they want to go
through an IRP project mostly outside of the PUC avoided cost
setting process, but that process will pretty much give us the
need for capacity and set the avoided cost.
So that's what I see the Company's program as,
and I -- don't you agree that that's a remarkable set of
disincentives to develop alternative energy?
A. I'm not sure I followed the last part of what you
were saying there. I mean, in the methodology that Idaho Power
has proposed, the hourly incremental cost methodology, we used
the AURORA model to basically determine the dispatch of Idaho
Power's resources. And then that flows through just through a
spreadsheet model that actually calculates the avoided cost
rates. Outside of that, there's really no tie-back to the --
to the IRP itself or anything else with it outside of if you
am
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are talking about first year deficits and that issue on the
capacity side.
Q. Well, I can't get down the AURORA needs with you.
I know Mr. Schoenbeck says there's to be two model runs and the
Company wants one.
A. Well, the IRP methodology employs two AURORA
runs. The new methodology we proposed only requires one.
Q. Correct. But my concern is, essentially, these
parameters are set by a group of citizens described in
Mr. Richardson's exhibit, outside this hearing room, and then
according to Ms. Grow, the ultimate result is presented to the
Commission for acceptance, not approval, is what Idaho Power
wants to present. Is that wrong?
A. I mean, that's an accurate description of the IRP
process. Again, the Commission acknowledges or accepts for
filing the IRP. That's the way it always has been. And it is
really a prudency review that they do of that document in the
whole planning process.
Q. So doesn't that let the fox watch the henhouse?
That is to say, doesn't Idaho Power get to set the rates and
then negotiate all of the contracts, or am I wrong?
A. Well, like you pointed out before, a vast
majority of the contracts would ultimately end up being
negotiated contracts. But, again, as long as the assumptions
from the IRP haven't changed, there shouldn't be much, if any,
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change in any of the pricing components.
Q. Mr. Stokes, thank you for your patience.
MR. ARKOOSH: And, Madam Chairman, thanks for
fishing me out on the page number.
COMMISSIONER SMITH: Certainly.
Ms. Sasser, did you have questions? Did I
already pass you?
MS. SASSER: I have a couple. Thank you,
Madam Chair.
CROSS-EXAMINATION
BY MS. SASSER:
Q. Hi, Mr. Stokes.
A. Hello.
Q. Just a couple of questions for you. I think
you've already said, but I'll ask again:
Have you reviewed Commission Staff witness's
testimony, Rick Sterling's testimony, for this case?
A. Yes, I have.
Q. Okay. So you're aware that -- well, sorry, I'll
rephrase.
Recognizing that Idaho Power still opposes the
use of a SAR methodology, as proposed in your testimony, does
Idaho Power consider Staff's proposed changes to the SAR
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methodology to be an improvement over the current SAR method?
A. Well, like I put in my rebuttal testimony, I
think the -- what's been proposed with the gas price forecast
is an improvement. Ultimately though, I feel like the SAR
model has some inherent flaws in it that you cannot account for
dispatchability of resources or just the different
characteristics of all the resource types. And if you believe
that, in my mind, to me, that says that model needs to go away.
I think the model served its purpose for a lot of years in
Idaho, but I think there's better ways to calculate avoided
cost rates at this point.
Q. Okay. If we were to keep the SAR methodology, do
you believe that the modifications proposed by Staff would be
improvements over the current methodology?
A. In general, yes, but again, I don't think they
totally fix the problem.
Q. Understood. And I have a couple of questions
with regard to the specifics of your testimony and issues with
the SAR methodology. On page 6 of your rebuttal testimony --
tell me when you're there.
A. Okay, go ahead.
Q. You make a statement at line 1, starting at
line 1 at the top of the page: These results show that the SAR
methodology is more sensitive to the natural gas price
assumption than Idaho Power's proposed hourly incremental cost
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methodology.
Can you explain why it is that you believe the
SAR methodology is more sensitive for the gas price?
A. Yes. That was the whole purpose of the analysis
we did. If you look at the table or chart down at the bottom
of page 7, we took a series of four different gas price
forecast streams that have been discussed or part of this case
over the time that it's been opened.
COMMISSIONER SMITH: Do you mean page 5?
THE WITNESS: No, I'm looking at the bottom of
page 7 of my rebuttal. There is a chart with four gray bars on
the left and four blue bars on the --
Q. BY MS. SASSER: That's page 5.
A. Oh, I'm sorry. I'm seeing a "7" up there. I
guess it is line 7. It is page 5, I apologize.
Yeah, each of those represents the avoided cost
rate that's calculated with both the SAR methodology and Idaho
Power's hourly incremental cost methodology using those
different gas price forecasts as the only variable, and you see
that basically the amount of change in the avoided cost rate
that you get from the using the SAR model is greater than what
you see as far as a differential compared to what Idaho Power's
method produces.
Q. Okay.
A. So being less sensitive to that gas price
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forecast I think is a big step in the right direction. I think
historically that's been one of the bigger issues with the SAR
model.
Q. Around about page 40 of your direct testimony, in
again talking about the SAR methodology and plus and minuses of
Idaho Power's proposal, you talk about -- I'm at line 19 --
seasonal and heavy light load pricing adjustments have been
made in recent PURPA contracts to try to incent PURPA resources
to deliver energy at times when it is more valuable. However,
the SAR methodology does not value the energy at the times it
is delivered to the Utility.
But wouldn't you agree that the seasonal heavy
and light load adjustments are an attempt to do that within the
SAR methodology?
A. They are an attempt to do the exact same thing.
Again, they don't do it anywhere nearly as well as I think what
we can do with the new methodology, because we're literally
looking at pricing on an hourly basis. So in my mind, you can
get a lot more granular and a lot more accurate than you can.
I think it's just a better result.
Q. Okay. At page 18 of your direct testimony, you
discuss surplus and deficit. Beginning at line 2, you state:
The net result is that Idaho Power is buying a significant
amount of energy that its customers do not need at above-market
prices, and in many instances the Company will end up selling
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that energy back into the market at a significant loss.
Do you believe that Idaho Power will still
sometimes sell excess PURPA generation at a loss if Schedule 74
is approved by the Commission?
A. Oh, certainly. You know, I think the amount of
times that Schedule 74 would actually come into play are going
to be pretty small. When you look at this chart at the top of
page 18, that's basically showing you that we're surplus 11
months out of 12 of the year. So there's -- I mean, there's a
lot of energy we're going to have to sell. If you combine that
chart with the one on page 16, that's really what paints the
whole picture there, because you see that chart on page 16
shows you the differential between what we're going to be
paying for that PURPA energy versus what we're going to get for
it at market, and that's really where a lot of that harm to our
customers is coming from.
Q. If you will turn to page 24 of your rebuttal
testimony, in discussing energy surplus and deficit positions,
beginning at line 13, you state that deductions for wheeling
and losses be made for any month that the Utility is surplus
throughout the term of the QF contract.
So would those months be assumed and identified
in advance as the contract is negotiated and be written into
the terms of the contract, or would they be determined
throughout the life of the contract on a monthly basis?
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A. Well, I guess my intent on that section, you
know, I definitely agree with Dr. McHugh's suggestion on how to
treat this, but wanted to take that a step further, because as
a Utility, as we're buying and selling electricity, we're
making decisions -- dispatch decisions based on transmission
and lost costs as well, and we do that for all the time, not
just up until there's our first deficit. That happens all the
time. And that's why, to me, it made more sense that that
ought to be factored into it throughout whatever term of the
PURPA contract is.
Q. So it would be a flexible contract then where it
is -- I mean, I guess I still haven't gotten a direct answer.
Is it something that is decided prior to and within
negotiations and incorporated into the terms of the contract at
the time of negotiations, or determined as the contract
progresses?
A. It was my intent that it would be determined
ahead of time and be factored into the pricing.
Q. Okay.
A. Because, again, and that was the point in my
testimony here, that that information is available in the IRP,
so you could figure all of that out ahead of time.
Q. Okay. One last point: In referring back to some
of your discussion with Mr. Richardson, page 46 of your
rebuttal testimony, there were discussions regarding the $45
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per megawatt delay damage security; and at line 15 -- I'm not
sure if he had you read or if he read, but I'll read it on your
behalf -- your testimony, your rebuttal testimony, states:
The Commission has specifically found this
requirement to be in the public interest and a just and
reasonable requirement of the contracting process.
And then Mr. Richardson handed you a five-page
Order of the Commission and asked you to find in there where
the Commission had adopted that standard or where you found
that language in there. If you will turn to -- can you turn to
page 3 o Order -- it is Exhibit 519 as identified by
Mr. Richardson, page 3.
A. Let's see. What was the Order number again?
Q. The Order number was 31034.
A. And you said page 3?
Q. Page 3 in the heading Commission Decision and
Findings.
A. Yes.
Q. Could you read that second paragraph to the
bottom of the page, please?
MR. RICHARDSON: Madam Chair, I'm going to object
to this friendly cross.
COMMISSIONER SMITH: And I'm going to sustain it.
The Order speaks for itself, Ms. Sasser, so the witness doesn't
need to read it.
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MS. SASSER: Okay. I withdraw the question.
have nothing further.
COMMISSIONER SMITH: Thank you.
Do we have q iestions from the Commissioners?
COMMISSIONER REDFORD: No.
COMMISSIONER KJELLANDER: No.
COMMISSIONER SMITH: Nor I, Mr. Stokes.
Redirect?
MR. WALKER: No redirect, Madam Chair.
COMMISSIONER SMITH: Thank you for your help,
Mr. Stokes.
THE WITNESS: Thank you.
MR. WALKER: May Mr. Stokes be excused?
COMMISSIONER SMITH: Is there any objection to
excusing Mr. Stokes? Seeing none, he's excused.
(The witness left the stand.)
MR. WALKER: Thank you, Madam Chair.
COMMISSIONER SMITH: I think we're ready for your
next witness.
MR. J. WILLIAMS: Thank you, Madam Chair. We're
going to mix it up a little bit: Jason Williams on behalf of
Idaho Power.
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23 At this time, I'd like to call Ms. Tess Park to
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TESSIA PARK,
produced as a witness at the instance of Idaho Power Company,
being first duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
BY MR. J. WILLIAMS:
Q. Good afternoon, Ms. Park.
A. Good afternoon.
Q. Could you please state your name, spelling your
last for the record?
A. Tessia Park, P-A-R-K.
Q. And by whom are you employed and in what
capacity?
A. I'm employed by Idaho Power as the director of
load serving operations.
Q. And are you the same Tess Park that caused to be
filed direct prefiled testimony and rebuttal testimony in this
proceeding?
A. lam.
Q. And did your direct testimony include what's been
identified as Exhibit No. 4?
A. Yes, it did.
Q. And do you have any corrections to either your
direct or your rebuttal testimony?
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A. No, I do not.
Q. And if I were to ask you here today under oath
the same questions set forth in your direct and rebuttal
testimony, would your answers be the same?
A. Yes, they would.
MR. J. WILLIAMS: Madam Chair, at this time I'd
move for the admission of Ms. Tess Park's prefiled direct
testimony, inclusive of what's been marked as Exhibit No. 4,
and her rebuttal testimony be spread upon the record as if
read.
COMMISSIONER SMITH: If there is no objection, we
will spread the prefiled testimony of Ms. Park upon the record
as if read, and admit Exhibits 4 and 5.
Oh. Did you do her rebuttal?
MR. J. WILLIAMS: I did her direct and her
rebuttal, and I believe just Exhibit No. 4.
I'm sorry, Exhibit No. 5 as well.
COMMISSIONER SMITH: Without objection, we will
also spread the prefiled rebuttal testimony as if read.
(The following prefiled direct and
rebuttal testimony of Ms. Park is spread upon the record.)
597
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HEDRICK COURT REPORTING PARK (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
1 Q. Please state your name and business address.
2 A. My name is Tessia Park and my business address
3 is 1221 West Idaho Street, Boise, Idaho 83702.
4 Q. By whom are you employed and in what capacity?
5 A. I am employed by Idaho Power Company ("Idaho
6 Power" or "Company") as the Director of Load Serving
7 Operations. In that role, I am responsible for the Grid
8 Operations and Balancing Operations functions for the
9 Company's electric system.
10 Q. Please describe your educational background
11 and work experience with Idaho Power.
12 A. I have been employed with the Company for 14
. 13 years in the Operations area. I worked in the Grid
14 Operations department as a Grid Operator, Grid Operator
15 Training Leader, and the Interchange Operations Leader. I
16 worked as the Grid Operations Manager from 2007 to June
17 2009 and then the Power Supply Operations Manager from June
18 2009 through 2010 where I assumed my current role. I have
19 attended Boise State University and am currently in my
20 final year of studies in the BAS Energy Management program
21 at Bismark State College.
22 Q. What is the purpose of your testimony in this
23 matter?
24 A. The purpose of my testimony is to describe the
. 25 economic and operational impacts resulting from the
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Idaho Power Company
1 uneconomic dispatch of Idaho Power base load resources
2 caused by the mandatory obligation to purchase generation
3 from qualifying facilities ("QF5") pursuant to the Public
4 Utility Regulatory Policies Act of 1978 ("PtJRPA") that, in
5 many instances, are not needed to serve the Company's
6 system load. I will also describe constraints around the
7 Company's ability to move energy to market during times of
8 excess supply, as well as describe how there is a finite
9 amount of intermittent generation that is capable of being
10 integrated onto the Company's system. Further, I will
11 describe the Company's proposed operational re-dispatch
12 rule and proposed tariff schedule that considers system
of 13 operational circumstances and dispatching of the Company's
14 generation resources in the most efficient manner versus
15 dispatching less efficient and more expensive resources so
16 as to be able to accommodate additional PURPA generation
17 resources onto the Company's system.

18 I. CURRENT SYSTEM OPERATION

19 Q. Please provide an overview of the amount of QF
20 generation currently on the Company's system.

21 A. As explained in the Direct Testimony of M.
22 Mark Stokes, as of December 31, 2011, Idaho Power had 119
23 QF projects under contract with an estimated nameplate
24 rating of 989 megawatts ("MW") . Of these projects, 96 (606

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Idaho Power Company
1 MW) are currently on-line, and an additional 23 projects
2 (383 MW) are scheduled to come on-line by early 2014.
3 Q. From an operations standpoint, do you have
4 concerns with the amount of QF generation that has been
5 added to the Company's system?
6 A. Yes. The Company is now in the position
7 where, at certain times of the year, it has to back-down
8 base load generation in order to integrate PURPA generation
9 which is predominantly intermittent in nature. When base
10 load generation is backed down, it can become difficult to
11 ramp up (or ramp down) that generation to meet variations
12 in system needs, especially when the Company has to reserve
. 13 a portion of its base load generation to ensure it can firm
14 and shape the intermittent PURPA generation for reliability
15 reasons. Put differently, the addition of PURPA resources
16 to the Company's system frequently requires the Company to
17 have partially loaded resources running and on-line in
18 order to meet the variability of intermittent resources.
19 Q. From an operations standpoint, how is
20 intermittent generation, such as wind, different from
21 traditional base load generation resources?
22 A. The big difference is the ability, or more
23 appropriately, the inability to schedule and dispatch
24 intermittent generators. Unlike traditional hydro and
. 25 thermal resources, intermittent resources like wind cannot
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Idaho Power Company
0 1 be scheduled. While the Company and the industry are
2 continuing to develop more robust forecasting tools, it is
3 still difficult to predict with any accuracy when the wind
4 will blow and thus when wind turbines will generate energy.
5 In other words, the Company has no way of controlling how
6 much of this type of energy it will get or when it will get
7 it. Moreover, the Company is currently required to absorb
8 this QF energy onto its system without regard to its
9 electrical system needs. This is especially problematic in
10 low loading periods, i.e., when the Company schedules its
11 near-term load and reliability forecasts and sets
12 generation levels at its base load units accordingly. • 13 During these times, the amount of total generation on the
14 Company's system (as a result of the surplus of QF energy
15 at certain times) can exceed Idaho Power's ability to back
16 down additional, base load resources. When this occurs,
17 this leaves the Company with only limited dispatchable
18 generation available for load ramping events (i.e., changes
19 in load or levels of intermittent generation.)
20 Q. Doesn't the Company have the ability to sell
21 excess energy on its system into the market?
22 A. Generally, yes. Given certain meteorological
23 conditions and based upon its generation resources, the
24 Company generally knows that there will be many times in • 25 the year when its generation will exceed its system load.
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Idaho Power Company
1 Transactions selling such surplus energy can be established
2 at varying intervals prior to the actual period of energy
3 surplus. For example, Idaho Power frequently recognizes
4 periods of surplus energy months in advance through the
5 long-term operations planning cycles as part of its Risk
6 Management Policy. Conversely, energy surpluses are, at
7 times, recognized during real-time operations, within only
8 several hours of the actual surplus condition.
9 Q. Are there Federal Energy Regulatory Commission
10 ("FERC") regulations that govern how the Company has to
11 sell energy into the market?
12 A. Yes. FERC Order No. 890 placed restrictions
. 13 on the Company's ability to sell power from utility-owned
14 generation resources. Regardless of the interval at which
15 the surplus is recognized and transacted, the actual real-
16 time delivery of power to the acquiring third-party is
17 managed in practice through the undesignation of network
18 resources, thereby releasing these resources from their
19 designation for serving network customer demand, and
20 assigning at least a portion of their production in support
21 of off-system sales. More specifically, when an
22 interconnecting resource connects to Idaho Power's system
23 as a designated network resource, that resource can only be
24 used to serve system load unless the Company specifically
. 25 undesignates that resource through a process that is
602 PARK, DI 5
Idaho Power Company
1 noticed on the Company's Open-Access Same-Time Frame
2 Information System ("OASIS") web site, which is managed by
3 the Company's transmission provider function. Once
4 undesignated, the network resources assigned in support of
5 off-system sales are effectively committed for this
6 purpose, and, as such, are necessarily resources having
7 generating capacity which is delivered with very high
8 dependability. Idaho Power's practice is to undesignate
9 generation provided from its fleet of hydro and thermal
10 resources, as these resources have the type of demonstrated
11 dependability over years of operation that is required.
12 Q. How much energy can Idaho Power make available
13 to sell into the market?
14 A. The amount of Idaho Power's hydro and thermal
15 generating capacity which can be undesignated for service
16 to network demand and instead assigned in support of off-
17 system sales is recognizably finite. During periods of
18 relatively high customer demand, energy surpluses that
19 occur are typically small enough to consume only a fraction
20 of the finite generating capacity which can be
21 undesignated. Variable generation from intermittent PURPA
22 resources occurring during these periods can fulfill its
23 purpose of serving network demand, thereby allowing the
24 Company-operated hydro and thermal generators to expand • 25 their commitment in support of off-system sales. Thus, the
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1 limiting conditions on the amount of variable generation
2 from PURPA resources which Idaho Power can accommodate are
3 not apparent during periods of relatively high customer
4 demand.
5 However, during periods of low customer demand,
6 energy surpluses are frequently very large, consuming much
7 of the finite generating capacity which can be assigned in
8 support of off-system sales. Thus, as variable generation
9 from PURPA resources increases in service to network
10 demand, the Company-operated generators can expand their
11 off-system commitment by only a limited amount. Variable
12 generation occurring beyond this amount has no further
. 13 network customer demand to serve, and consequently cannot
14 be integrated without violating FERC requirements on
15 designated network resources and their service in meeting
16 network customer demand.
17 Q. Do the FERC rules related to designation and
18 undesignation impact the total amount of intermittent
19 generation the Company is capable of integrating onto its
20 system?
21 A. Yes. Given the current network resource
22 stack, as well as the capabilities of the Company's
23 transmission system, there is only a finite amount of
24 intermittent generation the Company can add to its system.
. 25 As part of the Company's ongoing wind integration study,
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Idaho Power Company
1 Idaho Power is continuing to evaluate just how much that
2 is. While the Company is unable to precisely say how much
3 intermittent generation its system can absorb at this time,
4 given the recent proliferation of intermittent generation
5 on its system and the amount that is scheduled to come on-
6 line, the Company believes it is quickly approaching that
7 maximum intermittent generation saturation point. Once
8 reached, the only way the Company will be able to add more
9 intermittent generation will be to build or configure
10 additional generation resources designed specifically to
11 provide the regulating margin needed to integrate these
12 variable resources. At this time, the Company has no plans
. 13 to add or configure additional generation resources to
14 provide regulating margin.
15 Q. What is the Company's experience with the
16 intermittent PURPA generators on its system?
17 A. As indicated above, the Company receives no
18 schedule for these generation resources, so it only has a
19 limited amount of information available as to when or how
20 much intermittent generation it is going to receive on any
21 given day. Often times, wind generators, the bulk of QF
22 generators on Idaho Power's system, generate during the
23 Company's low loading periods (e.g., at night, during the
24 spring or fall, etc.) During these low loading periods,
. 25 there is generally a glut of energy available in the
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Idaho Power Company
1 Pacific Northwest. In fact, over the last couple of years,
2 the Company has seen a phenomenon where market prices at
3 the Mid Columbia trading hub actually go negative, meaning
4 one entity will pay another entity to take their excess
5 energy. If the market price for energy is not negative
6 during these low loading periods, it is often times less
7 than the dispatch cost of the Company's thermal resources.
8 Thus, if the Company were to sell the energy produced by
9 its coal plants into the market, it would be doing so at a
10 loss. Moreover, the Company is limited in its ability to
11 market and sell its base load energy displaced by PUPRA
12 contract energy because of the undesignation issues
. 13 discussed earlier and because such sales are made on the
14 "spot market." Additionally, transmission constraints on
15 the Company's system may limit the amount of energy that
16 can be moved to market at a given time. Again, because
17 Idaho Power does not know when or how much energy it will
18 get from wind generators, it often times will not know if
19 it will have energy available to sell until the day, or
20 most often, an hour ahead of when it is sold. Thus, it is
21 not possible for the Company to enter into forward-looking,
22 long-term energy transactions to sell excess wind
23 generation into the market because there is no guarantee in
24 the future if the energy produced by wind generators will
is 25 be available.
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PARK, DI 9
Idaho Power Company
1 Q. Can the Company undesignate its PURPA network
2 resources and sell that generation into the market?
3 A. Yes, but for the reasons described above, it
4 is difficult to do, primarily because the Company has no
5 ability to know with certainty whether generation from
6 intermittent PURPA resources will actually be generated.
7 In addition, if Idaho Power were to undesignate a PURPA
8 resource on its system and sell it into the market, and a
9 system condition requiring that sale to be curtailed
10 occurred, the Company would not be able to curtail the
11 PURPA generator because Idaho Power has no ability to
12 curtail PURPA generation for this purpose. In comparison,
13 when Idaho Power undesignates its base load or other
14 generation resources for sale into the market, and a system
15 condition occurs requiring that sale to be curtailed, the
16 Company curtails its generation resources. This example
17 highlights how even though PURPA resources are designated
18 as network resources, the Company has to give them special
19 treatment over how the Company treats its own generation
20 resources.
21 Q. How does the Company decide whether to
22 dispatch its resources to serve load or to sell into the
23 market?
24 A. Primarily, the Company bases its dispatch • 25 decisions upon costs. It is prudent and standard electric
607 PARK, DI 10
Idaho Power Company
1 utility practice to dispatch available, existing resources
2 to meet system load beginning with the least expensive
3 resource. For example, the Company's least cost resources
4 to dispatch are its hydra resources. Because these
5 resources use water as fuel, there is effectively no
6 incremental cast associated with running these resources.
7 Thus, their dispatch cast is very low. The next least-cost
8 resources are the coal generators whose current dispatch
9 costs are generally below $30 per megawatt-hour ("MWh").
10 These dispatch costs are driven largely by fuel costs
11 (i.e., coal costs) for each facility. Once on-line, Langley
12 Gulch, a natural-gas-fired combined cycle combustion . 13 turbine, will have dispatch costs that are heavily
14 influenced by the price of natural gas. Based upon the
15 current price of natural gas, dispatch costs of Langley
16 Gulch will be approximately $22.
17 Q. What are the dispatch costs of the PURPA
18 resources on your system?
19 A. Stating that the Company's PURPA resources
20 have dispatch costs is something of a misnomer because they
21 are, generally, not dispatchable. Instead, they connect to
22 the system and the Company takes whatever generation they
23 produce. The amount Idaho Power pays for PURPA generation
24 in comparison to the dispatch costs of Company-owned • 25 resources is generally much higher. For example, the
608
PARK, DI 11
Idaho Power Company
1 Company currently pays in the range of low-$50 per MWh up
2 to $85 or more per MWh for PURPA generation.
3 Q. How does the Company use its resources to meet
4 system load?
5 A. Historically, Idaho Power has been able to
6 rely on its low cost hydro system to meet the broad
7 fluctuations in system load that can occur during a single
8 day. For example, on a given October day, the Company's
9 load may be 1,250 MW at 6 a.m., grow to 1,600 MW by 10
10 a.m., drop to 1,400 MW by 3 p.m. and drop again to 1,300 MW
11 by 11 p.m. Because Idaho Power's hydro system can, within
12 environmental limitations, be dispatched "on demand," it is . 13 an ideal resource for meeting these daily fluctuations in
14 load.
15 Q. How has the addition of large amounts of PURPA
16 generation affected the way Idaho Power operates its
17 system?
18 A. The addition of large amounts of intermittent
19 generation on the system, coupled with the fact that it
20 oftentimes generates when the Company's system load is at a
21 low level, forces the Company to use the flexibility of the
22 hydro system that is normally used to meet load swings and
23 to meet system balancing needs (e.g., regulation reserves,
24 contingency reserves, etc.) of the wind generators. Thus, • 25 the Company is forced to use base load generation resources
609
PARK, DI 12
Idaho Power Company
1 to integrate the intermittent QF generation which comes at
2 an additional cost to customers.
3 Q. Doesn't the Company's current $6.50 wind
4 integration charge cover the cost of providing these
5 balancing services to intermittent generators, such as wind
6 generators, on your system?
7 A. Partially. As an initial matter, it is
8 important to point out that the $6.50 wind integration
9 charge was the result of a negotiated settlement and is not
10 reflective of the Company's actual integration costs. The
11 $6.50 wind integration charge included in the settlement
12 stipulation was intended to cover the lost opportunity cost
0 13 of having to de-optimize the operation of the Company's
14 hydroelectric resources in the Hells Canyon Complex in
15 order to provide the reserve capacity necessary to respond
16 to changes in wind generation. In the October 2007
17 addendum to Idaho Power's initial wind integration study,
18 an additional 48 MW of down regulating capability was also
19 assumed to be available from the Jim Bridger coal plant.
20 This assumption and the resulting impact to the wind
21 integration cost did not account for potential costs due to
22 thermal cycling.
23 Q. Is Idaho Power currently updating its wind
24 integration study?
25
610
PARK, DI 13
Idaho Power Company
1 A. Yes. Idaho Power has been working on an
2 update to its wind integration study for some time.
3 However, difficulties in modeling Idaho Power's electrical
4 system and generation resources in the model used by the
5 consultant hired to perform the study, have delayed the
6 completion of the study. The Company is currently working
7 through the issues with the consultant and hopes to have
8 the study completed by this summer.
9 Q. Can you summarize what all of this means from
10 an operational perspective?
11 A. In short, the recent influx of QF generation
12 onto the Company's system is requiring the Company to
13 displace lower cost, dispatchable generation resources with
14 higher cost, non-dispatchable, intermittent resources.
15 Simply put, for customers, this means they are paying more
16 for less reliable generation resources.
17 II. 18 C.F.R. § 292.304(f)
18 Q. Do FERC's PURPA regulations have a provision
19 that allows utilities to consider the economic and
20 operational impacts of PURPA generators?
21 A. Yes. FERC regulations implementing PURPA
22 contain a provision which deals with this issue.
23 Subsection 292.304(f) of Title 18 of the Code of Federal
24 Regulations describes situations whereby utilities are not • 25 required to purchase electric energy or capacity during any
611
PARK, DI 14
Idaho Power Company
1 period which, due to operational circumstances, purchases
2 from QF5 will result in costs greater than those which the
3 utility would incur if it did not make such purchases, but
4 instead generated an equivalent amount of energy itself.
5 In other words, this regulation allows the Company to
6 curtail QF generators on its system under certain
7 operational and economic circumstances.
8 Q. Is this regulation applicable to the situation
9 Idaho Power is currently in?
10 A. Absolutely. This FERC regulation refers to
11 the situation that Idaho Power is currently experiencing
12 during the Company's low loading periods. As described•
13 above, there are times when the Company is faced with
14 displacing lower cost, base load generation resources with
15 higher cost resources to serve system load.
16 Q. Doesn't the Company's Schedule 72 tariff and
17 existing firm energy sales agreements ("FESA") with QFs
18 give the Company the ability to curtail QF generation?
19 A. Yes, but not for reasons that have anything to
20 do with system efficiency and economics. Schedule 72 and
21 the FESA's give the Company the ability to curtail due to
22 system integrity issues. The FERC rule I cite above allows
23 the Company to limit the obligation to purchase QF energy
24 if the Company is operating only base load units and would • 25 be forced to cut back output from those units in order to
612
PARK, DI 15
Idaho Power Company
1 accommodate QF energy purchases. Such base load units
2 might not be able to later increase their output levels
3 rapidly enough to meet system demand, resulting in the
4 Company needing to rely upon less efficient and/or higher
5 cost resources to meet system load.
6 Q. Does the FERC rule you cite above only
7 consider economics?
8 A. No. The FERC rule requires that economics are
9 to be considered only during certain "operational
10 circumstances." My understanding of this is that
11 curtailment of QF's under the FERC rule applies only to
12 such low loading scenarios (as I describe in greater detail
S 13 later) and cannot be relied upon to curtail purchases of QF
14 energy for general economic reasons only.
15 Q. Are you aware of any state utility commissions
16 that have implemented the FERC rule you mention above?
17 A. Yes. I know of at least two states that have
18 addressed and/or implemented this FERC rule: Florida and
19 Nevada.
20 Q. Please briefly describe your understanding of
21 the situation in Florida.
22 A. It is my understanding that in the mid 1990s,
23 Florida Power Corporation ("FPC") was experiencing
24 operational circumstances during certain low loading
25 periods wherein the purchase of QF energy in lieu of taking
613
PARK, DI 16
Idaho Power Company
1 energy the utility could generate itself resulted in
2 negative avoided costs, meaning that purchases from QFs
3 caused FPC to incur greater net power production costs than
4 it would otherwise incur without those purchases. As a
5 result, the Florida Public Service Commission ("Florida
6 PSC") adopted a rule nearly identical to 18 C.F.R. §
7 392.204(f) and implemented it in such a way that allowed
8 FPC, during certain low loading conditions, to not have to
9 make purchases of QF energy at negative avoided costs and,
10 instead, curtail QF energy for periods of time.
11 Q. Please explain your understanding of how the
12 FERC regulation was implemented in Nevada. . 13 A. My understanding of what occurred in Nevada is
14 that the Nevada Public Service Commission ("Nevada PSC") in
15 the mid-1990s adopted a specific "Policy and Procedure of
16 Curtailment of Certain PURPA Qualifying Facilities" that
17 was proposed by Nevada Power Company. That policy was
18 adopted and implemented as a direct result of the authority
19 given to the Nevada PSC by the FERC rule. I have attached
20 a copy of the policy adopted by the Nevada PSC as Exhibit
21 No. 4.
22 Q. Has FERC given any direction as to how this
23 rule is to be implemented?
24 A. Yes. In a very recent order, FERC confirmed • 25 that while 18 C.F.R. § 292.304(f) does not give utilities
614
PARK, DI 17
Idaho Power Company
1 blanket authorization to curtail QF purchases for economic
2 reasons, during low loading periods, utilities may curtail
3 higher cost QF energy if the utility would have to dispatch
4 less efficient, higher cost units (other than base load
5 units) to meet system load. Entergy Services, Inc., 137
6 FERC P 61199, 2011 WL 6523725 (F.E.R.C.), Docket Nos. ER05-
7 1065-011, 0A07-32-008 (Dec. 15, 2011) ("Entergy Order")
8 III. IDAHO POWER'S OPERATIONAL DISPATCH PROPOSAL
9 Q. What specifically is Idaho Power proposing?
10 A. The Company is proposing an operational
11 dispatch model that allows the Company, during low loading
12 periods, to meet its energy needs by using its own lowest
13 cost, base load resources instead of dispatching less
14 efficient, higher cost resources to accommodate PURPA
15 generators on the Company's system. Attached as Exhibit
16 No. 5 is a copy of the Company's proposed Tariff Schedule
17 74 describing the proposal.
18 Q. Please provide a brief overview of the
19 Company's proposal.
20 A. In adhering to the FERC rule, the Company's
21 proposal will relieve the Company of its obligation to
22 purchase energy from PURPA generators during low loading
23 periods when the Company is operating only base load
24 resources and would be forced to cut back output from those • 25 resources in order to accommodate unscheduled QF energy
615
PARK, DI 18
Idaho Power Company
1 purchases. Because the Company's coal units have slow,
2 gradual ramp times for them to reach full generating
3 capacity, backing down such base load units too much to
4 accommodate QF purchases will impact their ability to come
5 back to full generating capacity to meet system load. If
6 this were to occur, Idaho Power would be in the position of
7 dispatching higher cost resources, such as the Company's
8 natural gas peaking plants or more expensive market
9 purchases, to meet variations in system load. This is
10 exactly the type of scenario under which the FERC rule was
11 meant to apply and why Idaho Power is requesting authority
12 from the Commission to implement it.
13 Q. Describe how you determined the Company's "low
14 loading periods."
15 A. The Company looked at its hourly energy needs
16 throughout the entire year. Generally, during most months
17 out of the year, the Company has more generation resources
18 than it has load primarily because the Company's summer
19 peak is significantly higher than its winter peak. During
20 these times of excess generation capacity, the Company
21 either backs down or shuts down its more expensive
22 generation resources, or, if the dispatch costs of those
23 resources are less than the market price, the Company will
24 generate energy and sell it into the market. Any profit
• 25 the Company makes in doing this flows back to customers as
616
PARK, DI 19
Idaho Power Company
1 a benefit through the Company's power cost adjustment
2 ("PCA") mechanism. During the months of the year when the
3 Company does not have enough generation to meet its loads,
4 the Company uses its peaking generation resources, as well
5 as market purchases to meet its system load needs. To
6 determine the Company's low loading periods, the Company
7 looked at those times of the year when system loads are
8 less than the Company's "must run" resources. "Must run"
9 resources consist of three types: (1) those generation
10 resources the Company must have available to serve near-
11 term forecasted load, (2) run-of-river hydro generators,
12 and (3) hydro generation needed to maintain the required
13 flows for environmental compliance. Pursuant to the FERC
14 licenses Idaho Power has for its run-of-river hydro
15 electric projects, the Company is obligated to take
16 whatever generation flows through them; it does not have
17 the ability to decrease or increase the generation. Thus,
18 the output of those resources depends upon water
19 conditions. It can be difficult to define in advance those
20 resources that are needed to reliably serve loads in future
21 hoUrs. For example, run-of-river hydro and minimum flow
22 hydro generation varies depending upon water flows and the
23 time of year. In addition, meteorological conditions
24 (e.g., unseasonably warm or cold temperatures or unusually • 25 dry or wet moisture levels, etc.) as well as other factors
617
PARK, DI 20
Idaho Power Company
1 that impact system load may dictate which resources are
2 considered "must run." In general, however, the Company
3 relies on thermal resources to meet base load requirements,
4 and use the flexibility of hydro resources to meet
5 variations in load throughout the day. The "must run"
6 periods are those periods when the load demand in the
7 upcoming hours or days requires the base load thermal
8 resources to be available to serve load (and assuming the
9 dispatch costs of thermal resources are less than market
10 prices during heavy load hours). This means the Company
11 must have its thermal plants generating and on-line and
12 capable of ramping up during heavy load hours and then
0 13 backing down again during light load hours.
14 Q. Why doesn't the Company simply shut off its
15 thermal units during the light load hours during these low
16 loading periods?
17 A. The coal units cannot be shut off for two
18 reasons. First, operationally, coal plants cannot be
19 simply shut off. Once fired, it takes a coal plant several
20 days to heat up in order to reach generation levels. In
21 addition, cycling off coal plants is very hard on the
22 generators as changes in temperatures from hot to cold and
23 cold to hot on a frequent basis causes excessive stress and
24 fatigue on the turbines and other equipment. Second, Idaho • 25 Power is only part owner of all three of the coal plants
618
PARK, DI 21
Idaho Power Company
1 and is not the operator of any of them. Under the
2 Company's contracts with the other co-owners and operators,
3 if the Company requests that a coal generator be taken off-
4 line, the Company is required to give seven days prior
5 notice prior to restarting it and may incur additional
6 charges from the operators for doing so.
7 Q. When will the Company's low loading periods
8 occur?
9 A. While it is impossible to predict exactly when
10 the Company's low loading periods will occur for the
11 reasons that I have outlined earlier in my testimony, the
12 Company anticipates that the low loading periods will occur
. 13 predominantly in the spring and fall when temperatures are
14 mild and no market exists for excess energy. The Company's
15 system load will be such that it needs to have thermal
16 units on-line to provide some energy during light load
17 hours so they can again provide energy during heavy load
18 hours. Over the last few years, it has been the Company's
19 observation that the intermittent PURPA generation
20 interconnected to the system generally provides a lot of
21 energy at night and during the spring and fall, the times
22 when the system is experiencing low loads. Thus, low
23 loading periods will likely occur during the night and
24 during the "shoulder months" of spring and fall.
• 25

619
PARK, DI 22
Idaho Power Company
1 Q. Can you provide a representative example of
2 when your proposed Schedule 74 Tariff would go into effect?
3 A. Yes. The following example is based upon an
4 actual generation day in October 2011. On a typical fall
5 day, the Company's load may swing between approximately
6 1,100 MW during light load hours and 1,600 MW during heavy
7 load hours. During the light load hours, the Company must
8 maintain constant minimum flows below Hells Canyon dam for
9 environmental compliance, thus limiting the ability to
10 curtail generation out of the Hells Canyon Complex to no
11 less than approximately 350 MW. During the fall, the
12 Company has relatively low, steady flows at the run-of-
13 river hydro plants, providing a constant, steady flow of
14 approximately 450 MW of energy. The Company will schedule
15 these hydro resources to serve load. Thermal units that
16 are "in the money" are on-line, which are capable of
17 providing us up to 600 MW. The Company will schedule all
18 of these resources to serve load. The Company has up to
19 395 MW of intermittent PURPA wind generation interconnected
20 to the system, none of which can be scheduled. In
21 addition, the Company has another 50 MW of firm PURPA
In this context, "in the money" simply means that Company-owned
generation resources would be less expensive than market prices. Under
this scenario, the Valmy plant would be cycled off for an extended
•

period of time because of its relatively high dispatch cost and because
it is not needed to serve load during these low load times of year.
620
PARK, DI 23
Idaho Power Company
1 generation (e.g., non-intermittent generation resources
2 such as digesters and hydros) that is scheduled.
3 Assume that between midnight and 4 a.m. load is
4 relatively steady at 1,100 MW. The Company has its thermal
5 units backed down and running at 300 MW, and its hydro
6 plants running at a minimum of 817 MW (350 MW from Hells
7 Canyon and 447 MW from the run-of-river hydro). The
8 Company has the additional 50 MW of non-intermittent PURPA
9 on-line and providing energy. Added together, these
10 resources are sufficient to serve the 1,100 MW of light
11 load. Importantly, the Company needs to keep its thermal
12 units running at least at 300 MW so they will be able to
13 ramp up to their full output of 600 MW to serve load during
14 the heavy load hours. If during the hours between midnight
15 and 4 a.m. the Company has 300 MW of unscheduled PURPA wind
16 generation come onto its system, it has to back down other
17 generation so as to balance generation and load across its
18 system. Because Idaho Power cannot back down its hydro
19 units, nor can it back down the thermal units below 300 MW,
20 the Company would curtail the PURPA generation during these
21 hours to balance generation with load. If Idaho Power were
22 to cycle off its thermal units in the middle of the night
23 to accommodate this PURPA generation, the Company would
24 need to start up its higher cost, less efficient natural
• 25 gas peaking units or make more expensive market purchases
621
PARK, DI 24
Idaho Power Company
1 (assuring transmission would be available) to meet system
2 load during heavy load hours during the next day.
3 IV. CURTAILMENT PROCEDURE
4 Q. On what basis does the Company propose to
5 curtail the excess PURPA generation during these low
6 loading periods?
7 A. During the "must run" periods, the Company
8 will curtail all PURPA resources to which this procedure
9 applies on a pro rata basis until there is no longer excess
10 energy on the Company's system.
11 Q. Will the Company notify the QF generators when
12 it is going to limit energy purchases from them? . 13 A. Absolutely. In fact, the FERC regulations
14 require the Company to provide notice to QFs prior to
15 curtailing them under C.F.R. § 292.304(f). Idaho Power
16 will provide QF5 notice on both a day-ahead basis based
17 upon forecasts and also provide them real-time notice if
18 the need to curtail changes.
19 Q. Is the Company proposing to implement this
20 policy to only new PURPA contracts or to all current and
21 new PURPA contracts?
22 A. The Company is proposing to apply this policy
23 to all PURPA contracts, both existing and new, that are
24 projects which contain generator output control limiters • 25 ("GOCLs") and are 10 MW or larger in size.
622
PARK, DI 25
Idaho Power Company
1 Q. Why is the Company suggesting these
2 parameters?
3 A. The Company set these parameters based upon
4 practical considerations. Large, intermittent QF
5 generators interconnected to Idaho Power's system have
6 GOLCs which give the Company the ability to limit QF
7 generation on a real-time basis. Correspondingly, the same
8 devices allow the Company to re-integrate these large QF
9 generators' full output onto the Company's system on a
10 real-time basis once the light loading periods have passed.
11 Smaller and older QF generators on the Company's system do
12 not have this technology. In many instances, such
13 technology could be installed, but it would be very
14 expensive and not economically feasible for small QF
15 projects. In addition, these smaller QF projects generally
16 contribute only small amounts of energy to the Company's
17 system, and curtailing such projects by themselves would
18 not likely impact the excessive energy the Company has on
19 its system during light loading periods.
20 Q. Does this conclude your direct testimony?
21 A. Yes.
22
23
24
25
623
PARK, DI 26
Idaho Power Company
1 Q. Please state your name and business address.
2 A. My name is Tessia Park and my business address
3 is 1221 West Idaho Street, Boise, Idaho 83702.
4 Q. Are you the same Tessia Park that submitted
5 direct testimony in this proceeding?
6 A. Yes, I am.
7 Q. What is the purpose of your rebuttal
8 testimony?
9 A. My rebuttal testimony responds to a variety of
10 issues raised in the direct testimony of intervenors in
11 this case, including a response to various criticisms
12 related to Idaho Power Company's ("Idaho Power" or
13 "Company") proposed Schedule 74 as well as other Schedule
14 74 and operational related issues.
15 I. IDAHO POWER'S PROPOSED SCHEDULE 74
16 Q. The Direct Testimony of Idaho Wind Partners I,
17 LLC ("Idaho Wind Partners") witness Richard Guy is critical
18 of how Idaho Power proposes to implement Schedule 74,
19 Policy and Procedure for Operational Dispatch of Certain
20 PURPA Qualifying Facilities, because it "lacks the
21 specificity to determine the specific circumstances in
22 which Idaho Power could cease purchases . . . ." From an
23 operations standpoint, why is it difficult to determine
24 when Schedule 74 would apply?
25 4D
624
PARK, REB 1
Idaho Power Company
1 A. Although the operational and system conditions
2 that must exist before Schedule 74 would apply are clearly
3 spelled out in Schedule 74 and match the operational
4 conditions set out by the Federal Energy Regulatory
5 Commission ("FERC") for the applicability of 18 C.F.R. §
6 292.304(f), it is impossible to predict with perfect
7 accuracy how often those operational conditions would occur
8 on Idaho Power's system and thus how often Idaho Power's
9 proposed Schedule 74 would impact Public Utility Regulatory
10 Policies Act of 1978 ("PURPA") generators operating on
11 Idaho Power's system. The factors that influence this
12 include the total amount of intermittent, unscheduled
13 Qualifying Facilities' ("QF") generation on the Company's
14 system, the delta between the minimum and maximum load on
15 the Company's system, and hydro conditions.
16 Q. Is it possible for you to estimate how often
17 Schedule 74 would apply to QFs on the Company's system?
18 A. As I explained earlier, it is impossible to
19 predict with perfect accuracy how often the Company would
20 need to apply Schedule 74. However, based upon the current
21 amount of intermittent generation currently on the
22 Company's system as well as based on recent, historic, and
23 near-term forecasted load and generation data for Idaho
24 Power's system, in my professional opinion and based upon
25 my experience in overseeing the Company's Grid Operations,
625
PARK, REB 2
Idaho Power Company
I would estimate that on an annual basis, the use of
Schedule 74 would impact QF generators on the Company's
system less than 5 percent of the time. In other words,
for QFs on the Company's system, Schedule 74 would result
in relieving Idaho Power of the obligation to purchase less
than 5 percent of the total annual generation it purchases
from QFs.
Q. Is this estimate a long-term estimate?
A. No. This estimate is based upon what I
believe would occur based upon current conditions on Idaho
Power's system. This estimate could be higher or lower
over time based upon the addition of more intermittent
generation on the Company's system and various changes in
hydro conditions as well as system load.
Q. The Direct Testimony of Dynamis Energy, LLC's
("Dynamis") Richard Looper is critical of the Company's
proposed Schedule 74's applicability to the QF project
because its project is not an intermittent resource. What
is your response?
A. Unlike the vast majority of other QF projects
on Idaho Power's system, generation from the Dynamis
project is non-intermittent in nature. Because its
proposed project is a fueled, thermal-based resource,
Dynamis would have the ability to shape and deliver energy
from its project. However, it is my understanding that
626 PARK, REB 3
Idaho Power Company
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1 during the negotiations for the Firm Energy Sales Agreement
2 between Idaho Power and Dynamis that Dynamis would not
3 agree to make the energy from its project dispatchable
4 unless Idaho Power agreed to pay a very high price for that
5 dispatchable energy. Idaho Power did not believe that
6 those high prices would be in the best interest of its
7 customers so it was unable to reach an agreement on the
8 dispatchability of the energy form this project. That
9 said, Idaho Power did agree to pricing and terms that would
10 provide an incentive to Dynamis to deliver energy to Idaho
11 Power during heavy load hours. However, since Dynamis does
12 not provide Idaho Power with scheduled deliveries, it is
13 possible that during certain times of the year, Dynamis
14 will be delivering energy to Idaho Power during heavy load
15 hours when the Company does not need that energy to serve
16 load. Like any other PURPA QF, Dynamis controls when, if,
17 and to what extent it delivers its generation to Idaho
18 Power's system. Consequently, Dynamis has an incentive to
19 make as many deliveries and make as much money as it can,
20 regardless of Idaho Power's need for that generation or the
21 cost of other available resources on Idaho Power's system
22 at the time the QF delivers its generation.
23 Q. Mr. Looper also states that "As far as other
24 renewable generators such as wind and solar, forecasting
. 25 tools have become more sophisticated and on-site weather
627
PARK, REB 4
Idaho Power Company
1 data combined with regional weather stations are being used
2 to monitor real time conditions." What is your response?
3 A. Mr. Looper is correct that the industry
4 continues to develop better forecasting tools to assist
5 with the ability to better anticipate when intermittent
6 resources will provide generation to Idaho Power's system.
7 The fact of the matter, however, is that it is still
8 impossible to predict with accuracy when the wind will
9 blow, and Idaho Power continues to experience volatility in
10 trying to determine when wind generation will provide
11 energy on its system. In addition, none of the QF wind
12 generators on Idaho Power's system provide generation
. 13 schedules to Idaho Power. And, even if they did, there are
14 no "teeth" in the power purchase agreements to enforce
15 those schedules. My understanding is that in the recent
16 agreements Idaho Power has entered into with QFs, the only
17 performance guarantees are a "Mechanical Availability
18 Guarantee," which only requires that the QFs' equipment be
19 mechanically available for a specific amount of time each
20 month. While I understand that as a policy matter there
21 are reasons for not requiring wind generators to provide
22 schedules, from a system planning and operating standpoint,
23 intermittent generators can cause significant issues with
24 reliably operating Idaho Power's system.
IS

25
628
PARK, REB 5
Idaho Power Company
1 Q. Mr. Looper is also critical of how Idaho Power
2 characterizes "must run" resources and how it will treat
3 those resources in the implementation of Schedule 74. What
4 is your response?
5 A. Mr. Looper's characterization of how Idaho
6 Power will determine its "must run" resources under
7 Schedule 74 misstates what Idaho Power has said in
8 testimony and responses to discovery and is based on the
9 assumption that some sort of carbon tax currently exists.
10 Idaho Power operates its coal resources based upon load
11 need and market conditions. Typically, in the spring
12 months, Idaho Power will have two Bridger units dispatched
. 13 and its Valmy and Boardman units will either be off-line or
14 Idaho Power's partners at those facilities will be taking
15 Idaho Power's share of generation. From an operational
16 perspective, Idaho Power will dispatch those two Bridger
17 units such that they are backed-down to minimum loading
18 during the light load hours and ramped-up to meet the peak
19 or sell into the market, if it is economical and beneficial
20 to the Company's customers, during the heavy load hours.
21 Importantly, and as explained in my direct testimony, the
22 Company's coal generators cannot simply be "shut off" and
23 then turned back on to serve load. Once fired from a cold
24 start, it takes a coal plant several days to heat up in
. 25 order to reach generation levels. In addition, and as
629
PARK, REB 6
Idaho Power Company
1 explained in my direct testimony, cycling off coal units is
2 hard on the generators as changes in temperatures from hot
3 to cold and cold to hot on a frequent basis causes
4 excessive stress and fatigue on the turbines and other
5 equipment.
6 Q. Mr. Looper contends that if a hypothetical
7 carbon tax were to come to pass, it may be cheaper to
8 operate the Company's natural gas peaker plants than its
9 coal units. What is your response?
10 A. I do not want to speculate as to whether some
11 sort of federal carbon tax would make it less expensive to
12 run Idaho Power's natural gas peaking units versus Idaho • 13 Power's coal generators. However, the reality is that,
14 currently, no carbon tax exists. If a carbon tax were to
15 be implemented, obviously, Idaho Power would need to
16 examine all of its resources to determine the impacts of
17 such a carbon tax on its system, including how it would
18 impact the implementation of Schedule 74. Since no carbon
19 tax currently exists and is not a real cost of operations,
20 it is not appropriate to treat it as such. Idaho Power
21 operates its own generation resources based upon real
22 economics, not hypothetical scenarios.
23 Q. Both Mr. Looper and the North Side Canal
24 Company's Donald Schoenbeck are critical of Idaho Power's • 25 characterization in Schedule 74 of including Langley Gulch
630
PARK, REB 7
Idaho Power Company
1 power plant ("Langley Gulch") as a "must run" resource.
2 What is your response?
3 A. Langley Gulch is considered a "must run"
4 resource to meet system peak demands and will also be "must
5 run" during periods of the year in which the Company needs
6 more flexibility in ramping to integrate the growing amount
7 of intermittent resources on Idaho Power's system.
8 Currently, Idaho Power relies, to a large extent, on the
9 ability of the Hells Canyon hydro facilities to integrate
10 intermittent generators on its system. Langley Gulch will
11 add more integration capability to Idaho Power's system
12 because of its ability to ramp up and down more quickly
. 13 than the Company's coal-fired generators. However,
14 although Langley Gulch has the ability to ramp up and down,
15 there are still limitations on taking it off-line during
16 low loading periods. To ensure its availability to ramp
17 when the variable intermittent resources drop or fall off,
18 Langley Gulch will need to be on-line and running at
19 minimum loadings during some periods, making it a "must
20 run" resource, in order to provide the regulation service
21 and other ancillary services required by North American
22 Electric Reliability Corporation mandatory reliability
23 standards.
24
•25
631
PARK, REB 8
Idaho Power Company
1 II. OTHER ISSUES
2 Q. What is your response to the Direct Testimony
3 of Idaho Conservation League's Justin Hayes?
4 A. As an initial matter, I must say that I am not
5 qualified to speak on the various details of the Company's
6 FERC licensing requirements for its hydro generation
7 facilities. The Company has a separate team of individuals
8 that deal in the specialized area of administering its FERC
9 licenses. That said, as the Director of Load Serving
10 Operations, I am responsible for ensuring that the
11 Company's Grid Operations group maintains Idaho Power's
12 hydro generators in accordance with the information
13 provided by its FERC licensing team.
14 As for Mr. Hayes' testimony, I really find it quite
15 puzzling. His entire testimony focuses on responding to a
16 single sentence made at page 20 of my direct testimony.
17 Mr. Hayes' only issue appears to be increasing water flows
18 at four of Idaho Power's run-of-river hydro generating
19 facilities. Water flow and other water quality issues are
20 part of Idaho Power's obligations to meet applicable
21 provisions of the federal Clean Water Act, as prescribed in
22 the Company's FERC licenses. Thus, Mr. Hayes'
23 recommendations are, in general, beyond the scope of this
24 proceeding.
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PARK, REB 9
Idaho Power Company
1 Q. At page 5 of the Direct Testimony of Ted
2 Sorenson for the Renewable Energy Coalition, Mr. Sorenson
3 describes how it is physically possible to ramp hydro
4 generation at facilities such as Idaho Power's run-of-river
5 hydros. What is your response?
6 A. Mr. Sorenson caveats his description of how it
7 is physically possible to ramp hydro generation by stating
8 he is not "getting into a discussion of legal issues
9 concerning what Idaho Power's FERC licenses may or may not
10 require . . . ." Idaho Power must operate its hydro system
11 in accordance with its FERC licenses. Thus, any
12 description of the operation of Idaho Power's hydro . 13 generators without consideration of the Company's FERC
14 licenses, which Mr. Sorenson does, is meaningless.
15 Q. Mr. Sorenson and Mr. Hayes claim that the FERC
16 licensing for the Mid-Snake projects allows for
17 implementing spill instead of generating. What is your
18 response?
19 A. While it is true the Company has some limited
20 ability to spill at its Mid-Snake hydro facilities, Mr.
21 Sorenson and Mr. Hayes fail to understand the operational
22 restrictions that are a portion of the FERC licenses
23 associated with those facilities. In order for the Milner,
24 Twin Falls, Bliss, and Lower Salmon Falls plants to pass • 25 river requirements via spill instead of generation, Idaho
633
PARK, REB 10
Idaho Power Company
1 Power grid operators must do so at each generating plant
2 while maintaining the FERC license requirements. Even if
3 this could be done without violating the requirements of
4 the FERC licensing, this is not an easy task nor is it one
5 that can be done quickly. It becomes even more complicated
6 when an over generation event occurs, such as high hydro
7 conditions and maximum wind generation on Idaho Power's
8 system. For example, take a situation where wind ramps up
9 by 300 megawatts ("MW") and then backs down by 250 MW
10 within a one hour time frame, which is a very realistic
11 scenario on Idaho Power's system. In this case, the Idaho
12 Power generation dispatcher would need to go through the . 13 timely process of carefully ramping the generation down
14 incrementally at each Mid-Snake plant, while ensuring that
15 FERC licensing criteria are not violated, as the wind
16 increased within the hour while opening the spill gates.
17 Importantly, this process is not responsive enough to
18 ensure the Company maintains its mandatory system
19 reliability parameters. Moreover, the generation
20 dispatcher is also tasked with operating the remaining
21 plants on the Company's system and responding to lost
22 generation and load variations which may be caused by a
23 variety of factors.
24 Q. The Direct Testimony of Dr. Don Reading • 25 suggests that from a transmission and interconnection cost
634
PARK, REB 11
Idaho Power Company
1 perspective, the Idaho Public Utilities Commission should
2 implement a policy that treats QF generators the same as
3 utility-owned resources and other non-PURPA generators,
4 where the utility is able to fully recover such
5 transmission and interconnection costs from its customers
6 and that non-utility, non-PURPA generators receive a refund
7 over time for the entire cost of transmission system
8 upgrades. What is your response?
9 A. I disagree that QF5 should be allowed to
10 recover interconnection and transmission costs associated
11 with QF projects. Utility-owned resources are part of a
12 thorough, integrated resource planning process which also . 13 must go through a contested regulatory proceeding to
14 receive a Certificate of Public Convenience and Necessity.
15 In addition, when siting utility-owned resources, the
16 Company looks at proximity of the resource to loads and/or
17 available transmission capacity. PURPA generators, on the
18 other hand, locate their generation projects without any
19 regard or consideration for Idaho Power's system needs,
20 proximity to loads, or available transmission capacity.
21 Idaho Power's customers must be held indifferent to the
22 transactions required by the QF. But for the QF
23 generator's request, the utility would not build the
24 interconnection and transmission facilities that are • 25 required to connect the QF generator to the system and
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PARK, REB 12
Idaho Power Company
1 bring its generation to Idaho Power loads. As a result of
2 the large amount of PURPA requests on Idaho Power's system,
3 the Company has to complete interconnection and
4 transmission system upgrades that it otherwise would not
5 need to serve load. Because these system upgrades do not
6 serve any other purpose or need required to provide service
7 to Idaho Power's customers, it would not be appropriate to
8 require customers to pay for interconnection and
9 transmission system upgrades that are not needed to serve
10 load.
11 Q. Mr. Looper's testimony discusses the March
12 2012 Bonneville Power Administration's ("BPA") Dispatch
13 Standing Orders wherein BPA proposes to compensate wind
14 generators on its system that it curtails due to generation
15 oversupply events. Mr. Looper alleges this is BPA's "own
16 version of Schedule 74." Do you agree that BPA's proposal
17 is similar to Idaho Power's proposed Schedule 74?
18 A. Absolutely not. Idaho Power's situation is
19 completely different than BPA's. The vast majority of the
20 wind generation on Idaho Power's system is QF generation
21 that Idaho Power has a "must purchase" obligation under
22 PURPA and which Idaho Power must use to serve load. The
23 wind generation on BPA's system is not being purchased by
24 BPA but consists of point-to-point transmission service • 25 that BPA simply wheels, or transmits, for the generator,
636
PARK, REB 13
Idaho Power Company
1 and does not use the generation to serve its customers.
2 Thus, BPA is proposing to curtail an oversupply of
3 generation in its balancing area when it cannot export
4 generation to other balancing areas - to curtail generation
5 during oversupply periods from a transmission provider's
6 perspective. Idaho Power's proposed Schedule 74 proposes
7 to operationally dispatch QF generators so as to
8 efficiently manage load services and load serving
9 operations on its system. Specifically, Idaho Power's
10 Schedule 74 is uniquely designed to effectuate FERC PURPA
11 regulations, namely 18 C.F.R. § 292.304(f), which relieves
12 Idaho Power from its obligation to purchase QF generation
S 13 during light loading periods, when only base load units are
14 operating and Idaho Power would be forced to cut back
15 output from the units in order to accommodate the
16 unscheduled QF energy purchases. Because such base load
17 units might not be able to later increase their output
18 levels rapidly when the system demand later increased,
19 resulting in the utility needing to rely upon less
20 efficient, higher cost units, FERC has stated that C.F.R. §
21 292.304(f) applies to such low loading situations and can
22 be used by utilities to curtail QF generation in such
23 instances. In sum, Idaho Power and BPA are in completely
24 different situations and it is not appropriate to draw
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PARK, REB 14
Idaho Power Company
1 comparisons between what BPA is proposing and what Idaho
2 Power is proposing.
3 Q. Does this conclude your rebuttal testimony?
4 A. Yes.
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Idaho Power Company
(The following proceedings were had in
open hearing.)
(Idaho Power Company Exhibit Nos. 4 and 5,
having been premarked for identification, were admitted into
evidence.)
MR. J. WILLIAMS: Thank you, Madam Chair. At
this time, the witness is now available for cross-examination.
COMMISSIONER SMITH: Thank you.
Mr. Solander, any questions?
MR. SOLANDER: No questions, thank you.
COMMISSIONER SMITH: Any questions?
MR. ANDREA: No questions, thank you.
COMMISSIONER SMITH: Mr. Arkoosh, do you have
questions?
MR. ARKOOSH: No, thank you, Madam Chairman.
COMMISSIONER SMITH: Questions for the witness?
MR. R. WILLIAMS: Yes, I do.
COMMISSIONER SMITH: Thank you.
CROSS-EXAMINATION
BY MR. R. WILLIAMS:
Q. Good afternoon, Ms. Park.
A. Good afternoon.
Q. On page 3 and 4 of your testimony, you talk about
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my client, Dynamis Energy, LLC, and you mention -- you say that
Dynamis would not agree to make the energy for its project
dispatchable unless Idaho Power agreed to pay a very high price
for that project.
Are you familiar with that or did you say that?
Of course you said that: It's in your rebuttal testimony.
A. Yes, I did say that in my rebuttal testimony.
Q. Okay. And you weren't in those negotiations with
Dynamis, were you?
A. No, I was not.
Q. So how did you come to understand that they
wanted a very high price for dispatchability?
A. Through conversations with other employees of
Idaho Power.
Q. And who did you have those conversations with?
A. Various people. I don't recall exactly who said
that it was the higher price.
Q. Okay. Well --
A. Higher dispatch cost.
Q. I mean, I was in those negotiations, so let me
suggest that maybe you talked with Randy Aliphin about that?
A. He was probably present in those conversations,
yes.
Q. So would it be fair to say that Randy Allphin
told you that Dynamis wanted too high a price for
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dispatchability? Is that a correct assumption from this
reading?
A. Yes.
MR. R. WILLIAMS: So may I approach the witness
with two potential exhibits?
COMMISSIONER SMITH: You may.
MR. ARKOOSH: He's got a bigger staff, I would
say, than Mr. Richardson.
MR. R. WILLIAMS: And very highly paid as well.
COMMISSIONER SMITH: Certainly experienced.
MR. R. WILLIAMS: That's right. If they charge
me by the hourly rate, I'm not going to be able to afford it.
Q. BY MR. R. WILLIAMS: Actually, Mr. Schoenbeck is
giving you the second one I wanted to talk about.
MR. R. WILLIAMS: If you would just give the
witness the first one and then we can get everybody else.
Q. BY MR. R. WILLIAMS: So, Ms. Park, what I've
handed to you is --
MR. J. WILLIAMS: Mr. Williams, can you just hold
on a second?
MR. R. WILLIAMS: Sure. Thanks.
COMMISSIONER SMITH: And is this going to be
1000 --
MR. R. WILLIAMS: 1001 is the document that says
Dynamis Project Pricing Analysis, For Discussion Purposes Only,
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prepared by Idaho Power.
COMMISSIONER SMITH: So that's already an
exhibit. Right?
MR. R. WILLIAMS: No, it's not. I just marked it
1001, so --
COMMISSIONER SMITH: I have a 1001.
MR. R. WILLIAMS: And then I'm marking 1002 on
the e-mail from Randy Allphin.
COMMISSIONER SMITH: We already have an Exhibit
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MR. R. WILLIAMS: Okay, well --
COMMISSIONER SMITH: And it's Mister -- is it
Looper?
MR. R. WILLIAMS: Looper.
COMMISSIONER SMITH: Mr. Looper. Attached to his
testimony is a 1001. So this would have to be 1002.
MR. R. WILLIAMS: Fortunately, that's why I left
it blank, for those kind of mistakes.
MR. J. WILLIAMS: Madam Chair, I'm going to
object on a couple of different grounds, one of which is the
attorney-client privilege. The information that Mr. Williams
has handed out is part -- a small part and parcel of extensive
confidential discussions related to the power purchase
agreement that Dynamis had with Idaho Power.
In addition, Ms. Park has already testified that
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she was not directly involved with those negotiations, and that
her testimony is based on conversations that she had with other
people.
So I guess I'm concerned with where Mr. Williams
is going with this, and I object on the grounds based on
privilege, beyond the scope of her testimony, and that it's
confidential.
COMMISSIONER SMITH: So whose information is
this? Is this Idaho Power's information or is this Dynamis?
MR. R. WILLIAMS: Madam Chairman, the first box
is what Dynamis proposed to Idaho Power. The next three boxes
are the proposals Idaho Power presented back to Dynamis, along
with the hourly pricing generation schedule and the load
shapes. Dynamis --
COMMISSIONER SMITH: Well, I'm just trying to get
at whose information is it, because, in my mind, that's the
entity that has the privilege. And if this is Dynamis's
information and they want to waive their privilege, I think
they're free to do that.
MR. R. WILLIAMS: Well, again, where it says the
Dynamis proposal, this was -- the very first box is the Dynamis
proposal which was given to Idaho Power, so to the extent that
we signed a confidentiality agreement -- which I don't believe
we did to negotiate the PPA, but maybe we did --
MR. J. WILLIAMS: Madam Chair --
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MR. R. WILLIAMS: -- we would waive that.
MR. J. WILLIAMS: The document itself says
"Prepared by Idaho Power Power Supply, January 2, 2011," so I'm
not sure if Mr. Williams' representation that this information
was proposed by Dynamis is correct. I, unfortunately, don't
know either without having Mr. Aliphin here or the other people
from Idaho Power to sit down and talk to them about it, because
I wasn't involved with those negotiations either.
COMMISSIONER SMITH: Mr. Williams.
MR. R. WILLIAMS: Well, my point in this line of
cross-examination is simply to, first of all, rebut the
accusation that the pricing proposal by Dynamis was improper --
or, was too high, because, in fact, we didn't make the pricing
proposal, Idaho Power did. And so I think I have the ability
to impeach her on the fact that what she's saying is not true.
We didn't make a pricing proposal, Idaho Power made the pricing
proposal. In fact, Idaho Power made three different options
and Dynamis accepted the second one, the two percent pricing
proposal, only to have it ripped out from them, as the second
e-mail from Mr. Allphin shows.
MR. J. WILLIAMS: Madam Chair, I'm going to --
again, Mr. Williams is potentially mischaracterizing the
negotiations, the extensive negotiations between Idaho Power
and Dynamis that Ms. Park has already testified to that she has
not been directly involved in.
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COMMISSIONER SMITH: So would if be preferable to
strike her testimony, which has an opinion about this,
apparently of which she was not personally engaged?
MR. R. WILLIAMS: Well, Madam Chair, that would
have been the easy thing to do, but I don't want to strike her
testimony. I want to use it to impeach her.
COMMISSIONER SMITH: So, I need about a
five-minute stretch break. This would be a good time to do
that. We'll be at ease for five minutes.
(Recess.)
COMMISSIONER SMITH: All right, we'll go back on
the record. Mr. Williams.
MR. J. WILLIAMS: Thank you, Madam Chair. Idaho
Power would propose to withdraw the portion of Ms. Park's
testimony beginning at the bottom of page 3, line 25, the
sentence beginning "However, it is my understanding," all the
way through to page 4 at line 11, ending with "heavy load
hours."
COMMISSIONER SMITH: This is in her rebuttal
testimony?
MR. J. WILLIAMS: I'm sorry, Madam Chair, yes,
it's in her rebuttal testimony, again beginning at the bottom
of page 3, line 25, beginning with the words "However, it is my
understanding," all the way through line 11, ending with "heavy
load hours.".
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Idaho Power would agree to withdraw that portion
of the testimony, purportedly believes that the -- well, we'll
just leave it at that.
MR. RICHARDSON: Could you repeat that section
that you've withdrawn?
MR. J. WILLIAMS: Sure. In Ms. Park's rebuttal
testimony at the bottom of page 3, beginning at line 25, the
words beginning "However, it is my understanding," all the way
through page 4, to line 11, ending with "heavy load hours."
COMMISSIONER SMITH: Mr. Williams.
MR. R. WILLIAMS: I have no objection.
COMMISSIONER SMITH: Okay. Then we will unadmit
or unspread the testimony of Ms. Park's rebuttal testimony
beginning line 25 with the word "however," through page 4,
line 11, ending with the period after "heavy load hours" will
be stricken.
Back to you, Mr. Williams.
MR. R. WILLIAMS: So I will not be using either
of the two exhibits that I --
COMMISSIONER SMITH: Okay, we will unmark --
MR. R. WILLIAMS: 1002 is still open.
Q. BY MR. R. WILLIAMS: Now, Ms. Park, on page 4 of
your rebuttal testimony, you also make the statement that
Dynamis controls when, if, and to what extent it delivers its
generation to Idaho Power. And I'm going to have passed to you
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an exhibit that is excerpts from the Dynamis contract, so I'm
going to wait until you get that.
COMMISSIONER SMITH: And this will be 1002.
MR. R. WILLIAMS: This is the new 102.
COMMISSIONER SMITH: 1002. Thousand.
(Dynamis Exhibit No. 1002 was marked for
identification.)
Q. MR. R. WILLIAMS: Do you have a copy of that
contract now?
A. Yes, I do.
Q. Okay. And I'm assuming you're not familiar with
the contract, so I'm just going to represent to you at this
point, subject to check, that this -- these are excerpts from
the actual contract executed between Dynamis Energy and Idaho
Power Company.
So were you aware that this contract contains
restrictions that prohibit Dynamis from generating during light
load hours?
A. I wouldn't clarify it -- or, classify it as
prohibiting, although it does result in no payment for energy
delivered.
Q. Okay. And, likewise, you're generally familiar
that this contract requires Dynamis to generate from the hours
of 7:00 a.m. to 10:00 p.m.
A. That is correct, they're incented to generate
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between those hours.
Q. So if you could turn to the second -- well, the
second page of this exhibit, it's page 14 of the contract, and
I'm going to read Section 6.3 to you beginning with the
first -- well, that part doesn't matter. But, anyway, they
have the first seven months, and then it says:
Unless excused by events of force majeure, forced
outage, or scheduled maintenance -- those are going to be magic
words here in a minute -- seller delivers hourly net energy to
Idaho Power. If seller delivers energy that exceeds plus or
minus ten percent, then effectively -- and they do -- they miss
their mark by a plus or minus ten percent of 20 megawatts, they
get -- they take a 15 percent price reduction.
I mean, that's essentially what this provision
says?
A. I would agree with that.
Q. Okay. And the only -- again, and the only
exceptions to this delivery obligation are the three horsemen:
Force majeure, forced outage, scheduled maintenance. Correct?
A. That is correct.
Q. So if Idaho Power --
And you've also testified that you believe that
under Schedule -- your proposed Schedule 74, the Company could
curtail Dynamis. Correct?
A. That is correct.
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Q. Okay. So if Idaho Power curtails Dynamis when
they are operating, how are they going to avoid this 15 percent
penalty? If the curtailment lasts such that they miss this ten
percent ban, how are they going to avoid this penalty?
A. First off, I'd like to say that because the
Dynamis, that 15 percent penalty, is during heavy load hours,
the potential to have the light loading types of curtailment
we're talking about are extremely minimal. In fact, I don't
know that I expect that it would ever occur.
Q. But you testify that it could occur in your
rebuttal?
A. There is a potential it could occur, very rare.
Very rare circumstance, it could occur.
Q. You're pretty adamant that this is not -- I mean,
if it happens in light load hours, correct, it wouldn't affect
them, right, but you testify that it could happen during heavy
load hours and you could not -- you assert the right under 74
to knock Dynamis off?
A. That is correct.
Q. So let's assume that you do that and it causes
them to miss this mark. Don't you force them into a penalty, a
de-rating of what their revenue would be?
A. I think that that would classify -- and I'm not
familiar with all of the terms of the contract, but it appears,
to me, that that would be a situation beyond their control and
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would be a force majeure event for which they wouldn't be
penalized.
Q. So you think that everytime that you testify
under Schedule 74 that you curtail anybody -- Dynamis or anyone
else -- you think that's force majeure?
A. No, I'm saying that it would be in this case, if
we curtail during a heavy load hour and they have penalties for
delivery that they have to meet during those heavy load hours,
that wouldn't be their responsibility to deliver during that
hour if we had limited their output.
Q. You probably haven't reviewed the force majeure
language of any of Idaho Power's PPAs, or have you?
A. I'm vaguely familiar with it, but not
specifically, no.
Q. But you still think that could be force majeure?
A. I would think so.
Q. Okay. Now, let's go over to the next paragraph,
7.3. And I've given you the benefit of - well, given
everybody the benefit of some underlining. And here it says --
this is the light load energy provision, and it says,
basically, it says seller cannot deliver energy during these
light load hours which are 10:00 p.m. to 7:00 a.m. And it says
any light load hour produced by seller and delivered to Idaho
Power may be accepted by Idaho Power at no cost, or you
actually can curtail us. Correct? I mean, isn't that what
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this says, Section 2: Idaho Power may curtail all light load
energy deliveries?
A. Yes, with no notice provided to the seller.
Q. So you actually negotiated here in this contract
a curtailment right. Correct? I mean, that's the way I read
this.
A. Yes, in this contract, there's a curtailment
provision for light load.
Q. And this provision would be enforceable by
Idaho Power, wouldn't it?
A. Yes, it would.
Q. I mean, if we were trying to stuff you with power
and you didn't want it, you could do whatever you could here at
the Commission or at court.
So back to Paragraph 6.3, Dynamis negotiated and
got a right to deliver to you firm power, 20 megawatts plus or
minus ten percent, for 18 hours of the day, subject to the
three horsemen. And if you -- let's just assume that Schedule
74 wasn't force majeure, yet you curtailed them. Wouldn't
Dynamis have the same enforcement rights against Idaho Power
and say, "You have to take my power during these days"?
A. I think that calls for a legal conclusion that I
can't render. I'm not --
Q. I'm going to switch topics a little bit. You
testify a lot about Langley Gulch, correct, and you have some
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experience scheduling Langley in the Idaho Power system?
A. We have very limited experience scheduling
Langley. It's only been online since --
Q. Okay.
A. -- July.
Q. Can Langley run in simple cycle mode as well as
combined cycle load?
A. Yes, it can.
Q. Okay. And so in that instance, it's really no
different than Bennett Mountain or Evander Andrews. I mean,
it's the same Siemens unit, roughly. It's maybe the next
generation, but they're roughly the same series of frame units,
correct, in simple cycle mode?
A. That's my understanding, yes.
Q. And when Langley runs in simple cycle, do you
know, what is its generating output at max?
A. Somewhere around 140 megawatts, but I am not a
hundred percent positive about that.
Q. So if Langley is running in simple cycle mode as
opposed to combined cycle mode, do you still consider the base
load for purposes of Schedule 74?
A. Because we are using Langley Gulch, as I said in
my testimony, because we use Langley Gulch as a method of
helping to integrate renewables, particular variable renewables
on our system, it could be that it would be considered must-run
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if we -- just like any other thermal resource, that if you had
to take it offline and would experience additional cost as a
result of that because you weren't able to bring it back,
which, you know, there are some costs associated with taking it
all the way offline and bringing it back, then we would.
Q. But we're talking about Langley running in simple
cycle mode now, not combined. There's no steam, there's no
water. Isn't that the equivalent of Bennett Mountain or
Evander Andrews when it's running in simple cycle mode?
A. It is from the standpoint that it acts like a
simple cycle, but it doesn't from the operational perspective
that it has additional capabilities that the others do not.
Q. Right, I understand that, but I'm stuck now with
Langley and simple cycle mode. And my question to you -- and I
think you said yes, but tell me if I'm wrong -- my question was
if Langley is running in simple cycle mode, you would still
consider must-run base load resource for purposes of Schedule
74. Correct?
A. I think I said it depends on the circumstances.
I couldn't say that a hundred percent of the time we would or
would not include it as must-run. It depends on the
operational circumstances at the time.
Q. So let me say it another way then. Let's just
assume Langley is running in simple cycle mode as a peaker and
you reserve your right the option to decide whether it is or is
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not a base load must-run resource. Is that what you just said?
A. That is correct.
Q. Okay. Now, let's say there is a problem at
Langley and it goes down. Would you substitute Evander Andrews
or Bennett Mountain in as the must-run unit in that case?
A. No.
Q. Well, what's the difference? They're all
essentially peaking units at that point. Why wouldn't you --
and if you have that discretion with Langley, why wouldn't you
transplant that discretion over to one of your other simple
cycle units?
A. Because they don't have the ability that a simple
cycle does to become a combined cycle. So just saying that --
taking Langley and saying it's a simple cycle unit and I'm only
going to consider it as a simple cycle unit, not a combined
cycle, isn't -- you're not comparing apples to oranges. I
mean, it's apples to apples, it's two different machines, so --
Q. Sure. Sure.
A. We will operate them differently.
Q. But wait. You said they're different machines.
They're the same machine when they're in simple cycle mode.
Correct?
A. Well, they are, except --
Q. They're Siemens 501 genesis machines. Correct?
A. Yes.
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Q. Okay. In the simple cycle mode?
A. In the simple cycle mode.
Q. Okay. Now, is Langley -- does it have a
limitation on the number of starts it can make per year by
Siemens?
A. There are limitations on Langley starts depending
on operationally whether those are cold starts or warm starts,
there's different limitations.
Q. Is there a warranty restriction where Siemens
said you may not start this more than X number of times per
year?
A. I am not aware of what the warranty is for
Langley.
Q. If you wouldn't mind checking for me, but my
understanding is that there are no restrictions from Siemens on
the number of starts Langley can make per year, but if I'm
wrong on that, we can clear that up.
MR. J. WILLIAMS: Madam Chair, I will object to
the question Mr. Williams has asked. If he can continue to
build upon that foundation, because the witness testified she
simply doesn't know. So his assumption is irrelevant.
MR. R. WILLIAMS: I think it's on your Web site.
Q. BY MR. R. WILLIAMS: Would your -- if I asked you
the same question regarding the number of starts for Bennett
Mountain, Evander Andrews, would your answer be the same, that
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you don't know what their starts are, limitation on their
starts by Siemens?
A. That is correct. As it applies to warranties, I
have no knowledge of that.
Q. Now, you represent again on your Web site that
Langley Gulch is a fast start unit. What does that mean, to
you?
A. Depending on whether it's at -- whether it's on
turning gear or not, that can it be up and operational within a
30-minute time frame.
Q. If it's in warm start mode, synchronized, what's
its ramp rate?
A. I'm not sure.
Q. Is it -- would you -- would you believe it can be
ramped at 25 megawatts per minute? Do you think that would be
reasonable?
A. Depending on where it's operating it at,
potentially, yes.
Q. Well, when it comes on, what's its minimum?
A. I don't know for sure.
Q. You don't know. Okay. Is the minimum different
between simple and combined cycle?
A. There's different operating limits for it, but
I'm not sure what, exactly, those are and how they're spelled
out. I don't physically operate the plant, so I'm not overly
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familiar with those limits.
Q. Now, Siemens represents it can go unsynchronized
from cold -- a flex unit that they have can go from cold start
to synchronized and ramping in 20 minutes or less. Are you
familiar with that?
A. No, I'm not.
Q. Okay. Let's assume that Bennett and -- Bennett
Mountain, Langley, and Evander Andrews could all ramp at 25
megawatts per minute once they're in a warm mode. Wouldn't
this allow you to go from zero generation to 450 megawatts in
about five to six minutes?
A. I think you're asking for something that would
say that you've got people at all those plants, manned, ready
to do that. Because, I mean, those people actually could get
those plants actually up running and doing that from a
notification? I'm not sure that they could do that.
Q. Well, aren't many times in the year Bennett
Mountain and Evander Andrews kept in a warm start mode where
they can be on the grid in less than ten minutes?
A. Yes, they are.
Q. Okay. But not all the times of the year. Right?
A. That is correct.
Q. What makes you decide whether to take them off
warm start or not?
A. Well, typically they're left in warm start unless
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they're out for maintenance of some sort. We don't usually
leave them not ready to ramp or not ready to start. But I will
tell you that operationally, we have not experienced that you
would ramp those units from cold start to full load within 20
minutes.
Q. Right, I understand. But let's say -- let's go
back to Bennett Mountain, Evander Andrews. You leave those in
warm start mode unless there's maintenance down. So can I
assume that that's, what, 70, 80 percent of the year, or what
would be a percentage for that?
A. Probably 70, 80 percent of the year is a --
Q. So if they're all sitting in warm start mode,
they can be on and ramping in ten minutes, and they can go from
nothing to 450 megawatts in six minutes?
A. I don't think that six minutes is realistic. I
just stated that my experience operationally is that from the
time we give a call to ramp those plants, it is longer than 20
minutes before they're up and operational, hit the grid, and up
to full load. So the six minutes that you're referring to I
don't think is realistic.
Q. You don't think so. Okay. All right. Now, do
you monitor wind generation on an hourly basis or do you
monitor it intrahour?
A. We monitor wind generation every four seconds.
Q. Every four seconds. Okay. In your rebuttal
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testimony on page 13, you state that transmission upgrades
caused by QFs should be borne by QFs because QF generation is
not necessary to serve load.
Do you want to look at that for a minute or do
you want to accept my statement?
A. I said that the vast majority of the wind
generation on Idaho Power's system is QF generation that Idaho
Power has a must-purchase obligation under PURPA and which
Idaho Power must use to serve load.
Q. Okay. Does QF energy that Idaho Power purchases
ever go to serve Idaho Power load?
A. Most often it goes to serve Idaho Power load.
Q. All right.
MR. R. WILLIAMS: Madam Chair, I believe I'm
done.
COMMISSIONER SMITH: Thank you, Mr. Williams.
Mr. Uda.
MR. UDA: Madam Chair, I beg the parties' and the
Commission's permission. I would like to wait because I only
have a very few questions and I have a feeling that my
cocounsel will probably ask my questions, so I would rather not
duplicate effort.
COMMISSIONER SMITH: All right. Do you have any
questions, Mr. Miller?
MR. MILLER: I do, Madam Chairman. Before
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starting, however, these questions may take some time. I'm
looking at the clock and seeing that it's getting close to
five o'clock, and I'm curious whether you would prefer to break
this cross-examination up or start it in the morning.
COMMISSIONER SMITH: And by "some time," does
that mean 5:30? 6:30? 8:00?
MR. MILLER: Well, one can never predict --
COMMISSIONER SMITH: This is true. This is true
and I understand that.
MR. MILLER: -- with certainty. It depends on
the responsiveness of the witness, the -- whether there are
objections from Counsel, whether it goes smoothly or doesn't go
smoothly, but I do have a number of questions that would take
some time.
COMMISSIONER SMITH: So, let's see,
Mr. Richardson, do you have questions for this witness?
MR. RICHARDSON: No, Madam Chairman.
COMMISSIONER SMITH: Ms. Nelson.
MS. NELSON: Madam Chair, I do.
COMMISSIONER SMITH: You do.
MR. OTTO: Yes, I do have questions,
Madam Chairwoman.
COMMISSIONER SMITH: And are yours as lengthy as
Mr. Miller's? It could be, huh?
MR. OTTO: It could be, it could be. I would say
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it would take us at least till 5:00. It very well could be
longer.
COMMISSIONER SMITH: So, Mr. Otto, let's go with
your questions.
MR. OTTO: Okay. There's a great line from a
movie: As you wish.
I don't know if anybody else here -- she knows
what I'm talking about.
MS. SASSER: Princess Bride.
MR. OTTO: Yes, there you go. I'm glad to see
somebody knew.
CROSS-EXAMINATION
BY MR. OTTO:
Q. Good afternoon, Ms. Park.
A. Good afternoon.
Q. I'm going to ask you about page 20 in your direct
testimony.
COMMISSIONER SMITH: Can we see if we can plug ml
the mic?
MR. OTTO: Okay. There we go. Is that better?
Q. BY MR. OTTO: Do you have your page 20 in front
of you?
A. Yes, I do.
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HEDRICK COURT REPORTING PARK (X)
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A. So, must-run resources, really what we're talking
about here is resources that we need or are required to serve
the load, those with operational restrictions that changing
output or like a run-of-the-river facility that, granted, you
could spill but would result in potential license violations
because of the river and the characteristics of those units,
and the hydro generation that's required to meet environmental
compliance.
Q. So as I see it, two of those categories are hydro
related, and those hydro projects, to your knowledge, are
governed by FERC licenses?
A. Yes, they are.
Q. So that's pretty important to what a must-run
resource is, what a FERC license says?
A. It's very important to a must-run resource.
Q. So what are --
The FERC licenses -- you can agree with me or not
on this, but FERC licenses will put constraints on how you
operate the hydro projects. True or no?
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Q. Okay. I don't. Oh, here we are.
So on that page, you describe three types of
must-run resources. And can you just kind of, in your own
words -- I know you covered it in your direct testimony, but
explain the importa ice of the must-run resources in your
testimony?
HEDRICK COURT REPORTING PARK (X)
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A. Yes, it's my understanding that they do.
Q. And what is the source of those constraints, like
what is a reason those constraints are put on?
A. The reason is to protect the environment, and
there's other things. And I'm not a FERC -- the FERC license
expert. I understand that there are FERC licenses, and the
operational limitations that that places on those units and our
ability to move them, and in particular, do any kind of a load,
follow with them.
Q. So then on your rebuttal testimony, on page 9,
you state that Mr. Hayes's testimony describing the source and
the reasons for some of those restrictions is beyond the scope
of this proceeding. So how do you square that circle? You
just described these are very important, but the witness who
actually testified about the source and meanings of those
restrictions is going beyond the scope. So which is it?
A. In my rebuttal testimony -- his entire testimony
focused on responding to that run-of-the-river part of my
testimony, which -- and our ability to spill or not spill, but
there's other operational restrictions that have license
impacts beyond just whether you could spill or not and the
implications of that from a real-time operations perspective.
Q. Sure, I acknowledge that it's operationally
challenging to balance loads and resources every day.
A. I think that to say that it's operational --
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operationally challenging is a little bit of an understatement.
When we deal with the day-to-day environment from
an operations perspective, we're looking at not only are loads
changing, we're looking at resources, we're looking at
transmission constraints and the ability to move those
resources, and we're looking at the variability of other
resources on the system. So we have a set of generators that
are dispatched in a manner -- which some of those are hydro
I resources -- that alleviates the concern and the impact of
operating those plants to follow load because to meet those
operational restrictions and not to violate a license, and to
maintain the reliability of the system and provide reliable
load service, becomes next to impossible from an operational
perspective.
Q. Well, I noticed the lights are on quite a bit
here in Idaho, so I think your team does a pretty good job of
doing this. Would you agree?
A. Yes, we do.
Q. So while it's difficult, you do do it?
A. We do do it, but we are not --
Q. Thank you.
A. -- using those units to follow load.
Q. So you testify that -- back on page 20, and it's
really about the idea of your must-run resources and how you
define those things. So you have run-of-the-river, and then
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you have other hydro generation needed to maintain required
flows for environmental compliance. And you spoke that some of
those obligations or constraints are imposed for water quality
or wildlife measures?
A. Yes, that's correct.
Q. Correct. Then you also testified that you're
actually not qualified to speak about those license
requirements. Is that true?
A. I can speak about them operationally in general,
but all of the specifics of the license requirements, I'm not
the FERC license expert.
Q. So does Idaho Power have any witness who is going
to speak to the actual requirements imposed by the FERC
licenses, or would that be you?
A. It's me. I don't know anybody else that's going
to speak to that.
Q. Okay. On page -- one of the issues that comes
up -- and this is in your rebuttal testimony. One moment,
please.
I'm sorry, it's in your direct testimony. It's
on page 8. And on page 8, it's the first paragraph. It's kind
of lines 7 through about 14. And to back up a little bit, the
kind of whole question and answer here is talking about --
you're talking about, you know, what you have to go through
with FERC about designating and undesignating resources to
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serve system load or off-system sales. And I'm glad that's not
my job, sounds very complicated, but -- and then you finish
that paragraph by saying at some point you're going to reach a
point where you just don't have the physical ability to
integrate variable resources.
Is that a fair characterization at the end of
that paragraph?
A. Yes, I said in there that the Company had no
plans to configure additional generation resources to provide
regulating margin.
Q. Okay. Did you review Mr. Hayes's testimony?
A. Yes, I did.
Q. Did you see exhibit -- nope, not this one. Did
you see Exhibit 1704?
A. I'm not familiar with that specific exhibit.
Q. Well, I'm going to hand this to you. It's in the
record, 1704, or will be eventually. And I'll ask you to just
identify what it is at the top and then I'll have you turn the
page in a moment.
So that -- what that is is an application to FERC
by Idaho Power for the authority to adjust how you're operating
the Bliss and the Low Salmon Hydroelectric Projects. Is that
true? Is that what you have?
A. Yes, that's what it is.
Q. Can you turn the page and there will be a
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highlighted paragraph, and then with a blue kind of circle
around the sentence. Can you read that?
A. "Idaho Power Company, licensee, is proposing to
amend Article 401 of the licenses for the Bliss and Lower
Salmon Falls Hydroelectric Projects to implement load-following
operation rather than run-of-the-river operation."
Q. Thank you. Could you turn back to the front page
and just note the date that that notice was sent out?
A. September 13th, 2010.
Q. Thank you. So are you going to stand by your
testimony that the Company has no plans to reconfigure its
operations?
A. It said to add or configure additional generation
resources, not ones that we currently have.
Q. Oh, so things you already have, you have no
thoughts about maybe changing how you operate those to
integrate things?
A. Well, obviously we had some thought about that
because we applied for a license to do load following at that
plant, but more as a means of following the load on the system
rather than integration of renewables, because at that point in
time, we didn't realize how much or what the vast quantity of
intermittent resources would be on our system.
Q. You didn't realize that in September 13th of
2010?
HEDRICK COURT REPORTING PARK (X)
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A. Not to the full extent, no.
Q. I guess I have one last question: Is -- in your
opinion, is the Company going to find the kind of least-cost,
most-reliable way to integrate resources by only thinking about
additional generation?
A. No. In fact, Idaho Power is working and I,
myself, am on several groups within the Northwest and other
areas. We've instituted programs like ACE Diversity
Interchange and other things to allow for and promote increased
capacity to integrate intermittent resources on the system. So
we are continuously involved in looking at different options
out there to help with the integration of intermittent
resources.
Q. Could one of those options be changing the way
you operate your lower -- your Middle Snake River dams?
A. Some of it could be that, depending on license
restrictions and what we are allowed to do.
Q. So just to conclude, it's your testimony that
operationally, it's difficult to integrate things and to adjust
generation and load, but that you're not qualified to actually
state whether you have legal restrictions on the ability to do
that?
A. I'm not qualified to state specifically what
those legal restrictions are, but I do know from the
operational perspective that times when we have moved those
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plants -- and I'm talking about moving one or two due to loss
of a unit -- we have experienced periods of times where we get
in trouble with license compliance due to violating
restrictions. And when you start from all of those Mid Snake
plants and start operating them between spill and generation,
which is, you know, a manual, have-to-be-monitored, per-unit
dispatch, it is not feasible to do that to respond to the
variability of wind and maintain the current license
requirements that we have.
MR. OTTO: Thank you. That's all I have.
COMMISSIONER SMITH: Ms. Nelson.
CROSS-EXAMINATION
BY MS. NELSON:
Q. Good afternoon, Ms. Park.
A. Good afternoon.
Q. I'm going to ask you a series of questions about
Schedule 74, so if you wanted to have Exhibit 5 of your direct
testimony handy, that would be helpful.
COMMISSIONER SMITH: Could you get the mic a
little closer, please? Thank you.
MS. NELSON: Is that better?
COMMISSIONER SMITH: That's better.
Q. BY MS. NELSON: Ms. Park, does Schedule 74
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provide for compensation to the QF in the event that Idaho
Power does not give proper notice as required by FERC Section
292.304(f) (3)?
A. Schedule 74 has a clause in it that talks about
the fact that we will notify the applicable QFs prior to
curtailment.
7 Q. Does it have any provision for compensation if
you fail to?
A. No.
Q. Does Schedule 74 include any provision for
seeking the Commission's verification that curtailment was
warranted either before or after the occurrence, as provided by
Section 304(f) (4)?
A. I'm not sure about what you're saying, that the
Commission would validate Section 304(f). I'm not -- I don't
recollect that requirement.
Q. Is there any provision in Schedule 74 where
you'll be seeking the Commission's verification of the
circumstances that you allege were the basis for the
curtailment?
A. No, there's not.
Q. Does Schedule 74 provide for any compensation to
QFs if curtailment causes that QF not to meet its firming
provisions, such as the 85 percent MAG or the 90 percent
threshold in a 90/110 contract?
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A. No, there's no provisions in Schedule 74 for
that.
Q. Is Idaho Power proposing to amend contracts that
are subject to the 90/110 band or the 85 percent NAG to exempt
the hours that a project is subject to curtailment that could
otherwise cause them not to meet those thresholds?
A. Currently at this time, we have not discussed
that.
Q. Does Schedule 74 apply to all contracts with GOLC
and the ten megawatt nameplate regardless of the methodology
used to set the rates in those contracts?
A. Yes, it does.
Q. Does Schedule 74 apply to all contracts with the
GOLC and the ten megawatt nameplate regardless of the rates or
other pricing terms in those contracts?
A. Yes, it does.
Q. Does Schedule 74 apply to all QF contracts with
GOLC and ten megawatt nameplate regardless of a Commission
Order approving the contract rate as representing the full
avoided cost for the life of the contracts?
A. Yes, it does.
Q. Does Schedule 74 apply to all QF contracts
regardless of any of the contract terms other than GOLC and ten
megawatt nameplate capacity?
A. Yes.
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Q. Is it Idaho Power's or the Commission's
responsibility to review each contract to determine whether
Schedule 74 applies?
A. I think that Idaho Power would review it, but I'm
not sure whose responsibility it would be to see whether it
applies or not.
Q. Would Idaho Power then let the Commission review
that decision for each contract?
A. I don't know that. I think that will be up to
our legal to help us decide that.
Q. How many QFs with existing contracts with Idaho
Power will be affected by Schedule 74?
A. I don't recall how many of them there are.
Q. What's the ballpark number?
A. Eighty.
Q. Has Idaho Power provided any specific notice to
the proposed -- of the proposed Schedule 74 to those affected
QFs?
A. No, they have not.
Q. Are all of those affected QF contract holders
party to this docket?
A. I do not know if they are or not.
Q. Are all of the affected QF contracts included in
the record to this proceeding?
A. I don't know that either.
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Q. If Schedule 74 is approved, will Idaho Power seek
to amend each of these existing QF contracts to incorporate
Schedule 74 in its terms?
A. Currently, it is not our plan to do that.
Q. If Schedule 74 is approved, at that time will
Idaho Power notify each of those affected QFs with existing
contracts?
A. We haven't discussed how we would notify.
Q. Will it be the Commission's role to sort through
disputes over the applicability of Schedule 74 to their
existing contracts?
A. Once again, that's not -- it's not an operational
question. I don't know the answer to that.
Q. How long have the circumstances you describe as
giving rise to the need for Schedule 74 been occurring?
A. Well, most definitely, this last year.
Q. Has the Company curtailed for Section 304(f)
reasons yet?
A. No.
Q. Did Idaho Power object to the methodology or the
rates included in Idaho Wind Partners' contracts at the time
that they were approved by this Commission?
A. I don't know that.
Q. You testified in response to some of
Mr. Williams' questions that some of the penalties included in
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Dynamis's contracts might be excused as an act of force
majeure. Is that correct?
A. Yeah. I just didn't see how it could apply if we
limited their output in that specific instance.
Q. Are you suggesting that Idaho Power's decision to
curtail QFs to avoid using higher cost resources is equivalent
to an act of God?
A. No.
MR. J. WILLIAMS: Madam Chair, that calls for a
legal conclusion. She's getting into the nature of whether it
is or is not a force majeure.
COMMISSIONER SMITH: The witness kind of led
herself in for it, and I think she already responded, so --
Q. BY MS. NELSON: Are you familiar --
COMMISSIONER SMITH: -- we'll let Ms. Nelson
proceed.
Q. BY MS. NELSON: Are you familiar with the force
majeure provision in the contracts that QFs hold with Idaho
Power?
A. Vaguely. I'm not totally, no.
Q. Are you suggesting that force majeure is a basis
for Idaho Power to curtail QFs?
A. No, I am not.
Q. Yet it is a basis for excusing the QF5'
performance under the contract when Idaho Power curtails?
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A. I'm not positive how that will all go out. I
think that it would be a legal discussion, when and if Schedule
74 is implemented, how that is handled.
Q. Do you think those legal disputes will come
before this Commission every time?
A. I think they have the opportunity to bring them
to the Commission if they so desire.
Q. There is a requirement in the force majeure
language in each of those contracts and we can get it out and
review it in detail if we need to, but it talks about how the
party that was excused has to provide notice to explain the
circumstances.
Would a QF be able to provide notice to Idaho
Power to explain the circumstances of curtailment after they
are curtailed?
A. I don't know the answer to that.
MS. NELSON: I don't have any further questions.
Thank you, Madam Chair.
COMMISSIONER SMITH: Thank you.
Ms. Sasser, 10 you have questions?
MS. SASSER: Two. Thank you, Madam Chair.
Npm
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CROSS-EXAMINATION
BY MS. SASSER:
Q. Hi, Ms. Parks.
A. Hi.
Q. "Park." Sorry, I keep adding an "s" to your
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A. You're not the only one.
Q. I just have a couple of questions:
On page 14 of your direct prefiled testimony, at
the top of the page, line 1, you talk about Idaho Power working
on an update to its wind integration study.
If the Commission were to adopt the integration
charge determined in Idaho Power's most recent integration
study, would it still be necessary to curtail wind plants under
the operational circumstances of 292.304 or your schedule,
proposed Schedule 74?
A. Yes, it would. The wind integration chart
doesn't reflect the uneconomic choice that we're talking about
from an operational perspective for Schedule 74. It isn't
about -- it's about the uneconomic movement of the hydro system
and to some degree the regulation of Bridger, but it does not
address what happens when you, instead of lining up your
resources for the following day to run, for example, a Bridger
unit, and then you -- you, because you were going to have
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forecasted so much wind you wouldn't run that Bridger unit, you
would put something else in service or, you know, just the
total volume of PURPA that would say, okay, we're going to have
too many resources for our load for that next day so we have to
dispatch Bridger off, for example, make it not available, it
doesn't address those costs associated with whatever
replacement would be to meet the other periods in time when
those resources aren't available. So that incremental cost is
not covered anywhere, and that's the piece that we're trying to
take the harm away from the customers for, because we're not
operating our resources in an efficient manner.
Q. Okay. And the last question:
In your direct testimony on page 25, you talk
about curtailment: The Company will -- starting at line 7:
The Company will curtail all PURPA resources to which this
procedure applies on a pro rata basis.
So does that mean that Idaho Power intends to
also curtail its own PURPA PPAs on a pro rata basis?
A. Idaho Power's PPAs are not -- if they're ten
megawatts or greater, they would be curtailed on a pro rata
basis. Beyond that, any -- any PURPA that's ten megawatts or
greater and has GOLC would be curtailed on a pro rata basis,
regardless of ownership.
MS. SASSER: Thank you. That's all I have,
Madam Chair.
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COMMISSIONER SMITH: Thank you.
So, Mr. Miller, I don't suppose you could be done
by 5:30.
MR. MILLER: Well, I'll start and we'll see wherel
we get by 5:30.
COMMISSIONER SMITH: No. Let's quit for the
evening and take up in the morning at 9:00 a.m. Thank you.
MR. MILLER: Could I ask just one procedural
question?
COMMISSIONER SMITH: You may. Can you turn on
your mic so I can hear it.
MR. MILLER: I was curious just for the parties'
benefit if the Commission has any thought as to whether to
consider closing arguments or whether it's not inclined toward
closing arguments in this case.
COMMISSIONER SMITH: Well, I am always open to
closing arguments, so I think that's fine if the parties would
like to do that.
MR. MILLER: Thank you, Madam Chairman.
COMMISSIONER SMITH: I would note that tomorrow
we will break for lunch at 11:55 and come back at 1:30 because
of commitments by Commissioners.
So, with that, we'll see you in the morning at
•moi.p
(The hearing adjourned.)
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