20120629Dickman Rebuttal.pdf

ROCKY MOUNTAIN
POWER
'A DIVISION Of PAACORP
RECEIVED
2012JUN29 M1IO:50 201 South Main, Suite 2300
Salt Lake City, Utah 84111
June 29, 2012
i r
VIA OVERNIGHT DELIVERY
)TL1 COMPi
Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702
RE: CASE NO. GNR-E-11-03
IN THE MATTER OF THE COMMISSION'S REVIEW OF PURPA QF
CONTRACT PROVISIONS INCLUDING THE SURROGATE AVOIDED
RESOURCE (SAR) AND INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING PUBLISHED AVOIDED COST
RATES.
Dear Ms. Jewell:
Please find enclosed for filing an original and nine (9) copies of Rocky Mountain Power's
rebuttal testimony in the above-captioned case.
All formal correspondence and regarding this Application should be addressed to:
Ted Weston
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, Utah 84111
Telephone: [phone]
Fax: [phone]
Email: [e-mail]
Daniel E. Solander
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Telephone: [phone]
Fax: [phone]
Email: [e-mail]
Communications regarding discovery matters, including data requests issued to Rocky Mountain
Power, should be addressed to the following:
By E-mail (preferred):
By regular mail:
datareguest(pacificori,.com
Data Request Response Center
PacifiCorp
825 NE Multnomah St., Suite 2000
Portland, OR 97232
Idaho Public Utilities Commission
June 29, 2012
Page 2
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.
Sincerely,
Jeffrey K. Larsen
Vice President, Regulation & Government Affairs
Cc: GNR-E-1 1-03 Service List
CERTIFICATE OF SERVICE
I hereby certify that on this 29 th day of June, 2012, I caused to be served, via E-mail, a
true and correct copy of Rocky Mountain Power's Rebuttal Testimony in Case No. GNR-
E-1 1-03 to the following:
Donovan E. Walker
Jason Williams
Idaho Power Company
P0 Box 70
Boise, ID 83707-0070
E-mail: [e-mail]
jwi1liams(,idahopower.com
Michael G. Andrea
Avista Corporation
1411 E. Mission Ave.
Spokane, WA 99202
E-mail: [e-mail]
Daniel Solander Dr. Don Reading
PacifiCorp dba Rocky Mountain Power Exergy Development Group of Idaho LLC
201 S. Main St., Suite 2300 6070 Hill Road
Salt Lake City, UT 84111 Boise, ID 83702
E-mail: daniel.solander(pacificorp.com dreading(mindspring.com
Donald L. Howell, II
Kristine A. Sasser
Deputy Attorneys General
Idaho Public Utilities Commission
472 W. Washington
P0 Box 83720
Boise, ID 83720-0074
E-mail: don.howe1l(puc.idaho.gov
kris.sasser21puc.idtho.gov
Robert D. Kahn
Northwest and Intermountain Power
Producers Coalition
1117 Minor Ave., Suite 300
Seattle, WA 98101
E-mail: rkahn(nippc.org
Robert A. Paul
Grand View Solar II
15690 Vista Circle
Desert Hot Springs, CA 92241
E-mail: robertapau108(gmail.corn
Peter J. Richardson
Gregory M. Adams
Richardson & O'Leary, PLLC
P0 Box 7218
Boise, ID 83702
E-mail: [e-mail]
gre g(richardsonandoleary. corn
Don Sturtevant
Energy Director
J.R. Simplot Company
P0 Box 27
Boise, ID 83707-0027
E-mail: [e-mail]
James Carkulis
Managing Member
Exergy Development Group of Idaho, LLC
802 W. Bannock St., Suite 1200
Boise, ID 83702
E-mail: [e-mail]
Ronald L. Williams
Williams Bradbury, P.C.
1015 W. Hays St.
Boise ID, 83702
E-mail: [e-mail]
John R. Lowe
Consultant to Renewable Energy Coalition
12050 SW Tremont St.
Portland, OR 97225
E-mail: jravenesanmarcos(yahoo.com
Bill Piske, Manager
Interconnect Solar Development, LLC
1303 E. Carter
Boise, ID 83706
E-mail: [e-mail]
Benjamin J. Otto
Idaho Conservation League
710 N. Sixth Street (83702)
P0 Box 844
Boise, ID 83701
E-mail: botto(idahoconservation.org
Don Schoenbeck
RCS
900 Washington St. Suite 780
Vancouver, WA 98660
[e-mail]
Ted Diehl
General Manager
North Side Canal Company
921 N. Lincoln St.
Jerome, ID 83338
E-mail: [e-mail]
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 11th East
Idaho Falls, ID 83404
E-mail: [e-mail]
C. Thomas Arkoosh
Capitol Law Group PLLC
205 N. 10th St. 4th Floor
P0 Box 2598
Boise, ID 83701
[e-mail]
R. Greg Femey
Mimura Law Offices, PLLC
2176 E. Franklin Rd., Suite 120
Meridian, ID 83642
E-mail: greg(mimuralaw.com
Dean J. Miller
McDevitt & Miller, LLP
P0 Box 2564
Boise, ID 83701
E-mail: [e-mail]
Wade Thomas
General Counsel
Dynamis Energy, LLC
776 W. Riverside Dr., Suite 15
Eagle, ID 83616
E-mail: [e-mail]
Brian Olmstead
Twin Falls Canal Company
P0 Box 326
Twin Falls, ID 83303
E-mail: [e-mail]
Bill Brown, Chair
Board of Commissioners of Adams
County, ID
P0 Box 48
Council, ID 83612
E-mail: [e-mail]
Glenn Ikemoto
Margaret Rueger
Idaho Windfarms, LLC
672 Blair Avenue
Piedmont, CA 94611
E-mail: [e-mail]
Margaretenvisionwind.com
M.J. Humphries Arron F. Jepson
Blue Ribbon Energy LLC Blue Ribbon Energy LLC
4515 S. Ammon Road 10660 South 540 East
Ammon, ID 83406 Sandy, UT 84070
E-mail: b1ueribbonenergygmai1.com E-mail: [e-mail]
Lori Thomas Dean J. Miller
Capitol Law Group Chas. F. McDevitt
P0 Box 2598 Ridgeline Energy
Boise, ID 83701-2598 McDevitt & Miller LLP
1thomascapitollawgroup.com 420 West Bannock Street
P0 Box 2564-83701
Boise, ID 83702
E-mail: joe@mcdevitt-mi 1 ler.corn
[e-mail]
Megan Walseth Decker Mary Lewallen
Senior Staff Counsel Clearwater Paper Corporation
Renewable Northwest Project 601 W. Riverside Ave., Suite 1100
917 SW Oak Street, Suite 303 Spokane, WA 99201
Portland, OR 97205 [e-mail]
E-mail: megan(2irnp.org
Liz Woodruff Tauna Christenson
Ken Miller Energy Integrity Project
Snake River Alliance 769N 1100 E
P0 Box 1731 Shelley, ID 83274
Boise, ID 83701 tauna(energyintegrityproject.org
E-mail:
[e-mail]
kmiilersnakerivera11iance.org
Deborah E. Nelson
Kelsey J. Nunez
Givens Pursley LLP
601 W. Bannock Street (83702)
P0 Box 2720
Boise, ID 83701-2720
den(aivenspurslev.com
kjn(ägivenpursley.com
ri 'A I - A fi
Carrie Meyer
Coordinator, Admini ative Services
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
COMMISSION'S REVIEW OF PURPA
) CASE NO. GNR-E-11-03
QF CONTRACT PROVISIONS
) INCLUDING THE SURROGATE
) Rebuttal Testimony of Brian S. Dickman AVOIDED RESOURCES (SAR) AND
INTEGRATED RESOURCE
) PLANNING (IRP) METHODOLOGIES
FOR CALCULATING PUBLISHED
AVOIDED COST RATES
ROCKY MOUNTAIN POWER
CASE NO. GNR-E-11-03
June 2012

I Q. Please state your name, business address and present position with

2 PacifiCorp, dba Rocky Mountain Power Company (the "Company").

3 A. My name is Brian S. Dickman, my business address is 825 NE Multnomah St.,

4 Suite 600, Portland, Oregon 97232, and my present title is Manager, Net Power

5 Costs.

6 Q. Have you previously sponsored testimony in this proceeding?

7 A. No. I am adopting the direct testimony of Company witness Ms. Kelcey Brown

8 that was submitted as part of the Company's original filing in this proceeding. I

9 am the Company witness responding to issues raised by intervening parties

10 concerning the Company's avoided cost methodology, including any issues

11 concerning the direct testimony and exhibits submitted by Ms. Brown.

12 Qualifications

13 Q. Briefly describe your education and business experience.

14 A. I received a Master of Business Administration from the University of Utah with

15 an emphasis in finance and a Bachelor of Science degree in accounting from Utah

16 State University. Prior to joining the Company, I was employed as an analyst for

17 Duke Energy Trading and Marketing. I have been employed by the Company

18 since 2003 including positions in revenue requirement and regulatory affairs, and

19 I assumed my current role managing the Company's net power cost group in

20 March 2012.

21 Q. Have you testified in previous regulatory proceedings?

22 A. Yes. I have filed testimony in proceedings before the Idaho Public Utilities

23 Commission, the Wyoming Public Service Commission, and the Utah Public
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Rocky Mountain Power
I Service Commission.
2 Testimony Summary
3 Q. Please provide an overview of your testimony.
4 A. My testimony responds to avoided cost modeling issues raised by the Idaho
5 Public Utilities Commission Staff ("Staff') and intervening parties in this
6 proceeding. Commercial avoided cost issues will be addressed in the testimony of
7 Company witness Mr. Paul H. Clements. In general, PacifiCorp agrees with Staff
8 witnesses Mr. Rick Sterling and Dr. Cathleen McHugh that the Surrogate
9 Avoided Resources ("SAR") and Integrated Resource Plan ("IRP")
10 methodologies are conceptually appropriate techniques to calculate avoided costs.
11 It is critical, however, that the IRP methodology reflects the best available
12 information to compute the avoided cost specific to each utilities system in order
13 to ensure Idaho retail customers remain indifferent whether the utilities procure
14 energy from qualifying facilities ("QFs") or through the pursuit of a least cost
15 plan developed in an IRP.
16 Q. How is your testimony structured?
17 A. My testimony addresses the following issues:
18 • IRP Methodology Updates - PacifiCorp recommends modeling inputs be
19 updated contemporaneously at the time of each pricing request in order to
20 minimize the cost to retail customers from using outdated modeling
21 assumptions.
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Rocky Mountain Power

1 • Choice of Model - The proposal that the Company be restricted from

2 using the Generation and Resource Integrated Decisions ("GRID") model

3 should be rejected.

4 • Timing of Capacity Payments - The Company's IRP process accounts for

5 the incremental need and cost of capacity on its system, and accordingly,

6 capacity payments should be determined based on the timing of the next

7 deferrable resource in the IRP preferred portfolio.
8 IRP Methodology Updates

9 Q. Please identify the issues raised regarding modeling updates in the IRP

10 methodology.

11 A. The two primary questions raised by parties are: 1) which avoided cost modeling

12 inputs should be updated between IRPs, and 2) how frequently should utilities

13 perform these updates. Modeling inputs are the key drivers for the price that is

14 offered to a QF using the IRP methodology and it is critical to use the best

15 available information.

16 Q. What updates did Staff recommend as appropriate to be made between

17 IRPs?

18 A. Staff witness Mr. Sterling proposes updates be made for fuel price forecasts, load

19 forecasts, and new long-term contract obligations (including new signed QF

20 contracts).

21 Q. Do you agree?

22 A. Yes. I agree that each of these inputs should be subject to update between IRPs,

23 with some clarification. For PacifiCorp in particular, in order to maintain
Dickman, Re - 3
Rocky Mountain Power

I consistency within the GRID model used for the IRP methodology, updating the

2 cost of fuel also requires updating forecast market prices for electricity. In

3 addition to Mr. Sterling's recommendation, PacifiCorp believes updates to all

4 executed purchase and sale agreements for power, fuel, transportation and

5 transmission (including short term agreements) are necessary to achieve a

6 matching of the best available information at the time of the pricing request!

7 PacifiCorp also agrees with Mr. Sterling's recommendation that updates to fuel

8 and electricity price forecasts should be from the same sources (or combination of

9 sources) as used in the Company's IRP.

10 Q. Did others make recommendations regarding which updates should be

11 allowed?

12 A. Yes. Mr. Don Schoenbeck recommended only updating natural gas prices from a

13 third party source and executed QF purchase power agreements. Dr. Don Reading

14 proposed that only natural gas prices from a third party source be updated.

15 Q. Do you agree with these recommendations?

16 A. No. These proposals limit the Company's ability to accurately calculate avoided

17 costs. Updating the natural gas price in isolation is appropriate for the SAR

18 methodology since the SAR model only considers the overall cost of a Combined

19 Cycle Combustion Turbine ("CCCT"). On the other hand, the IRP methodology

20 relies on the overall value a QF would provide when added to the Company's

21 resource portfolio. To accurately calculate that value requires the use of a

22 production cost model such as GRID updated with the most current information
'Contrary to Dr. Reading's statement on page 25 of his direct testimony, to avoid skewing the calculation
of avoided costs, modeling updates are made to both the base case and the incremental case that includes
the zero-cost QF resource.
Dickman, Re -4
Rocky Mountain Power
I available. Updating natural gas prices in isolation could produce unintended
2 results. As mentioned above, the GRID model requires an update to the forward
3 market prices for electricity coincident with changes in natural gas prices.
4 Increasing natural gas prices without increasing wholesale power market prices,
5 as some have proposed, could result in natural gas-fired resources not generating
6 due to the inaccurate spark-spread. This does not reflect reality since wholesale
7 power market prices would likely increase in parallel with increases in natural gas
8 prices allowing natural gas-fired resources to continue to operate economically.
9 Q. What recommendations were made regarding the frequency of modeling
10 updates?
11 A. Mr. Sterling recommends annual updates for load and fuel forecasts, while
12 updates for new contracts would be done whenever a new long-term purchase or
13 sale commitments is made. Mr. Schoenbeck and Dr. Reading each propose to
14 limit updates to once per year.
15 Q. Do you agree?
16 A. No. PacifiCorp recommends updating all modeling inputs, other than the
17 incremental resource additions outlined in the IRP preferred portfolio, at the time
18 the QF pricing is prepared. This will ensure that the IRP methodology provides
19 the most accurate avoided costs and will maintain retail customer indifference.
20 These types of updates are routinely made for the Company's avoided cost
21 calculations in Utah and Wyoming.
Dickman, Re - 5
Rocky Mountain Power
I Q. Have you calculated an example of the effect using outdated modeling inputs
2 can have on avoided cost prices?
3 A. Yes. Table 1 below provides two calculations of avoided cost rates for the
4 hypothetical 22 megawatt ("MW") wind resource included in Table A of Ms.
5 Brown's direct testimony, which I have adopted. The illustrative wind avoided
6 cost price in Ms. Brown's direct testimony was based on modeling inputs current
7 as of January 2012. Alternatively, I have calculated the avoided cost for the same
8 wind resource using modeling inputs current as of May 2011, eight months
9 earlier.
Table 1
Impact of Using Outdated Modeling Inputs
Idaho Wind: 22 MW 34.4% CF
Model Updates Through
January 2012 May 2011 Delta
Avoided Cost Rate ($/MWH) (a) $33.09 (b) $ 53.22 (c) $20.13
Annual Generation (MWH) 66,576 66,576 -
Annual Ratepayer Cost $ 2,202,784 $3,542,843 $ 1,340,059
20 Yr. Ratepayer Cost $ 44,055,679 $70,856,856 $26,801,177
(a)Nominal Levelized 2013 -2032
(b)IRP Methodology avoided cost from the direct testimony of Ms. Brown.
(c)Recalculated avoided cost using model inputs dated May 2011
10 As shown in the first column of Table 1, using more recent modeling inputs
11 resulted in annual avoided cost payments of $2.2 million or $44.0 million over a
12 20 year contract term. Using model inputs from only eight months earlier would
13 have result in annual avoided cost payments of $3.5 million or $70.9 million over
14 a 20 year contract term. If the Company did not have the ability to base pricing on
15 the most accurate information known to the utility at the time of the request, $26.8
16 million of additional cost would be imposed on retail customers over the life of
Dickman, Re - 6
Rocky Mountain Power
I the contract.
2 Q. Does the impact of using outdated inputs have the potential to exceed $26.8
3 million?
4 A. Yes. Had the same pricing been provided to an 80 MW wind facility, the impact
5 of using outdated modeling inputs would exceed $97 million over a 20 year
6 contract term.
7 Q. What arguments are made to justify less frequent updates to modeling
8 inputs?
9 A. Parties have presented three general arguments to justify the use of non-
10 contemporaneous modeling inputs. The first argument, made by witnesses Dr.
11 Reading and Mr. Schoenbeck, is that performing due diligence on
12 contemporaneous model inputs imposes an undue burden on QF developers. The
13 second argument, made by Mr. Sterling, is that the use of contemporaneous model
14 inputs would complicate contract negotiations. The third argument, made by Mr.
15 Schoenbeck, is that the use of contemporaneous data enables utilities to
16 manipulate prices.
17 Q. Are these arguments persuasive?
18 A. No. The merits of these arguments must be weighed against the tens of millions of
19 dollars of needless cost that limiting updates to an annual cycle could impose on
20 retail customers. As demonstrated in Table 1 even a relatively small QF contract
21 commits customers to significant costs over the life of the QF obligation.
2 $26.8 million *8OMW/22MW.
Dickman, Re - 7
Rocky Mountain Power

I Q. How do you respond to the argument that the use of contemporary inputs

2 allows for "game, playing" by the utilities?

3 A. If there is a common understanding of what is being updated, it should be

4 straight-forward for parties to perform a meaningful review of the model inputs.

5 Utilities receive no unfair benefit through the use of contemporaneous inputs

6 other than being able to provide a more accurate price. Furthermore, the timing of

7 the pricing request is under the control of the QF developer, not the Company.

8 Q Could prices could go up as well as down from updates?

9 A. Yes. Prices may either increase or decrease as a result of an update.

10 Q. Does the use of an annual model update schedule provide developers with the

11 opportunity to choose between the outdated price and a contemporaneous

12 price?

13 A. Yes. Developers are aware of changing market conditions and are responsive to

14 changes in prices. Unlike a utility which has no control over when requests are

15 made, a developer has the option to either request prices now or to Wait until after

16 an annual update, depending on market conditions. This asymmetry would harm

17 retail customers and can easily be eliminated through the use of a

18 contemporaneously calculated price.

19 Q. Do you agree with Mr. Schoenbeck's proposal that the eligibility cap for

20 published prices should be set at 10MW nameplate capacity for all types of

21 QF projects, and that the IRP method should only be used for projects above

22 that cap?

23 A. No. The Company reiterates its position stated in the direct testimony of Ms.
Dickman, Re - 8
Rocky Mountain Power

I Brown that the eligibility cap for wind and solar QFs seeking published avoided

2 cost prices should remain at 100kW. The 100kW limit for wind and solar QFs is

3 an appropriate tool to ensure accurate pricing developed using the IRP method

4 and to remove the incentive for larger projects to disaggregate and seek higher

5 published prices.

6 Q. Please summarize your comments regarding model updates.

7 A. The retail customer impact of not using contemporaneous model inputs is

8 significant for a large QF resource. The burden on a QF developer resulting from

9 using contemporaneous model inputs does not outweigh the potential impact of

10 inaccurate prices. Contemporaneous and comprehensive updates of model inputs

11 allow utilities to provide the most accurate pricing to QF developers at any point

12 in time and ensure indifference to retail customers.
13 Choice of Model

14 Q. Please summarize Mr. Schoenbeck's recommendation regarding the use of a

15 third-party model to develop avoided cost pricing.

16 A. Mr. Schoenbeck argues that internally developed models, such as PacifiCorp's

17 GRID model, require far too many exogenous inputs that can influence avoided

18 cost pricing and that utilities should be required to use a third-party model, such

19 as AURORA.

20 Q. How do you respond to Mr. Schoenbeck's recommendation?

21 A. Mr. Schoenbeck's recommendation is unfounded. The GRID model has

22 undergone extensive review in regulatory proceedings and is the same model that

23 is used by the Company in Idaho (and the five other jurisdictions served by the
Dickman, Re - 9
Rocky Mountain Power
1 Company) to develop net power costs in rate making proceedings.
2 Q. Does PacifiCorp provide access to the GRID model for others to review?
3 A. Yes. PacifiCorp provides access and support for the GRID model. This allows
4 developers to perform a detailed review of all of the model inputs and outputs.
5 Timing of Capacity Payments
6 Q. Please explain your understanding of Staff witness Dr. McHugh's proposal of
7 when to include capacity payments under the proposed SAR methodology.
8 A. Dr. McHugh proposes to include capacity payments under the SAR methodology
9 in the year in which a utility's IRP load and resource balance shows that the
10 utility becomes capacity deficient. She distinguishes the capacity deficiency by
11 summer or winter season, and bases a resource-specific capacity payment on the
12 ability of that resource to contribute during the deficient season's peak.
13 Q. Are any other recommendations made regarding the trigger for applying a
14 capacity payment?
15 A. Yes. Mr. Schoenbeck proposes that Idaho Power should determine the timing of
16 capacity payments based on the results from its loss of load expectation study
17 rather than basing it on the results of its IRP load and resource balance.
18 Q. Do you agree with either proposal related to the timing for including a
19 capacity payment?
20 A. No. As demonstrated in PacifiCorp's IRP, the Company has access to a variety of
21 wholesale electricity market hubs that provide flexibility around the timing of
22 procuring capacity resources. In the Company's 2011 IRP Update the load and
23 resource balance using existing resources indicates the Company is peak deficit
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Rocky Mountain Power

I beginning in 2014, excluding planning reserves. A loss of load study is utilized to

• 2 determine the level of planning reserves required, which then influences the

3 preferred resource portfolio. In PacifiCorp's IRP Update, new CCCT resources

4 are projected to be added in 2014 and 2016. However, because the 2014 resource

5 has already gone through the procurement process and is currently under

6 construction, the next deferrable capacity resource in the Company's portfolio is

7 in 2016. Consistent with the IRP, capacity payments should be included in

8 avoided costs coincident with the timing of next deferrable resource.

9 Q. Has this issue been addressed recently in any other state served by

10 PacifiCorp?

11 A. Yes. In Docket UM 1396, Order No. 10-488, the Oregon Commission determined

12 that "the start date of the first 'major resource acquisition' in the action plan of the

13 most recent acknowledged IRP demarcates the resource 'sufficiency' and

14 'deficiency' periods."

15 Q. Do you agree with Dr. Reading's assertion that the Company's IRP is not

16 subject to sufficient scrutiny to warrant its use as an input into the avoided

17 cost process?

18 A. No. PacifiCorp agrees with Avista witness Mr. Clint Kalich and Staff witness Dr.

19 McHugh that today's IRPs are developed with input from the public, regulators,

20 and various other interested parties and should be relied upon in the development

21 of avoided cost prices. Given the six-state nature of PacifiCorp's system,

22 development of the Company's IRP is a rigorous process and the results receive a

23 significant amount of scrutiny, not just in Idaho but across our service territory.
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Rocky Mountain Power
I Q. Does this conclude your testimony?
2 A. Yes.
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Rocky Mountain Power