20120131Brown Direct_Exhibit 201.pdf

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Janua 31, 2012 1012 JAN 31 AM 10: 20
201 South Main, Suite 2300
Salt Lake City, Utah 84111
VI OVERNIGHT DELIVERY
Jean D. Jewell
Commssion Secreta
Idaho Public Utilties Commission
472 W. Washigton
Boise, ID 83702
RE: IN THE MATTER OF TH COMMISSION'S REVIEW OF PURP A QF
CONTRACT PROVISIONS INCLUDING THE SUROGATE AVOIDED
RESOURCE (SAR) AND INTEGRATED RESOURCE PLANG (lRP)
METHODOLOGIES FOR CALCULATING PUBLISHED AVOIDED COST
RATES.
IPUC Case No. GNR-E-ll-03
Dear Ms. Jewell:
Please fid enclosed for filing an original and nie (9) copies of Rocky Mounta Power's
testimony in the above-captioned case.
All formal correspondence and regarding ths Application should be addressed to:
Ted Weston
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, Uta 84111
Telephone: [phone]
Fax: [phone]
Emal: ted.weston(ßpacificorp.com
Danel E. Solander
Rocky Mountain Power
201 South Main Stret, Suite 2300
Salt Lake City, Uta 8411 i
Telephone: [phone]
Fax: [phone]
Email: danel.solander(ßpacificorp.com
Communcations regarding discovery matters, including data requests issued to Rocky Mountan
Power, should be addressed to the followig:
By E-mail (preferred):datarequest(ßpacificorp.com
By reguar mail:Data Request Response Center
PacifiCorp
825 NE Multnomah St., Suite 2000
Portland, OR 97232
RECE D
2m2 JM. 31 AM (0= 20
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
COMMISSION'S REVIEW OF PURP A
QF CONTRACT PROVISIONS
INCLUDING THE SURROGATE
AVOIDED RESOURCES (SAR) AND
INTEGRATED RESOURCE
PLANNG (IRP) METHODOLOGIES
FOR CALCULATING PUBLISHED
AVOIDED COST RATES
)
) CASE NO. GNR-E-ll-03
)
) Direct Testimony of Kelcey Brown
)
)
)
ROCKY MOUNTAI POWER
CASE NO. GNR-E-ll-03
January 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 Kelcey Brown and my business address is 825 NE Multnomah Street,
4 Suite 600, Portland, Oregon 97232, and my present title is Lead/Senior
5 Regulatory Consultant.
6 Qualifications
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Briefly describe your education and business experience.
I have been employed by PacifiCorp since May 2011. Since that time I have
worked on net power costs, avoided cost proceedings, and the preparation of the
Company's Federal Energy Regulatory Commission ("FERC") transmission rate
case filing. Prior to joining PacifiCorp, I worked at the Oregon Public Utilty
Commission from November 2007 through May 2011. During my time at the
Commission I sponsored testimony in several dockets involving net power costs,
integrated resource planning, and various revenue and policy issues. From 2003
through 2007 I worked as the Economic Analyst for a telecommunications
company, Blackfoot Telephone, where I was responsible for revenue forecasts,
resource acquisition analysis, pricing, and regulatory support. I have a B.S. in
Business Economics from the University of Wyoming, which I received in 2001,
and completed all course work towards a Master's degree in Economics from the
University of Wyoming, which focused primarily on regulatory economics.
21 Summary of Testimony
22 Q.What is the purpose of your testimony?
23 A.The purose of my testimony is to provide information regarding the
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Rocky Mountain Power
1 appropriateness of the Commission approved methodologies to calculate avoided
2 costs rates for Idaho qualifying facilities ("QF"). More specifically, I wil discuss
3 the Surogate Avoidable Resource ("SAR") methodology to calculate published
4 rates and the Integrated Resource Plan ("IRP") methodology to calculate
5 negotiated contract rates.
6 Q.Is the Company presenting any additional witnesses in this proceeding?
7 A.Yes. Mr. Paul H. Clements, an originator for PacifiCorp Energy, presents
8 testimony describing the Company's experience under the curent avoided cost
9 methodology for QF customers that do not qualify for published rates. In addition,
10 he sponsors a proposed tariff Schedule 38 which is intended to govern the QF
11 process when a developer requests pricing of Non-Standard QF contracts in Idaho
12 going forward. Lastly, Mr. Clements wil provide comments on the ownership of
13 renewable energy credits ("REC") as it pertins to QFs.
14 Background
15 Q.Why is the Company reviewing the SAR and IRP based methodologies?
16 A.On August 6, 2009, the Idaho Public Utilities Commission (Commission) opened
17 a generic docket (Case No. GNR-E-09-03) to assess the continued viability of the
18 Commission's existing proxy unit or SAR methodology for calculating published
19 avoided cost rates. Specifically, the Commission wanted to explore the continued
20 reasonableness of using published avoided cost rates as presently calculated for
21 all Qualifying Cogeneration and Small Power Production Facility ("QF") resource
22 tyes.
23 The Commission directed that the appropriateness of a single avoided cost
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Rocky Mountain Power
1 SAR methodology for published rates was to be re-examined in the context of
2 PUR A and FERC requirements and how different generation and operation
3 capabilities compare with other resources being offered to Idaho utilties. Under
4 the Commission's direction, Staff prepared a straw man wind SAR proposal
5 which was distrbuted to interested partes ("QFs and utilities") on May 27,2010,
6 for their review and comment.
7 On June 18, 2010, interested paries fied reply comments. A workshop
8 was held November 3, 2010, to discuss the straw man proposal and the paries
9 reply comments. On November 5, 2010, Idaho Power, Avista, and Rocky
10 Mountain Power filed a joint petition requesting that the issues raised in the
11 workshop be addressed and that the eligibility cap for published avoided cost rates
12 be lowered to 100 kW.
13 On December 3, 2010, the Commission issued Order No. 32131 directing
14 A vista, Idaho Power, Rocky Mountain Power and other interested parties to
15 address the utilities' petition to reduce the published avoided cost eligibilty cap.
16 Comments and reply comments were fied and oral arguents were held Januar
17 27,2011. On February 7, 2011, the Commission issued final Order No. 32176
18 temporarily reducing the eligibilty cap to 100 kW for published avoided costs
19 rates.
20 On June 8, 2011, the Commission initiated Case No. GNR-E-II-0l (Phase
21 II) to investigate and determine requirements by which wind and solar qualifying
22 facilties ("QFs") could obtain a published avoided cost rate without allowing
23 large QFs to obtain a rate that does not accurately reflect a utilty's avoided cost
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Rocky Mountain Power
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for such projects. Specifically, the Commission solicited information and
investigation of a published avoided cost rate eligibility cap strctue that: (l)
allowed small wind and solar QFs to avail themselves of published rates for
projects producing 10 aMW or less; and (2) prevents large wind and solar QFs
from disaggregating into small projects in order to obtain published avoided cost
rates that exceed a utilty's actual avoided cost.
Case No. GNR-E-11-01 affirmed the Commission's decision to maintain
the 100 kW. eligibility cap for published avoided cost rates for wind and solar
QFs, and stated its intent to initiate a proceeding to investigate and analyze both
the SAR and IRP methodologies. In its Notice of Review, in Order No. 32352,
dated September 1, 2011, the Commission initiated this proceeding to reexamine
the appropriateness of both the SAR and IRP methodologies for calculating
avoided cost rates.
Please summarize your testimony.
The Company's position is that the curent implementations of the SAR and IRP
methodologies are appropriate for the published and negotiated avoided cost rates,
respectively, as long as the 100 kW eligibility cap threshold for wind and solar
QFs is maintained for published SAR rates. The SAR methodology used for
calculating published avoided cost rates for smaller QFs continues to provide a
simple and transparent means of pricing that minimizes transaction costs a very
small QFmight incur to negotiate a power purchase agreement. However, the
SAR methodology is not the best methodology as the QF project capacity
increases since it does not take into consideration the value a specific QF project
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Rocky Mountain Power
1 would provide to each utility's unique power system and does not account for the
2 characteristics of each individual QF. The IRP methodology on the other hand, as
3 established in IPC-E-95-09, is an appropriate method to assess the value of a QF
4 project in terms of its capabilty to deliver its resource when the Company is in
5 need of such a resource, and is reflective of the value of the QF to the Company
6 and its customers. Table A, provided below, is a summary of the IRP avoided cost
7 rates for a representative QF of each technology tye.
Table At
RMP-IRP Calculation Method for Avoided Cost Rates
AmidedCost: 20-Year Nominal Levelized
Project
Descripton
Capacity Capacity
(MW Factor
Capacity Energy
Contribution (S/MWh)
Capacity
(S/kW-yr)
Est. S/MWH at
StatedCF----------------------- ----------- ------------- --------------- -------------- --------------- -----------------
Base Load Therml
Hydro
Solar (peak)
Solar (Eergy)
Wind
20
20
20
20
22
92.0010
34.0%
22.6%
22.6%
34.4%
100.0%
64.6%
26.8%
13.6%
4.2%
$4.57
$46.96
$39.99*
$39.77*
$31.52*
$118.16
$76.80
$31.67
$16.07
$4.96
$55.23
$7275
$55.99
$47.89
$33.17
* Avoided energy cost reduced for renewable integration charge at $6.50 ($2009).
8 The SAR Methodology
9 Q.Please provide an overview and history of the SAR methodology in
10 calculating published rates for Idaho QFs.
11 A.The SAR method uses the fixed and varable cost of a combined cycle
12 combustion tubine ("CCCT") as a proxy resource and assumes that these costs
1 The Solar (Energy) and Solar (Peak) projects are representative of a solar project that is configued to
produce the maximum amount of total energy versus a solar project that is configued to produce more
energy durng the Company's system peak.
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represent the utilty's long term avoided costs.2 The Commission originally
established the SAR method over 30 years ago on August 8, 1980, when the
Commission issued its first order, Order No. 15746, establishing the principles
applicable to purchases of power from PURPA QFs.3 In Order No. 15746, the
Commission determined that a hypothetical base load coal plant would be the unit
a utility would build or defer absent QF generation and was representative of the
utility's avoided cost.
In 1993, in Case No. PPL-E-93-5, the Commission concluded that the
SAR proxy resource should be a CCCT rather than a coal plant.4 Since then, there
have been periodic updates of the underlying CCCT costs, but the SAR method
itself has changed very little.
Is the Company proposing any changes to the SAR method of calculating
published avoided cost rates?
No.
Do you believe that the SAR method is an appropriate methodology to value
the energy and capacity that small QF resources provide to utilties?
Yes. With the recently affrmed 100 kW eligibility cap for wind and solar QFs,
the SAR method is a reasonable methodology for calculating published avoided
cost rates for resources that wil not materially impact a utilty's load and resource
plan.
2 Case No. U-1500-170, Order 22636 I.P.U.C. 6-7 (1989).
3 See Case No. P-300-12, Order 15743 I.P.U.C 31(1980), Order 16025 I.P.U.C 31(1980).
4 See Case No. PPL-E-93-5, Order 25882 I.P.U.C. 3-4. See also Case Nos. WW-93-1O, IPC-E-93-28 PPL-
E-93-5, and UPL-E-93-7 where the utilíties filed simultaneous applications representing that the SAR
methodology based on a coal resource was no longer fair, just, and reasonable.
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Rocky Mountain Power
1 Q.Does the Company believe it is important to maintain the recently affrmed
2 size eligibilty thresholds for wind and solar QFs seeking Idaho published
3 avoided cost prices at 100 kW?
4 A.Yes. As discussed by Company witness Mr. Bruce Griswold in Case Nos. GNR-
5 E-1O-04 and GNR-E-ll-01, the Company believes the 100 kW eligibilty cap for
6 wind and solar QFs and the use of an IRP methodology as explained below for
7 larger projects is appropriate, does not deter wind or solar development, and is the
8 surest reasonable approach for restrcting disaggregation.
9 The IRP Methodology
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Please provide a background of the IRP methodology
On January 31, 1995, the Commission issued Order No. 25882, requiring the
Company to develop an IRP-based methodology to calculate avoided costs for QF
resources exceeding the then one megawatt ("MW") eligibility cap. In its order,
the Commission stressed that the methodology should price QF resources such
that customers would be indifferent to whether capacity was procured as a result
of the IRP process or as a result of a QF contract. The Commission noted that:
"Requiring (QF) projects to prove their viability by market standards
ensures that utilities wil not be required to acquire resources priced higher
than would result from a least cost planing process."s
Parties then stipulated to Staffs proposed IRP methodology in Case No. IPC-E-
95-09 and the stipulation was subsequently adopted by the Commission in Order
No. 26576.
Please describe the IRP methodology.
The IRP methodology is comprised of seven steps, which essentially values the
5 Case No. PPL-E-93-5, Order 25882 I.P.U.C. 7.
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1 avoided cost of the QF by taking the difference between the present value revenue
2 requirement ("PVRR") of the base case resource plan and a modified resource
3 plan that includes the QF resource. These seven steps, as established in the
4 stipulation adopted in Case No. IPC-E-95-05, are as follows:
5 1. An IRP is prepared for the Utilty. The IRP should consider a range of
6 load forecasts for varous sets of possible economic conditions. The
7 IRP should also consider all possible resources for meetig load, both
8 supply side and demand side. In addition, consideration should be
9 given to the risks and uncertainties associated with each scenario
10 examined. The least cost combination of resources is selected to meet
11 each scenario. The most likely scenario is identified as the base case12 plan.
13 2. An initial simulation analysis using a power supply and/or capacity
14 expansion model chosen by the utility is used to calculate the PVRR of
15 the base case resource plan over the lifetime of the proposed QF16 contract.
17 3. The proposed QF resource is added to the base case resource plan
18 during all years of the proposed contract. The required description of
19 the QF project includes all data and information needed to model the
20 intended dispatchable or non-dispatchable operations of the project on
21 the power supply system (see pps. 9-10 for a list of data and
22 information needed from QFs).
23 4. A second simulation analysis, including the QF resource, is performed
24 which results in an adjustment of the amount and/or timing of the new
25 resources in the base case plan. The modified plan including the QF
26 purchase is constrcted to maintain resource adequacy and system
27 reliability equivalent to that of the base case plan.
28 5. The PVRR of the modified resource plan including the QF is
29 calculated over the full term of the QF contract, excluding the total
30 purchase costs of the QF resource itself.
31 6. Finally, the present value of the QF project avoided cost is calculated
32 by subtracting the PVRR of the modified plan, with the costs of the QF
33 set to zero, from the PVRR of the base case resource plan:
34 7. Rates for capacity and energy from the QF project can now be
35 developed for which, on a present value basis, the expected payments
36 of the QF are equal to the project's avoided cost over the life of the
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Is the Company proposing any changes to the seven step IRP methodology
developed in IPC-E-95-09?
No. The IRP methodology continues to reflect an accurate forecast of the
Company's avoided costs. Also, as a gauge of reasonableness and consistency, the
IRP methodology is similar to the non-standard large QF avoided cost
methodologies adopted by both ofRMP's other jursdictions, Utah and Wyoming.
What are the main components of the avoided cost price calculation using the
IRP methodology?
Using the IRP methodology, QF avoided cost prices consists ofthree components:
avoided energy costs, avoided capacity costs, and integration costs (where
appropriate).
Please describe how the Company calculates the avoided costs of energy
under the IRP methodology.
The calculation of the avoided energy cost follows the steps identified above and
begins with the existing and planned resources that represent the Company's IRP
preferred portfolio. Using the preferred portfolio, the Company runs two energy
simulations using its Generation and Regulation Initiatives Decision Tool
("GRID") modeL. The first simulation (the Base Simulation) calculates the PVR
of the preferred portfolio. The second simulation (the Avoided Cost Simulation)
calculates the PVR of a modified version of the preferred portfolio that includes
the QF at no cost and includes the energy impact associated with the deferral of a
6 See Case No. IPC-E-95-9, Order 26576, I.P.u.c. (1996) approving the settlement stipulation set fort in
Staff Exhibit No. 101.
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portion of the next avoidable CCCT in a manner that maintains resource adequacy
and system reliabilty equivalent to that of the Base Simulation. The difference in
PVRR from the GRID studies between the Avoided Cost. Simulation and the Base
Simulation is used to determine the avoided energy cost. The avoided energy cost
does not include the benefit of deferrng the fixed costs of the next avoidable
CCCT.
Please describe how the Company calculates the avoided costs of capacity
under the IRP methodology.
The Company calculates the avoided cost of capacity outside of the GRID model
by determining the PVR of the deferred fixed costs associated with the parial
displacement of the next deferrable CCCT in the Company's IRP. The levelized
fixed costs of the deferrable CCCT, plus ongoing operation and maintenance, are
developed from the PVR savings of the deferred fixed costs on a $/kW/year
basis. Based on the estimated capacity contrbution of the QF, the capacity
component is calculated and added to the energy component of the avoided cost
payment. The attached Technical Appendix, Exhibit No. 201, provides examples
and details how the Company uses its assumptions from the most recently fied
IRP for calculating the capacity payment portion of the QF avoided costs.
Different tyes of resources wil have different abilties to defer the
capacity of the next deferrable CCCT. The Company refers to this as a resources
capacity contrbution which I wil discuss later.
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Rocky Mountain Power
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How does the Company determine the "next deferrable CCCT" for purposes
of calculating the capacity payment?
A CCCT resource is deferrable or avoidable until the Company mákes an
ireversible commitment to acquire it. An irreversible contract commitment
generally occurs upon order approval of an acquisition of a resource, the
completion of an RFP process to build the resource or the execution of a contract
to procure the capacity. Curently, the next deferrable CCCT is the 597 MW type
"F" natural gas resource planed in the Utah South transmission area beginning
June, 2016.
What is capacity contribution?
Capacity contribution is the ability of the QF resource to contrbute towards
meeting the .Company's hourly summer peak system obligation to serve load. For
non-intermittent thermal QF resources, such as cogeneration or biomass
resources, the Company assumes the QF's entire rated capacity can contrbute
towards the Company's summer peak obligation. For intermittent resources, such
as wind and solar, and energy-limited resources, such as hydro, the Company
takes historical data from existing projects that have contrbuted to the
Company's summer peak obligation to determine the capacity contrbution.
How is the capacity contribution calculated for wind, solar and hydro QFs?
The Company matches the hourly generation profie for each of these
technologies against historical hourly loads from 2007 through 2010 and
identifies the quantity of generation of each technology durng the Company's top
100 summer peak hours in each year. Next, the Company identified the amount of
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capacity contrbution each technology would be expected to provide at least 90
percent of the time. This percentage was then used to establish the capacity
contribution for hydro, wind and solar QFs.
Please summarize the Company's calculated capacity contribution óf the
representative solar, hydro, wind and thermal QF resources.
The Company calculated a capacity contrbution of its rated capacity of 4.2
percent for a wind resource, 64.6 percent for a hydro resource, 100 percent for a
thermal resource, and based on the configuation of the solar facility, 13.6 percent
for a solar facility that maximizes its energy across all hours, and a 26.8 percent
capacity contrbution for a solar facilty that is physically configued to produce
greater energy during the company's peak times, but with slightly less total
energy generation. For details of how the Company calculated the capacity
contrbutions for each resource please refer to Exhibit No. 201, which describes
and ilustrates the assumptions and calculations used by the Company.
Does the Company apply an integration charge to intermittent resources
such as wind and solar?
Yes. Pusuant to Order No. 31021 in Case No. P AC-E-09-07, the Company
applies a $6.50IMWH charge to wind and has also applied the same integration
charge to solar QFs.7 The integration charge represents a reduction to prices
provided to a QF and is calculated on a nominal basis using real 2009 dollars.
7 The Company does not curently own or operate a solar facility. However, solar resources are intermittent
varable resources that present operational integration costs that are similar to that of a wind resource. The
Company believes that the wind integration charge, established by the Commission in Order No. 31021, is
a reasonable approximation of the integration costs associated with a solar resource.
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Rocky Mountain Power
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Do previously signed QFs also impact the deferrable capacity available from
the next deferrable CCCT?
Yes. To the extent that the preferred portfolio, or deferrable CCCT, was modified
to take into consideration a signed QF, this partially displaced portion can no
longer be deferred. This ensures that the Company includes a consistent level of
capacity in the simulated resource portfolios as newly signed QFs are added into
the resource plan.
At the time the QF makes a request for avoided cost prices, does the
Company update the GRID model for known and measurable changes that
occur subsequent to filing the IRP?
Yes. The Company updates the GRID model based on the most recently available
information each time a QF requests avoided cost pricing. This includes updates
related to new contracts, fuel prices, forward price cures, load forecasts and
other assumptions. However, the underlying IRP preferred portfolio does not
change and is consistent with the most recently filed IRP.
Please summarize your testimony.
With the eligibility cap of 100 kW in place for solar and wind QF facilities, the
Company believes that the previously adopted SAR and IRP methodologies
continue to provide an accurate means of calculating avoided cost prices for Idaho
QFs.
Does this conclude your direct testimony?
Yes.
Brown, Di - 13
Rocky Mountain Power
Case No. GNR-E-II-03
Exhibit No. 201
Witness: Kelcey Brown
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony of Kelcey Brown
January 2012
Rocky Mountain Power
Exhibit 201 Page 1 of 5
Case No. GNR-E-11-03
Witness: Kelcey Brown
Technical Appendix
Capacity Contribution Overview
The Company calculates non-standard avoided cost rates in Idaho using the Integrated Resource Plan
("IRP") Methodology. The IRP Methodology confers a capacity payment to Qualifying Facilities
("QFs") based on the degree to which the QF wil allow the Company to avoid or defer constrction of a
Combined Cycle Combustion Turbine ("CCCT") resource. The amount of capacity provided by a QF is
known as its capacity contribution, which is stated as a percentage of its nameplate capacity. The
capacity contrbution is calculated based on the historical operation of each tye of QF resource and its
abilty to defer the capacity of the next deferrable CCCT. The Company calculated each resources
capacity contrbution by analyzing the historical generation over the Company's 100 sumer peak load
hours in each of four historical years and assumg a 90 percent probabilty that the resource wil produce
at least that same level of power durng peak hours in the futue. Using the Company's owned wind,
therml and hydro facilities, and solar data from the 2011 IRP, the capacity contrbution of each resource
using historic data for calendar years 2007 to 20101 is as follows:
Resource Set
Wind
Solar (Peak-oriented)
Solar (Energy-oriented)
Hydro
Thermal
Capacity
Contribution
4.2%
26.8%
13.6%
64.6%
100.0%
Capacity Contribution Methodology
Assumptions
The capacity contribution calculation uses the following assumptions:
· The measurement is. based on the aggregate capacity benefit of a resource set taken as a
whole, not the capacity benefit of an individual resource analyzed in isolation.
~ A resource set is defined as a group of resources that rely on the same generation
technology, such as wind, solar, hydro, and thermal QF resources.
~ The use of an aggregate capacity value is required because statistically a
geographically dispersed array of facilities wil produce a level of reliabilty that is
higher than anyone of the resources taken separately.
1 Calendar years 2007 though 2010 were used in order to present a multiyear view of the capacity provided by a
paricular resource set over a range of 100 sumer peak load conditions in each year. At the time the Company
completed its analysis calendar year 2011 data was not yet available.
Ro,cky Mountain Power
Exhibit 201 Page 2 of 5
Case No. GNR-E-11-03
Witness: Kelcey Brown
~ The use of an aggregate output ensures that the resource set shares proportionally in,
the capacity benefit provided by the set as a whole.
· To determine the amount of capacity contrbution attbutable to a resource set, the generation
output is measured over the top 100 suier peak load hours in a year and the results of four
years are averaged.
~ The period of measure is restricted to summer load hours since. the Company peak
occurs in the summer months, and wil continue to do so in the foreseeable futue. On
a weather normalized basis, a winter peak does not occur until the top 160th hour.
Calculation
As stated previously, the Company calculated the capacity contrbution provided by a particular resource
set in the top 100 summer peak load hours assuming a 90 percent probabilty that it wil produce the same
level of power durng peak hours in the futue. Each resource set is calculated separtely over a four year
period. The average of the four annual values represents the capacity contrbution for that resource set.
· Compile the aggregate energy output from all resources within the resource set in each hour
of the year.
· Calculate the aggregate nameplate capacity from all resources in the resource set in each hour
of the year.
· Divide the aggregate energy output by the aggregate nameplate capacity to arrve at the
aggregate capacity factor for each hour ofthe year.
· Using actual hourly system load data for 2007-2010 to determine the top 100 load hours that
occured in each year between the months of June and September. The resulting hours are the
top 100 summer peak load hours for each year 2007-2010.
· Align the hourly aggregate generation of the resource set to the top 100 sumer peak load
hours.
· Calculate the capacity contribution based on a .90 percent probability from the level of
generation of the resource set durng those peak hours.
Wind
The Company determined that the historic wind generation contributed a capacity contrbution of 4.2
percent. This value is comparable to the 5 percent wind capacity contrbution assumption used by the
Northwest Power and Conservation Councii.2
2 Sixth Northwest Conservation and Electrc Power Plan, N.W.P.C.C. Chapter 12,4,
http://www .nwcounciL.org! energy!powerplan!6/final!SixthPowerPlan Ch I 2.pdf .
Rocky Mountain Power
Exhibit 201 Page 3 of 5
Case No. GNR-E-11-03
Witness: Kelcey Brown
Hourly generation logs were used to develop the capacity contrbution for the Company's system wind
resources. The analysis included both owned and non-owned wind resources where the Company
acquired the output under a power purchase agreement.
Wind Capacity Contnbutioo
Top 100 Summer Load Hours
8.0%
4.056
2.D%
2007 200S 2009 2.010 Capaciti¡
Contribution
¡Average)
The resources included in the wind analysis were as follows:
Wind Resource COD Type Nameplate Capacity---..-_..._-
Chewon Wind OF 1211/2009 PPA 16.5
Combine Hills 12122/2003 PPA 41.0
Dunlap I Wind 10/1/2010 Owned 111.0
Foote Creek Generation 7/21/1997 Owned 32.1
Glenrock ILL Wind 1/1712009 Owed 39.0
Glenrock Wind 12131/2008 Owned 99.0
Goodnoe Wind 5/31/2008 Owned 94.0
High Plains Wind 9/13/2009 Owned 99.0
Leaning Juniper 1 9/14/2006 Owned 100.5
Marengo 1 & 2 8/3/2007 Owned 210.6
McFadden Ridge Wind 9/29/2009 Owned 28.5
Mountain Wind 1 & 2 OF 7/2/2008 PPA 140.7
Oregon Wind Farm OF 3/31/2009 PPA 64.6
Rock Ri\er i 11/7/2001 PPA 50.0
Rollng Hils Wind 1/17/2009 Owned 99.0
Seven Mile ii Wind 12131/2008 Owned 19.5
Seven Mile Wind 12131/2008 Owned 99.0
Spanish Fork Wind 2 OF 7/31/2008 PPA 18.9
Three Buttes Wind 1211/2009 PPA 99.0
Threemile Canyon Wind OF p500139 9/1/2009 PPA 9.9
Top of the World Wind p522807 10/1/2010 PPA 200.2
WOI\erine Creek 211212006 PPA 64.5
Total Wind December 31, 2010:1,736.5
================
Rocky Mountain Power
Exhibit 201 Page 4 of 5
Case No. GNR-E-11-03
Witness: Kelcey Brown
Solar
The Company does not curently operate any solar resources from which it can derive data to develop the
capacity contribution value for a solar QF. In the absence of actual system dåta, the Company relied on a
simulated hourly solar profie developed by the National Renewable Energy Laboratory (NREL). The
identical simulated hourly data is compared against the top 100 sumer load hours in each year 2007 -
2010. Unlike wind, where the levels of generation change in each year depending on the output of the
resource set, the simulated solar output remains constant in each year and is compared to changes in the
top 100 peak sumer load hours from year-to-year.
A slight change in the configuation of a solar resource can have a substantial impact on the capacity
value that it provides. Therefore, the Company differentiates between solar resources based on whether
they are configued to provide more generation during the Company's peak hour or whether they are
configued to maximize total energy. The capacity contrbution calculations were based on two simulated
resource sets with the following characteristics.
Configuration
Tilt
Azimuth
Capacity Contrbution
Energy-orientation
Latitude
Due South
26.8%
Peak-orientation
Latitude minus 15°
Due South plus 25°
13.6%
In developing the solar generation profie the Company used an NREL tool, called PVW atts, in order to
simulate hourly solar generation levels based on historic meteorological solar radiation data. The
PVW atts tool develops a solar profile based on input parameters such as the location, size, array tye, tilt
angle, and azimuth angle of the solar resource.
The capacity contribution calculation was based on a simulated set of solar resources located throughout
the Company's service terrtory. It was developed using the combined simulated profiles from five
locations: Pocatello, ID; Yakma, WA; Pendleton, OR; Lander, WY; and Salt Lake City, UT. The
analysis was performed twce, first with all of the resources configued to peak and second with all of the
resourced configued to energy, as detailed above.
Energy-oriented Solar Capacit Contributon
Top 100 Summer load Hours
5'3.0%
40.0n
30.0%
:W.O~
10.0%
0.0%
2007 200S 2009 imo (apai:it'¡
Contribution
(Average)
Rocky Mountain Power
Exhibit 201 Page 5 of 5
Case No. GNR-E-11-03
Witness: Kelcey Brown
Peak-oiiented Sodar capacity Contiibuon
Top 100 Summer load Hours
Sf.UJ%
4îJ.îJS1
30.09~
2û.D~
LO.O~
Û.O*
2007 :mos 2009 2010 Capaeity
Contribution
(Average)
Hydro
The company used historic generation levels from four hydro projects operated as ru-of-river located in
or near Idaho to calculate the capacity contrbution value of 64.6 percent for hydro QF projects.
Following are the calculated annual capacity contrbution levels from 2007-2010 for hydro. The four ru-
of-river resources analyzed in the Company's hydro capacity contrbution calculation include Idaho
Falls,3 Island Park Hydro, Ashton Hydro and Big Fork Hydro.
Hydro Capacity Contiibuon
Top 100 Summer load Hours
100.0%
90.0%
80.0%
70.0%
£0.0%
50..0%
40.0%
2007 2008 2009 2010 Ca.padti¡
Contribution
(Average)
3 The analysis includes the combined output from the Idaho Falls ru of river projects and excludes Gem State.