20120131Stokes Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION’S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE SURROGATE )CASE NO.GNR-E-1l-03AVOIDEDRESOURCE(SAR)AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING
PUBLISHED AVOIDED COST RATES.
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
M.MARK STOKES
Please state your name and business address.
My name is M.Mark Stokes and my business
1221 West Idaho Street,Boise,Idaho.
By whom are you employed and in what capacity?
I am employed by Idaho Power Company (“Idaho
“Company”)as the Manager of Power Supply
Q.Please describe your educational background
and work experience with Idaho Power.
A.I am a graduate of the University of Idaho
with a Bachelor of Science Degree in Civil Engineering.I
also hold a Masters Degree in Business Administration from
Northwest Nazarene University and am a registered
professional Engineer in the state of Idaho.
I joined Idaho Power in 1991 as a member of the
construction management team responsible for the
construction of the Mimer Hydroelectric Project.In 1992,
I joined the Generation Engineering Department where I was
responsible for dam safety and regulatory compliance for
Idaho Power’s 17 hydroelectric projects.In 1996,I began
working with Idaho Power’s Hydra Services Group,a new
business initiative within the Power Production Department,
where I was responsible for business development and
marketing.In 1999,I returned to my previous position
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STOKES,DI
Idaho Power Company
Q.
A.
address is
Q.
A.
Power”or
Planning.
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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.
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,
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 RECOMMENDATIONS
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 QP can obtain a power purchase agreement with Idaho
25 Power;and
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?
STOKES,DI 4
Idaho Power Company
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 QP
7 development on Idaho Power’s system significantly exceeds
8 the QP development of any other Northwest utility.
PURPA Nameplate by State and Utility (MW)
ID OR MT UT WA WY CA Total
9
Idaho Power 940 28 21 989
PacifiCorp 65 167 179 6 378 20 815
Avista 7 95 102
Northwestern Energy 351 351
Portland General Electric 14 14
Puget Sound Energy 44 44
2011 Annual Average Load by State and Utility (aMW)
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 733 733
Portland General Electric 2,403 2,403
Puget Sound Energy 2,507 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%0.6%
Puget Sound Energy 1.8%1.8%
10 The table above highlights that Idaho Power with
11 1,858 average megawatts (“aMW”)of average annual load has
STOKES,DI 5
Idaho Power Company
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.
STOKES,DI 6
Idaho Power Company
1
Idaho Power Compared to Regional RPS Standards
30%--
--
25%
20%---
15%
10%-
5%-
Other
0%
Idaho Power Assumed WA RPS WA RPS WA RPS OR RPS 2011 ORRPS 2015 OR RPS 2020CR RPS 2025 MT RPS MT RPS
2014 Federal RES 2012 2016 2020 2010 2015
2020
Note:Federal RES includes subtracting hydro generation from the sales base in the calculated requirement.
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 QE
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 QFs for which it does not receive the RECs.
STOKES,DI 7
Idaho Power Company
19%
PURPA
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 QEs is passed through the PCA,and collected from Idaho
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.
Idaho Power PURPA Payments
2004-2020
200
180
—
160 ------
140 ---—
120 ---
100 -
------
80 -----—------
13
1-P-I[
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
STOKES,DI 9
Idaho Power Company
1 reach the $40 million in costs seen in 2004.Five years
2 later,in 2009,that amount grew by 50 percent to
3 approximately $60 million.Just three years later,in
4 2012,that $60 million will double to $120 million of
5 annual PURPA power supply costs.That number increases to
6 $167 million by 2014 and by 2026,it will be $186 million
7 annually,an approximate 465 percent increase in costs from
8 2004.
9 Q.How do these large increases in PURPA power
10 supply expenses affect customer rates?
11 A.As stated earlier,PURPA power supply costs
12 are paid for by Idaho Power’s customers through the PCA
13 mechanism.Each year 100 percent of the power supply
14 expense related to PURPA QFs is passed through the PCA,and
15 collected from Idaho Power’s customers.The dramatic
16 increases discussed above in annual PURPA power supply
17 costs have a corresponding and equally dramatic impact on
18 customers’bills.As shown in the figure below,the effect
19 of the increase in PURPA power supply costs alone will
20 increase the annual PCA rate from the $62.9 million
21 currently approved in base rates to $78.4 million,with
22 three months of the PCA year still remaining.
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STOKES,DI 10
Idaho Power Company
Idaho Power PURPA Expense by PCA Year
$90,000,000
:::
$50,000,000 ---
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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
STOKES,DI 11
Idaho Power Company
1 upon the current QP projects and approved contracts the
2 Company has now.
3 Q.Is there a corresponding trend with the
4 amount of generation provided by QFs?
5 A.Yes.The amount of generation provided,and
6 projected to be provided by QFs to Idaho Power increases in
7 a similar fashion,as shown in the figure below:
Idaho Power PURPA Contract Nameplate Capacity
1982-2014
1,000
900
800
700
600 ---------
500 -----
400 ----
300 -----—
200 -
8
‘°:P !!!!!!!-!-!t!!!!-
9 In summary,over the 10 years between 2004 and 2014,
10 the number of Idaho Power PURPA projects on-line since 2004
11 has increased by 95 percent (61 projects in 2004 to 119
12 projects currently under contract),total nameplate
13 capacity has increased 530 percent (157 MW in 2004 to 989
14 MW currently under contract)and total estimated cost has
15 increased 318 percent ($40 million in 2004 to a projected
16 cost in 2014 of $167 million)
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 QEs 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 QPs 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 QE projects providing approximately 28 MW located
24 in its Oregon jurisdiction.Idaho Power has requested
25 authorization from the Public Utility Commission of Oregon
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.UN
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 QP 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
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 A.One approach to determine the value of QF
2 purchases is to compare PURPA contract rates to historical
3 and forward market prices.Investigation reveals that
4 there has been a significant difference between the
5 historical prices paid to PURPA resources and the Mid-C
6 index and,on a forward looking basis,there continues to
7 be a significant difference between PURPA prices and the
8 Mid-C forward market prices.This difference is
9 illustrated in the following figure:
Average PURPA Price Compared to Mid-C Index
2002-2022
90 —-----
80 -----------—--——------—------—-----
70 —
—Average Mid-C Index —PURPA Price ——Est.PURPA Price ——Mid-C Forwards10
11 In 2005 and 2008,the average price paid to PURPA
12 projects was reasonably close to the Mid-C index price;
13 however,the Mid-C index was down significantly in 2009 and
14 2010,and dropped further in 2011,yet the price paid to
15 PURPA projects remained relatively constant.And,as
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.
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STOKES,DI 17
Idaho Power Company
Idaho Power 2014 Surplus/Deficit
December 2011 OP Plan
1,000
800 -----—-
______________
:1!L!i:lirl’’
-200
-400 L_________________---
_____
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
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 QE
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
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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 QE 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
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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 QF5 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
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
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
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 QP projects regardless of
16 the generation technology or motive force.
17 Q.What is the significance of large amounts of
18 intermittent and variable QE 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
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
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 IRP5,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
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 4ETHODOLOGIEs
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.
STOKES,DI 26
Idaho Power Company
i 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 QF5 over 100 kW.
10 A.SAR 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
is 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
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 general rate
11 cases,they are updated after a utility rate case with a
12 resulting change in the utility’s cost of capital.
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
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
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
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
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
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 NWh 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
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,131 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
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
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-1O-04,and Phase II,GNR-E
13 11—01?
14 A.Yes.In both prior phases to this 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-Ol,which are also incorporated herein
25 by this reference.These problems have not gone away,and
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
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
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
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
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
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
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 IR?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
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 aMW.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
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
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
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 QP 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
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
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.
13
14
15
16
17
18
19
20
21
22
23
24
25
STOKES,DI 47
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.GNR-E-11-03
IDAHO POWER COMPANY
STOKES,DI
TESTIMONY
EXHIBIT NO.I
PURPA QF Projects as of December 31,2011
Resource
On-line Type Project Name State County MW
1 Biomass Tamarack Cspp ID Adams 5.00
2 Biomass Cogen Co OR Grant 10.00
3 Cogen Magic Valley ID Miriidoka 10.00
4 Cogen Magic West ID Elmore 10.00
5 Cogen Tasco -Nampa ID Canyon 2.00
6 Cogen Tasco -Twin Falls ID Twin Falls 3.00
7 Digester B6 Anaerobic Digester ID Gooding 2.28
8 Digester Bettencourt Dry Creek BioFactory,LLC ID Twin FaIls 2.25
9 Digester Big Sky West Dairy Digester (DF-AP #1 LLC)ID Gooding 1.50
10 Digester Double A Digester ID Lincoln 4.50
11 Digester Pacatello Waste ID Bannock 0.46
12 Hydro Arena Drop ID Canyon 0.45
13 Hydro Barber Dam ID Ada 3.70
14 Hydro Birch Creek ID Gooding 0.05
15 Hydro Black Canyon #3 ID Gooding 0.14
16 Hydra Blind Canyon ID Gooding 1.50
17 Hydro Box Canyon ID Twin Falls 0.36
18 Hydro Briggs Creek ID Twin FaIls 0.60
19 Hydra Bypass ID Jerome 9.96
20 Hydra Canyon Springs ID Twin FaIls 0.13
21 Hydra Cedar Draw ID Twin Falls 1.55
22 Hydra Clear Springs Trout ID Twin FaIls 0.52
23 Hydra Crystal Springs ID Twin Falls 2.44
24 Hydra Curry Cattle Company ID Twin FaIls 0.22
25 Hydra Dietrich Drop ID Jerome 4.50
26 Hydra Elk Creek ID Idaho 2.00
27 Hydra Falls River ID Fremont 9.10
28 Hydra Faulkner Ranch ID Gaading 0.87
29 Hydra Fisheries Dev.ID Gooding 0.26
30 Hydra Ceo-Ban #2 ID Lincoln 0.93
31 Hydra Hailey Cspp ID Blame 0.06
32 Hydra Hazeltan A ID Jerome 7.70
33 Hydra Hazeltan B ID Jerome 7.60
34 Hydra Horseshoe Bend Hydra ID Boise 9.50
35 Hydra Jim Knight ID Gaoding 0.34
36 Hydra Kasel &Witherspoon ID Twin FaIls 0.90
37 Hydra Koyle Small Hydra ID Goading 1.25
38 Hydra Lateral#10 ID Twin FaIls 2.06
39 Hydra Lemayne ID Gooding 0.08
40 Hydra Little Waad Rvr Res ID Blame 2.85
41 Hydra Littlewaod I Arkoosh ID Lincoln 0.87
42 Hydra Low Line Canal ID Twin FaIls 7.97
43 Hydra Low Line Midway Hydra ID Twin Falls 2.50
44 Hydra Lawline #2 ID Twin Falls 2.79
45 Hydra Magic Reservoir ID Blame 9.07
46 Hydra Malad River ID Goading 0.62
47 Hydra Marco Ranches ID Jerome 1.20
48 Hydra Mile 28 ID Jerome 1.50
49 Hydra Mill Creek (City of Cave)OR Union 0.80
50 Hydra Mitchell Butte OR Malheur 2.09
51 Hydra Mora Drap Small Hydroelectric Facility ID Ada 1.85
52 Hydra Mud CreekIS &S ID Twin FaIls 0.52
53 Hydra Mud CreeklWhite ID Twin Falls 0.21
54 Hydra Owyhee Dam Cspp OR Malheur 5.00
55 Hydra Pigeon Cove ID Twin Falls 1.89
56 Hydra Pristine Springs #1 ID Jerome 0.13
Exhibit No.1
Case No.GNR-E-11-03
M.Stokes,PC
Page 1 of 3
PURPA QF Projects as of December 31,2011
Resource
On-line Type Project Name State County MW
57 Hydra Pristine Springs Hydra #3 ID Jerome 0.20
58 Hydra Reynolds Irrigation ID Canyon 0.28
59 Hydra Rim View ID Gooding 0.20
60 Hydra Rack Creek #1 ID Twin Falls 2.05
61 Hydra Rack Creek #2 ID Twin Falls 1.90
62 Hydra Sagebrush ID Lincoln 0.43
63 Hydra Sahko Hydra ID Twin Falls 0.50
64 Hydra Schaffner ID Lemhi 0.53
65 Hydra Shingle Creek ID Adams 0.22
66 Hydra Shashane #2 ID Lincoln 0.58
67 Hydra Shashone Cspp ID Lincoln 0.37
68 Hydra Snake River Pottery ID Gooding 0.07
69 Hydra Snedigar ID Twin Falls 0.54
70 Hydra Tiber Dam MT Liberty 7.50
71 Hydra Trout-Ca ID Gaoding 0.24
72 Hydra Tunnel #1 OR Malheur 7.00
73 Hydra White Water Ranch ID Gaading 0.16
74 Hydra Wilson Lake Hydra ID Jerome 8.40
75 Industrial Simplot Pocatella ID Power 12.00
76 Landfill gas Hidden Hollow Landfill Gas ID Ada 3.20
77 Wind Bennett Creek Wind Farm ID Elmore 21.00
78 Wind Burley Butte Wind ID Cassia 21.30
79 Wind Camp Reed Wind Park,LLC ID Elmore 22.50
80 Wind Cassia Wind Farm LLC ID Twin FaIls 10.50
81 Wind Fossil Gulch Wind ID Twin Falls 10.50
82 Wind Golden Valley Wind ID Cassia 12.00
83 Wind Horseshoe Bend Wind MT Cascade 9.00
84 Wind Lime Wind Energy OR Baker 3.00
85 Wind Oregon Trail Wind ID Twin Falls 13.50
86 Wind Thousand Springs Wind ID Twin Falls 12.00
87 Wind Tuana Gulch Wind ID Twin Falls 10.50
88 Wind Hat Springs Wind Farm ID Elmore 21.00
89 Wind Milner Dam Wind ID Cassia 19.92
90 Wind Payne’s Ferry Wind Park,LLC ID Twin Falls 21.00
91 Wind Pilgrim Stage Station Wind ID Twin Falls 10.50
92 Wind Rackland Wind Project ID Power 80.00
93 Wind Salmon Falls Wind ID Twin Falls 22.00
94 Wind Sawtooth Wind Project ID Elmore 21.00
95 Wind Tuana Springs Expansion ID Twin Falls 35.70
96 Wind Yahaa Creek Wind Park,LLC ID Twin Falls 21.00
Subtotal 605.86
Exhthit No.1
Case No.GNR-E-11-03
M.Stokes,PC
Page 2 of 3
PURPA QF Projects as of December 31,2011
Resource
Not On-line Type Project Name State County MW
1 Biomass Yellowstone Power ID Gem 10.00
2 Biomass Dynamis ID Ada 22.00
3 Digester Double B Dairy ID Cassia 2.0D
4 Digester Rock Creek Dairy ID Twin Falls 4.00
5 Digester Swager Farms ID Twin Falls 2.00
6 Hydro Fargo Drop Hydro ID Canyon 1.27
7 Hydro Clark Canyon Dam MT Beaverhead 4.70
8 Landfill Gas Hidden Hollow Energy II Landfill Gas Project ID Ada 3.20
9 Solar Grand View Solar ID Elmore 20.00
10 Solar Murphy Solar ID Owhyee 20.00
11 Wind Cold Springs Windfarm ID Elmore 23.00
12 Wind Cottonwood Wind Park ID Twin FaIls 20.00
13 Wind Deep Creek Wind Park ID Twin Falls 20.00
14 Wind Desert Meadow Windfarm ID Elmore 23.00
15 Wind Hammett Hill Windfarm ID Elmore 23.00
16 Wind High Mesa ID Elmore 40.00
17 Wind Lava Beds Wind ID Bingham 18.00
18 Wind Mainline Windfarm ID Elmore 23.00
19 Wind Notch Butte Wind ID Jerome 18.00
20 Wind Rogerson Flats Wind Park ID Twin Falls 20.00
21 Wind Ryegrass Windfarm ID Elmore 23.00
22 Wind Salmon Creek Wind Farm ID Twin FaIls 20.00
23 Wind Two Ponds Windfarm ID Elmore 23.00
Subtotal 383.17
119 Total Projects Under Contract 989.03
Exhibit No.1
Case No.GNR-E-11-03
M.Stokes,PC
Page 3 of 3
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.GNR-E-11-03
IDAHO POWER COMPANY
STOKES,DI
TESTIMONY
EXHIBIT NO.2
Idaho Power Company PURPA Expense
Historical Forecast
Year aMW Expense Year aMW Expense
1982 0 $241,681 2012 213 $120,482,150
1983 3 $1,947,675 2013 274 $155,210,454
1984 10 $8,419,576 2014 284 $166,947,907
1985 27 $16,201,679 2015 283 $171,257,482
1986 45 $23,089,962 2016 280 $173,427,475
1987 45 $22,938,180 2017 272 $172,227,474
1988 46 $23,378,405 2018 270 $174,432,632
1989 55 $29,049,008 2019 265 $175,616,330
1990 56 $29,409,440 2020 258 $174,141,098
1991 51 $27,969,279 2021 254 $176,548,408
1992 43 $22,148,359 2022 253 $178,754,351
1993 65 $33,596,827 2023 250 $181,645,438
1994 62 $30,884,222 2024 241 $183,240,619
1995 75 $37,999,969 2025 239 $185,748,585
1996 89 $43,716,927 2026 235 $185,908,600
1997 107 $55,971,675 2027 228 $185,127,749
1998 104 $54,957,741 2028 214 $177,699,725
1999 106 $56,152,052 2029 196 $168,409,199
2000 98 $53,685,443 2030 191 $167,527,389
2001 83 $44,976,174 2031 134 $125,520,070
2002 79 $43,931,661 2032 104 $99,380,022
2003 75 $38,186,005 2033 42 $39,374,103
2004 77 $39,840,544 2034 30 $28,101,276
2005 82 $43,327,053 2035 30 $28,525,215
2006 104 $53,666,055 2036 22 $20,619,789
2007 89 $45,494,057 2037 5 $5,623,914
2008 86 $45,885,564 Total $3,621,497,454
2009 111 $59,011,557
2010 104 $54,972,118
2011 162 $85,015,997
Total $1,126,064,887
Exhibit No.2
Case No.GNR-E-11-03
M.Stokes,IPC
Page 1 of 1
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Case No.GNR-E-11-03
M.Stokes,IPC
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 31st day of January 2012 I served a true andcorrectcopyoftheDIRECTTESTIMONYOFM.MARK STOKES upon the followingnamedpartiesbythemethodindicatedbelow:
Commission Staff X Hand DeliveredDonaldL.Howell,II
____U.S.
MailKristineA.Sasser
____Overnight
MailDeputyAttorneysGeneral
____FAX
Idaho Public Utilities Commission X Email [e-mail]472WestWashington(83702)kris.sasserpuc.idaho.qovP.O.Box 83720
Boise,Idaho 83720-0074
Avista Corporation
____Hand
DeliveredMichaelG.Andrea
____U.S.
MailAvistaCorporation
____Overnight
Mail1411EastMissionAvenue,MSC-23
____FAX
P.O.Box 3727 X Email [e-mail],Washington 99220-3727
PacifiCorp dibla Rocky Mountain Power
____Hand
DeliveredDanielE.Solander
____U.S.
MailPacifiCorpd/b/a Rocky Mountain Power
____Overnight
Mail201SouthMainStreet,Suite 2300
____FAX
Salt Lake City,Utah 84111 X Email danieLsoIanderpacificorp.com
Kenneth Kaufmann
____Hand
DeliveredLOVINGERKAUFMANN,LLP
___U.S.
Mail825NEMultnomah,Suite 925
____Overnight
MailPortland,Oregon 97232
____FAX
X Email kaufrnann©jdaw.com
Exergy Development,Grand View Solar II,
____Hand
DeliveredJ.R.Simplot,Northwest and Intermountain
____U.S.
MailPowerProducersCoalition,Board of
____Overnight
MailCommissionersofAdamsCounty,Idaho,
____FAX
and Clearwater Paper Corporation X Email peterkhardsonandoleary.comPeterJ.Richardson qreq(ärichardsonandoleary.cornGregoryM.Adams
RICHARDSON &O’LEARY,PLLC
515 North 27th Street (83702)
P.O.Box 7218
Boise,Idaho 83707
CERTIFICATE OF SERVICE -1
Exergy Development Group
____Hand
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James Carkulis,Managing Member
____U.S.
Mail
Exergy Development Group of Idaho,LLC
____Overnight
Mail
802 West Bannock Street,Suite 1200
____FAX
Boise,Idaho 83702 X Email jcarkulisexergydevelopment.com
Grand View Solar II
____Hand
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Robert A.Paul
____U.S.
Mail
Grand View Solar II
____Overnight
Mail
15690 Vista Circle
____FAX
Desert Hot Springs,California 92241 X Email robertpaul08gmail.com
J.R.Sim plot Company
____Hand
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Don Sturtevant,Energy Director
____U.S.
Mail
J.R.Simplot Company
____Overnight
Mail
One Capital Center
____FAX
999 Main Street X Email don.sturtevant(simplot.com
P.O.Box 27
Boise,Idaho 83707-0027
Northwest and Intermountain Power
____Hand
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Producers Coalition
____U.S.
Mail
Robert D.Kahn,Executive Director
____Overnight
Mail
Northwest and Intermountain Power
____FAX
Producers Coalition X Email rkahnnippc.org
1117 Minor Avenue,Suite 300
Seattle,Washington 98101
Board of Commissioners of Adams
____Hand
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County,Idaho
____U.S.
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Bill Brown,Chair
____Overnight
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Board of Commissioners of
____FAX
Adams County,Idaho X Email bdbrow©frontiernet.net
P.O.Box 48
Council,Idaho 83612
Clearwater Paper Corporation
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Mary Lewallen
____U.S.
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Clearwater Paper Corporation
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601 West Riverside Avenue,Suite 1100
____FAX
Spokane,Washington 99201 X Email marvJewallenclearwaterpaper.com
CERTIFICATE OF SERVICE -2
Renewable Energy Coalition
____Hand
DeliveredThomasH.Nelson,Attorney
____
U.S.MailP.O.Box 1211
____Overnight
MailWeiches,Oregon 97067-1211
____FAX
X Email nelson(ãthneslon.com
John R.Lowe,Consultant
____Hand
DeliveredRenewableEnergyCoalition
____U.S.
Mail12050SWTremontStreet
____Overnight
MailPortland,Oregon 97225
____FAX
X Email jravenesanmarcos(yahoo.com
Dynamis Energy,LLC
____Hand
DeliveredRonaldL.Williams
____U.S.
MailWILLIAMSBRADBURY,P.C.
____Overnight
Mail1015WestHaysStreet
____FAX
Boise,Idaho 83702 X Email [e-mail]
Wade Thomas,General Counsel
____Hand
DeliveredDynamisEnergy,LLC
____U.S.
Mail776EastRiversideDrive,Suite 150
____Overnight
MailEagle,Idaho 83616
____FAX
X Email wthornasçjynamisenergy.com
Idaho Windfarms,LLC
____Hand
DeliveredGlennIkemoto
____U.S.
MailMargaretRueger
____Overnight
MailIdahoWindfarms,LLC
____FAX
672 Blair Avenue X Email gjennienvisionwind.comPiedmont,California 94611 mararet©nvonwind.com
Interconnect Solar Development,LLC
____Hand
DeliveredR.Greg Ferney
____U.S.
MailMIMURALAWOFFICES,PLLC
____Overnight
Mail2176EastFranklinRoad,Suite 120
____FAX
Meridian,Idaho 83642 X Email gregrnimuralaw.com
Bill Piske,Manager
____Hand
DeliveredInterconnectSolarDevelopment,LLC
____U.S.
Mail1303EastCarter
____Overnight
MailBoise,Idaho 83706
____FAX
X Email [e-mail]
CERTIFICATE OF SERVICE -3
Renewable Northwest Project
____Hand
Delivered
Dean J.Miller
____U.S.
Mail
McDEVITT &MILLER LLP
____Overnight
Mail
420 West Bannock Street (83702)
____FAX
P.O.Box 2564 X Email [e-mail]
Boise,Idaho 83701
Megan Walseth Decker
____
Hand Delivered
Senior Staff Counsel
____
U.S.Mail
Renewable Northwest Project
____
Overnight Mail
917 SW Oak Street,Suite 303
____
FAX
Portland,Oregon 97205 X Email
North Side Canal Company and Twin Falls
____Hand
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Canal Company
____U.S.
Mail
Shelley M.Davis
____Overnight
Mail
BARKER ROSHOLT &SIMPSON,LLP
___FAX
1010 West Jefferson Street,Suite 102 (83702)X Email smd©Jdahowaters.com
P.O.Box 2139
Boise,Idaho 83701-2139
Brian Olmstead,General Manager
____Hand
Delivered
Twin Falls Canal Company
____U.S.
Mail
P.O.Box 326
____Overnight
Mail
Twin Falls,Idaho 83303
____FAX
X Email [e-mail]
Ted Diehl,General Manager
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North Side Canal Company
____U.S.
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921 North Lincoln Street
____Overnight
Mail
Jerome,Idaho 83338
____FAX
X Email nscanalcableone.net
Birch Power Company
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Ted S.Sorenson,P.E.
____U.S.
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Birch Power Company
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5203 South 1 1th East
____FAX
Idaho Falls,Idaho 83404 X Email [e-mail]
Blue Ribbon Energy LLC
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M.J.Humphries
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Blue Ribbon Energy LLC
____Overnight
Mail
4515 South Ammon Road
____FAX
Ammon,Idaho 83406 X Email bfterlbbonenerqyqmail.com
CER11FICATE OF SERViCE -4
Arron F.Jepson
Blue Ribbon Energy LLC
10660 South 540 East
Sandy,Utah 84070
____
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___U.S.
Mail
____Overnight
Mail
___FAX
X Email [e-mail]
Idaho Conservation League
Benjamin J.Otto
Idaho Conservation League
710 North Sixth Street (83702)
P.O.Box 844
Boise,Idaho 83701
Snake River Alliance
Ken Miller
Clean Energy Program Director
Snake River Alliance
350 North 9th Street #B610
P.O.Box 1731
Boise,Idaho 83701
____
Hand Delivered
___
U.S.Mail
____
Overnight Mail
___FAX
X Email bottocidahoconservation.orq
Hand Delivered
___
U.S.Mail
____
Overnight Mail
FAX
X Email krniiesnakeriveraWçor
n E.Walker
CERTIFICATE OF SERVICE -5