20120629Stokes Rebuttal.pdf

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An IDACORP Company
DONOVAN E.WALKER
Lead Counsel
dwalkeridahopower.com
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June 29,2012
VIA HAND DELIVERY
Jean D.Jewell,Secretary
Idaho Public Utilities Commission
472 West Washington Street
Boise,Idaho 83702
Re:Case No.GNR-E-11-03
PURPA SAR and IRP Methodologies —Idaho Power Company’s Rebuttal
Testimony
Dear Ms.Jewell:
Enclosed for filing in the above matter are nine (9)copies each of the testimonies of
M.Mark Stokes and Tessia Park.One copy of each of the aforementioned testimonies has
been designated as the “Reporter’s Copy.”In addition,a disk containing Word versions of
the testimonies is enclosed for the Reporter.
DEW:csb
Enclosures
1221 W.Idaho St.(83702)
P.O.Box 70
Boise,ID 83707
yours,
in E.Walker
f
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-l1-03
AVOIDED RESOURCE (SAR)AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING
PUBLISHED AVOIDED COST RATES.
IDAHO POWER COMPANY
REBUTTAL TESTIMONY
OF
M.MARK STOKES
1 Q.Please state your name and business address.
2 A.My name is M.Mark Stokes and my business
3 address is 1221 West Idaho Street,Boise,Idaho.
4 Q.Are you the same M.Mark Stokes that submitted
5 direct testimony in this proceeding?
6 A.Yes,I am.
7 Q.What is the purpose of your rebuttal
8 testimony?
9 A.In my rebuttal testimony,I will address the
10 following items:
11 1.I will respond to recommendations to
12 change the source of the natural gas price forecast used to
13 set avoided cost rates.In addition,I will discuss the
14 sensitivity of each of the avoided cost methodologies to
15 changes in natural gas prices.
16 2.I will respond to statements made by
17 others in direct testimony supporting the continued use of
18 the Surrogate Avoided Resource (“SAR”)methodology and
19 provide additional information supporting my recommendation
20 to abandon the use of the SAR methodology.
21 3.I will respond to questions raised by
22 others in direct testimony regarding Idaho Power Company’s
23 (“Idaho Power”or “Company”)proposed Hourly Incremental
24 Cost methodology and provide additional support for the
25 adoption of this methodology to set avoided cost rates.
STOKES,REB
Idaho Power Company
1 4.I will also respond to recommendations
2 made by others regarding contract term,the published rate
3 eligibility cap,the avoided cost of capacity and energy,
4 the use of a carbon adder in avoided cost rate
5 calculations,the security deposit for liquidated damages,
6 and the need to litigate Integrated Resource Plans (“IRP”)
7 5.I will describe why the electric
8 utilities that purchase energy from a Qualifying Facility
9 (“QF”)should also receive the associated environmental
10 attributes and/or Renewable Energy Credits (“REC5”)
11 associated with the purchase of that energy.
12 6.Finally,I will present Idaho Power’s
13 proposed Schedule 73 to address the QF contracting process.
14 I.NATURAL GAS PRICE FORECAST
15 Q.Several parties have filed testimony in
16 support of using a natural gas price forecast developed by
17 the Energy Information Administration (“EIA”)in the
18 calculation of avoided cost rates.Do you support this
19 recommendation?
20 A.Yes.I believe using the EIA forecast and
21 updating it annually in July of each year is a step in the
22 right direction.However,it does not resolve the
23 underlying problem that the natural gas price forecast
24 assumption has too significant of an impact on the avoided
25 cost rates produced by the SAR methodology.
STOKES,REB 2
Idaho Power Company
1 In addition,current and near—term market prices for
2 natural gas are approximately half of the EIA forecast
3 presented in Exhibit No.301 of the Direct Testimony of
4 Idaho Public Utilities Commission Staff (“Staff”)witness
5 Cathleen McHugh.This ETA forecast was released in January
6 2012 and is already off by approximately 50 percent in the
7 near term.This highlights the underlying problem that the
8 avoided cost rates can become out of date rather quickly
9 and,further,avoided cost rates determined using the SAR
10 methodology compound this problem because they are overly
11 sensitive to the natural gas price assumption used in the
12 model.In addition to establishing a better,more accurate
13 source for the natural gas price forecast,I believe it
14 would be of greater benefit to adopt an avoided cost
15 methodology that is less sensitive to the natural gas price
16 assumption,such as the Hourly Incremental Cost methodology
17 proposed by Idaho Power.
18 Q.Do you have any proposed modifications to
19 Staff’s recommendation to use the EIA gas forecast and
20 update it annually in July of each year?
21 A.Yes.ETA releases an annual natural gas price
22 forecast in the spring of each year.In addition,during
23 the interim months between EIA’s annual forecast,EIA
24 releases a short—term forecast.Idaho Power recommends
25 that the short—term forecast also be adopted.This will
STOKES,REB 3
Idaho Power Company
1 help to somewhat address the problem identified earlier in
2 my testimony where I describe how the EIA annual forecast
3 can rapidly become outdated and inaccurate in a rapidly
4 shifting natural gas market.As previously noted,the EIA
5 gas forecast released in January 2012 is already more than
6 50 percent off in the near term.By incorporating EIA’s
7 monthly updates,this inaccuracy can be somewhat mitigated
8 on a monthly basis,rather than allowing an entire year to
9 pass with the corresponding inaccuracy transferred to
10 avoided cost rates.
11 Q.Is the Hourly Incremental Cost methodology
12 proposed by Idaho Power in this case less sensitive to
13 changes in the natural gas price forecast than the SAP.
14 methodology?
15 A.Yes,it is.Idaho Power has compared the gas
16 price sensitivity of the SAP.methodology and Idaho Power’s
17 Hourly Incremental Cost methodology.Both methodologies
18 were used to calculate avoided cost rates for a base load
19 resource using Idaho Power’s 2011 IRP natural gas price
20 forecast (August 2010),the Northwest Power and
21 Conservation Council’s updated forecast (August 2011),the
22 EIA forecast (January 2012),and current NYMEX forward
23 prices.This series of natural gas price forecasts
24 occurred over a time period where prices were falling and
25 are shown in the following figure.
STOKES,REB 4
Idaho Power Company
Gas Price Forecasts (Sumas)
$8.00 ———-—-—-—-
7
‘-4
(.4
$90
$80
510 -
$60w
$60
ocj $40
-U
I $20
°
$0
SAR
Notes:•SAR model run using Sumas natural gas forecast
t Hourly Incremental Cost Methodology using April 2012 load forecast and no carbon
Hourly Incremental CostMethodology I
STOKES,REB 5
Idaho Power Company
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
-*—2OS1IRP Expected Case
NPCC Updated (Aug 2011)
—MA 2012 Early Release (Mountain Region)
$1.00 -----——---—
—---IPC May 2012 Forwards Using NYMEX (May2012)
L_____
$o00 --—--—--——-
1 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
2 The results of this comparison are provided in the
3 figure below and show the 20-year,levelized avoided cost
4 rates from the SAR methodology vary from $80.43 to $62.18
5 (23 percent)and the Hourly Incremental Cost methodology
6 varies from $52.42 to $42.88 (18 percent)
Natural Gas Price Sensitivity AnaIsis
$80.43
--2011 IRP NPCC Updated E1A2012 Early
Expected Case Forecast (Aug Release
2011)
1
IPC Forwards
UsingNYMEX
(May2012)
2011 IRP NPCCUpdated EIAIO12 Early IPC Forwards
Expected Case Forecast(Aug Release Using NYMEX
2011)(May2012)
1 These results show that the SAR methodology is more
2 sensitive to the natural gas price assumption than Idaho
3 Power’s proposed Hourly Incremental Cost methodology.
4 Natural gas prices have historically been the most volatile
5 of all the inputs used to set avoided cost rates.Using a
6 methodology that is less sensitive to the gas price
7 forecast will likewise reduce the volatility of avoided
8 cost rates.
9 II.SAR METHODOLOGY
10 Q.Do you agree with the statement made by Dr.
11 Don Reading that avoided cost rates calculated using the
12 SAR methodology “have been remarkably accurate in
13 hindsight.”(Reading Direct,p.7,1.8.)
14 A.No,I do not.As I stated in my direct
15 testimony,historically there has been a significant
16 difference between the prices paid to QF resources on Idaho
17 Power’s system and the Mid—C market index to the direct and
18 substantial detriment of Idaho Power’s customers and,on a
19 forward looking basis,there continues to be a significant
20 difference between QF prices and the Mid—C forward market
21 price.This difference is illustrated in the following
22 figure:
23
24
25
STOKES,REB 6
Idaho Power Company
Average PURPA Price Compared to Mid-C Index
2002-2022
90 ---—-———--—
80 —----—______
_________—______
70 —--—
___
—____
_______________
60
50
ZZzLZ
10 ----
____
I
—AverageMid-Cindex —PURPA Price ——Est.PURPA Price ——Mid-CForwards
1
2 While the t4id-C index does not represent an avoided
3 cost rate,it does highlight the harm done to Idaho Power’s
4 customers when Idaho Power has excess QF’energy which must
5 be sold into the market at a substantial loss.
6 Q.Why do you believe avoided cost rates
7 determined by the SAR methodology are not accurate?
8 A.The concerns I have are not limited to the SAR
9 methodology,but any proxy method,which is why I believe
10 the SAR methodology should be abandoned and not just
11 modified,as recommended by others in this proceeding.
12 The SAR methodology is currently based on the
13 estimated cost of a utility building,owning,and operating
14 a combined-cycle combustion turbine (“CCCT”),and does not
15 account for all of the unique characteristics of the
16 various types of QF resources,including the availability
STOKES,REB 7
Idaho Power Company
1 of generation during system peak loads.In addition,the
2 methodology does not take into consideration that QF
3 resources are not economically dispatched in the same
4 fashion as utility-owned resources as under the Public
5 Utility Regulatory Policies Act of 1978 (“PURPA”),Idaho
6 Power has a “must purchase”obligation.For these reasons,
7 the product a QF resource delivers is very different from
8 the product produced by a utility—owned resource such as a
9 CCCT,and is not as valuable to the utility with its
10 obligation to serve load in a least-cost,reliable manner.
11 The high rates produced by the SAR methodology and
12 the subsidies available to many QF developers in the form
13 of investment and production tax credits as well as
14 renewable energy certificates are the primary drivers in
15 why Idaho Power has recently seen a landslide in QF
16 development.While the Idaho Public Utilities Commission
17 (“Commission”)cannot control state and federal subsidies
18 and tax incentives,it can remove some of the financial
19 incentive which is harming Idaho Power customers,and was
20 never the purpose nor intent of PURPA,by abandoning the
21 SAR methodology completely.
22 Q.Do you have any other basis for Idaho Power’s
23 recommendation that the SAR methodology be abandoned for
24 the purposes of calculating Idaho Power’s avoided cost
25 rates paid to PURPA QFs?
STOKES,REB 8
Idaho Power Company
1 A.Yes.Eased upon Idaho Power’s direct
2 testimony,and its March 12,2012,Motion for a Temporary
3 Stay of its Obligation to Enter into New Power Purchase
4 Agreements with Qualifying Facilities filed in this matter,
5 the Commission made findings “that the methodologies
6 previously approved by this Commission,as utilized and
7 applied by Idaho Power,do not currently produce rates that
8 reflect Idaho Power’s avoided cost and are not just and
9 reasonable,nor in the public interest.”Order No.32498.
10 Idaho Power believes that based upon its system
11 configuration,costs,and operations —including the large
12 amount of PURPA generation that currently exists on its
13 system —that the SAR methodology is no longer capable of
14 providing rates that are just and reasonable,nor in the
15 public interest.The resulting rates from the SAR
16 methodology do not result in rates that hold Idaho Power’s
17 customers indifferent as to whether they are paying for
18 power generated by a QF or that which is otherwise
19 generated or acquired by the Company.While it may,or may
20 not,be appropriate to continue the use of the SAR
21 methodology for Idaho’s other investor—owned utilities,it
22 is no longer appropriate to continue its use for Idaho
23 Power for the reasons set forth by Idaho Power in this
24 proceeding.
25
STOKES,REB 9
Idaho Power Company
1 Q.Several witnesses in this case have filed
2 testimony advocating the continued use of the SAR
3 methodology because of its transparency and simplicity.Do
4 you agree with this?
5 A.No,I do not.I believe these statements were
6 made only because the SAR methodology has been used for a
7 long period of time in Idaho and people have become
8 familiar with it.Just because the SAR methodology has
9 been used in Idaho for a number of years does not
10 necessarily mean that the methodology is transparent or
11 simple.In a recent Public Utility Commission of Oregon
12 case involving avoided cost rates,Public Utility
13 Commission of Oregon staff rejected the SAR methodology on
14 the basis of its complexity and lack of transparency,
15 particularly the tilting rate capital calculation contained
16 in the model.
17 Q.On page 8 of his direct testimony,Dr.Reading
18 references a National Economic Research Associates (“NERA”)
19 survey that is mentioned in the Direct Testimony of Idaho
20 Power witness William 1-lieronymus.What conclusion does Dr.
21 Reading make regarding this survey?
22 A.Dr.Reading points out that the survey results
23 showed 14 states out of 49 surveyed used some form of the
24 proxy method.Dr.Reading’s conclusion from this data is
25
STOKES,REB 10
Idaho Power Company
1 that it “indicates the SAR method is widely accepted as
2 valid method [sic]for determining avoided cost rates.”
3 Q.Do you agree with Dr.Reading’s conclusion?
4 A.No,for two primary reasons.First,the
5 survey was regarding the use of a proxy method,not the
6 specific SAR methodology as it has been used in Idaho.Dr.
7 Reading makes a big leap to get to his conclusion that the
8 SAR methodology is somehow valid because a few states use
9 some form of a proxy method.Second,while the survey does
10 indicate some states use a form of the proxy method (14 out
11 of 49 or 29 percent),it can also be stated that 35 out of
12 49 states (or 71 percent)have chosen other methodologies
13 for determining avoided cost rates.Dr.Reading chooses to
14 ignore this conclusion,which is in fact compelling data to
15 suggest that a proxy method is not the best way to
16 calculate a utility’s avoided costs.
17 III.HOURLY INCREMENTAL COST METHODOLOGY
18 Q.Do you believe that levelized avoided cost
19 rates available to QFs should be the same or very similar
20 to the per megawatt—hour (“MWh”)production cost of a
21 utility-owned resource as Dr.Reading suggests?
22 A.No,I do not.There are many reasons that I
23 will elaborate upon in my testimony as to why the two cost
24 figures would not match or even be close,the most
25 important of which is that a utility—owned resource will be
STOKES,RED 11
Idaho Power Company
1 dispatched based upon need,system reliability,and
2 economics while,currently,a QF resource is incented to
3 generate as much as Possible in all months of the year
4 regard55 of need,cost,or economic considerations
5 because the electric utility has a “must purchase”
6 obligatj under PURPA.
7 Throughout his direct testimony,Dr.Reading is
8 critical of any changes to avoided cost rate calculations
9 proposed by parties to this case on the grounds that a
10 proposed change “does not put the QF on an equal cost
11 footing with the utility’s own resources.”(Reading Direct,
12 p.13,1.2).Furthermore,on page 5 of his direct
13 testimony,Dr.Reading quotes the following passage from
14 Comjssion Order No.15746 (1980)
15 This Commission endorses the Policy
16 of having each Utility pay its full
17 avoided cost when Purchasing power
18 from cogenera5 and small power
19 producers.Such a price will bring
20 about the equ±lirj solution
21 typical of a competitive market
22 where the marginal cost of all firms
23 Producing a like produce iS equal.
24 Anything less will fail to bring
25 about the condition of a free,
26 competitive market and will leave
27 the utility,as the sole buyer,in a
28 POsition to dictate price as it Sees
29 fit.(Emphasis added.)
30 I have added the emphasis in the passage above
31 because i do not believe QF generation and utility_owned
32 generajo are “like products”because they are not bound
STOKES,REB 12
Idaho Power Company
1 by the same economic constraints.In addition,I do not
2 believe the SAR methodology is capable of capturing these
3 differences.
4 Further,the definition of avoided cost is “the
5 incremental costs to an electric utility of electric energy
6 or capacity or both which,but for the purchase from the
7 qualifying facility or qualifying facilities,such utility
8 would generate itself or purchase from another source.”18
9 C.F.R.§292.101(b)(6).Avoided cost must additionally
10 leave a utility’s customers neutral or indifferent as to
11 whether the electricity was generated by the utility or the
12 QF.Order No.32262,18 C.F.R.§292.304.Customers are
13 not being held indifferent and are paying much more for QF
14 generation under the SAR avoided cost rates than other
15 available power the Company could generate itself or
16 otherwise acquire.
17 Q.On page 34 of Dr.Reading’s testimony,he
18 provides a chart showing four different levelized costs.
19 He goes on to describe the costs as being dramatically
20 different,and questions whether Idaho Power’s proposed
21 Hourly Incremental Cost methodology produces a realistic
22 estimate of avoided cost.Do you agree with Dr.Reading’s
23 assessment?
24 A.No,I believe the differences between the
25 levelized costs reported by Dr.Reading can be easily
STOKES,REB 13
Idaho Power Company
1 explained and serve to highlight some of the differences
2 between a QF and a utility-owned resource.Specifically,I
3 am going to focus on the difference between Idaho Power’s
4 2011 IRP estimated levelized cost of $98 per MWh for a
5 utility—owned and operated CCCT and the Hourly Incremental
6 Cost methodology’s avoided cost rate of $47.40 per MWh for
7 a base load QF resource.An explanation of the factors and
8 assumptions behind these levelized cost estimates
9 demonstrates the avoided cost rates calculated under the
10 Hourly Incremental Cost methodology are not dramatically
11 different from estimated utility costs to build and operate
12 a resource,after taking into account characteristics of
13 the utility-owned resource relative to the QP resource.
14 Q.Please explain further the differences between
15 the levelized costs of a QP resource and one which is
16 utility-owned and operated.
17 A.A key difference between these cost estimates
18 is the assumed annual capacity factor for the two
19 resources.The 2011 IRP estimate assumes a 270 megawatt
20 (“MW”)CCCT economically dispatched at a 65 percent annual
21 capacity factor,while the Hourly Incremental Cost
22 methodology base load resource example assumes a QF
23 resource operating at a 92 percent annual capacity factor.
24 With a much higher capacity factor,the QF delivers energy
25 during a considerable number of hours during which the
STOKES,REB 14
Idaho Power Company
1 Company’s costs to operate its existing resources are
2 relatively low.Consequently,the costs the QF allows
3 Idaho Power to avoid during these hours are also relatively
4 low.If the QF were dispatchable and only operated when
5 economical and in the same manner the utility would operate
6 its own resources (65 percent annual capacity factor),the
7 Hourly Incremental Cost methodology’s levelized rate would
8 increase by approximately $13 per MWh.
9 A second difference relates to the period over which
10 the cost is levelized.The 2011 IRP cost is levelized over
11 a 30—year period,while the $47.40 per MWh calculated under
12 the Hourly Incremental Cost methodology is levelized over a
13 20-year period.Extending the Hourly Incremental Cost
14 methodology analysis to 30 years and then leveling the
15 costs over an additional 10 years increases the proposed
16 methodology’s estimate by approximately $6 per MWh.
17 Another factor explaining the difference between the
18 cost estimates involves the natural gas price forecast used
19 for each.Operating costs for a CCCT in the 2011 IRP are
20 based on earlier forecasts of nominal natural gas prices at
21 Sumas reaching approximately $13 per MMBtu by 2030.By
22 comparison,the more recent August 2011 Northwest Power and
23 Conservation Council fuel price forecast used in the Hourly
24 Incremental Cost methodology has nominal Sumas prices
25 reaching only about $9 per MMBtu by 2030.While part of
STOKES,REB 15
Idaho Power Company
1 the Hourly Incremental Cost methodology’s appeal is its
2 lower sensitivity to changes in natural gas prices,the use
3 of the higher 2011 IRP natural gas forecast in the proposed
4 methodology still produces an increase of approximately $5
5 per MWh in the estimated levelized cost.
6 It is also important to note that the Hourly
7 Incremental Cost methodology defers avoided capacity costs
8 until the Boardman to Hemingway transmission line is
9 operational in 2016.In contrast,the 2011 IRP estimate
10 for a CCCT begins accounting for capacity costs when the
11 plant is placed in—service.For the sake of comparison,if
12 the avoided capacity costs in the Hourly Incremental Cost
13 methodology were assumed to begin in 2013,the proposed
14 methodology would yield an estimated levelized cost about
15 $3 per MWh higher.
16 Q.Are there other differences between a utility—
17 owned CCCT and a QF resource that differentiate the value
18 each type of resource provides?
19 A.Yes,there are other differences between a
20 utility—owned resource and a QF resource;however,they are
21 more qualitative.First,a utility—owned CCCT is able to
22 provide operating reserves necessary for the reliable
23 operation of the electrical system.This is particularly
24 important for Idaho Power because of the increasing amounts
25 of variable and intermittent generation being added to the
STOKES,REB 16
Idaho Power Company
1 system.An intermittent QF generator,on the other hand,
2 increases the amount of operating reserves a utility must
3 have available.
4 Second,a utility-owned CCCT can be undesignated as
5 a network resource and utilized to source firm,off-system
6 sales,when economical,which benefits customers by
7 offsetting other power supply costs.The ability to
8 provide operating reserves and source firm,off-system
9 sales are directly related to the fact that a utility-owned
10 CCCT is dispatchable,while a QF resource is not.
11 Finally,new utility—owned resources are scrutinized
12 during public regulatory processes for the development and
13 acknowledgment of the Company’s IRP and filing for a
14 Certificate of Public Convenience and Necessity (“CPCN”)
15 where it must be demonstrated to regulators,customers,and
16 other stakeholders that the new resource will be not only
17 used and useful but also least cost.This helps to ensure
18 that any new resource selected is well suited to the
19 electrical system and customer needs.For example,the
20 need for a resource in 2012 like Langley Gulch power plant
21 was first introduced and vetted in the Company’s 2004 IRP,
22 and subsequently in the Company’s 2006,2009,and 2011
23 IRPs.In addition,it was subject to a fully contested
24 CPCN proceeding at the Commission in Case No.IPC-E-09-03.
25 In contrast,Idaho Power is forced to take whatever QF
STOKES,REB 17
Idaho Power Company
1 generation is proposed to it with no regard to customer
2 need,the QF’s impact on the reliable operation of Idaho
3 Power’s system,or the cost that QP generation imposes on
4 Idaho Power’s customers.Idaho Power was obligated to sign
5 294 MW of QF wind contracts during a two-month period in
6 late 2010 without any evaluation or scrutiny given to
7 whether those resources were needed,or how they would
8 impact customer rates or the reliable operation of Idaho
9 Power’s electrical system.
10 Q.Based on your review,what do you conclude
11 from the cost comparison chart shown on page 34 of Dr.
12 Reading’s testimony?
13 A.Dr.Reading asserts that the magnitude of the
14 difference in the levelized costs “calls into question the
15 claims that the proposed method is a realistic estimate of
16 the Company’s avoided cost.”(Reading Direct,p.34,1.
17 4.)Based on review of the levelized costs presented,and
18 the inputs and assumptions used for each,I believe the
19 differences in the costs can be easily explained and
20 highlight why a QF resource does not provide the same value
21 as a utility-owned resource.It is for these same reasons
22 that the SAR methodology,or any other proxy method,is
23 incapable of accounting for all the differences in resource
24 characteristics and is therefore not able to produce
25 accurate,or appropriate,avoided cost rates.
STOKES,REB 18
Idaho Power Company
1 Q.Would you characterize Idaho Power’s proposed
2 Hourly Incremental Cost methodology as transparent and
3 simple?
4 A.Yes,I would.In the Hourly Incremental Cost
5 methodology,the AURORA model is used to determine the
6 dispatch of utility—owned resources;beyond that,all other
7 information and calculations are done in an Excel
8 spreadsheet,which I believe is very transparent.The main
9 Excel worksheet is large,but only because it performs the
10 same calculation for every hour of the contract term.
11 As far as simplicity,I have had the opportunity to
12 become familiar with the spreadsheet and the methodology
13 over the past few months and believe it is simpler and more
14 transparent than the SAR model.Others likely do not share
15 this view because they have not yet spent much time working
16 with it.While I was not involved with avoided cost rates
17 when the SAR methodology was implemented,my guess is
18 similar feelings were also expressed at that time because
19 it was new to everyone.
20 Q.Do you believe Staff has thoroughly reviewed
21 the Hourly Incremental Cost methodology and spreadsheet?
22 A.Yes,I do.In fact,based on the discovery
23 questions Idaho Power received from Staff,I would say
24 Staff did a very thorough review of the methodology and
25 supporting data submitted by Idaho Power.
STOKES,REB 19
Idaho Power Company
1 Q.After reviewing the Hourly Incremental Cost
2 methodology,is Staff supportive of the method Idaho Power
3 is proposing?
4 A.Yes,they are.Beginning on page 8 and
5 Continuing through page 13 of his direct testimony,Staff
6 witness Sterling discusses various aspects of the Hourly
7 Incremental Cost methodology proposed by Idaho Power.The
8 following statements are taken from Mr.Sterling’s
9 testimony and are representative of the support expressed
10 for the proposed methodology:
11 I believe that Idaho Power has
12 properly focused on the incremental
13 costs that the utility incur
14 as the basis for determining avoided
15 costs.(Sterling Direct,p.10,1.
16 21.)
17 I believe that the IRP methodology
18 as proposed by Idaho Power conforms
19 more closely with FERC’s definition
20 of avoided cost than the way in
21 which Idaho Power has employed the
22 methodology in the past.(Sterling
23 Direct,p.11,1.1.)
24 I believe that the methodology as
25 proposed by Idaho Power is
26 acceptable,and as I stated
27 previously,an improvement over the
28 currently_accepted methodology.
29 (Sterling Direct,p.13,1.8.)
30 Q.Although supportive of the Hourly Incremental
31 Cost methodology proposed by Idaho Power,Staff is still
32 recommending the SAR model be used to establish published
33 rates.Do you agree with this?
STOKES,REB 20
Idaho Power Company
1 A.No,I do not.There are many reasons for
2 abandoning the SAR methodology that I expound on in both my
3 direct and rebuttal testimony,and I will not reiterate
4 them all here.However,I would like to emphasize that I
5 believe it would be an unnecessary administrative burden to
6 continue to use the SAR methodology for published rates
7 when a single method could be adopted and used to set both
8 published and negotiated avoided cost rates.
9 Q.Does the Company have any changes or updates
10 to the Hourly Incremental Cost methodology or pricing that
11 it would like to submit?
12 A.Idaho Power has no proposed changes to the
13 methodology itself as such is proposed in the Direct
14 Testimony of Karl Bokenkamp.However,the Company does
15 have updated current avoided cost prices derived from the
16 Hourly Incremental Cost methodology.Submitted as Exhibit
17 No.9 to my rebuttal testimony are updated current prices
18 for the four representative QF generation types that
19 coincide with and replace the current prices reflected in
20 Corrected Exhibit No.8 previously submitted with witness
21 Bokenkamp’s pre—filed direct testimony.The updated
22 current prices in my Exhibit No.9 were derived using the
23 EIA natural gas forecast recommended by Commission Staff
24 and Idaho Power’s updated April 2012 load forecast.The
25 updated pricing takes into account recent events,such as
STOKES,REB 21
Idaho Power Company
1 the removal of loads associated with Hoku Materials,Inc.,
2 as well as other updated adjustments.
3 IV.SAR METHODOLOGY MODIFICATIONS
4 Q.Although you propose abandoning the SAR
5 methodology in favor of Idaho Power’s Hourly Incremental
6 Cost methodology for both published and negotiated rates,
7 do you have any comments on the modifications to the SAR
8 methodology proposed by other witnesses?
9 A.Yes,I do.As an initial matter,I must
10 reiterate that Idaho Power believes the Commission should
11 completely abandon the use of the SAR methodology for
12 determining avoided cost rates.For all the reasons
13 explained in my direct testimony and elsewhere in my
14 rebuttal testimony,the Company believes the Hourly
15 Incremental Cost methodology is a better,more accurate
16 manner in which to determine avoided costs.That said,if
17 the Commission elects to retain the SAR methodology,I
18 would recommend a number of changes to that methodology,
19 including updating the index used to determine natural gas
20 prices.As I previously stated,several witnesses support
21 using the EIA natural gas price forecast and updating it on
22 an annual basis.Because of the frequency of updates,I
23 believe this would be better than continuing to rely on the
24 Northwest Power and Conservation Council forecast;however,
25 it still does not resolve the primary problem of the SAR
STOKES,REB 22
Idaho Power Company
1 methodology being overly sensitive to changes in the
2 natural gas price assumption.
3 Q.In his direct testimony,Staff witness
4 Sterling agrees with your proposal to use a simple-cycle
5 combustion turbine (“SCCT”)to determine the avoided cost
6 of capacity for all QE resource types.(Sterling Direct,
7 p.16,1.24.)Could an SCCT be used in the SAR
8 methodology as well?
9 A.Yes,I believe it could be if just the capital
10 and fixed costs of an SCCT were used to determine the
11 capacity portion of the avoided cost rate.The energy
12 component would still require using the heat rate and other
13 variable operations and maintenance assumptions appropriate
14 for a CCCT.
15 Q.In her direct testimony,Staff witness McHugh
16 proposes to apply the “first deficit year”concept to both
17 the capacity and energy components of avoided cost rates
18 (McHugh Direct,p.9,1.10).Do you agree with her
19 proposal?
20 A.Yes,with one recommended change.As I
21 understand the proposal,capacity payments would be removed
22 from the avoided cost rate until the month the first
23 uncommitted resource is identified in each utility’s IRP.
24 For the avoided cost of energy payments,deductions from
25 the rate would be made to account for transmission wheeling
STOKES,REB 23
Idaho Power Company
1 costs and losses until the first month an energy deficit
2 occurs in each utility’s IRP.In general,I support this
3 proposal because I believe this treatment of capacity costs
4 is an appropriate way to account for the ability of a QF to
5 come on—line at any time irrespective of a utility’s need.
6 For the energy component,transmission wheeling and losses
7 are real costs that result from having to sell surplus
8 energy into the market and,therefore,I am also supportive
9 of this concept with one modification.
10 Q.What is your recommended modification to
11 Staff’s proposal with regard to avoided cost of energy
12 payments?
13 A.Energy surplus/deficit positions are
14 determined on a monthly basis in the IRP.Therefore,I
15 propose that deductions for wheeling and losses be made for
16 any month the utility is surplus throughout the term of the
17 QF contract,not just until the first deficit month is
18 reached.A utility factors in wheeling and transmission
19 loss costs as part of making the decision of whether to
20 dispatch a utility-owned resource.Because a QF resource
21 is incented to deliver as much energy as it can to the
22 utility during all months of the year,I believe It would
23 be appropriate to account for these costs for any month the
24 utility is surplus throughout the term of the contract.
25
STOKES,REB 24
Idaho Power Company
1 Q.Canal company witness Schoenbeck proposes
2 numerous changes to the SAR methodology beginning on page
3 16 of his direct testimony.Can you summarize his
4 recommendations?
5 A.Yes,I can.Mr.Schoenbeck’s recommended
6 changes to the SAR methodology are fairly extensive and
7 include:
8 The SAR method could employ an
9 exogenously determined market price,
10 either hourly or monthly by on and
11 off peak period ...(Schoenbeck
12 Direct,p.16,1.18.)
13
14 Determining four different sets of
15 published prices based on the four
16 different QF delivery patterns
17 applied to the cost stream would
18 recognize the delivery
19 characteristics of each resource
20 type just as Idaho Power is
21 proposing ....(Schoenbeck
22 Direct,p.17,1.2.)
23
24 By requiring annual updates to the
25 gas prices and the corresponding
26 market prices,the SAR method will
27 not be static between integrated
28 resource plan publications.
29 (Schoenbeck Direct,p.17,1.7.)
30
31 Mr.Schoenbeck goes on to state,“The only item that
32 cannot be directly addressed by these modifications is how
33 additional QFs that commence delivering generation to Idaho
34 Power might impact Idaho’s published avoided costs,if at
35 all.”(Schoenbeck Direct,p.17,1.10)
STOKES,REB 25
Idaho Power Company
1 Q.Do you have any comments regarding Mr.
2 Schoenbeck’s recommended changes to the SAR methodology?
3 A.Yes,but only a general comment.As I read
4 through the recommended changes,it began to sound more
5 like an endorsement of the IRP methodology or the Hourly
6 Incremental Cost methodology proposed by Idaho Power.I am
7 not sure if it would even be feasible to implement the
8 changes Mr.Schoenbeck is recommending to the current SAR
9 model.At the very least,with his recommended changes I
10 think it would be difficult to still consider the SAR model
11 a proxy method for determining avoided cost rates.
12 V.AVOIDED COST OF CAPACITY
13 Q.The Staff and the utilities in this case are
14 recommending the avoided cost of capacity be removed from
15 the avoided cost rate until the first deficit year appears
16 in the IRP.Why do you believe this is appropriate?
17 A.As I have previously stated,utility-owned
18 resources are identified in the IRP based on need and are
19 only constructed or acquired when the need exists.From
20 this standpoint,utilities and QFs would be treated the
21 same as a utility would not be able to place a resource
22 into rates until it was used and useful and a QF would not
23 receive capacity payments until there was an identified
24 need.
25
STOKES,REB 26
Idaho Power Company
1 Q.On page 14 of his direct testimony,Dr.
2 Reading states “the denial of capacity payments during a
3 period of claimed surplus does not put a QE facility and a
4 company owned generating plant on an equal footing.”Do
5 you have any evidence to the contrary?
6 A.Yes,I do.In the 1980s,Idaho Power faced a
7 surplus capacity situation at the same time that the
8 Company attempted to place the Valmy II generating unit
9 into rate base.The Idaho Public Utilities Commission
10 determined that the Valmy II plant was not used and useful
11 because Idaho Power was in a surplus situation,meaning
12 that in the load and resource balance,resources exceeded
13 load.The exact words of the Commission were:
14 We find as a fact that Idaho Power’s
15 share of the Valmy II generating
16 plant is not used and useful in the
17 service of its Idaho ratepayers.
18 Power’s,Schneider’s,and Miller’s
19 evidence on this point is
20 overwhelming and uncontroverted.
21 The Company’s own load and resources
22 plan demonstrates that Valmy II is
23 surplus capacity until approximately
24 1993.In the interim,the Company’s
25 limited dispatches from Valmy II
26 could be reliably replaced,at a
27 fraction of that plant’s fully
28 distributed cost,by generation from
29 Idaho Power’s other plants and
30 purchases from the surplus market.
31 (Idaho Public Utilities Commission
32 Case U—1006—265,Order No.20610,p.
33 103.)
STOKES,REB 27
Idaho Power Company
1 The final result of this case was that Idaho Power
2 was not allowed a rate of return on this resource until
3 1989,four years after the resource was constructed and
4 operational.
5 Q.Beginning on page 9 of his direct testimony,
6 Dr.Reading includes a lengthy discussion of long-run and
7 short—run marginal costs based on the NERA “Grey Books”
8 that were published prior to the passage of PURPA.
9 Specifically on page 12,Dr.Reading states “Unless QFs are
10 credited for long—run capacity costs they will never by
11 [sic]compensated on an equal basis relative to what the
12 utilities receive in rates to build plant.”Does the
13 Hourly Incremental Cost methodology proposed by Idaho Power
14 compensate QF developers based on Idaho Power’s long—run
15 capacity cost?
16 A.Yes,the Hourly Incremental Cost methodology
17 compensates QE resources for the capacity they provide
18 based on the estimated long-term cost to add generation
19 capacity to Idaho Power’s system.Idaho Power has proposed
20 using the capital costs from an SCCT as the generation
21 resource that determines the capacity credit for QF
22 generation.Using the capital cost from a SCCT insures
23 that a QF resource receives equal treatment to utility—
24 owned resources.In fact,the Hourly Incremental Cost
25 methodology is consistent with the recommendation from the
STOKES,REB 28
Idaho Power Company
1 NERA Grey Books to use the “long-run marginal costs of
2 generating capacity”that Dr.Reading highlights in his
3 testimony.
4 Dr.Reading argues that QF resources would not be
5 compensated based on long-run marginal costs because they
6 would not receive capacity payments until the first deficit
7 year identified in the IRP.What this is ultimately saying
8 is that QF developers should receive preferential treatment
9 and be compensated for capacity regardless of a utility’s
10 need for the capacity.
11 Compensation for capacity based long-run marginal
12 costs is also impacted by the five—year contract term Idaho
13 Power has proposed.QP developers have rightly argued that
14 it is unrealistic for them to recover the capital cost of
15 their projects in a five-year term.While a utility
16 typically does have generation assets recovered in rates
17 past a five-year period,it is important to point out that
18 PURPA’s obligation,and,thus Idaho Power’s obligation to
19 contract,lasts past the Company’s proposed five-year
20 contract term.Accordingly,as a QF project continues to
21 sign new five-year contracts,it would continue to be
22 compensated for capacity long after a utility-owned
23 resource had been fully depreciated.
24 Q.On page 31 of his direct testimony,canal
25 company witness Schoenbeck proposes using loss of load
STOKES,REB 29
Idaho Power Company
1 analysis results to determine when QF resources should
2 begin being compensated for capacity.Do you agree with
3 this?
4 A.No,I do not agree for at least two reasons.
5 First,the loss of load expectation analysis Idaho Power
6 performs as part of the IRP is done after a preferred
7 portfolio has been identified and is only done to verify
8 that the selected portfolio provides a reasonable level of
9 assurance that projected loads can be met.Second,a loss
10 of load expectation (or probability)study is complex and
11 difficult to explain to anyone not familiar with the
12 concepts.It would be hard to imagine any of the
13 iritervenors in this case that are proponents of simple and
14 transparent processes being supportive of this
15 recommendation.
16 Q.Mr.Schoenbeck supports his proposal because
17 it produces earlier capacity payments for QF resources,and
18 then goes on to discuss “the game that can be played,”by
19 utilities in basing the start of capacity payments on the
20 first deficit month in the IRP load and resource balance.
21 (Schoenbeck Direct,p.31,1.13.)To support this
22 statement,Mr.Schoenbeck references Idaho Power’s Boardman
23 to Hemingway transmission project and its scheduled on—line
24 date of 2016.Do you agree that Idaho Power was “playing a
25
STOKES,REB 30
Idaho Power Company
1 game”with the scheduled on-line date for the Boardman to
2 Hemingway transmission project?
3 A.No,I do not.Late in the process of
4 preparing Idaho Power’s 2011 IRP,it was determined that
5 delays in permitting were going to cause the scheduled
6 operational date of the project to slip from 2015 to 2016.
7 Therefore,the IRP load and resource balance showed a
8 deficit in 2015,which was eliminated with an “east-side”
9 purchase for the summer months.Idaho Power has relied on
10 short—term purchases from the east side of its system in
11 the past when necessary;however,it is not the preferred
12 choice for market purchases or something the Company wants
13 to rely on long term due to low market liquidity and
14 typically higher prices.
15 I believe Mr.Schoenbeck’s “gaming”concerns could
16 be addressed simply by clarifying how the first deficit
17 year is determined.The way Idaho Power has applied it in
18 the case of the Boardman to Hemingway project mentioned
19 above is based on when the next planned resource is to come
20 on-line.This methodology is based on the utility resource
21 that is potentially being “avoided”due to any new QE’
22 resources.The other method that could be used would be to
23 strictly rely on the first deficit year identified in each
24 utility’s load and resource balance,which would address
25 Mr.Schoenbeck’s concern.
STOKES,REB 31
Idaho Power Company
1 VI.AVOIDED COST OF ENERGY
2 Q.In his direct testimony,Dr.Reading comments
3 on Idaho Power’s proposed Hourly Incremental Cost
4 methodology by stating,“the approach incorrectly assumes
5 avoided costs should be based on a very short—run hourly
6 basis.”(Reading Direct,p.29,1.10).Do you agree with
7 Dr.Reading’s assessment?
8 A.No,I do not.Dr.Reading assumes that
9 because the avoided cost of energy is calculated on an
10 hourly basis,the calculation ±5 only focused on the
11 “short-run.”The avoided cost of energy calculation in the
12 Hourly Incremental Cost methodology is in fact very
13 “granular”in that every hour for the QF contract term is
14 analyzed.This does not suggest that the methodology is
15 only focused on the “short-run”because the calculation is
16 done for each and every hour throughout the entire contract
17 term.
18 VII.CONTRACT TERM
19 Q.In his direct testimony,canal company witness
20 Schoenbeck states “The five—year term is unfair and
21 inappropriate because ±t creates a mismatch between the
22 maximum contract term allowed a QF versus the economic life
23 used or assumed for a comparable utility-owned resource.”
24 (Schoenbeclc Direct,p.9,1.1.)Do you believe this is
25 true?
STOKES,REB 32
Idaho Power Company
1 A.No.What Mr.Schoenbeck does not point out is
2 that a QE resource could simply continue to sign new five-
3 year contracts and ultimately receive capacity payments
4 long after a utility-owned resource was fully depreciated.
5 I believe Mr.Schoenbeck’s statement is based on the
6 expectation that the QF would have to pay off any debt
7 associated with the project during the first five—year
8 contract.While I have no firsthand knowledge of whether
9 project financing would become more difficult for QF
10 developers,I do not believe this assumption supports the
11 statement that a five-year contract term is “unfair and
12 inappropriate.”
13 Q.Mr.Schoenbeck goes on to state that “locking
14 into fixed price arrangements reduces Idaho Power’s
15 exposure to market price movements.”(Schoenbeck Direct,p.
16 13,1.13.)Do you agree with this?
17 A.No.In fact,it has the opposite effect of
18 putting all of the risk on Idaho Power customers and giving
19 the QFs a hedge against potential unfavorable market
20 shifts.History indicates that avoided cost rates exceed
21 market prices and that QFs predominantly insist upon
22 contracts only when contractual prices exceed market rates.
23 See the chart on page 7 of my rebuttal testimony.This
24 chart clearly shows that over the past 10 years Idaho Power
25 has paid substantially more for QF energy compared to
STOKES,REB 33
Idaho Power Company
1 market rates.Although it is true in theory that actual
2 prices can go up or down relative to the forecast or
3 contract price,if the price is favorable to the QF,they
4 will insist upon a long-term contract,develop the project,
5 and continue to generate.On the other hand,if the price
6 is not favorable,or no longer favorable,the QF has the
7 options of not contracting,contracting but not developing,
8 or bringing the project on-line,not generating or
9 generating less,or ultimately ceasing operations and
10 walking away from the project and contract.The point
11 being that it is a hedge,or an option that the QF can
12 exercise with customers taking all the downside price risk
13 and hit,and rarely if ever seeing any upside.
14 Q.Does Staff agree with Idaho Power’s views
15 regarding this risk that is shouldered by customers?
16 A.Yes.Staff witness Sterling also supports
17 this view in his direct testimony regarding fuel price
18 risk.
19 Prices established at the start of a
20 long-term contract could prove to be
21 too high or too low compared to
22 other alternatives or to market
23 prices in effect throughout the term
24 of the contract.A long-term
25 contract locks in those prices,
26 regardless of what happens with
27 market prices.Because 100 percent
28 of PURPA costs are passed on to
29 customers through PCAs,ratepayers
30 are fully exposed to the risk that
31 PURPA rates may prove to be too
32 high.(Sterling Direct,p.30,1.
33 25.)
STOKES,REB 34
Idaho Power Company
1 I believe what Mr.Sterling states is the exact
2 situation Idaho Power’s customers are currently in due to
3 avoided cost rates that have historically been set too high
4 using the SAR methodology.
5 Q.Staff witness Sterling proposes that a five-
6 year contract term only apply to QF projects larger than
7 the published rate cap.Do you agree with this?
8 A.While Idaho Power appreciates Staff’s
9 agreement that the maximum contract term for all QF
10 contracts under the Hourly Incremental Cost methodology be
11 set at five years,Idaho Power recommends that the five-
12 year contract term apply to all PURPA QF power sale
13 contracts.Staff’s recommendation that contracts for all
14 other QF resources under the SAR methodology be entitled to
15 20—year contracts would only be acceptable to the Company
16 if the published rates based upon the SAR methodology were
17 to remain available only to QFs with a nameplate capacity
18 below 100 kilowatts (“kW”).If the Commission reduces the
19 published rate cap to 100 kW for all QF resource types as
20 the Company has recommended,then most of the risk
21 customers face due to longer-term contracts will be
22 minimized.However,if longer—term contracts are available
23 for published rates for larger QFs up to 10 MW or 10
24 average megawatts,then all of the problems associated with
25 price risk described above,and by Staff and the Company in
STOKES,REB 35
Idaho Power Company
1 direct testimony,will continue to exist,and continue to
2 harm customers.
3 As stated earlier,the shorter maximum contract term
4 is a safeguard for customers to ensure that the very large
5 risk of locking in prices for the entire duration of the
6 contract is not allowed to continue to inflict substantial
7 financial harm to customers.Because Federal Energy
8 Regulatory Commission (“FERC”)regulations allow a QF to
9 unilaterally elect to have the prices in its contract set
10 for the entire duration of the contract based upon price
11 estimates at the time of contracting —as opposed to prices
12 at the time the energy is delivered —the Company,and the
13 Commission,have no means to bring prices back to reality
14 should a large deviation in prices materialize to the
15 detriment of customers,as Idaho Power has demonstrated in
16 its direct testimony in the current case.This is
17 exacerbated by FERC’s prohibitions regarding certain price
18 “reopeners”in the QF power sales agreements.
19 Consequently,the only real tool left for the Commission to
20 assure that the Company and its customers are not saddled
21 with substantial long-term harm from price projections that
22 end up deviating substantially from actual prices is to
23 shorten the term of the contract.The obligation to
24 purchase will remain,and the QF can enter into a new
25 contract for the years past year five,or the maximum term
STOKES,REB 36
Idaho Power Company
1 of the contract.The Commission and the utility customers
2 can then be assured that even should the price estimates
3 that are established in the contract become harmful and
4 deviate substantially from reality,that they will be
5 looked at anew and refreshed with the new contract,once
6 the maximum term expires.
7 VIII.PUBLISHED RATE CAP
8 Q.Canal company witness Schoenbeck recommends
9 setting the published rate cap at 10 MW of nameplate
10 capacity for all resource types (Schoenbeck Direct,p.14,
11 1.10).Do you have any concerns regarding this proposal?
12 A.Yes,I do.Regardless of what avoided cost
13 methodology the Commission decides to use to set rates,
14 published rates could remain stagnant for one to two years.
15 Past experience shows much can change in the energy
16 industry during this time frame,and in order to protect
17 customers from the risk associated with changed conditions,
18 I believe the published rate cap should be set at the
19 minimum FERC required level of 100 kW for all resource
20 types.
21 As I have proposed previously,if published rates
22 are set using the Hourly Incremental Cost methodology for
23 the various resource types,published rates and negotiated
24 rates for each resource type will remain virtually
25 identical as long as the assumptions made in the IRP remain
STOKES,REB 37
Idaho Power Company
1 valid.If any of the assumptions do change,the utilities
2 will be able to update the inputs used in the methodology
3 in order to calculate a current and accurate avoided cost
4 rate.This idea on how to implement and apply published
5 and negotiated rates also has the advantage of no longer
6 needing to rely on the SAR methodology,which I do not
7 believe calculates accurate avoided cost rates.
8 IX.CARBON ADDER
9 Q.On page 24 of his direct testimony,canal
10 company witness Schoenbeck advocates for including
11 potential carbon costs in the avoided cost of energy.
12 Witness Looper also discusses the addition of carbon tax
13 costs on page 7 of his direct testimony.Do you agree with
14 their statements?
15 A.No,I do not.Estimates of future carbon
16 costs are used in the IRP process to evaluate the relative
17 difference between the cost of various resource portfolios.
18 None of these costs are currently real nor are they
19 included in customer rates.
20 Idaho Power has addressed the carbon adder issue in
21 every IR?it has prepared since at least the 2004 IRP,and
22 used high and low cases for risk analysis purposes.During
23 the IRP cycle,the cost and potential implementation date
24 of a carbon adder are discussed with stakeholders,and
25 today there is just as much uncertainty of these
STOKES,REB 38
Idaho Power Company
1 projections as there was in 2004.While appropriate for
2 purposes of evaluating the relative difference between
3 future resource acquisitions in the IRP process,these
4 potential carbon costs do not exist today,and it would be
5 inappropriate to include them in any avoided cost rate.
6 X.IRP LITIGATION
7 Q.On page 18 of his direct testimony,Dr.
8 Reading proposes that utility IRP5 should “be subject [sic]
9 greater scrutiny and subjected to a litigated hearing and
10 ultimately approval by the Commission.”(Reading Direct,p.
11 18,1.2.)In leading up to this recommendation,Dr.
12 Reading states,“I would agree if the utilities IRPs were,
13 in fact,subject to significant oversight in their
14 development and submission.”(Reading Direct,p.17,1.1.)
15 Do you agree with Dr.Reading’s opinion concerning the
16 level of oversight in the IRP process?
17 A.No,I do not.It takes Idaho Power
18 approximately one year to prepare an IRP,and during that
19 time,the Company conducts monthly meetings with the IRP
20 Advisory Council.Members of the council include
21 political,environmental,and customer representatives,
22 Commission Staff representatives,and representatives of
23 other public-interest groups.In addition,the meetings
24 are open to the public and are typically well attended by
25 other stakeholders and interested individuals.The primary
STOKES,REB 39
Idaho Power Company
1 purpose of the meetings is to discuss issues related to the
2 IRP and to solicit input on the assumptions that go into
3 the plan.
4 Following the completion of the IRP and subsequent
5 filing with the Commission,additional public meetings are
6 conducted to present the plan to the public.During this
7 same time,the Commission also solicits public comments.
8 As the person ultimately responsible for the
9 preparation of Idaho Power’s IRP,I can say that there is a
10 significant amount of oversight in the process of preparing
11 the plan.
12 Q.Are there specific reasons the Commission
13 should not make the IRP a “litigated process”?
14 A.Yes,there are at least three reasons.First,
15 IRPs are intentionally ‘‘accepted”and not “approved”by the
16 Commission so there is no inference of approval of any of
17 the action items contained in the plan.Any new generation
18 resources identified in the plan must still go through a
19 CPCN process,which is fully litigated.
20 Second,the Commission,utilities,and others
21 recognize that things can change within the two-year period
22 between IRP filings.Having the IRP accepted and not
23 approved provides flexibility for the utilities to react to
24 these changes,without having to go through a protracted
25 legal proceeding.
STOKES,REB 40
Idaho Power Company
1 Finally,as I stated previously,it takes
2 approximately one year to prepare an IRP.The regulatory
3 process as it exists today typically takes an additional
4 six months and shortly after that internal preparations
5 begin for the next IRP.If the IRP were to be fully
6 litigated,I do not believe the two-year cycle would allow
7 time for the Commission to issue an order before the next
8 plan would be underway.
9 XI.ENVIRONMENTAL ATTRIBUTES
10 Q.Did Idaho Power make any specific requests of
11 the Commission with regard to Environmental Attributes or
12 RECs of QF generation in its direct testimony in this case?
13 A.No.In Lisa Grow’s direct testimony,Idaho
14 Power acknowledged that RECs were listed by the Commission
15 as one of the issues to be examined in this proceeding in
16 Order No.32352;however,the Company stated that it had no
17 specific request of the Commission in this regard at the
18 time that direct testimony was filed (January 31,2012)
19 Q.Did the Company make any other statements
20 regarding the issue of REC5 in its direct testimony?
21 A.Yes.Witness Grow stated:
22 Issues related to PURPA QFs and
23 RECs are currently being litigated
24 by the Company before the
25 Commission in Case No.IPC—E-11—15.
26 The Commission has had proceedings
27 in the past regarding issues
28 related to the ownership of RECs
STOKES,REB 41
Idaho Power Company
1 between PURPA QEs and the
2 purchasing utility,but the issue
3 of ownership of RECs in the state
4 of Idaho remains an unsettled
5 issue.Idaho Power understands
6 that the Idaho Legislature,which
7 is currently in session,may be
8 considering proposed legislation
9 that would address the ownership of
10 REC5 from PURPA QF’projects,and
11 thus the Company has no specific
12 request of the Commission in this
13 regard at this time.
14
15 Grow Direct,p.13,1.22 through p.14,1.8.
16 Q.Has anything changed with regard to the
17 pending Commission cases regarding QF RECs or with the
18 Idaho Legislature since January 31,2012?
19 A.Yes,with regard to both.The Idaho
20 Legislature ended its 2012 session without taking any
21 action with regard to the ownership of RECs and utility
22 purchased QE generation.Additionally,the Commission
23 recently issued Order No.32580 in Case No.IPC-E—11—15
24 denying a QP’s motion for summary judgment regarding its
25 request to require the utility to disclaim ownership of
26 RECs in a QE power purchase agreement.
27 Q.Does Idaho Power have any specific requests of
28 the Commission with regard to RECs from utility—purchased
29 QF generation at this time?
30 A.Yes.Idaho Power,similar to other parties to
31 this docket,requests that the Commission specifically find
32 that the Environmental Attributes or RECs from utility
STOKES,REB 42
Idaho Power Company
1 purchased QF generation are owned by the purchasing
2 utility.
3 Q.Have other parties to this docket asked the
4 Commission to make similar findings?
5 A.Yes.Witness Paul Clements on behalf of Rocky
6 Mountain Power,and witness Rick Sterling on behalf of
7 Commission Staff have recommended that the Commission find
8 that the purchasing utilities should be determined the
9 owners of the REC5 from PURPA projects that sell their
10 generation to the utility.
11 Q.What basis do you have for this
12 recommendation?
13 A.First of all,Idaho Power agrees with witness
14 Sterling’s conclusion that FERC has clearly determined that
15 REC ownership with regard to QF generation is a matter for
16 the states to decide.Citing,merican Ref-Fuel Company,
17 105 FERC ¶61,004 (2003).Additionally,this was confirmed
18 by the Commission in Order No.32580,Case No.IPC-E-11-15
19 (June 21,2012).The Commission in that Order denied a
20 QF’s motion for summary judgment requesting that the
21 Commission order the utility to disclaim ownership of the
22 REC5 in its QF power purchase agreement.The Commission
23 confirmed that the decision regarding ownership of RECs
24 from QF generation is a decision that lies with the states,
25 and that such a decision has not yet been made in the state
STOKES,REB 43
Idaho Power Company
1 of Idaho.The Commission stated,quoting FERC,“States,in
2 creating RECs,have the power to determine who owns the
3 REC5 in the initial instance,and how they may be sold or
4 traded;it is not an issue controlled by PURPA.”Order No.
5 32580,p.5 (citations omitted).The Commission found,“no
6 specific federal or state laws governing the ownership of
7 RECS”and rejected the QF’s arguments that other facts
8 supported the QF’s contention that it owned the RECs from
9 the PURPA power sale.Order No.32580,pp.9-13.The
10 Commission also verifies that its past orders regarding QF
11 REC issues did not address the ownership of those RECs in
12 the initial instance (Id.,at pp.10-11)and that the issue
13 of QF REC ownership in the state of Idaho remains an
14 undecided issue,“Grand View cannot assert a Commerce
15 Clause violation when the ownership of RECs has not been
16 decided.”Id.,p.16.
17 Q.Have any of the QF parties to this docket
18 acknowledged the Commission’s authority to decide the issue
19 of QF REC ownership?
20 A.Yes.Clearwater Paper Corporation,J.R.
21 Simplot Company,and Exergy Development Group of Idaho,
22 LLC,through their witness,Dr.Reading,have asked the
23 Commission to make a decision “as soon as possible”
24 regarding the ownership of environmental attributes.
25 Reading Direct,p.60.In addition,Grand View Solar II,a
STOKES,REB 44
Idaho Power Company
1 party to this case,is the QP referenced above in Order No.
2 32580 that filed its Complaint asking the Commission to
3 order Idaho Power to disclaim ownership of the RECs in its
4 proposed QF power sales agreement,which the Commission
5 denied.
6 Q.Does Idaho Power agree with Rocky Mountain
7 Power witness Clements’recommendations that the Commission
8 determine that the utility owns the Environmental
9 Attributes of the QF generation it purchases pursuant to
10 PURPA with no additional compensation beyond what is
11 already paid for the QF generation?
12 A.Yes.Idaho Power agrees with the position and
13 statements of Rocky Mountain Power in the Direct Testimony
14 of Paul Clements Direct,p.6,1.22 through p.10,1.13,
15 and by this reference adopts and supports the same.
16 Q.Does Idaho Power agree with Staff witness Rick
17 Sterling’s recommendations to the Commission with regard to
18 the ownership of RECs from utility purchased QF generation?
19 A.Yes.Idaho Power agrees with witness
20 Sterling’s recommendation that the Commission find that the
21 utility owns the REC5 from utility purchased QF generation.
22 However,the Company disagrees with his recommendation that
23 the utility be required to pay any amount over the avoided
24 cost rate for rates determined under the SAR avoided cost
25 methodology.The Company,and its customers,in such an
STOKES,REB 45
Idaho Power Company
1 instance would be paying twice for what it had all ready
2 purchased from the QF,and paying above the avoided cost.
3 XII.LIQUIDATED DAMAGES
4 Q.Several witnesses discuss liquidated damages
5 and the current Commission—approved requirement to post
6 delay damage security with the current PURPA power sales
7 agreements.Does Idaho Power have a position in this
8 regard?
9 A.Yes.Idaho Power is in favor of and supports
10 the Commission’s requirements to post delay damage security
11 with all PURPA power sales agreements in the amount of $45
12 per kW of nameplate capacity.This has been specifically
13 addressed in numerous Commission cases and numerous
14 different power sales agreements with various QF projects.
15 The Commission has specifically found this requirement to
16 be in the public interest and a just and reasonable
17 requirement of the contracting process.With regard to the
18 reasonableness of liquidated damages,some witnesses,such
19 as Dr.Reading,focus only upon the comparison to the cost
20 of replacement power should the QF not bring its project
21 on—line when it commits itself to a Scheduled Operation
22 Date that it chooses in the contract.This highlights an
23 important part of Idaho Power’s case that it provided much
24 evidence of in its direct testimony,and that is typically
25 the Company can acquire replacement power from other
STOKES,REB 46
Idaho Power Company
1 available sources at a cost that is below the contract
2 price in the PURPA contract.This,however,is not the
3 only measure of harm and damages.In addition to the
4 system operation and planning problems that failure to
5 bring generation units on—line in a timely manner and when
6 they are scheduled to come on—line,there is the
7 substantial value that the QF gets by locking in a price,
8 and a pricing stream with its contract.If a QF is allowed
9 to come on—line,or not,at its choosing with no
10 consequences and no liability for the value of that option,
11 then customers are left in a financially disadvantaged
12 position and uncompensated for the price lock and option
13 they extended to the QF project.There are financial
14 instruments that can be purchased that would allow a
15 utility to lock in a 20-year,or long—term,stream of
16 prices,and have the option to not execute on that option
17 at a date certain in the future.Such products are very
18 costly,and could be as much as $5 per MWh of power.The
19 $45 per kW of nameplate capacity is very small in
20 comparison,but at least provides an agreed upon valuation
21 of an assessment of risk that the customers are bearing
22 associated with whether a QF generator brings its project
23 on-line when it commits that it will.
24
25
STOKES,REB 47
Idaho Power Company
1 XIII.SCHEDULE 73
2 Q.The Company stated in its direct testimony
3 that one of the items it seeks from the Commission is
4 “Establishment of a Commission-authorized negotiation
5 process and procedure by which a PURPA QF can obtain a PPA
6 with Idaho Power.”Grow Direct,p.14.Does Idaho Power
7 have any further details regarding this request?
8 A.Yes.Upon Idaho Power’s review of Rocky
9 Mountain Power’s proposed Tariff Schedule 38,provided as
10 Exhibit No.202 to Rocky Mountain Power witness Clements’
11 testimony,Idaho Power has drafted its proposed Tariff
12 Schedule No.73,which sets forth a similar process for QFs
13 proposing to contract with Idaho Power.I submit Idaho
14 Power’s proposed Tariff Schedule No.73 as Exhibit No.10
15 to this rebuttal testimony.Additionally,submitted as
16 Exhibit No.11 herewith is a red-lined version of Rocky
17 Mountain Power’s proposed Schedule 38,which shows in red—
18 line format the substantive changes between Schedule 38 and
19 Idaho Power’s proposed Schedule 73.
20 Q.Does this conclude your rebuttal testimony in
21 this case?
22 A.Yes,it does.
23
24
25
STOKES,REB 48
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.GNR-E-11-03
IDAHO POWER COMPANY
STOKES,REB
TESTIMONY
EXHIBIT NO.9
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.GNR-E-11-03
IDAHO POWER COMPANY
STOKES,REB
TESTIMONY
EXHIBIT NO.10
Idaho Power Company
I.P.U.C.No.29,Tariff No.101 Original Sheet No.73-1
SCHEDULE 73
ENERGY SALES AGREEMENT PROCEDURES
FOR QUALIFYING FACILITIES
AVAILABILITY
Service under this schedule is available to owners of Qualifying Facilities (QF”)throughout the
Company’s service area within the State of Idaho.
APPLICABILITY
To owners of existing or proposed QFs who desire to make sales to the Company at avoided
cost rates.Such owners shall be required to enter into written power purchase and interconnection
agreements with the Company pursuant to the procedures set forth in this Schedule 73.Additional or
different requirements may apply to Idaho QFs seeking to make sales to third parties or out-of-system
QFs seeking to wheel power to Idaho for sale to the Company.
I.PROCESS FOR NEGOTIATING POWER PURCHASE AGREEMENTS
A.Communications
Unless otherwise directed by the Company,all communications to the Company
regarding QF power purchase agreements shall be directed in writing as follows:
Idaho Power Company
ATTN:Cogeneration and Small Power Production
1221 West Idaho Street
Boise,Idaho 83702
Any requirement for written notice in this Schedule 73 shall be via mail unless the
parties agree by mutual consent to an alternative form.The Company shall
respond to all such communications in a timely manner as more fully described
below.If the Company is unable to respond on the basis of incomplete or
missing information from the QF owner,the Company shall indicate what
additional information is required.Thereafter,the Company shall respond in a
timely manner following receipt of all required information as more fully described
below.
B.Procedures
1.Examples of the Company’s typical generic power purchase agreement
may be obtained from the Company’s web site at wwwidahopower.com,
or if the owner is unable to obtain it from the web site,the Company shall
send a copy via mail within seven calendar days of a written request
directed to the address in Part I.A.
Exhibit No.10
Case No.GNR-E-11-03
M.Stokes,IPC
Page 1 of 6
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No.
______
Gregory W.Said,Vice President,Regulatory Affairs
Effective —1221 West Idaho Street,Boise,Idaho
Idaho Power Company
I.P.U.C.No.29,Tariff No.101 Original Sheet No.73-2
SCHEDULE 73
ENERGY SALES AGREEMENT PROCEDURES
FOR QUALIFYING FACILITIES
(Continued)
PROCESS FOR NEGOTIATING POWER PURCHASE AGREEMENTS (Continued)
B.Procedures (Continued)
2.To obtain an indicative pricing proposal with respect to a proposed
project,the owner shall provide in writing to the Company,general project
information reasonably required for the development of indicative pricing.
A project is defined as an existing or proposed QF that desires to make
sales to the Company and that can satisfy the requirements of this
Schedule 73.General project information shall include,but not be limited
to:
a.project name and contact information;
b.generation technology and other related technology applicable to
the site;
c.design capacity (MW),station service requirements,and net
amount of power to be delivered to the Company’s electric
system;
d.quantity and timing of hourly power deliveries (estimated hourly
generation data for every hour of a one-year period).Upon
request,the Company will supply an electronic spreadsheet that
can be used by the QF for this purpose;
e.proposed site location and electrical interconnection point;
f.proposed on-line date (date on which deliveries of energy will
commence)and outstanding permitting requirements;
g.demonstration of ability to obtain QF status;
h.fuel type(s)and source(s);
proposed contract term;and
j.status of interconnection arrangements.
3.The Company shall not be obligated to provide an indicative pricing
proposal until all information described in Paragraph 2 has been received
in writing from the QF owner.Within 30 calendar days following receipt of
all information required in Paragraph 2,the Company shall provide the
owner with an indicative pricing proposal,which may include other
indicative terms and conditions,tailored to the individual characteristics of
the proposed project.Such proposal may be used by the owner to make
determinations regarding project planning,financing,and feasibility.
However,such prices are merely indicative and are not final and binding.
Prices and other terms and conditions are only final and binding to the
extent contained in a power purchase agreement executed by both
parties and approved by the Commission.Upon request,the Company
shall provide with the indicative prices a description of the methodology
used to develop the prices.Exhibit No.10
Case No.GNR-E-11-03
M.Stokes,PC
Page 2 of 6
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No.
______
Gregory W.Said,Vice President,Regulatory Affairs
Effective —
_______
1221 West Idaho Street,Boise,Idaho
Idaho Power Company
I.P.U.C.No.29,Tariff No.101 Original Sheet No.73-3
SCHEDULE 73
ENERGY SALES AGREEMENT PROCEDURES
FOR QUALIFYING FACILITIES
(Continued)
PROCESS FOR NEGOTIATING POWER PURCHASE AGREEMENTS (Continued)
B.Procedures (Continued)
4.If the owner desires to proceed with the project after reviewing the
Company’s indicative proposal,it shall request in writing that the
Company prepare a draft power purchase agreement to serve as the
basis for negotiations between the parties.In connection with such
request,the owner shall provide the Company with any additional project
information that the Company reasonably determines to be necessary for
the preparation of a draft power purchase agreement,which may include,
but shall not be limited to:
a.updated information of the categories described in Paragraph B.2;
b.evidence of adequate control of proposed site;
c.identification of,and timelines for obtaining any necessary
governmental permits,approvals,or authorizations;
d.assurance of fuel supply or motive force;
e.anticipated timelines for completion of key project milestones;and
f.evidence that any necessary interconnection studies have been
completed and assurance that the necessary interconnection
arrangements are being made in accordance with Part II.
5.The Company shall not be obligated to provide the owner with a draft
power purchase agreement until all information required pursuant to
Paragraph 4 has been received by the Company in writing.Within 45
calendar days following receipt of all information required pursuant to
Paragraph 4,the Company shall provide the owner with a draft power
purchase agreement containing a comprehensive set of proposed terms
and conditions,including a specific pricing proposal for purchases from
the project.Such draft shall serve as the basis for subsequent
negotiations between the parties and,unless clearly indicated,shall not
be construed as a binding proposal by the Company.
Exhibit No.10
Case No.GNR-E-11-03
M.Stokes,PC
Page 3 of 6
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No.
______
Gregory W.Said,Vice President,Regulatory Affairs
Effective —1221 West Idaho Street,Boise,Idaho
Idaho Power Company
I.P.U.C.No.29,Tariff No.101 Original Sheet No.73-4
SCHEDULE 73
ENERGY SALES AGREEMENT PROCEDURES
FOR QUALIFYING FACILITIES
(Continued)
PROCESS FOR NEGOTIATING POWER PURCHASE AGREEMENTS (Continued)
B.Procedures (Continued)
6.After reviewing the draft power purchase agreement,the owner shall
prepare an initial set of written comments and proposals regarding the
draft power purchase agreement and shall provide such comments and
proposals,or notice that it has none,to the Company.The Company
shall not be obligated to commence negotiations with a QF owner until
the Company has received an initial set of written comments and
proposals from the QF owner.Following the Company’s receipt of such
comments and proposals,the owner shall contact the Company to
schedule contract negotiations at such times and places as are mutually
agreeable to the parties.In connection with such negotiations,the
Company:
a.shall not unreasonably delay negotiations and shall respond in
good faith to any additions,deletions,or modifications to the draft
power purchase agreement that are proposed by the owner;
b.may request to visit the site of the proposed project if such a visit
has not previously occurred;
c.shall update its pricing proposals at appropriate intervals to
accommodate any changes to the Company’s avoided cost
calculations,the proposed project,or proposed terms of the draft
power purchase agreement;
d.may request any additional information from the owner necessary
to finalize the terms of the power purchase agreement and satisfy
the Company’s due diligence with respect to the project;and
e.shall resolve disputes related to power purchase agreement terms
consistent with Part III of this Schedule 73.
7.When both parties are in full agreement as to all terms and conditions of
the draft power purchase agreement,the Company shall prepare and
forward to the owner within 45 calendar days a final,executable version
of the agreement.The Company reserves the right to condition execution
of the power purchase agreement upon simultaneous execution of an
interconnection agreement between the owner and the Company’s power
delivery function,as discussed in Part II.Prices and other terms and
conditions in the power purchase agreement shall not be final and binding
until the power purchase agreement has been executed by both parties
and the Commission approves the agreement.
Exhibit No.10
Case No.GNR-E-11-03
M.Stokes,IPC
Page 4 of 6
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No.Gregory W.Said,Vice President,Regulatory Affairs
Effective —1221 West Idaho Street,Boise,Idaho
Idaho Power Company
I.P.U.C.No.29,Tariff No.101 Original Sheet No.73-5
SCHEDULE 73
ENERGY SALES AGREEMENT PROCEDURES
FOR QUALIFYING FACILITIES
(Continued)
PROCESS FOR INTERCONNECTION
In addition to negotiating a power purchase agreement,QFs intending to make sales to
the Company are also required to enter into a Generator Interconnection Agreement
(“GIA”)pursuant to the Company’s Schedule 72 —Interconnections to Non-Utility
Generation and be designated as a network resource to serve Idaho Power’s system
load.The Company’s obligation to make purchases from a QF is conditioned upon the
consummation of all necessary interconnection arrangements.
It is recommended that the owner initiate its request for interconnection as early in the
planning process as possible,to ensure that necessary interconnection arrangements
proceed in a timely manner on a parallel track with negotiation of the power purchase
agreement.
Because of functional separation requirements mandated by the Federal Energy
Regulatory Commission,interconnection and power purchase agreements are handled
by different functions within the Company.Interconnection agreements (both
transmission and distribution level voltages)are handled by the Company’s power
delivery function.
A.Communications
Initial communications regarding the interconnection process should be directed
to the Company in writing as follows:
Idaho Power Company
ATTN:Load-Serving Operation
1221 West Idaho Street
Boise,Idaho 83702
B.Procedures
The required procedures for QF interconnection to Idaho Power’s system are set
forth in the Company’s Schedule 72 —Interconnections to Non-Utility Generation.
Generally,the interconnection process involves (1)initiating a request for
interconnection,(2)completion of studies to determine the system impacts
associated with the interconnection and the design,cost,and schedules for
constructing any necessary interconnection facilities,and (3)execution of a GIA.
Exhbt No.10
Case No.GNR-E-1 1-03
M.Stokes,ic
Page 5 of 6
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No.Gregory W.Said,Vice President,Regulatory Affairs
Effective —1221 West Idaho Street,Boise,Idaho
Idaho Power Company
I.P.U.C.No.29,Tariff No.101 Original Sheet No.73-6
SCHEDULE 73
ENERGY SALES AGREEMENT PROCEDURES
FOR QUALIFYING FACILITIES
(Continued)
Ill.PROCESS FOR FILING A COMPLAINT WITH THE COMMISSION ON CONTRACT
TERMS
Before filing a complaint with the Idaho Public Utilities Commission on any specific
power purchase agreement term not agreed upon between the counterparty and the
Company,a counterperty must wait 60 calendar days from the date it notifies the
Company in writing that it cannot reach agreement on a specific term.This includes but
is not limited to any disputes that are not resolved through the procedures set forth in
Part I.B.6.
Exhibit No.10
case No.GNR-E-11-03
M.Stokes,c
Page 6 of 6
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No.Gregory W.Said,Vice President,Regulatory Affairs
Effective —1221 West Idaho Street,Boise,Idaho
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.GNR-E-11-03
IbAHO POWER COMPANY
STOKES,REB
TESTIMONY
EXHIBIT NO.11
‘ROCKY
MOUNTAIN
POWER
A DIVISION OF PACIFICORP
I.P.U.C.No.1 Original Sheet No.38.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO.38
STATE OF IDAHO
Avoided Cost Purchases from Non-Standard Qualifying Facilities
Availabillte
Service under this schedule is available tTo owners of Qualifying Facilities (“QF”)in all territory
served by the Company inthroughout the Company’s Service Area within the State of Idaho.
Applicabiljye
To owners of existing or proposed QFs who desire to make sales to the Company at Avoided Cost
Ratesand who:(1)have a dcsi capacity greater than 1,000 lcW and a historic or projected annual
capacity factor of seventy percent or below,or (2)have an average monthly capacity and associated
energy of greater than 10,000 kW and a historic or projected annual capacity factor of greater than
seventy percent.Such owners shall be required to enter into written power purchase and
interconnection agreements with the Company pursuant to the procedures set forth belowin this
Schedule 73.Additional or different requirements may apply to Idaho QFs seeking to make sales to
third-parties or out-of-system QFs seeking to wheel power to Idaho for sale to the Company.
I.Process For Negotiating Power Purchase Agreements
A.Communications
Unless otherwise directed by the Company,all communications to the Company
regarding QF power purchase agreements shall be directed in writing,by mail,as
follows:
Power Comoanv
iviariagur QF ContractsATTN:Cogeneration and Small Power Production
825 NE Multnomah St,Suite 6001221 West Idaho Street
Portland,Oregon 97232Boise,Idaho 83702
Any requirement for written notice in this tariff shall be via mail unless the parties
agree by mutual consent to an alternative form.The Company shall respond to all
such communications in a timely manner as more fully described below.
(Continued)
Submitted Under Case No.GNR-E-ll-03
ISSUED:January 31,2012 Exhibit No.11EFFECTIVE:Case No.GNR-E-1 1-03
M.Stokes,IPC
Page 1 of 9
ROCKY MOUNTAIN
POWER
A DIVISION Of PACIFICOAP
I.P.U.C.No.1 Original Sheet No.38.2
ELECTRIC SERVICE SCHEDULE NO.38-Continued
A.Communications (continued)
If the Company is unable to respond on the basis of incomplete or missing information from
the QF owner,the Company shall indicate what additional information is required.
Thereafier,the Company shall respond in a timely manner following receipt of all required
information as more fully described below.
B.Procedures
1.Examples of the Company’s typical generic power purchase agreement may be
obtained from the Company’s website at
www.pacificorp.comwww.idahopower.com,or if the owner is unable to obtain it
from the website,the Company shall send a copy via mail within seven calendar
days of a written request directed to the address in Part I.A.
2.To obtain an indicative pricing proposal with respect to a proposed Project,the
owner shall provide in writing to the Company,general project information
reasonably required for the development of indicative pricing.A Project is defined
as an existing or proposed QF that desires to make sales to the Company and that
can satisfy the requirements of Schedule 38.General project information shall
include,but not be limited to:
a)Project name and contact information;
ageneration technology and other related technology applicable to the site;
i)cdesign capacity (MW),station service requirements,and net amount of power
to be delivered to the Company’s electric system;
e)çquantity and timing of monthly hourly power deliveries (including Project
ability to respond to dispatch orders from the Companyestimated hourly
generation data for every hour of a one-year period).Upon request,the
Company will supply an electronic spreadsheet that can be used by the OF for
this purpose;
&proposed site location and electrical interconnection point;
-)f proposed on-line date (date on which deliveries of energy will commence)and
outstanding permitting requirements;
)gdemonstration of ability to obtain QF status;
fuel type(s)and source(s);
h)plans for fuel and transportation agreements,including plans for what party or
parties will pay transmission costs;
Submitted Under Case No.GNR-E-l 1-03
Exhibit No.11
ISSUED:January 31,2012 EFFECTIVE:case No.GNR-E-11-03
M.Stokes,IPC
Page 2 of 9
‘ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICOHP
I.P.U.C.No.1 Original Sheet No.38.2
i)proposed contract term and pricing proviionc (i.e.,fixed,eca1ating,indexed);
and,
j)status of interconnection arrangements.
(Continued)
Submitted Under Case No.GNR-E-11-03
ExhbitNo.11ISSUED:January 31,2012 EFFECTIVE:case No.GNR-E-11-03
M.Stokes,IPC
Page 3 of 9
ROCKY MOUNTAIN
IPOWER
A DIVISION OF PACIFICORP
I.P.U.C.No.1 Original Sheet No.38.3
ELECTRIC SERVICE SCHEDULE NO.38-Continued
B.Procedures (continued)
3.The Company shall not be obligated to provide an indicative pricing proposal until
all information described in Paragraph 2 has been received in writing from the QF
owner.Within 30 calendar days following receipt of all information required in
Paragraph 2,the Company shall provide the owner with an indicative pricing
proposal,which may include other indicative terms and conditions,tailored to the
individual characteristics of the proposed Project.Such proposal may be used by
the owner to make determinations regarding Project planning,financing and
feasibility.However,such prices are merely indicative and are not final and
binding.Prices and other terms and conditions are only final and binding to the
extent contained in a power purchase agreement executed by both parties and
accepted for filingapproved by the Idaho Public Utilities Commission.Upon
request,the Company shall provide with the indicative prices a description of the
methodology used to develop the prices.
4.If the owner desires to proceed with the Project after reviewing the Company’s
indicative proposal,it shall request in writing that the Company prepare a draft
power purchase agreement to serve as the basis for negotiations between the parties.
In connection with such request,the owner shall provide the Company with any
additional Project information that the Company reasonably determines to be
necessary for the preparation of a draft power purchase agreement,which may
include,but shall not be limited to:
a)updated information of the categories described in Paragraph B.2;
b)evidence of adequate control ofproposed site;
c)identification of,and timelines for obtaining any necessary governmental
permits,approvals or authorizations;
d)assurance of fuel supply or motive force;
e)anticipated timelines for completion ofkey Project milestones;and,
f)evidence that any necessary interconnection studies have been completed and
assurance that the necessary interconnection arrangements are being made in
accordance with Part II.
(Continued)
Submitted Under Case No.GNR-E-l1-03
Exhibit No.11
ISSUED:January 31,2012 EFFECTIVE:Case No.GNR-E-11-03
M.Stokes,IPC
Page 4 of 9
ROCKY MOUNTAIN
POWER
A DIVSIOF OF PACFICORP
I.P.U.C.No.1 Original Sheet No.38.4
ELECTRIC SERVICE SCHEDULE NO.38-Continued
B.Procedures (continued)
5.The Company shall not be obligated to provide the owner with a draft power
purchase agreement until all information required pursuant to Paragraph 4 has been
received by the Company in writing.Within 45 calendar days following receipt of
all information required pursuant to Paragraph 4,the Company shall provide the
owner with a draft power purchase agreement containing a comprehensive set of
proposed terms and conditions,including a specific pricing proposal for purchases
from the Project.Such draft shall serve as the basis for subsequent negotiations
between the parties and,unless clearly indicated,shall not be construed as a binding
proposal by the Company.
6.After reviewing the draft power purchase agreement,the owner shall prepare an
initial set of written comments and proposals regarding the draft power purchase
agreement and shall provide such comments and proposals,or notice that it has
none,to the Company.The Company shall not be obligated to commence
negotiations with a QF owner until the Company has received an initial set of
written comments and proposals from the QF owner.Following the Company’s
receipt of such comments and proposals,the owner shall contact the Company to
schedule contract negotiations at such times and places as are mutually agreeable to
the parties.In connection with such negotiations,the Company:
a)shall not unreasonably delay negotiations and shall respond in good
faith to any additions,deletions or modifications to the draft power
purchase agreement that are proposed by the owner;
b)may request to visit the site of the proposed Project if such a visit has
not previously occurred;
c)shall update its pricing proposals at appropriate intervals to
accommodate any changes to the Company’s avoided-cost calculations,
the proposed Project or proposed terms of the draft power purchase
agreement;
d)may request any additional information from the owner necessary to
finalize the terms of the power purchase agreement and satisfy the
Company’s due diligence with respect to the Project;and,
e)shall resolve disputes related to power purchase agreement terms
consistent with Part III of this tariff.
(Continued)
Submitted Under Case No.GNR-E-l 1-03
Exhibit No.11ISSUED:January 31,2012 EFFECTIVE:Case No.GNR-E-11-03
M.Stokes,PC
Page 5 of 9
ROCKY MOUNTAIN
POWER
A DIVISION OF PACIFICORP
I.P.U.C.No.1 Original Sheet No.38.5
ELECTRIC SERVICE SCHEDULE NO.38-Continued
B.Procedures (continued)
7.When both parties are in full agreement as to all terms and conditions of the draft
power purchase agreement,the Company shall prepare and forward to the owner
within 45 calendar days a final,executable version of the agreement.The Company
reserves the right to condition execution of the power purchase agreement upon
simultaneous execution of an interconnection agreement between the owner and the
Company’s power delivery function,as discussed in Part II.Prices and other terms
and conditions in the power purchase agreement shall not be final and binding until
the power purchase agreement has been executed by both parties and the Idaho
Public Utilities Commission accepts approves the agreement for filing.
II.Process for Negotiating Interconnection Agreements
In addition to negotiating a power purchase agreement,QFs intending to make sales to the
Company are also required to enter into an Generator linterconnection ngreement (“GIA”)
pursuant to the Company’s Schedule 72 —Interconnections to Non-Utility Generation and
be designated as a network resource to serve Idaho Power’s system load that governs the
physical interconnection of the Project to the Company’s transmission or distribution
system.The Company’s obligation to make purchases from a QF is conditioned upon the
consummation of all necessary interconnection arrangements.
It is recommended that the owner initiate its request for interconnection as early in the
planning process as possible,to ensure that necessary interconnection arrangements proceed
in a timely manner on a parallel track with negotiation of the power purchase agreement.
Because of functional separation requirements mandated by the Federal Energy Regulatory
Commission,interconnection and power purchase agreements are handled by different
functions within the Company.Interconnection agreements (both transmission and
distribution level voltages)are handled by the Company’s power delivery function.
(Continued)
Submitted Under Case No.GNR-E-l 1-03
Exhibit No.11
ISSUED:January 31,2012 EFFECTIVE:Case No.GNR-E-11-03
M.Stokes,PC
Page 6 of 9
‘rROCKY MOUNTAIN
tPOWER
A DIVISION OF FACIFICORF
I.P.U.C.No.1 Original Sheet No.38.6
ELECTRIC SERVICE SCHEDULE NO.38-Continued
II.A.Communications
Initial communications regardingilic interconnection agreements process should be
directed to the Company in writing as follows:
PacifiCorp Transmissionldaho Power Company
Transmission Account ManagemcntATTh:Load-Seng Operation
825 NE Multnomah St,Suite 16001221 West Idaho Street
Portland,Oregon 97232Boise,Idaho 83702
Bascd on the Project size and other characteristics,the Company shall direct the QF
owner to the appropriate individual within the Company’s power delivery function
responsible for negotiating the interconnection agreement with the QF owner.
Thereafter,the QF owner should dircct all communications regarding
interconnection agreements to the designated individual,with a copy of any written
communications to the address set forth above.
B.Procedures
The required procedures for OF interconnection to Idaho Power’s system are set
forth in the Company’s Schedule 72 —Interconnections to Non-Utility Generation.
Generally,the interconnection process involves (I)initiating a request for
interconnection,(2)completion of studies to determine the system impacts
associated with the interconnection and the design,cost,and schedules for
constructing any necessary interconnection facilities,and(3)execution of anGIA
Interconnection Facilities Agreement to address facility construction,testing and
acceptance,and (‘1)execution of an Interconnection Operation and Maintenance
Agreement to address ownership and operation and maintenance issues.
For interconnections impacting the Company’s Transmission System,the Company
shall process the interconnection application touh PacifiCo Transmission
Services following the procedures for studying the generation interconnection
described in the latest version of the Company’s Open Acce55 Transmission Tariff,
PacifiCorp FERC Electric Tariff,\Tolume No.11 Pro Forma Open Access
Transmission Tariff (OATT)on file with the Fedemi Energy Regulatory
Commission.A copy of the OATT is available on line at:
nannwww.uwu’.paciucOrp.com
Submitted Under Case No.GNR-E-l 1-03
Exhibit No.11ISSUED:January 31,2012 EFFECTIVE:case No.GNR-E-11-03
M.Stokes,PC
Page 7 of 9
‘V ROCKY MOUNTAIN
POWER
A DIVISION OF FACIFICORF
I.P.U.C.No.1 Original Sheet No.38.6
For interconnections impacting the Company’s Distribution System only,the
Company will process the interconnection application through the Manager QF
Contracts at the address shown in Part I.A.
(Continued)
Submitted Under Case No.GNR-E-ll-03
Exhibit No.11
ISSUED:January31,2012 EFFECTIVEta5e No.GNR-E-11-03
M.Stokes,IPC
Page 8 of 9
ROCKY MOUNTAIN
POWER
A DIV SION OF PACIFICORP
I.P.U.C.No.1 Original Sheet No.38.7
ELECTRIC SERVICE SCHEDULE NO.38-Continued
III.Process for Filing a Complaint with the Commission on Contract Terms
Before filing a complaint with the Idaho Public Utilities Commission on any specific power
purchase agreement term not agreed upon between the counterparty and the Company,a
counterparty must wait 60 calendar days from the date it notifies the Company in writing
that it cannot reach agreement on a specific term.This includes but is not limited to any
disputes that are not resolved through the procedures set forth in Part I.B.6.
Submitted Under Case No.GNR-E-l 1-03
ISSUED:January 31,2012 EFFECTIVE:0jJlj
1-03
M.Stokes,PC
Page 9 of 9
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 29th day of June 2012 I served a true and
correct copy of the REBUTTAL TESTIMONY OF M.MARK STOKES upon the following
named parties by the method indicated below:
Commission Staff
____Hand
Delivered
Donald L.Howell,II
____U.S.
Mail
Kristine A.Sasser
____Overnight
Mail
Deputy Attorneys General
____FAX
Idaho Public Utilities Commission X Email [e-mail]
472 West Washington (83702)kris.sasserpuc.idaho.qov
P.O.Box 83720
Boise,Idaho 83720-0074
Avista Corporation
____Hand
Delivered
Michael G.Andrea
____U.S.
Mail
Avista Corporation
____Overnight
Mail
1411 East Mission Avenue,MSC-23
____FAX
P.O.Box 3727 X Email michael.andrea(davistacorp.com
Spokane,Washington 99220-3727
PacifiCorp dibla Rocky Mountain Power
____Hand
Delivered
Daniel E.Solander
____U.S.
Mail
PacifiCorp d/b/a Rocky Mountain Power
____Overnight
Mail
201 South Main Street,Suite 2300
____FAX
Salt Lake City,Utah 84111 X Email daniel.solanderpacificorp.com
Exergy Development,Grand View Solar II,
____Hand
Delivered
JR.Simplot,Northwest and Intermountain
____U.S.
Mail
Power Producers Coalition,Board of
____Overnight
Mail
Commissioners of Adams County,Idaho,
____FAX
and Clearwater Paper Corporation X Email peterrichardsonandoleary.com
Peter J.Richardson [e-mail]
Gregory M.Adams
RICHARDSON &O’LEARY,PLLC
515 North 27th Street (83702)
P.O.Box 7218
Boise,Idaho 83707
Exergy Development Group of Idaho,LLC
____Hand
Delivered
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 jcarkuliscexercwdeveIopment.com
CERTIFICATE OF SERVICE -1
Dr.Don Reading
____Hand
Delivered
Ben Johnson Associates,Inc.
____U.S.
Mail
6070 Hill Road
____Overnight
Mail
Boise,Idaho 83703
____FAX
X Email dr(benjohnsonassociates.com
Grand View Solar II
____Hand
Delivered
Robert A.Paul
____U.S.
Mail
Grand View Solar II
____Overnight
Mail
15690 Vista Circle
____FAX
Desert Hot Springs,California 92241 X Email robertapaul08(gmail.com
JR.Simplot Company
____Hand
Delivered
Don Sturtevant,Energy Director
____U.S.
Mail
J.R.Simplot Company
____Overnight
Mail
One Capital Center
____FAX
999 Main Street X Email don.sturtevantsimpIot.com
P.O.Box 27
Boise,Idaho 83707-0027
Northwest and Intermountain Power
____Hand
Delivered
Producers Coalition
____U.S.
Mail
Robert D.Kahn,Executive Director
____Overnight
Mail
Northwest and Intermountain Power
____FAX
Producers Coalition X Email rkahp©nJppçog
1117 Minor Avenue,Suite 300
Seattle,Washington 98101
Board of Commissioners of Adams
____Hand
Delivered
County,Idaho
____U.S.
Mail
Bill Brown,Chair
____Overnight
Mail
Board of Commissioners of
____FAX
Adams County,Idaho X Email bdbrown(dfrontiernet.net
P.O.Box 48
Council,Idaho 83612
Clearwater Paper Corporation
____Hand
Delivered
Man,Lewallen
____U.S.
Mail
Clearwater Paper Corporation
____Overnight
Mail
601 West Riverside Avenue,Suite 1100
____FAX
Spokane,Washington 99201 X Email rnalewallencclearwaterpaper.com
Renewable Energy Coalition and Dynamis
____Hand
Delivered
Energy,LLC
____U.S.
Mail
Ronald L.Williams
____Overnight
Mail
WILLIAMS BRADBURY,P.C.
___FAX
1015 West Hays Street X Email [e-mail]
Boise,Idaho 83702
CERTIFICATE OF SERVICE -2
Renewable Energy Coalition
____Hand
Delivered
John R.Lowe,Consultant
____U.S.
Mail
Renewable Energy Coalition
____Overnight
Mail
12050 SW Tremont Street
____FAX
Portland,Oregon 97225 X Email iravenesanmarcos(yahoo.com
Dynamis Energy,LLC
____Hand
Delivered
Wade Thomas,General Counsel
____U.S.
Mail
Dynamis Energy,LLC
____Overnight
Mail
776 East Riverside Drive,Suite 150
____FAX
Eagle,Idaho 83616 X Email wthomas(dynamisenergy.com
Interconnect Solar Development,LLC
____Hand
Delivered
R.Greg Ferney
____U.S.
Mail
MIMURA LAW OFFICES,PLLC
____Overnight
Mail
2176 East Franklin Road,Suite 120
____FAX
Meridian,Idaho 83642 X Email qreq(mimuralaw.com
Bill Piske,Manager
____Hand
Delivered
Interconnect Solar Development,LLC
____U.S.
Mail
1303 East Carter
____Overnight
Mail
Boise,Idaho 83706
____FAX
X Email billpiskeccableone.net
Renewable Northwest Project,Idaho
____Hand
Delivered
Windfarms,LLC,and Ridgeline Energy LLC
____U.S.
Mail
Dean J.Miller
____Overnight
Mail
Chas.F.McDevitt
____FAX
McDEVITT &MILLER LLP X Email jpmcdevitt-miller.corn
420 West Bannock Street (83702)cha©pcdevitt-mHler.com
P.O.Box 2564
Boise,Idaho 83701
Megan Walseth Decker
____
Hand Delivered
Senior Staff Counsel
____
U.S.Mail
Renewable Northwest Project
____
Overnight Mail
421 SW6thAvenue,Suite 1125
___
FAX
Portland,Oregon 97204 X Email megarnpq
Idaho Windfarms,LLC
____Hand
Delivered
Glenn Ikemoto
____U.S.
Mail
Margaret Rueger Overnight Mail
Idaho Windfarms,LLC FAX
672 Blair Avenue X Email glennvionwcLcorn
Piedmont,California 94611 rnargaret©nvisionwind .com
CERTIFICATE OF SERVICE -3
Twin Falls Canal Company and
Canal Company
C.Thomas Arkoosh
CAPITOL LAW GROUP,PLLC
205 North 10th Street,4th Floor
P.O.Box 2598
Boise,Idaho 83701-2598
North Side
____Hand
Delivered
___U.S.
Mail
____Overnight
Mail
___FAX
X Email tarkooshcapitoIIawqroup.com
ELECTRONIC SERWCE ONLY
Lori Thomas
CAPITOL LAW GROUP,PLLC
205 North 10th Street,4th Floor
P.O.Box 2598
Boise,Idaho 83701-2598
____Hand
Delivered
___U.S.
Mail
____Overnight
Mail
___FAX
X Email lthomascapitollawqroup.com
ELECTRONIC SERWCE ONLY
Donald W.Schoenbeck
RCS,Inc.
900 Washington Street,Suite 780
Vancouver,Washington 98660
____Hand
Delivered
___U.S.
Mail
____Overnight
Mail
___FAX
X Email [e-mail]
ELECTRONIC SERWCE ONLY
Twin Falls Canal Company
Brian Olmstead,General Manager
Twin Falls Canal Company
P.O.Box 326
Twin Falls,Idaho 83303
ELECTRONIC SERWCE ONLY
North Side Canal Company
Ted Diehl,General Manager
North Side Canal Company
921 North Lincoln Street
Jerome,Idaho 83338
Birch Power Company
Ted S.Sorenson,P.E.
Birch Power Company
5203 South 11th East
Idaho Falls,Idaho 83404
____Hand
Delivered
___U.S.
Mail
____Overnight
Mail
___FAX
X Email olrnstead(dffcanal.com
____Hand
Delivered
___U.S.
Mail
____Overnight
Mail
___FAX
X Email [e-mail]
____Hand
Delivered
___U.S.
Mail
____Overnight
Mail
___FAX
X Email tetsorensorL net
Blue Ribbon Energy LLC
M.J.Humphries
Blue Ribbon Energy LLC
3470 Rich Lane
Ammon,Idaho 83406-7728
____Hand
Delivered
____U.S.
Mail
____Overnight
Mail
___FAX
X Email blueribbonenerqy(gmail.com
CERTIFICATE OF SERVICE -4
Arron F.Jepson
____Hand
Delivered
Blue Ribbon Energy LLC
____U.S.
Mail
10660 South 540 East
____Overnight
Mail
Sandy,Utah 84070
____FAX
X Email arronesg(ãaol.com
Idaho Conservation League
____Hand
Delivered
Benjamin J.Otto
____U.S.
Mail
Idaho Conservation League
____Overnight
Mail
710 North Sixth Street (83702)
____FAX
P.O.Box 844 X Email botto2idahoconservation.org
Boise,Idaho 83701
Snake River Alliance
____Hand
Delivered
Liz Woodruff,Executive Director
____
U.S.Mail
Ken Miller,Clean Energy Program Director
____Overnight
Mail
Snake River Alliance
____FAX
350 North 9th Street #B61 0 X Email lwoodruffsnakeriveralIiance.orq
P.O.Box 1731 kmiIlersnakeriveralliance.orq
Boise,Idaho 83701
Energy Integrity Project
____Hand
Delivered
Tauna Christensen
____U.S.
Mail
Energy Integrity Project
____Overnight
Mail
769 North 1100 East
____FAX
Shelley,Idaho 83274 X Email taunacenerqyinteqrityproiect.orq
Idaho Wind Partners I,LLC
____Hand
Delivered
Deborah E.Nelson
____
U.S.Mail
Kelsey J.Nunez
____Overnight
Mail
GIVENS PURSLEY LLP
___FAX
601 West Bannock Street X Email [e-mail]
P.O.Box 2720 kjn©givenspursley.com
Boise,Idaho 83701-2720
Christa Bearry,Legal Assistant (J
CERTIFICATE OF SERVICE -5