20141010final_order_no_33150.pdf

Office of the Secretary
Service Date
October 10,2014
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY’S APPLICATION TO UPDATE )CASE NO.IPC-E-13-22
ITS WIND INTEGRATION RATES AND )
CHARGES.)ORDER NO.33150
________________________________________________________________________________________
)
On November 29,2013,Idaho Power Company filed an Application with the
Commission seeking to update its wind integration rates and charges.The case was processed by
Modified Procedure through the use of comments and reply.By this Order,the Commission
approves updated wind integration rates and charges as more fully set out below.
BACKGROUND
Idaho Power reports rapid growth in wind generation over the past several years.
Idaho Power maintains that it currently manages a total of 678 megawatts (MW)of wind
generation capacity on its system —577 MW of capacity are provided by Public Utility
Regulatory Policies Act (PURPA)projects and an additional 101 MW of wind generation
capacity is provided by a non-PURPA project (Elkhorn Valley Wind Farm).Idaho Power states
that 505 MW of its total wind generation capacity has been added to the Company’s system
during 2010,2011 and 2012.
Idaho Power’s Application maintains that due to the variable and intermittent nature
of wind generation the Company must modify its system operations to successfully integrate
wind projects without impacting system reliability.Idaho Power explains that it must provide
operating reserves from resources that are capable of increasing or decreasing dispatchable
generation on short notice to offset changes in non-dispatchable wind generation.The effect of
having to hold operating reserves on dispatchable resources is that the use of those resources is
restricted and they cannot be economically dispatched to their fullest capability.Idaho Power
states that this results in higher power supply costs that are subsequently passed on to customers.
Idaho Power asserts that its capability to integrate wind generation is nearing its limit.
The Company maintains that,even at the current level of wind generation capacity penetration,
dispatchable thermal and hydro generators are not always capable of providing the balancing
reserves necessary to integrate wind generation.Idaho Power states that this situation is
ORDER NO.33150 1
expected to worsen as wind penetration levels increase,particularly during periods of low
customer demand.
Idaho Power maintains that the costs associated with wind integration are specific and
unique for each individual electrical system based on the amount of wind being integrated and
the other types of resources that are used to provide the necessary operating reserves.The
Company explains that,in general terms,the cost of integrating wind generation increases as the
amount of nameplate wind generation on the electrical system increases.Idaho Power asserts
that the costs associated with wind integration are currently under-collected.
Wind integration costs are assessed on a percentage basis of various avoided cost
rates.The Company states that the use of a percentage of avoided cost rates really has no
relation to actual costs of the additional reserves necessary to integrate variable and intermittent
resources on the system.Idaho Power further maintains that setting the amount of wind
integration charge for the entire duration of the power sales agreement assures further under-
collection of integration costs as those costs rise.The under-collection from existing wind QFs
results in an additional allocation to new wind QFs.
The Company’s Application discusses three separate methods by which wind
integration costs could be accounted for in avoided cost rates.
1)Maintaining current allocation;
2)Current allocation with an integration tariff;and
3)Equitable allocation of costs.
The Company’s Application proposes two overall changes,which have been incorporated into
each of the three methods offered above,to address the collection of wind integration costs.
Change one abandons the use of percentage of avoided cost rate allocation and instead allocates
a fixed amount based upon penetration level.Change two decouples the wind integration charge
from the avoided cost rate contained in the power sales agreement and instead has wind
integration costs assessed as a stand-alone tariff charge.
PROCEDURAL HISTORY
A Notice of Application was issued on December 31,2013,allowing 21 days for
intervention.Idaho Winds,LLC;Snake River Alliance;Cold Springs Windfarm,LLC;Desert
Meadow Windfarm,LLC;Hammett Hill Windfarm,LLC;Mainline Windfarm,LLC;Ryegrass
Windfarm,LLC;Two Ponds Windfarm,LLC;Renewable Northwest Project;America Wind
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Energy Association;Cassia Windfarm,LLC;Hot Springs Windfarm,LLC;Bennett Creek
Windfarm,LLC;Cassia Gulch Wind Park,LLC;Tuana Springs Energy,LLC;High Mesa
Energy,LLC;Rockland Wind Farm,LLC;Idaho Wind Partners I,LLC;and Meadow Creek
Project Company,LLC,petitioned for,and were granted,intervention.A Notice of Parties was
issued on January 31,2014.
Twelve intervenors’(all qualifying facilities “QFs”)represented by the firm of
Richardson Adams filed a Motion to Dismiss on January 31,2014 (hereafter,“Petitioners”).
Petitioners argued that federal preemption principles should apply that would prohibit the
Commission from considering the Application of Idaho Power.On February 7,2014,pursuant
to Rule of Procedure 256.04,the remaining Intervenors2 filed motions in response to the Motion
to Dismiss.Idaho Power filed an Answer to the Motion to Dismiss and additional motions on
February 21,2014.The Petitioners filed a Reply to Idaho Power’s Answer on February 28,
2014.
The Commission issued Order No.33030 on April 30,2014,denying Petitioners’
Motion to Dismiss.The Commission stated that “[aj Commission proceeding commenced to
consider a request by a utility to update its wind integration rates and charges does not conflict
with federal statutes.”Order No.33030 at 7.However,we clarified that “any Commission
approved modifications to Idaho Power’s wind integration rates and charges will apply only
prospectively —to new contracts as they are entered into by the parties and submitted to the
Commission for approval.”Id.at 8.
The Commission allowed parties 14 days to withdraw as intervenors if any party
believed that,based on its ruling in Order No.33030,the intervenor no longer had a direct and
substantial interest in the underlying proceeding.Several parties withdrew from the case.An
Amended Notice of Parties was issued on May 20,2014.Thereafter,the parties proposed,and
the Commission adopted a procedural schedule that included an opportunity for settlement
discussions.Order No.33054.
Cold Springs Windfarm,LLC;Desert Meadow Windfarm,LLC;Hammett Hill Windfarm,LLC;Mainline
Windfarm,LLC;Ryegrass Windfarm,LLC;Two Ponds Windfarm.LLC;Cassia Wind Farm,LLC;Hot Springs
Windfarm,LLC;Bennett Creek Windfarm,LLC;Cassia Gulch Wind Park,LLC;Tuana Springs Energy,LLC;and
High Mesa Energy,LLC.
2 American Wind Energy Association;Idaho Wind Partners I,LLC;Idaho Winds,LLC;Renewable Northwest
Project;Rockland Wind Farms,LLC;Snake River Alliance;and Meadow Creek Project Company,LLC.
ORDER NO.33150 3
Although the parties were unable to resolve their differing positions during settlement
negotiations,the parties requested additional time for discovery and comment in order to develop
a more thorough record.The Commission approved the amended schedule which allowed for
supplementary comments and supplementary reply.Order No.33075.
COMMENTS
Commission Staff
Based upon the results of Idaho Power’s 2013 updated wind integration study,Staff
believes that the costs currently being assessed for wind integration no longer represent the
actual costs to integrate wind and should be revised.Staff explained that the current method of
computing wind integration costs as a percentage of avoided costs,and the $6.50 per MWh cap,
were outcomes of negotiation and compromise in a settlement process.The current integration
costs and the method under which they are applied were never expected to be a precise
quantification of the costs,but instead were intended to represent a reasonable approximation of
costs that are somewhat difficult to determine.Consequently,Staff supports establishing wind
integration charges at specific dollar figures that increase with wind penetration level.
Staff stated that integration costs will invariably change over time as a variety of
other changes occur.Integration costs will likely increase as more intermittent resources are
added to the utility’s system,as fuel costs increase,and as electric market prices increase.On
the other hand,downward pressure on integration costs will occur as forecasting improves,as
shorter real-time markets develop (e.g.,intra-hour trading,15-minute scheduling,5-minute
dispatch),as energy imbalance markets develop,and as new technologies evolve,including
energy storage.Staff admitted that not only is it difficult to accurately determine integration
costs now,but it is even more difficult to predict what those costs may be over the duration of a
20-year PURPA contract.
Idaho Power’s first proposed method to implement integration charges maintains the
existing structure but only updates the rates and penetration levels.Under this method the
Company proposes that the integration charges be set based on the assumption that all
incremental integration costs be recovered from new wind projects.Staff supports this proposal
because it maintains the use of three tiers and specifies costs within each tier rather than
percentages of avoided cost rates.The primary advantage to this proposal is that it would
provide certainty to wind project developers because integration charges would remain fixed
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throughout the duration of the contract.The primary disadvantage to this approach,however,is
that new projects would bear an increasingly larger share of integration costs because as
intermittent energy is added to the utility’s system,without the aid of new technology and/or
storage options,the costs to integrate wind sharply increase.However,Staff believes that
applying an increasing burden for each wind project that comes online is reasonable because the
intermittent energy produced creates an increasing burden for the utility.Staff believes that new
projects should be responsible for the full incremental cost of integration.
The second alternative method proposed by Idaho Power—Current Allocation with
Integration Tariff—is a slight modification to the first method.Under this method,rather than
embedding the integration charges as part of the avoided cost prices in the contract rates,as is
currently done,the Company would implement a new integration charge tariff which would
identify the integration charges at the respective levels,separately from the power sales
agreement.Under this method,the current deduction of $6.50/MWh would be used until total
nameplate wind generation reached 700 MW.Once 700 MW is reached,the wind integration
charge would be increased to $6.89/MWh.Subsequent increases would occur as each
incremental 100 MW of wind generation is added.Staff believes that the primary benefit to a
tariff-based integration charge is that it would allow integration charges to be changed over time
as the costs of integration change.However,making integration charges subject to change over
the course of a long-term contract,while it may more accurately reflect actual integration
charges,presents uncertainty that Staff believes QFs would find unacceptable.
The third method proposed by Idaho Power —Equitable Allocation of Costs—would
spread the integration costs equitably across all PURPA wind generators.In this way,all wind
generators would be sharing equitably in the current costs of integrating wind onto the
Company’s system.Staff believes that the Commission’s decision in Order No.33030 would
preclude this method from being adopted.
Renewable Northwest and American Wind Energy Association
Renewable Northwest and American Wind Energy Association (AWEA)(collectively
“Intervenors”)filed joint comments.The Intervenors’comments focus on what they describe as
“fundamental flaws”in Idaho Power’s 2013 wind integration study.Comments at 3.“The
primary shortcomings of the 2013 study are that it does not accurately portray Idaho Power’s
actual operating procedures or best practices by (1)using the day-ahead wind forecast error
ORDERNO.33150 5
instead of the hour-ahead forecast error in calculating the reserve requirement for wind;and (2)
calculating reserve requirements based on the outdated assumption that reserves accommodate
wind variability on a stand-alone basis,when in reality,grid operators balance the deviations of
net load (load minus wind and other generation).”Id.The Intervenors contend that Idaho
Power’s methodological errors result in an incremental reserve requirement that is three times
greater than what is actually necessary.
The Intervenors noted that Idaho Power’s 2007 wind study relied on hour-ahead
forecast errors and netted the variability of load,wind and conventional generation.Renewable
Northwest and AWEA oppose the use of day-ahead forecasting in the 2013 study.The
Intervenors describe hour-ahead wind forecasts as “inherently more accurate”than day-ahead
forecasts.Id.at 5.“Indeed,it is a well-established scientific fact that wind energy forecast error
is greatly reduced as one moves closer to real-time,as one would expect for any forecast.”Id.
The Intervenors maintained that the effect of using day-ahead forecasts “is to greatly inflate the
amount and cost of balancing reserves needed to integrate wind.”Id.at 7.
Renewable Northwest and AWEA agree that Idaho Power must set up its system a
day ahead to be able to provide sufficient balancing reserves to manage the hourly forecasting
error from wind and load,“but that is not the same thing as needing to determine the hour-by-
hour wind schedules a day in advance of real time and hold reserves based on that larger forecast
error.”Id.at 10.The Intervenors contended that unit commitment decisions based on day-ahead
forecasts do not equate to a requirement to hold a fixed amount of balancing reserves based on
the day-ahead forecast.The Intervenors maintained that “the common practice in utility wind
integration studies (and for most Northwest utilities)is to determine the maximum (90th
percentile)amount of hour-ahead balancing reserves needed (based on a 45-,30-,15-,or 10-
minute-ahead persistence forecast)and hold that amount every hour of the year.”Id.Renewable
Northwest and AWEA state that this approach would reduce costs significantly and is consistent
with Idaho Power’s approach in its 2007 wind study.
The Intervenors argued that another primary source of error in Idaho Power’s 2013
wind study is the study’s failure to account for the netting between the forecasting/scheduling
errors of load and wind —especially considering the deviations of other generators.The
Intervenors go so far as to state that “all wind integration studies that reflect best practices in the
field calculate reserves based on net load (load minus wind),as it is widely understood that
ORDERNO.33150 6
calculating reserves for wind alone results in an incorrect answer.”Id.at 13.Renewable
Northwest and AWEA also maintained FERC has stated that a failure to account for net load
results in an incorrect calculation of total reserve needs.
Finally,the Intervenors state that wind integration costs are largely caused by
obsolete grid operating practices.They argue that regions with efficient grid operating practices
see much smaller integration costs.“Wind integration rates and charges should be going down
to reflect the efficiency improvements resulting from [Idaho Power’sl forecasting tool and other
operation tools available to the Company.”Id.at 18.“Because integration costs are largely
caused by outdated grid operating practices,it is unreasonable to allocate these costs to wind
generators.”Id.at 17.
The Intervenors advocate use of the 2007 wind study for guidance in this case
because of the “methodological errors”in Idaho Power’s 2013 study.Renewable Northwest and
AWEA believe that $5.30/MWh is a reasonable integration cost for Idaho Power and is
consistent with what other transmission providers in the region have calculated.Id.at 19.At a
minimum,the Intervenors encourage the Commission to refrain from approving Idaho Power’s
proposed wind integration rates and charges until the Company revises its 2013 wind study.
Idaho Power Reply
On reply,Idaho Power proposed a new tariff —Schedule 87,Intermittent Generation
Integration Charges.The charges set forth in Schedule 87 are the amounts to be deducted from
avoided cost rates each year,beginning in the year the project comes on-line and based on the
nameplate capacity of installed wind generation at the scheduled operation date of the proposed
new project.Each penetration level (for each 100 MW increment of wind penetration)has its
own table clearly identified and set forth in Schedule 87 and discloses both the levelized
integration charge as well as the non-levelized stream of integration charge amounts listed by
year.As with published avoided cost rates,the scheduled operation date for the proposed
generation project is used as the starting point in the table and each yearly amount through the
term of the proposed contract is set out.Idaho Power explained that these amounts would be
included in the PURPA energy sales agreement for a new project and would remain as set forth
in that agreement for the entire term.The cost of wind integration increases as the penetration
level of wind increases on the system.
ORDER NO.33150 7
In response to the comments of Renewable Northwest and AWEA,Idaho Power
maintained that it is precisely the experience that the Company has gained since the 2007 wind
study “that specifically informed the Company’s conscious decisions to change to the day-ahead
wind forecast and to not net the reserve requirements of load and wind in its 2013 study.”Reply
at 11.Idaho Power pointed out that “AWEA admittedly advocated for general policy
considerations for integration studies on the whole,and from a national perspective.”Id.Idaho
Power argued that the decision about how to conduct a proper wind integration study is not a
one-size-fits-all endeavor that works for every utility across the country.The Company stated
that because its wind is PURPA generation,Idaho Power does not have the operational flexibility
that it might have with non-PURPA wind.“Because the PURPA generation is a designated
network resource to serve load on the Company’s system,and the Company must accept delivery
whenever it is delivered by QF projects,the decisions must be made about the
designation/undesignation of Idaho Power’s other resources in order to keep the system balanced
and reliably serving load.These decisions incur costs.”Id.
Idaho Power explained that it consciously chose to use day-ahead wind forecast data
and to not use net load and wind reserves.The Company stated that this was done primarily
because it is reflective of Idaho Power’s actual operations.“Because of the non-liquidity in
hour-ahead and real-time markets that exist in Idaho Power’s region and to which Idaho Power
has access to,the Company is not able to reliably recover these sunk day-ahead costs as it
balances its system in real time.”Id.at 12.
Idaho Power maintained that Renewable Northwest and AWEA’s objections to the
wind study methodology might be fair criticisms of studies in general and from a nationwide
perspective,but they are without merit as it pertains to the use of day-ahead forecast data and the
netting of reserves for Idaho Power because of the way costs are actually incurred in the
operation of Idaho Power’s system on a day-ahead basis.
SUPPLEMENTARY COMMENTS
Commission Staff
Staff reviewed the calculations performed by Idaho Power to translate the incremental
wind integration charges from the 2013 wind study into the proposed Schedule 87 tariff.In its
computations,the Company assumed a 3 percent inflation rate to convert real into nominal
charges,and applied a discount rate of 6.7 percent to levelize the charges.In response to Staff
ORDER NO.33150 8
production requests,Idaho Power states that both of these rates were chosen because they were
the percentage rates used in the 2013 Integrated Resource Plan.Staff believes that use of a 3
percent inflation rate is reasonable.However,Staff recommended that the Company use a
discount rate consistent with that used for levelizing avoided cost rates computed in the
Surrogate Avoided Resource (SAR)methodology —currently that rate is 8.18 percent.These
rates are comparable to,but slightly lower than those proposed by Idaho Power in its Schedule
87.
Staff supports the tariff-based approach proposed by Idaho Power in its reply
comments.Staff believes that incremental increases in wind integration charges as wind
penetration levels increase is reasonable.Staff further supports the proposal that once integration
charges are set forth in an agreement,the charges remain unchanged for the term of the
agreement.Staff further recommended that Idaho Power be expected to periodically conduct
new wind integration studies as electric markets,technologies and operating practices evolve,
and to update its wind integration charges accordingly as they are contained in any approved
tariffs such as Schedule 87.
Renewable Northwest and American Wind Energy Association
The Intervenors maintain that the majority of costs identified in Idaho Power’s 2013
wind study are not wind integration costs,but rather costs associated with remarketing must-take
PURPA energy when the utility is surplus on energy.As such,Renewable Northwest and
AWEA contend that these costs should be included in the Company’s avoided cost methodology.
“A true ‘wind integration study’would not use the methodologies employed in the Company’s
2013 Study and would instead focus on the within-hour balancing needs of the net load and wind
variability.”Intervenor Supplementary Comments at 2.The Intervenors admit that all power
systems are unique,but they dispute that unique circumstances on a given system would warrant
abandonment of standard statistical analysis and industry standards on wind integration analysis.
They further disagree that the system circumstances described by Idaho Power translate to costs
that are inherently attributable to the costs of integrating wind energy.
The Intervenors argue that the avoided cost methodology already produces an hourly
forecast and an hourly avoided cost value for every MWh of energy integrated into Idaho
Power’s system for the life of the project.Therefore,Renewable Northwest and AWEA contend
that there is no evidence to suggest the AURORA model’s hour-by-hour avoided cost calculation
ORDER NO.33150 9
does not already capture the costs that Idaho Power characterizes as day-ahead forecasting error
costs in the 2013 study.
Idaho Power’s treatment of these day-ahead costs in its 2013 Study
methodology is incorrect from a wind integration perspective,but in the
context of excess must-take PURPA energy,we understand that Idaho Power
may have difficulty remarketing surplus PURPA energy on a day-ahead basis.
If the Company believes the AURORA model does not capture all the costs
associated with excess must-take PURPA energy when the utility is surplus,it
should reexamine and adjust the avoided cost methodology.
Id.at 4.
The Intervenors dispute Idaho Power’s explanation of not netting its load and wind
forecasts.“Idaho Power and other utilities already integrate hundreds of thousands of different
loads on a daily basis,each with unique properties for variability and uncertainty.”Id.at 11.
The Intervenors argue that Idaho Power could easily follow the standard practice employed by
every other utility and use basic statistical techniques to combine sources of variability and
uncertainty that have different normally distributed shapes to determine the optimal reserve
levels.
Finally,the Intervenors expressed concern about application of Idaho Power’s 2013
wind study beyond the PURPA context.Renewable Northwest and AWEA also recommended
that the Commission require regular updates to the Company’s wind integration studies to ensure
that the most current data and methodologies are being used.
Idaho Power Reply
On reply,Idaho Power accepted Staffs recommendation to use a discount rate of 8.8
percent instead of 6.7 percent —consistent with the levelization of published avoided cost rates.
The Company also reiterated its explanation of Renewable Northwest/AWEA’s objections to the
methodologies used in the 2011 wind study.Idaho Power stated that the Intervenors’comments
“not only demonstrate a lack of understanding of Public Utility Regulatory Policies Act of 1978
(PURPA),but also a lack of understanding of what the Company’s request is in this case.”Idaho
Power’s Supplementary Reply at 8.
First,Idaho Power stated that its Application for wind integration charges is limited to
PURPA QF generators.Second,the Company argued that a QF is responsible for paying the
costs caused by its generation because the Company is required to integrate the variable and
intermittent generation that the QF provides.Idaho Power asserted that “[tjhe 2013 Study
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identifies costs associated with the modified operation of Idaho Power’s system because of the
must-take addition of PURPA generation,which is not scheduled,not dispatchable,and is
delivered in any amount at any time and in any quantity that the QF chooses.”Id.at 10.
FINDINGS AND CONCLUSIONS
The Idaho Public Utilities Commission has jurisdiction over Idaho Power,an electric
utility,and the issues raised in this matter pursuant to the authority and power granted it under
Title 61 of the Idaho Code and the Public Utility Regulatory Policies Act of 1978 (PURPA).The
Commission has authority under PURPA and the implementing regulations of the Federal
Energy Regulatory Commission (FERC)to set avoided costs,to order electric utilities to enter
into fixed-term obligations for the purchase of energy from qualified facilities (QFs)and to
implement FERC rules.FERC regulations grant the states latitude in implementing the
regulation of sales and purchases between QFs and electric utilities.See Federal Energy
Regulatory Commission v.Mississippi,456 U.S.742,102 S.Ct.2126,72 L.Ed.2d 532 (1982).
The Commission has reviewed the record in this case,including Idaho Power’s
Application and testimony,initial comments and reply,and supplemental comments and reply
filed by the parties.This Commission has already recognized that “the costs of wind integration
are real,not illusory.A wind integration adjustment recognizes that variable wind generation
presents operational integration costs to a utility that are different from other PURPA qualified
resources.”Order No.30488 at 12.Consequently,it is not a matter of whether a wind
integration charge is appropriate,but rather,what costs reasonably represent Idaho Power’s
additional operational efforts to balance out wind’s intermittent,must-take generation.
Renewable Northwest and AWEA seem to acknowledge that there are additional
costs associated with must-take PURPA wind energy,but the Intervenors resist classifying the
costs as integration costs.We find that if a utility incurs additional operational costs as a result
of having to balance intermittent,must-take PURPA generation,those costs are reasonably
classified as integration costs.This finding is consistent with PURPA and FERC regulations that
require avoided cost rates to be just and reasonable to the utility’s ratepayers.18 C.F.R.§
292.304(a)(1).It is also in accord with this Commission’s position that PURPA transactions
should not harm ratepayers.Order No.32697 at 13.
The Intervenors urge the Commission to disregard the analysis provided by Idaho
Power’s 2013 wind study because (1)it utilizes day-ahead forecasts versus hour-ahead forecasts
ORDERNO.33150 11
and (2)the study does not account for netting of reserves associated with load and wind.
Renewable Northwest and AWEA argue that these methodological errors were not present in the
Company’s 2007 study.Idaho Power admits that the methodology used in the 2013 study differs
from the methodology of the 2007 study based on experience that the Company has gained since
the 2007 study.Idaho Power explained that,at the time the 2007 study was accomplished,the
Company had very little wind on its system.The Company maintains that knowledge gained
over the past seven years about how to successfully integrate wind generation onto its system
specifically led to the changes in methodology.
We find the methodology used in Idaho Power’s 2013 wind study just and reasonable.
Idaho Power makes decisions on a day-ahead basis regarding the designation/undesignation of its
resources.However,despite the Company’s day-ahead forecast,it is bound by a must-purchase
obligation with regard to PURPA generation.To keep its system balanced and reliably serving
load,the Company must make last-minute adjustments in order to accommodate the must-take
PURPA generation.Adjustments are made and costs are incurred as a direct result of having to
integrate the intermittent wind energy.
Indeed,upon approval of the current wind integration charges,the Commission
recognized that “as experience and data increases,the ability to calculate wind integration costs
will improve.”Order No.30488 at 13.We directed Idaho Power to monitor and regularly
review its data and propose adjustments to wind integration rates and charges as warranted.We
find that the changes in methodology between the Company’s 2007 and 2013 wind studies are
consistent with knowledge and experience acquired as Idaho Power learned to successfully
integrate increasing amounts of wind on its system.
We find that the current mechanism for recovery of integration costs has resulted in
under-collection of the actual costs required to integrate wind onto Idaho Power’s system.We
recognize that the previous method for determining integration charges was the result of
compromise and settlement.The Commission accepted and approved a formula to calculate
integration that loosely represented the actual costs of the additional reserves necessary to
integrate a variable and intermittent resource.To be sure,the formula was approved without a
full appreciation for the amount of PURPA wind generation that is currently under contract with
Idaho Power.
ORDER NO.33150 12
We find use of the Company’s proposed tariff schedule fair,just and reasonable.
Schedule 87 charges illustrate the amounts to be deducted from avoided cost rates,beginning in
the year the project comes on-line,based on the nameplate capacity of installed wind generation
at the scheduled operation date of the proposed new project.If the project fails to come on-line
as scheduled,integration charges should be adjusted accordingly.As might be expected,the cost
of wind integration increases as the penetration level of wind on Idaho Power’s system increases.
As part of a tariff schedule,the integration charges can be updated as integration costs
change,as new studies are completed and as technologies improve.Staff recommended,and
Idaho Power accepted,applying a discount rate of 8.18 percent to levelize the integration charges
—as opposed to the 6.7 percent initially proposed by the Company.An 8.18 percent discount
rate is consistent with the discount rate used for levelizing avoided cost rates under the SAR
methodology.Consequently,we approve Idaho Power’s proposed Schedule 87,utilizing a
discount rate of 8.18 percent.We find that utilizing tariffed charges/rates as a decrement to the
published avoided cost rate for wind QFs results in net rates that represent the full avoided cost
of wind generation;rates that are fair,just,reasonable and in the public interest.18 C.F.R.§
292.304.
ORDER
IT IS HEREBY ORDERED that Idaho Power’s Schedule 87 be approved,as more
fully described herein.
THIS IS A FINAL ORDER.Any person interested in this Order may petition for
reconsideration within twenty-one (21)days of the service date of this Order.Within seven (7)
days after any person has petitioned for reconsideration,any other person may cross-petition for
reconsideration.See Idaho Code §6 1-626.
ORDER NO.33150 13
DONE by Order of the Idaho Public Utilities Commission at Boise.Idaho this /Q
day of October 2014
ATTEST:
..
MARSHA H.SMITH,COMMISSIONER
Jean D.Jewell
Commission Secretary
0:IPC-E-I 3-22ks5
[S SION ER
ORDERNO.33150 14