20110909Comments.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BARNO. 6618
RECE! D
2011 SEP -9 PM 4: 18
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR A ) CASE NO. IPC-E-ll-IO
DETERMINATION REGARDING THE FIRM )
ENERGY SALES AGREEMENT WITH ) COMMENTS OF THE
INTERCONNECT SOLAR DEVELOPMENT, ) COMMISSION STAFF
LLC FOR THE SALE AND PURCHASE OF )ELECTRIC ENERGY. )
)
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Kristine A. Sasser, Deputy Attorney General, and in response to the Notices
issued on July 8,2011 (Order No. 32290), and August 30, 2011 (Order No. 32347) Case
No. IPC-E-ll-l 0, submits the following comments.
BACKGROUND
On June 17, 2011, Idaho Power Company (Idaho Power; Company) filed an Application
with the Commission requesting acceptance or rejection of a 25-year Firm Energy Sales
Agreement (Agreement) between Idaho Power and Interconnect Solar Development LLC
(Interconnect Solar) dated June 7, 2011. The Application states that Interconnect Solar would sell
and Idaho Power would purchase electric energy generated by the Interconnect Solar photovoltaic
solar generating facility (Facility) located near Murphy, Idaho. The Application states that
STAFF COMMENTS 1 SEPTEMBER 9, 2011
Interconnect Solar proposes to construct, own, operate and maintain a 20 MW (maximum
capacity, nameplate) photovoltaic solar generating facilty. Application at 2. The Facilty wil be
a Qualifying Facility (Q F) under the applicable provisions of PURP A.
The Agreement is for a term of 25 years and contains avoided cost rates established
pursuant to the Commission's approved Integrated Resource Planning (IRP) avoided cost
methodology as curently required by the Commission for solar QFs with a design capacity of
more than 100 kilowatts (kW). Order No. 32262. Interconnect Solar selected June 1,2012, as its
Scheduled First Energy Date and July 1,2012, as its Scheduled Operation Date. ¡d. at 3.
STAFF ANALYSIS
Order Nos. 25882,25883, and 25884, issued on January 31, 1995, require that utilties
utilize their Integrated Resource Plans (IRPs) to establish avoided cost rates for larger projects.
A general description of how the IRP methodology was intended to be employed was prepared by
Commission Staff and was included as an exhibit to a Settlement Stipulation that was ultimately
adopted by the Commission in Case No. IPC-E-95-9. Staffs description of the methodology,
although fairly detailed, stil falls far short of specifying all of the details that would be needed to
apply the methodology to a specific project. It was intended that the details of the IRP
methodology would be worked out over time as large projects were proposed, just as the SAR
methodology evolved over the course of many years. However, almost no IRP-based projects
were ever proposed; consequently, details of the methodology have never been fully fleshed out.
Over the course of the 16 years since the IRP methodology was first conceived, the
computer models typically used in the IRP methodology have changed considerably and become
far more powerfuL. In fact, some of the models currently used for the IRP methodology did not
even exist in 1995. The IRP methodology has only been employed twice since its inception-
once by Avista to develop rates for Potlatch's PURPA facilty (now Clearwater Paper), and once
by Idaho Power to develop rates for the Rockland wind project. This case would be the first to
derive IRP-based rates for a solar project.
There are numerous assumptions and decisions that must be made in order to use the IRP
methodology, many of which are unique to paricular generation technologies. Consequently,
thorough review of this Agreement entails far more than just going through a checklist to ensure
the methodology has been properly followed and the utilty's avoided costs have been properly
calculated.
STAFF COMMENTS 2 SEPTEMBER 9,2011
The Agreement presented for Commission approval contains rates, terms and conditions
that differ considerably from those in recent power sales agreements wherein rates were based on
published avoided cost rates. In this Agreement, an assortment of methods has been used to
determine the rates. In paricular, energy rates have been computed using an IRP methodology, a
capacity component to the rates has been computed using an entirely new methodology, and
seasonal and heavy/light load hour adjustments have been made using the same adjustment
mechanisms approved for published avoided cost rates. In addition, some terms and conditions in
the Agreement have been determined purely though negotiation between the paries.
Idaho Power Error in Computations
In preparing responses to Staff production requests in this case, Idaho Power identified
errors in its computations to determine the capacity component of the rates. The current levelized
price within the Agreement calculates to be $105.16 ($43.44 capacity cost component and $61.71
energy cost component). Upon review of its calculations, Idaho Power discovered that an
inappropriate escalation rate had been applied to the 2009 IRP Combined Cycle Combustion
Turbine (CCCT) capital cost used in this PURPA IRP pricing modeL. Correction of the CCCT
capital cost component results in a calculated levelized price of $94.59 ($32.88 capacity cost
component and $61.71 energy cost component).
Staff reviewed the Company's initial calculations and its revised calculations and agrees
that an error was made. Staff agrees that the revised calculations are correct but, as discussed in
more detail below, disagrees that a CCCT should have been used as the basis for determining the
capacity component of the rates.
CCCT vs. SCCT as Basis for Computing Capacity Value
As a basis for determining the capacity value of generation from the Interconnect Solar
Facilty, Idaho Power used the capacity cost of a CCCT. In short, the Company considered the
probabilty of the solar Facilty to provide generation durng the 3:00 pm to 7:00 pm peak load
period during July, and in tur, valued this capacity based on the capacity costs of a CCCT from
the Company's 2009 IRP.
In response to Staff production requests, Idaho Power stated that it based the value of
capacity on a CCCT in order to maintain consistency with the published avoided cost
methodology and also to be consistent with previous IRP-based PURP A price calculations.
STAFF COMMENTS 3 SEPTEMBER 9,2011
The Company concedes, however, that as a solar project, the generation shape of this project is
distinctly different than other PURP A resources and it may be that a different resource such as a
Simple Cycle Combustion Turbine (SCCT) more closely resembles the operating characteristics of
a solar resource and thus may be a more appropriate basis for the avoided cost of capacity.
Obviously, the generation profile of a solar project peaks in mid-day and is greater in the
sumer than in winter. Idaho Power's load profile is similar, although the utility's peak load
typically occurs in late afternoon or early evening, and its winter peak occurs on the coldest,
shortest days of the winter, usually in the morning when there is little sunlight. Idaho Power's
existing and future SCCT units would typically be dispatched in peak sumer and winter hours,
somewhat similar to the hours when a solar facility's generation would be greatest. Solar
generation could, at least in theory, frequently displace generation from SCCT units.
To investigate whether an SCCT or a CCCT would be a more appropriate basis for
calculating capacity value, Staff compared the capacity factors for SCCT and CCCT units
included in the Company's 20-year resource plan in its 2009 IRP. Based on modeling results from
the IRP, the capacity factors for Idaho Power's existing SCCT units and the futue SCCT units in
the preferred resource portfolio ranged from 0 to 14 percent, and averaged about nine percent for
all peakng units. By contrast, the Langley Gulch CCCT, the only CCCT in Idaho Power's
portfolio, shows an anual capacity factor ranging from 36 to 49 percent, with a 20-year average
of 49 percent. By comparison, as reported by EIA, average capacity factors from 2003-2007 for
SCCT units in the U.S. is 11.1 percent and for CCCT units is 37.3 percent. i
The anual capacity factor for the Interconnect Solar Facilty is estimated to be 21 percent
based on data collected by Idaho Power for its rooftop solar facilty, roughly half the capacity
factor for a typical CCCT but nearly double the capacity factor for a typical SCCT. If an SCCT
instead of a CCCT were used as the basis for calculating capacity value for the Facilty, the
calculated levelized price would drop from $94.59 to $73.95 per kWh ($12.24 capacity cost
component and $61.71 energy cost component).
It could be argued that the Interconnect Solar facilty has no capacity value because it
canot be guaranteed to provide capacity whenever needed with 100 percent certinty due to cloud
cover or darkness. Moreover, unlike a CCCT or a SCCT, a solar facilty is not dispatchable.
i Sources: Energy Information Administration. Form EIA-860. "Annual Electric Generator Report;" Form ElA-860.
"Annual Electric Generator Report." and predecessor forms.
STAFF COMMENTS 4 SEPTEMBER 9, 2011
Because capacity provided by a solar facility canot be guaranteed while capacity from either a
CCCT or an SCCT can be provided with nearly 100 percent certainty, whatever capacity a solar
facilty can provide is not equivalent to the same unit of capacity from a dispatchable CCCT or
SCCT.
Nonetheless, there is a high likelihood that the solar project can provide at least some
capacity durng Idaho Power's peak load hour. In recognition of this, Idaho Power examined 2010
solar data durng the period from 3:00 pm to 7:00 pm in July when the utility's annual hourly peak
load typically occurs. Idaho Power then chose a capacity value that would be exceeded 90 percent
of the time. Idaho Power reasoned that the 90 percent exceedance value was appropriate because
it was consistent with assumptions made for other resources in its IRP. While a 90 percent
capacity factor may be reasonable for planng puoses, it could be argued that a 100 percent
exceedance value should be used for a rate determination in order for the capacity of a solar
facilty to be equivalent to a unit of capacity from a SCCT or a CCCT. If a 100 percent
exceedance criterion were used instead of a 90 percent value, the capacity value of the solar
facilty would necessarily decrease from the value computed by Idaho Power.
Staff conducted additional analysis that further supports a lower capacity value than that
assumed by Idaho Power. In 2010, the Company's peak anual load occurred on June 28th during
the hour ending at 7:00 pm. Assuming there were no clouds at the time, a 20 MW solar facilty
would have been producing approximately only 1.8 MW.
Idaho Power based its capacity analysis on solar data collected at its small solar project
located on the roof of its Boise headquarers. The project consists of fixed photovoltaic (PV)
panels. The Interconnect Solar facilty, however, proposes to employ a PV panel system with
single axis tracking. Single-axis tracking allows the PV panels to track the sun in one axis as it
moves across the sky. As a result, a single-axis system wil produce a higher capacity extending
longer into the morning and evening hours, and such a system will produce approximately 30
percent more generation over the course of a year than a fixed-axis system.
Rather than basing its calculation of capacity value on an assumption of a fixed-axis
system, Staff believes that an assumption of a single-axis system would be more appropriate
because it would match the actual type of system proposed by Interconnect Solar. If a single-axis
assumption were used instead, Staff believes that the impact would roughly offset the difference
between using a 90 percent exceedance assumption and a 100 percent exceedance assumption.
Although the impacts would mostly be offsetting, Staff stil believes that a correct assumption is
STAFF COMMENTS 5 SEPTEMBER 9, 2011
necessary in each instance in order to properly and more accurately value capacity for the
Interconnect Solar facility.
Amount of Capacity Value Captured in AURORA Energy Prices
To calculate the value of the energy component of the prices in the Agreement, Idaho
Power modeled expected generation from the Facility using the AURORA electric price
forecasting modeL. The Company assumed that the prices generated by the model reflected the
costs of energy only, and that no capacity value was reflected in the prices.
The debate over whether AURORA prices include only energy value or whether there is at
least some capacity value included is ongoing. Idaho Power's approach assumes that there is no
capacity value reflected in AURORA prices. This assumption reasons that AURORA, when not
ru in a capacity expansion mode, is strictly a dispatch model that considers only the variable cost
of operating resources. The opposing argument is that the marginal energy prices generated by
AURORA permit resources to recover at least some fixed costs whenever they are not operating
on the margin.
Staff believes that Idaho Power's assumption that AURORA prices reflect only the value of
energy is a conservative one in favor of Interconnect Solar. Staff believes that there is, in fact,
some capacity value contained in AURORA prices. Although Staff is uncertain of how to
quantify the amount, it is importt to recognize that an alternative position to the assumptions
made by Idaho Power exists.
Failure to Recognize Need for New Capacity
The method used by Idaho Power to calculate the capacity component of the prices in the
Agreement fails to recognize whether and when Idaho Power actually has a need for new capacity.
Under Idaho Power's approach, capacity value is added to the prices from the beginning of the
Agreement's term through its entire duration. The fact is, however, that Idaho Power does not
show a capacity deficit in its 2011 IRP until 2015. By adopting a pricing schedule that includes
payment of a capacity component several years prior to Idaho Power's identified need for new
capacity, prices in the Agreement are higher than they would be otherwise. Staff believes that
some method needs to be devised and deployed to recognize need for new capacity (or lack of it in
this case) in the computation of contract prices.
STAFF COMMENTS 6 SEPTEMBER 9, 2011
Use of Seasonal and Daily Weighting Factors to Adjust Prices
As stated previously, anual energy prices in the Agreement are derived using the
AURORA economic dispatch model for the Facilty's estimated energy shape. The energy prices
contain the same differentiation between Heavy Load and Light Load pricing, as well as different
seasonal prices as is curently used for published avoided cost rates. In addition, this Agreement
introduces Heavy Load Peak pricing to hours between 3:00 pm and 7:00 pm in the months of July
and August. Under this pricing mechanism a premium of five percent is added to Heavy Load
Peak prices and prices in Heavy Load Standard hours are decreased by two percent.
As justification for this pricing adjustment mechanism, Idaho Power states that because the
resultant pricing from the IRP methodology is dependent upon, and very sensitive to, the energy
shape provided by the Facility as an input to the pricing model, this additional Heavy Load Peak
pricing differentiation was added as a price-based performance guarantee measure to protect
customers from overpaying for energy based upon a specific daily load shape should the project
not operate according to that load shape. Consequently, if the Facilty delivers the Heavy Load
Peak energy consistent with the load shape it provided to Idaho Power, and upon which the IRP-
based rates were calculated, the Facilty will receive the full IRP-based avoided cost price. Should
the Facilty fail to deliver the peak load energy that its IRP-based avoided cost pricing is based
upon, it will automatically receive the lower Heavy Load Standard price.
Staff agrees conceptuly to increasing prices in heavy load peak hours, but sees no direct
evidence to specifically support a five percent premium in Heavy Load Peak hours and a two
percent decrease in Heavy Load Standard hours. The energy price components derived using
AURORA would have recognized the higher and lower energy values throughout the day and
throughout the seasons of the year. Staff suggests that the price shapes calculated by AURORA
be used as the basis for hourly and seasonal price adjustments, rather than hourly and seasonal
adjustment factors used for published avoided cost rates. The adjustment factors used for
published rates were developed many years ago and were intended to recognize hourly and
seasonal variations in energy value, but when better information is available, and when it is
specific to a paricular project as it is here, then better information should be used.
25-yr. vs. 20-yr. Contract
The Agreement is for a term of 25 years rather than 20 years as has historically been
standard for nearly all PURP A agreements. Idaho Power asserts that the 25-year contract term
STAFF COMMENTS 7 SEPTEMBER 9, 2011
was the result of negotiations that attempted to balance the paries' interests in a maner that was
favorable to Idaho Power customers and to Interconnect Solar. Staff has no objection to a 25-year
contract term.
Use of 2009 IRP Assumptions vs. 2011 IRP Assumptions
The analysis done by Idaho Power to derive the prices contained in the Agreement was
based on data and assumptions from the Company's 2009 IRP. Key assumptions from the IRP that
could significantly affect prices in the Agreement include fuel prices, resource costs, loads,
makeup of the preferred portfolio, and C02 prices and policy. Idaho Power used its 2009 IRP
because it is the most recent IRP acknowledged by the Commission. However, on June 30, 2011,
Idaho Power submitted its 2011 IRP. A comment deadline has yet to be established for the 2011
IRP.
Although using the most recent IRP acknowledged by the Commission is consistent with
the IRP methodology for computing avoided cost rates, the data and assumptions in the 2011 IRP
are undeniably more curent. Neither Idaho Power nor Staff has performed analysis to compute
contract prices based on 2011 IRP data. Clearly, however, use of the 2011 IRP would produce
different results. If this Agreement is rejected and must eventually be renegotiated, Staff
recommends that the 2011 IRP be used as a basis for the analysis.
Integration Costs
Solar, similar to wind, is an intermittent generation resource. Numerous studies have
confirmed and quantified wind integration costs, but very few solar integration cost studies have
been done. Nevertheless, Staff believes that solar integration costs are material, and may be
comparable to wind integration costs. No integration costs have been considered in the
Agreement, yet in response to Staff production requests, Idaho Power concedes that actual
integration costs will not be zero. The Company reports that while it has not yet begun its own
solar integration study, it has undertaken some broad research in an attempt to find representative
solar studies and results. In reviewing numerous documents, Idaho Power reports that it appears
to be widely assumed and accepted that there is some level of integration cost associated with all
intermittent resources such as wind and solar generation. Some aricles suggest that the
integration cost for solar integration may be less than the calculated wind integration cost, yet
STAFF COMMENTS 8 SEPTEMBER 9, 2011
other aricles suggest that solar energy is even more difficult and costly to integrate than wind due
to the more frequent, sudden deviations in solar generation (i.e., clouds).
The Commission has approved only one other PURPA contract for a solar facilty.2 In that
contract, no discount to account for solar integration cost was included because of lack of data and
studies. Staf was hopeful that data could be gathered from the Grand View I project and that
Idaho Power could complete a solar integration study before additional solar projects were
proposed. Unfortately, that clearly has not happened. In any case, Staff is convinced that
integration costs associated with the Interconnect Solar Facilty wil not be zero. Based on prior
studies of wind integration costs, the Commission conservatively capped integration costs at $6.50
per MWh. Staff believes that absent additional information, the same $6.50 per MWh integration
cost is a better estimate than no integration cost at all, and should be applied as a discount to the
avoided cost rates in the Agreement.
Weighted Cost of Capital Used in Idaho Power Analysis
In its analysis to compute the rates included in the Agreement, Idaho Power used a
weighted cost of capital of seven percent. This is the same weighted cost of capital that the
Company used in preparing its 2009 IRP. Staff believes that a more appropriate weighted cost of
capital is 8.18 percent, the weighted cost of capital from Idaho Power's last general rate case (IPC-
E-08-10). If a weighted cost of capital of 8.18 percent is used instead of seven percent, the
avoided cost rates computed by Idaho Power would be lowered slightly.
Scheduled Operation Date is Prior to Completion Date for Interconnection Facilties
Interconnect Solar must complete a Generation Interconnection Agreement (GIA) and is
responsible for all costs associated with interconnection of the Facilty to Idaho Power's system
and any necessar transmission upgrades for its generation to serve load. Idaho Power states that,
at the time this Application was fied, the GIA has not yet been signed and the required payment
for interconnection and transmission upgrades has not been paid. Idaho Power estimates that, after
payment is made, 18 months is required for Idaho Power to complete the interconnection and
transmission facilties.
2 Grand View Solar I, Case No.
IPC-E-IO-19, Order No. 32068.
STAFF COMMENTS 9 SEPTEMBER 9,2011
Idaho Power maintains that Interconnect Solar has been expressly advised in writing
that the Scheduled Operation Date it selected was prior to such time that the
interconnection/transmission facilities are scheduled to be constructed and completed.
Application at 8. Idaho Power states that Interconnect Solar has acknowledged and expressly
agreed to accept all risk associated with not meeting the Scheduled Operation Date, including
forfeiture of the Delay Securty, and potential termination of the Agreement. ¡d.
Interconnect Solar and Idaho Power have agreed to liquidated damage and securty
provisions of $45 per kW of nameplate capacity. Agreement" 5.3.2, 5.8.1. Delay Liquidated
Damages shall apply if Interconnect Solar fails to bring the Facilty on-line by the Scheduled
Operation Date.
Staff is concerned that the Facilty's Scheduled Operation Date is prior to the date on which
Idaho Power is obligated to complete construction of the necessary transmission and
interconnection facilities. Interconnect Solar appears to believe that siting studies can be
completed soon enough to allow transmission and interconnection facilties to be constructed
before Idaho Power's scheduled completion date, and is wiling to accept the risk of failng to meet
its Scheduled Operation Date. Despite Interconnect Solar's wilingness to accept this risk, Staff
believes it would be unwise to approve an agreement when such a high likelihood that delay
damages wil be assessed exists from the star.
PURP A Requirements Related to Avoided Costs
PURPA requires electric utilties to purchase power from Qualifying Facilties (QFs) at the
utilties avoided cost. Reference 18 CFR § 292.303(a). Avoided cost means the incremental costs
to an electric utilty of electric energy or capacity or both which, but for the purchase from the
qualifying facility or qualifying facilties, such utilty would generate itself or purchase from
another source. Reference 18 CFR § 292.101(6). Rates for purchases shall: (i) Be just and
reasonable to the electric consumer of the electric utilty and in the public interest; and (ii) Not
discriminate against qualifying cogeneration and small power production facilities. Reference 18
CFR § 292.304(a).
STAFF COMMENTS 10 SEPTEMBER 9, 2011
In determining avoided costs, the following factors shall, to the extent practicable, be taken
into account:
(l) The utilty's estimated costs of energy and capacity;
(2) The availabilty of capacity or energy from a QF during the system daily and seasonal peak
periods, including:
(i) The abilty of the utilty to dispatch the qualifying facility;
(ii) The expected or demonstrated reliabilty of the qualifying facilty;
(iii) The terms of any contract or other legally enforceable obligation, including the
duration of the obligation, termination notice requirement and sanctions for non-
compliance;
(iv) The extent to which scheduled outages of the qualifying facility can be usefully
coordinated with scheduled outages of the utilty's facilties;
(v) The usefulness of energy and capacity supplied from a qualifying facilty during system
emergencies, including its abilty to separate its load from its generation;
(vi) The individual and aggregate value of energy and capacity from qualifying facilties
on the electric utility's system; and
(vii) The smaller capacity increments and the shorter lead times available with additions of
capacity from qualifying facilities; and
(3) The relationship of the availabilty of energy or capacity from the QF to the ability of the
electric utilty to avoid costs, including the deferral of capacity additions and the reduction of
fossil fuel use; and
(4) The costs or savings resulting from variations in line losses from those that would have existed
in the absence of purchases from a QF if the purchasing electric utility generated an equivalent
amount of energy itself or purchased an equivalent amount of electric energy or capacity.
Reference 18 CFR § 292.304( e).
Clearly, PURPA does not permit states to establish avoided cost rates that exceed the
utilty's actual avoided costs. Most notably, PURP A does not include provisions that allow
avoided cost rates to consider factors other than those listed above. For example, benefits often
associated with renewable projects such as jobs creation, economic development, tax revenue, etc.
canot explicitly be considered in avoided cost calculations. To the extent such benefits exist and
to the extent states wish to provide incentives for them, those incentives must be realized through
sources other than avoided costs.
STAFF COMMENTS 11 SEPTEMBER 9, 2011
Related Cases
On September 1,2011, the Commission initiated Case No. GNR-E-II-03. The purose of
the case is to review the terms of PURP A power purchase agreements including, but not limited
to, the Surogate Avoided Resource (SAR) and Integrated Resource Planning (IRP) methodologies
for calculating avoided cost rates. The case is the third phase of a more comprehensive review of
PURPA-related issues. In the first phase, Case No. GNR-E-1O-04, the primar issue was whether
to temporarily reduce the eligibilty cap for published avoided cost rates from 10 aMW to 100 kW
while the Commission investigates other issues. In the second phase, Case No. GNR-E-I1-01, the
primary purose was to address the issue of disaggregation of large wind and solar projects into
small projects in order to obtain published avoided cost rates.
Staff expects that nearly all of the specific issues that have been raised regarding the
Interconnect Solar Agreement wil be addressed more fully in a generic context in Case
No. GNR-E-II-03. Because most of these issues will likely be common to other future contracts,
Staff expects a full debate amongst all interested paries in the generic case. Staff intends that any
positions it takes regarding the Interconnect Solar Agreement be confined to only that Agreement,
and not prejudice or set a precedent for any positions Staff may take in the generic case.
RECOMMENDATIONS
Staff recommends that the Commission not approve the Agreement. Staff acknowledges
the Commission's support, and recent reinforcement of, rates derived by the IRP methodology and
negotiations between the paries. However, pursuant to PURP A and FERC regulations, avoided
costs paid to QFs are not to exceed the incremental cost that the utilty would incur if it generated
the energy/capacity itself or purchased from another source. Simply put, Staff does not believe
that the rates contained in the Agreement are an accurate reflection of Idaho Power's avoided
costs. First and foremost, Idaho Power acknowledges that an error was made in computing the
rates in the Agreement, and that correction of this error reduces the 25-year equivalent levelized
rates in the Agreement from $105.16 to $94.59 per MWh. Furher, Staff believes that the capacity
component of the rates should have been computed based on the cost of an SCCT instead of a
CCCT, which reduces the rates further to $73.95 per MWh (25-year equivalent levelized rate). In
addition, Staff believes that some discount should be applied to the rates in the Agreement to
account for integration costs. Staff suggests a reasonable discount would be $6.50 per MWh, the
same integration cost assigned to PURPA wind contracts. Ifthe paries can derive a "base" set of
STAFF COMMENTS 12 SEPTEMBER 9, 2011
rates incorporating the changes discussed above, Staff believes that those "base" rates should be
further adjusted for seasonality and heavy and light hours using the results of AURORA analysis
rather than using the same adjustment factors curently used for published rates.
Respectfully submitted this q ¡t day of September 2011.
~)a'~4UAKi.sasser --
Deputy Attorney General
Technical Staff: Rick Sterling
i:umisc:commentsipce i i. i Oksrps comments
STAFF COMMENTS 13 SEPTEMBER 9, 2011
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 9th DAY OF SEPTEMBER 2011,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-II-1O, BY E-MAILING AND MAILING A COPY THEREOF, POSTAGE
PREPAID, TO THE FOLLOWING:
DONOV AN E WALKER
LEAD COUNSEL
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: dwalker(ßidahopower.com
RANDY C ALLPHIN
ENERGY CONTRACT ADMIN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: rallphin(ßidahopower.com
RANDY HEMMER MGR
INTERCONNECT SOLAR
DEVELOPMENT LLC
3777 TWILIGHT DR
BOISE ID 83703
E-MAIL: randyhemmer(ßclearire.net
RONALD L WILLIAMS
WILLIAMS BRADBURY PC
1015 W HAYS ST
BOISE ID 83702
E-MAIL: ron(iwiliamsbradbury.com
~X~
SECRETARY
CERTIFICATE OF SERVICE