20120126Comments.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BARNO. 6618
RECEIVED
2011 JAN 26 PH 2: 19
In A l H'''\ rj~ n:~I If"'Ul'''\(li:) r .vf.c..L..,',j. .,i.
UTIliTIES COMMiSSIOj~
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 )
DETERMINATION REGARDING ITS FIRM )
ENERGY SALES AGREEMENT WITH HIGH )
MESA ENERGY, LLC. )
)
CASE NO. IPC-E-1l-26
COMMENTS OF THE
COMMISSION STAFF
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
Notice of Application and Notice of Modified Procedure issued in Order No. 32414 on
December 16, 2011, in Case No. IPC-E-II-26, submits the following comments.
BACKGROUND
On November 22,2011, Idaho Power Company (Idaho Power; Company) fied an
Application with the Commission requesting acceptance or rejection of a 20-year Firm Energy
Sales Agreement (Agreement) between Idaho Power and High Mesa Energy, LLC (High Mesa)
dated November 16, 2011. The Application states that High Mesa would sell and Idaho Power
would purchase electric energy generated by the High Mesa wind project (Facilty) located near
Bliss, Idaho. The Application states that High Mesa proposes to own, operate and maintain a 40
MW (maximum capacity, nameplate) generating facility. Application at 2. The Facilty will be
STAFF COMMENTS 1 JANUARY 26, 2012
a Qualifying Facilty (QF) under the applicable provisions of the Public Utilty Regulatory
Policies Act of 1978 (PURP A).
The Agreement is for a term of 20 years and contains avoided cost rates calculated
though the use of the Integrated Resource Plan (IRP) avoided cost methodology as curently
required by the Commission for wind QFs with a design capacity of more than 100 kilowatts
(kW). Order No. 32262. High Mesa selected November 1,2012, as its Scheduled First Energy
Date and December 28,2012, as its Scheduled Operation Date. ¡d. at 2.
The Application maintains that all applicable interconnection charges and monthly
operation or maintenance charges under Schedule 72 wil be assessed to High Mesa. Idaho
Power states that the Facilty is curently in the generator interconnection process. "Upon
resolution of any and all upgrades required to acquire transmission capacity for this Facilty's
generation, and upon execution of the FE SA and the GIA, this Facility may then be designated as
a network resource." ¡d. at 5. High Mesa and Idaho Power have agreed to liquidated damage
and security provisions. Agreement ~~ 5.3, 5.8.1.
Idaho Power states that the Facility has also been made aware of and accepted the
provisions in the Agreement and Idaho Power's approved Schedule 72 regarding non-
compensated curtailment or disconnection of its Facilty should certain operating conditions
develop on Idaho Power's system. The Application notes that the paries' intent and
understading is that "non-compensated curailment would be exercised when the generation
being provided by the Facilty in certain operating conditions exceeds or approaches the
minimum load levels of (Idaho Power's) system such that it may have a detrimental effect upon
(Idaho Power's) abilty to manage its thermal, hydro, and other resources in order to meet its
obligation to reliably serve loads on its system." Application at 6.
STAFF ANALYSIS
Order Nos. 25882, 25883 and 25884, issued on Januay 31, 1995, require that utilties
utilze their Integrated Resource Plans (IRPs) to establish avoided cost rates for larger PURP A
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
STAFF COMMENTS 2 JANUARY 26, 2012
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 three times since its
inception--nce by A vista to develop rates for Potlatch's PURP A facilty (now Clearater
Paper), once by Idaho Power to develop rates for the Rockland wind project, and once by Idaho
Power to develop rates for the Interconnect 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 utility's avoided costs have been properly
calculated.
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,
and a capacity component to the rates has been computed using a new methodology not yet
thoroughly scrutinized. In addition, some terms and conditions in the Agreement have been
determined purely through negotiation between the paries.
Rates
The Agreement contains non-levelized avoided cost rates that escalate annually from
2012 through the end of the contract term in 2032. The rates are specified by month for both
heavy and light load hours. Idaho Power notes that the energy price identified by the IRP
methodology for this Facility is equivalent to a 20-year levelized price of $56.43 per MWh.1
i The actual energy pricing stream varies throughout the term of the contract based upon the time of year and time of
day during which the energy is delivered to Idaho Power.
STAFF COMMENTS 3 JANUARY 26,2012
Application at 4. By comparison, the 20-year levelized published avoided cost rate is $68.51. A
graphical comparison of the rates contained in the Agreement to currently approved published
avoided cost rates, both for heavy and light load hours, is shown below.
Published Avoided Cost Rates
vs. Contract Rates
120
100
80:2
3:
:E-.60V)-
lV..tVci 40
20
_Published HLH -. Published LlH
- Contract HlH Contract lLH
0 N m -:Lt ID ,.co CI 0 ..N m -:Lt ID ,.co CI 0 ..N......,.,.....,.N N N N N N N N N N m m m000000000000000000000NNNNNNNNNNNNNNNNNNNNN
Idaho Power's analysis indicates that a total of approximately $105 milion wil be paid to
High Mesa over the 20-year term of the Agreement. The net present value of the payments is
estimated to be approximately $45 milion.
Although the rates in the Agreement were computed using the IRP methodology, as
discussed above, there are many assumptions and computational details that have yet to be
standardized. Most of these details are expected to be ironed out in the ongoing GNR-E-II-03
case. In the current case, Idaho Power has made assumptions and employed computational
methods it believes are reasonable and within the bounds of the IRP methodology. However, .
Staff in some cases would have made different assumptions and calculations. Staff
recommended that different assumptions and computational methods be used in the recent
Interconnect Solar case (lPC-E-II-10). Although the Commission ultimately approved the
STAFF COMMENTS 4 JANUARY 26, 2012
contract stating that "Idaho Power negotiated an Agreement with Interconnect Solar based on its
past practices and current understanding of this Commission's directives," the Commission
recognized Staffs consideration of alternative factors. The Commission found that Staffs
analysis considered "reasonable factors that the utilties should be considering while negotiating
future power purchase agreements until such time as the Commission establishes firm guidelines
for IRP-based rates." Order No. 32384 at 10.
With regard to computation methods and assumptions in this case, Idaho Power has
adopted some of Staffs recommendations made in the Interconnect Solar case, but has rejected
others. Staff continues to believe that certain other assumptions and computational methods are
appropriate, and discusses its recommendations below.
CCCT vs. SCCT as Basis for Computing Capacity Value
As a basis for determining the capacity value of generation from the High Mesa Facility,
Idaho Power used the capacity cost of a combined cycle combustion turbine (CCCT). In short,
the Company considered the probabilty of the wind Facilty to provide generation during the
3:00 pm to 7:00 pm peak load period during July, and in turn, valued this capacity based on the
capacity costs ofa CCCT from the Company's 2009 IRP.
In response to Staff production requests in the Interconnect Solar case, 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. The Company conceded, however, that as a solar project, the generation
shape 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.
In the case of the High Mesa Wind Project, an anual capacity factor of about 26 percent
is expected, and during Idaho Power's peak hours 3:00 pm to 7:00 pm in July, a peak hour
capacity factor of only 5 percent is expected. Idaho Power's existing and future SCCT units
would typically be dispatched in peak summer ~d winter hours, and would typically represent
the lowest cost capacity Idaho Power could acquire. Wind generation could at various times
displace generation from a SCCT unit or a CCCT unit.
STAFF COMMENTS 5 JANUARY 26, 2012
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 future SCCT
units in the preferred resource portfolio ranged from 0 to 14 percent, and averaged about nine
percent for all peaking 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.
The anual capacity factor for the High Mesa Facility is estimated to be 26 percent, far
less than the capacity factor for a typical CCCT but up to 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 $56.43 to $53.47 per MWh.
It could be argued that the High Mesa facilty has no capacity value because it canot be
guaranteed to provide capacity whenever needed with 100 percent certainty due to the
intermittency of wind. Moreover, unlike a CCCT or a SCCT, a wind facilty is not dispatchable.
Because capacity provided by a wind facilty cannot be guaranteed while capacity from either a
CCCT or an SCCT can be provided with nearly 100 percent certainty, whatever capacity a wind
facility 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 wind project can provide at least some
capacity during Idaho Power's peak load hours. In recognition of this, Idaho Power examined
generation estimates for the Project during the period from 3:00 pm to 7:00 pm in July when the
utilty's anual 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 planing purposes, it could be
argued that a 100 percent exceedance value should be used for a rate determination in order for
the capacity of a wind 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 wind facility would necessarily decrease from the value computed by Idaho Power.
STAFF COMMENTS 6 JANUARY 26,2012
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 run 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 High Mesa. 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 important 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 the year 2015. (The 2009 IRP
showed a very small capacity deficit beginning in 2013). 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. In the case of wind projects,
however, because they provide minimal capacity anyway, the failure to recognize need for new
capacity in rate computations has a relatively minor effect.
STAFF COMMENTS 7 JANUARY 26, 2012
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 was the most recent IRP acknowledged by the Commission on August 17, 2011, the
date on which the Company completed its price analysis. However, on December 30,2011, the
Commission issued an Order accepting Idaho Power's 2011 IRP. Reference Order No. 32425.
Although Idaho Power's use of the 2009 IRP for computing avoided cost rates was
appropriate because it was the most recently acknowledged IRP at the time the analysis was
done, 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.
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 7.86 percent, the weighted cost of capital from Idaho Power's last general rate case
(IPC-E-II-08). If a weighted cost of capital of 7.86 percent is used instead of seven percent, the
avoided cost rates computed by Idaho Power would be lowered slightly.
Escalation of Prices from 2030-2032
For the last two years of the Agreement, Idaho Power estimated the avoided cost rates
rather than computing them. Idaho Power's AURORA simulations from the 2009 IRP only
extended through 2029, consequently, rates beyond 2029 could not be based exactly on
AURORA. To derive rates beyond 2029, Idaho Power simply extrapolated the rates from the
prior year using a three percent escalation rate. In this paricular case, the effect of the
extrapolation is very small; consequently, Staff does not object to it. However, Staff believes
STAFF COMMENTS 8 JANUARY 26,2012
that a more appropriate approach would be to extend the years over which the AURORA
modeling is conducted in order to capture energy prices over the full term of the Agreement.
Overall Impact of All Staff-Proposed Adjustments on Contract Rates
The overall impact of all of the changes proposed by Staff would be a decrease in
avoided cost rates of approximately $3 per MWh. This is equivalent to slightly more than a five
percent decrease.
The Agreement provides that High Mesa wil own the Renewable Energy Credits (RECs)
for the first 10 years of the Agreement and that Idaho Power wil own them for the last 10 years.
Agreement at ~~ 8.1, 8.2. REC ownership has been split in a similar fashion in several recent
PURP A contracts. Staff has no objection to the sharing arrangement in the Agreement.
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 Surrogate Avoided Resource (SAR) and Integrated Resource Planing (lRP)
methodologies for calculating avoided cost rates. The case is the third phase of a more
comprehensive review ofPURPA-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-II-0l, the primar purpose 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 High
Mesa Agreement wil be addressed more fully in a generic context in Case No. GNR-E-1 1-03.
Because most of these issues wil likely be common to other future contracts, Staff expects a full
debate amongst all interested parties in the generic case. Staff intends that any positions it takes
regarding the High Mesa Agreement be confined to only that Agreement, and not prejudice or set
a precedent for any positions Staff may take in the generic case.
STAFF COMMENTS 9 JANUARY 26, 2012
RECOMMENDATIONS
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 this
Agreement are an accurate reflection ofIdaho Power's avoided costs. Consequently, Staff
recommends that the Commission not approve the Agreement. First, 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 would reduce the rates in the Agreement by about $3 per MWh. In
addition, Staff believes that the rates in the Agreement fail to recognize Idaho Power's need (or
lack of need) for new generation, particularly wind. Finally, Staff takes issue with use of2009
rather than 2011 IRP assumptions and use of a seven percent discount rate.
Notwithstanding Staffs recommendation to 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. (See Interconnect Solar, IPC-E-ll-l 0, Order
No. 32384). Staff recognizes that the assumptions and analysis techniques employed by Idaho
Power in developing the rates in the Agreement may reflect past practice and the Company's
current understanding of the IRP methodology. Furthermore, Staff recognizes that there is
considerable room for negotiation, and that such flexibility has been exercised in this case.
1(\"JrlRespectfully submitted this 00- day of Januar 2012.
~~d.~AKristine A. Sasser
Deputy Attorney General
Technical Staff: Rick Sterling
i :umisc: commentsipce i i .26ksrps comments
STAFF COMMENTS 10 JANUARY 26, 2012
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 26TH DAY OF JANUARY 2012,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-II-26, BY E-MAILING AND MAILING A COPY THEREOF, POSTAGE
PREP AID, TO THE FOLLOWING:
DONOV AN E WALKER
JASON B. WILLIAMS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: dwalker(fidahopower.com
jwi lliams(fidahopower. com
HIGH MESA ENERGY LLC
C/O EXELON WIND
4601 WESTOWN PKWY
STE 300
WEST DES MOINES IA 50266
E-MAIL: urs(fexeloncorp.com
RANDYC ALLPHIN
ENERGY CONTRACT ADMIN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: rallphin(fidahopower.com
HIGH MESA ENERGY LLC
RICHARD A CUMMINGS
COUNSEL FOR SELLER
PO BOX 1545
BOISE ID 83701
E-MAIL:
rcummings(fcummingslawidaho.com
CHRISTI RITCHIE
E-MAIL ONLY:cjritchie(fnorthrim.net
r-, r~.\toL
SECRETARY
CERTIFICATE OF SERVICE