20120202Comments.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 6618
RECEiVED
2011 FEB -2 PH 3: 48
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 )DYNAMIS ENERGY, LLC )
)
CASE NO. IPC-E-1l-25
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilties 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. 32413 on December 15,
2011, in Case No. IPC-E-11-25, submits the following comments.
BACKGROUND
On November 22, 201 i, 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 Dynamis Energy, LLC (Dynamis
Energy; Dynamis) dated November 16,2011. The Application states that Dynamis Energy would
sell and Idaho Power would purchase electric energy generated by the Dynamis Ada County
Landfill project (Facility; Project) located near Boise, Idaho. The Application states that Dynamis
proposes to own, operate and maintain a 22 MW (maximum capacity, nameplate) landfill waste-
STAFF COMMENTS 1 FEBRUARY 2,2012
to-energy generating facilty. Application at 2. The Facilty wil be a QF under the applicable
provisions of the Public Utilty Regulatory Policies Act of 1978 (PURPA).
The Agreement is for a term of 20 years and contains avoided cost rates calculated though
the use of the Integrated Resource Plan (IRP) methodology. Dynamis Energy selected October
15,2013, as its Scheduled First Energy Date and February 14,2014, as its Scheduled Operation
Date. ¡d. at 3.
The Application maintains that all applicable interconnection charges and monthly
operation or maintenance charges under Schedule 72 wil be assessed to Dynamis Energy. Idaho
Power states that the Facilty is currently in the generator interconnection process. "Upon
resolution of any and all upgrades required to acquire transmission capacity for this Facility's
generation, and upon execution of the FESA and the GIA, this Facility may then be designated as
a network resource." ¡d. at 5.
STAFF ANALYSIS
Order Nos. 25882, 25883 and 25884, issued on January 31, 1995, require that utilities
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 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 i 995. The IRP methodology has only been employed four times since its
inception-once by Avista to develop rates for Potlatch's PURPA facility (now Clearater Paper),
and by Idaho Power to develop rates for the Rockland wind project, the Interconnect Solar project,
and the High Mesa Wind Project.
STAFF COMMENTS 2 FEBRUARY 2, 2012
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 parties.
Rates
The Agreement contains non-Ievelized avoided cost rates that escalate anually from 2014
through the end of the contract term in 2034. 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 Facilty is equivalent to a 20-year levelized price of $92.35 per MWh. i Application at 5. By
comparison, the 20-year levelized published avoided cost rate is $73.44.
The rates in the Agreement appear high in comparison to both published rates and to rates
contained in recent other PURP A contracts with IRP-based rates. (See High Mesa Wind, Case
No. IPC-E-II-26, wherein the equivalent 20-year levelized rates is $56.43 per MWh). The higher
rates in the Dynamis Agreement can be attributed primarily to the two following factors:
1) The Facility only plans to deliver energy between the hours of8:00 am through 10:00
pm, every day of the year. Except for Sundays and holidays, all of these hours are
heavy load hours when energy is substantially more valuable. No energy is proposed
to be delivered at night, from 10:00 pm through 8:00 am.
2) Because the Facilty is expected to operate daily at a very high daytime capacity factor,
and because its generation will not be intermittent, 100 percent of the Facilty's
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 FEBRUARY 2, 2012
capacity wil be available during Idaho Power's peak load hours in the summer.
Consequently, Dynamis Energy receives credit in rate calculations for its full
nameplate capacity equal to the assumed capacity cost of a combined cycle combustion
turbine (CCCT). By comparison, intermittent generation, like wind, receives credit for
only a very small portion of its nameplate capacity, typically five percent.
For reference purposes, a graphical comparison of the rates contained in the Agreement to
curently approved published avoided cost rates, both for heavy and light load hours, is shown
below.
140
120
100
:ëŠ 80
:?-.V)-ci 60-IV0:
40
20
Published Avoided Cost Rates
vs. Contract Rates
__Published HLH _Published LLH
- Contract HLH Contract LLH
0 N t"""i.1.r-00 O"0 .-N t"""i.\.r-00 O"0 ..N t"""i.\................-N N N N N N N N N N t"t"N'N'N'N't"0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0NNNNNNNNNNNNNNNNNNNNNNNNN
Idaho Power's analysis indicates that a total of approximately $189 millon wil be paid to
Dynamis Energy over the 20-year term of the Agreement. The net present value of the payments
is estimated to be approximately $82 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-I 1-03
STAFF COMMENTS 4 FEBRUARY 2, 2012
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 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 utilities 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.
Idaho Power Error in Computations
In reviewing responses to Staffs production requests in this case, Staff identified what it
believes is an error in Idaho Power's computations to determine the capacity component of the
rates. Idaho Power uses the capacity cost of a CCCT as the basis for computing capacity value of
the QF. The underlying assumption in calculating capacity value is that, but for the addition of the
new PUPRA QF, a CCCT would otherwise be built to provide capacity. The CCCT is assumed to
be added in the same year that the PURPA QF goes online. Therefore, it is important that the
CCCT capital cost reflect the construction cost in the same year as the Scheduled Operation Date
as the QF.
In its analysis in this case, Idaho Power based its calculation of capacity value on the
capital cost ofa CCCT constructed in 2012, not in 2014 when Dynamis Energy's Scheduled
Operation Date occurs. To correct this error, Staff believes that the assumed capital cost of the
CCCT in 2012 should be inflated by two years to 2014. The effect of this correction, Staff
believes, would be an increase in avoided cost rates of approximately $1 per MWh in each year of
the Agreement.
STAFF COMMENTS 5 FEBRUARY 2, 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 Facilty 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 Dynamis Energy. Staff believes that there is, in fact, some
capacity value contained in AURORA prices. Although Staff is uncertin 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 i
capacity deficit beginning in 2013). By adopting a pricing schedule that includes payment ofa
capacity component one year 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 the Dynamis Project, the effect of failing to
recognize the need for new capacity is relatively minor because the Project's Scheduled Operation
Date is only one year before Idaho Power's identified capacity deficit.
STAFF COMMENTS 6 FEBRUARY 2, 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 July 8, 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 current. 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
(lPC-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.
Extrapolation of Prices from 2030-2034
For the last five 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, therefore, 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 that a more appropriate
STAFF COMMENTS 7 FEBRUARY 2, 2012
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.
Renewable Energy Credits
The Agreement provides that Dynamis Energy and Idaho Power wil split ownership of
Renewable Energy Credits (RECs) on a 50/50 basis for the entire term of the Agreement.
Agreement at ~~ 8. i, 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 A voided Resource (SAR) and Integrated Resource Planing (lRP) 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-I0-04, 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
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
Dynamis Energy Agreement wil be addressed more fully in a generic context in Case No.
GNR-E-II-03. Because most of these issues wil 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 Dynamis Energy Agreement be confined to only that Agreement,
and not prejudice or set a precedent for any positions Staff may take in the generic case.
Idaho Power and Customer Safeguards
Several public comments have been submitted expressing general concerns about risk
exposure to ratepayers and taxpayers if the Dynamis Energy Project fails to perform. Dynamis
Energy proposes to use gasification technology, which first involves thermally converting waste
products into a combustible gas. The technology Dynamis Energy proposes to employ is new and
STAFF COMMENTS 8 FEBRUARY 2, 2012
relatively untested, at least in applications for commercial power production, and is much different
than the technology used at two existing facilties located at the Ada County landfill?
Idaho Power is required under PURP A to offer to purchase the Project's output, regardless
of the technology employed, as long as the Project meets the requirements of a Qualifying
Facility. Reference 18 C.F.R. §292.303(a). Similarly, the Commission does not have the
authority to assess the viabilty of a project's technology as long as it has been certified as a QF by
the Federal Energy Regulatory Commission. Idaho Power and the Commission can, however,
require that the power sales agreement contain provisions to protect ratepayers if the project fails
to perform. This Agreement contains numerous provisions intended to protect Idaho Power and
its ratepayers. Most of the provisions have become standard in all PURP A contracts. Some of
these provisions are described below.
No Payment for Energy not Delivered
Undoubtedly, the most significant safeguard for Idaho Power and its ratepayers is that no
payment to Dynamis Energy is required unless energy is delivered. Although not an explicit term
of the Agreement, this is the fundamental basis of all PUPRA contracts.
Delay Liquidated Damages
The Agreement requires that Delay Liquidated Damages wil apply should Dynamis fail to
bring the Facilty on-line by the Scheduled Operation Date. If the Operation Date occurs after the
Scheduled Operation Date, but within 90 days of that Scheduled Operation Date, then damages are
equal to the sum of all Hourly Energy Production amounts for the entire Delay Period multiplied
by the curent month's market energy cost, but no less than $15 per MWh. The $15 per MWh
minimum is a new requirement specific to this Agreement. (See Agreement at ~ 1.6). If the
Operation Date occurs more than 90 days past the Scheduled Operation Date, then damages are
specified as $45 per kW of nameplate capacity for the Facilty. If the Facility fails to achieve its
Operation Date within 90 days of the Scheduled Operation Date, the failure wil be a Material
Breach of the Agreement and Idaho Power may terminate the Agreement if not cured by Dynamis.
Reference Agreement at ir~ 5.3-5.6, ir 5.8.1.
2 One existing facilty, online since 6/29/2006, has a 3.2 MW capacity and burs landfill gas collected from buried
decomposing garbage. The other facilty, not yet online, wil be a twin to the original facilty.
STAFF COMMENTS 9 FEBRUARY 2, 2012
Delay Security
Dynamis and Idaho Power have also agreed to Delay Security provisions requiring
Dynamis to post Delay Security in an amount equal to $45 per kW of nameplate capacity within
30 days of Commission approval of the Agreement. The purpose of Delay Security is to provide a
source of funds in the event Delay Liquidated Damages are assessed. Reference Agreement at ir
5.8.1.
Reduced Price for Surplus Energy
Surlus Energy, generally, is energy produced by the Facilty that is less than 90 percent or
more than 110 percent of the hourly amounts specified in the Agreement. Surplus Energy is
priced at the lower of the current month's market price or 85 percent of off-peak prices in the
Agreement. The purpose of this contract provision is to encourage Dynamis to generate as closely
as possible in accordance with the timing and amount specified in the Agreement. Reference
Agreement at ~~ 1.38 and 7.4. The requirement for a reduced price for Surlus Energy is in
accordance with Commission Order Nos. 29632 and 29682.
Minimum Generation Requirement
The Agreement contains minimum generation requirements that must be met by Dynamis.
Reduced energy prices apply for short-term failures to meet minimum generation requirements.
Failure to deliver 30,000 MWh in any year constitutes an event of Default. Reference Agreement
at ~~ 6.3-6.4.
Security Requirements
The Agreement contains various standard security requirements in accordance with prior
Commission orders. Reference Order Nos. 21690 and 29587. Security requirements include
Engineer's Certifications for 1) Operations and Maintenance Policy, 2) Ongoing Operations and
Maintenance, and 3) Design and Construction Adequacy. Reference Agreement at ~~ 4.1.4 and
19.3.2. The Agreement also includes minimum insurance requirements for Dynamis. Reference ~
4.1.5, ~~ 13.2-13.4, ~ 19.3.1.
STAFF COMMENTS 10 FEBRUARY 2, 2012
Non-Compensated Curtailment
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
understanding 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 6-7.
Other Terms of the Agreement
In addition to the various terms discussed above, the Agreement contains other standard
terms and conditions intended to protect Idaho Power and its ratepayers. For example, the
Agreement addresses Indemnification (~ 13.1 ), Force Maj eure (~ 14.1), Liabilty (~ 15.1), and
Disputes and Default (~ 19.1).
Minor Typographical Errors
There are several typographical errors in the Agreement that Staff believes need to be
corrected. Appendix C of the Agreement includes Engineer's Certification forms for 1) Operation
and Maintenance Policy, 2) Ongoing Operation and Maintenance, and 3) design and Construction
Adequacy. Each of the three forms refers to a IS-year contract lengt. This should be corrected to
refer to a 20-year contract length.
Staff Responsibilty
Staffs responsibilty in this case is to review the Firm Energy Sales Agreement between
Idaho Power and Dynamis Energy and recommend that the Commission either approve or
disapprove it. Staff must ensure that the rates in the Agreement fairly and accurately reflect Idaho
Power's avoided costs, and that the terms and conditions contained in the Agreement are in
compliance with PURPA. In exercising its responsibility, Staff must also ensure that Idaho Power
and its ratepayers are reasonably protected from adverse impacts of project delay, deficient
performance, default or termination.
STAFF COMMENTS 11 FEBRUARY 2,2012
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. Staff does not believe that the rates contained in this Agreement are an
accurate reflection of Idaho Power's avoided costs. Consequently, Staff recommends that the
Commission not approve the Agreement. First, Staff believes that Idaho Power made an error in
its computations of the capacity component of the rates, which would increase the rates in the
Agreement by about $1 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. Finally, Staff takes issue
with use of 2009 rather than 201 i IRP assumptions, use of a seven percent discount rate, and
extrapolation of the rates for the final five years of the Agreement.
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 parties. (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
curent understanding of the IRP methodology. Furhermore, Staff recognizes that there is
considerable room for negotiation, and that such flexibilty has been exercised in this case.
.1NbRespectfully submitted this ~day of February 2012.
~:"ja. ~QA. stine A. Sasser ~
Deputy Attorney General
Technical Staff: Rick Sterling
i:umisc:comments/ipce I i .2Sksrps comments
STAFF COMMENTS 12 FEBRUARY 2, 2012
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 2ND DAY OF FEBRUARY 2012,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-1l-25, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
DONOV AN E WALKER
JASON B. WILLIAMS
IDAHO POWER COMPANY
PO BOX 70 .
BOISE ID 83707-0070
E-MAIL: dwalken.ß1idahopower.com
jwiliamsØ)idahopower. com
C LLOYD MAHAFFEY
WADE D THOMAS
DYNAMIS ENERGY LLC
776 E RIVERSIDE DR STE 150
EAGLE ID 83616
E-MAIL: LloydØ)dynamisenergy.com
wthomasØ)dynamisenergy.com
RANDY C ALLPHIN
ENERGY CONTRACT ADMIN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: rallphinØ)idahopower.com
~~SECRETAR ~
CERTIFICATE OF SERVICE