20110916Reply Comments.pdf

WILLIAMS. BRADBURY
ATTORNEYS AT LAW
RECEIVED
zon SEP 16 AM II: 33
September 16, 2011
Ms. Jean Jewell
Commission Secreta
Idaho Public Utilities Commission
472 W. Washington
Boise,ID 83702
Re: IPC-E-ll-lO
Dear Ms. Jewell:
Please find enclosed an original and seven copies of Reply Comments of Interconnect
Solar Development, LLC for filing in the above referenced case.
Than you for your assistance in this matter. Please feel free to give me a call should
you have any questions.
Sincerely,J?~tJ~
Ronald L. Wiliams
RLW/jr
Enclosures
cc: Peter Richardson
1015 W. Hays Street - Boise, ID 83702
Phone: [phone] - Fax: [phone] - ww.wiamsbradbur.com
Ronald L. Willams, ISB No. 3034
Wiliams Bradbur, P.C.
1015 W. Hays St.
Boise,ID 83702
Telephone: [phone]
Fax: [phone]
ron~willamsbradbury.com
RECEIVED
2011 SEP 16 Mi ll: 33
Attorneys for Interconnect Solar Development, LLC
BEFORE THE IDAHO PUBLIC UTILITES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR A )
DETERMINATION REGARDING THE FIRM )
ENERGY SALES AGREEMENT WITH )
INTERCONNECT SOLAR DEVELOPMENT, )
LLC, FOR THE SALE AND PURCHASE OF )ELECTRIC ENERGY. )
)
Case No. IPC-E-ll-lO
REPLY COMMENTS OF
INTERCONNECT SOLAR
DEVELOPMENT, LLC
COMES NOW, Interconnect Solar Development, LLC, ("Interconnect Solar" or
"ISD") by and through its counsel of record, Wiliams Bradbur, PC, and files these
Reply Comments in response to Comments of Commission Staff.
Introduction
Idaho Power Company ("Idaho Power" or the "Company") and Interconnection
Solar entered into a Firm Energy Sales Agreement ("FESA" or "Agreement")) on May
11, 2011, and the Agreement was submitted to the Commission on June 17, 2011. On
September 9, 2011 Commission Staff recommended rejection of the Agreement for a host
of reasons primarily related to Staffs belief that the Company should have employed
different and untested avoided cost methodologies or used different modeling input
variables.
REPLY COMMENTS OF INTERCONNCT SOLAR DEVELOPMENT, LLC Page 1
Previously in this case Grand View PV Solar sought intervention because Grand
View suspected that Staff would propose, in the context of this case, changes in the
maner, methodologies or input varables in which Idaho Power calculates avoided costs
for solar projects greater than 100 kW. The Commission rejected Grand View's
intervention, stating that this case is "not the appropriate foru for Grand View Solar to
debate generally about how avoided costs are calculated." 1 The Commission also noted
the ongoing PURPA implementation investigation, saying: "It is though Case No. GNR-
E-II-03 that the Commission intends to address the larger issues surounding avoided
cost calculations and methodologies."i
What Grand View suspected could happen, and what the Commission said should
not happen, has in fact happened. That is, Staff has recommended significant policy,
methodology and input factor changes for "larger,,3 QF project avoided cost calculations.
No other paries or Qualifying Facilty (QF) communties of interest - and there are many
as evidenced by the parties in GNR-E-ll-03 - will have a chance to respond to Staffs
proposed fudamenta changes in avoided cost calculation.
The same reason the Commission used in denying Grand View's intervention-
that ths is "not the appropriate foru ... to debate generally about how avoided costs
are calculated" - applies equally to Staffs recommendations. For ths reason alone,
Staffs recommendations should be rejected and deferred into the Commission's generic
avoided cost case, now on a parallel track.
1 IPUC Order No. 32350, p. 2
2 ¡d.
3 In this case, larger projects refers to wind and solar projects greater than 100 kW and, for all other tyes
ofQFs, greater than 10 aMW.
REPLY COMMNTS OF INTERCONNECT SOLAR DEVELOPMENT, LLC Page 2
Staff's Proposed Methodology Changes to Capacity Valuation
1. CCCT Capita Costs, SCCT Capital Costs or Solar Capital Costs: The
first methodology change proposed by Staff is that the capita costs of a simple cycle
combustion turbine (SCCT) be used instead of the capital costs of a combine cycle gas
fired power plant (CCCT).4 Such a change fudamentally depars from the methodology
established by the Commission more than 15 years ago that has been applied consistently
ever since. If such change is waranted, it deserves and better scrutiny in GNR -11-03 than
Interconnect Solar has the time, ability and expertise to provide in this case.
The methodology employed for the last several decades for determining
avoided costs for smaller QFs5 is known within the industr as the "Proxy Method.,,6 In
1995 the Commission shifted from using a coal-fired power plant to a CCCT for puroses
of establishing proxy avoided costs, finding that: "Today, however, a gas CCCT is clearly
the curent choice of most utilities and Staff. We find that it is the most appropriate SAR
for use in calculating the published avoided cost rates."?
In a companion cases the Commission established the avoided cost methodology
for larger QFs, which the Commission determined as ineligible for the published or
"stadard" avoided cost rates. In this case the Commission approved a Stipulation of the
Paries and specifically approved Staff Exhibit 101, which adopted a Differential
Revenue Requirement (DRR) methodology to be used in setting avoided cost rates for
larger QF projects. This DRR methodology is now generally referred to as the "IRP
4 Staff Comments, p. 4.5 Wind and solar projects less than 100 kW and all other projects less than 10 aMW.
6 This methodology looks at all the costs (fixed and variable) of an avoided or surogate power plant and
develops avoided costs that mirror the plant's life costs.7 IPUC Order No. 25884, p. 3.
8 Case No. IPC-E-95-9
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Methodology." Worthy of note is that a third avoided cost methodology - the "Peaker
Method,,9 - was not adopted by the Commission for either smaller or larger QFs.
Staff Exhibit 101, attched to Staf Witness Sterling's direct testimony in the
1995-96 case, prescribed how the IRP/DRR methodology is to be employed by utilties in
calculating avoided costs. Ths Exhibit was specifically adopted by the Commission as
the approved methodology for calculating IRP/DRR rates for larger projects.10 Exhibit
lOt's section on "IRP Data for Avoided Cost Calculations" describes a new approach to
IRP calculated avoided costs where the Commission will no longer decide the modeling
assumptions and input variables for each utility in calculating IRP based avoided costs
(as had been the case with the avoided coal-fired avoided plant). Rather, Staff Exhbit
101 directed that: "With implementation of the IRP methodology, the Companies will be
responsible for determining those variables. As long as the values and assumptions fall
within a reasonable range, utilities are free to choose values most appropriate for their
own situation."ll
Very recently, the Commission approved IRP based rates for the Rockland Wind
project which were calculated using Idaho Power's AURORA dispatch modeL. In Order
No. 32125 approving the Rockland contract the Commission noted that application of
ths methodology "(is) consistent with the Commission requirements for projects larger
than 10 MW.,,12 Shifting, in this solar case, to use of a SCCT for avoided capital cost
9 When using the Peaker Method to calculate avoided costs, the utilty's power supply model is ru with
and without the given facility, at zero cost, to produce varable costs. Then, the capital costs of a peaking
unit are added to find full avoided costs.
10 In essence, Staff
Exhibit 101 requires Idaho Power to compares the present value of the Company's
revenue requirement (PVR) with and without the QF. Idaho Power's AURORA model accomplishes this
"differential" calculation with respect to energy values. Idaho Power then separately calculates avoided
capacity differentials.11 Exhibit 101, Case No. IPC-E-95-9, R. Sterling DI, Page 15 of24 (emphasis added).
12 IPUC Order No. 32123, p. 1. (emphasis added)
REPLY COMMENTS OF INTERCONNECT SOLAR DEVELOPMENT, LLC Page 4
differentials would be completely inconsistent with longstading Commission
requirements for the calculation of QF avoided cost rates for all PURPA projects, as
applied for almost two decades.
Since 1995, a CCCT proxy or surogate resource has been used to
establish Idaho Power's avoided energy and capacity for smaller QFs, and has also been
used to establish the capacity cost differential for larger projects pursuant to the DRRRP
methodology. The fact that there are many of the former/smaller projects and only a few
of the latter/larger ones does not justify Stafs recommendation to abandon the IRP/DRR
methodology for the larger projects and replace it with a Peakng Plant methodology.
That is essentially what Staff is recommending. In calculating avoided cost rates for
Rockland Wind and now for Interconnect Solar, Idaho Power has reasonably determined
that a capacity value differential based on a CCCT is the "most appropriate" application
of Commission directives as to how to calculate avoided costs. One needs look no fuher
than the curent construction of the Langley Gulch CCCT for affirmation of this
methodology and choice of input varables.
Staff also argues that use of capital costs of a SCCT is appropriate to calculate
solar avoided costs, because "(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.,,13 Both Staff and Idaho Power also
agree that a solar project's peak delivery occurs at the same time that Idaho Power's load
profile peaks. If ths case is to now investigate a possibly "better" (than CCCT) surogate
resource capital cost differential, then Interconnect Solar believes that the "best" avoided
capacity resource is not a SCCT but instead should be a solar facility. This is, in fact,
13 Staff Comments, p. 4.
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what Staff recommended in Case No. GNR-E-09-03 - different avoided costs rates for
different QF technologies, based on each technology's energy and capacity costs. Using
this alternative avoided cost methodology, a solar QF would receive a solar based
avoided cost calculated using solar capital costs - instead of gas-fired thermal generation
costs, either CCCT or SCCT. 14 Such a resources based avoided cost methodology would
also render moot the need to "guess" at what might be a "solar integration" rate discount,
15 a topic discussed in greater detail in a following section.
2. Staffs Comments and Idaho Power's Modeling Fail. to Recognize the
Actual Capacity Value of the Interconnect Solar PV System: In modeling the capacity
value of lSD's avoided cost rates, Idaho Power estimated lSD's capacity factor using
Idaho Power's rooftop solar facility. This factor alone unairly biased down lSD's
capacity avoided cost rate, for two reasons. First, the ISD solar facilties are not "fixed"
or immovable, like Idaho Power's, and instead are built on a single rotating axis allowing
for sun-tracking over the course of a day. Second, the solar panels to be installed by ISD
are of much greater solar effciency than Idaho Power's existing solar panels, due to
recent and rapid technology advancements. Yet even with these model biases already
working against ISD capacity pricing, Staff recommends that this bias be ignored because
the rates contained in the agreement are based on a 90 percent exceedance value, but
should have been based on more appropriate 100 percent exceedance value. Because of
14 For comparison puroses, the 30 year levelized capacity costs for thee different generating resources
are as follows: (i) $5.00 IkW for gas fied SCCT, (ii) $14.00Ikw for gas fired CCCT, and (ii) $28.00IkW
for Solar - Flat Plate. See Idaho Power Integrated Resource Plan, p. 84 of IRP Technical Appendix:
htt://www.idahopower.comlpdfs/ AboutUslPlaningForFutue/ïi/20 11120 11 IRP AppendixCTechnicalApp
endix.pdf
15 As Staff noted in its comments in Case No. GNR-E-09-03: "If a wind SAR is adopted, wind integration
charges would no longer have to be quantified." Staff Comments at p. 8.
htt://www.puc.idaho.gov/intemeticases/elec/GNRlGNRE0903/staff20090918COMMENTS.PDF
REPLY COMMENTS OF INTERCONNECT SOLAR DEVELOPMENT, LLC Page 6
the shortness oftime and complications raised regarding this issue16, Interconnect Solar is
unable to adequately respond to ths new issue raised by Staf and suggest it a better topic
for review in GNR-E-II-03.
Staff also conducted additional analysis that "fuher supports" a lower capacity
value than that assumed by Idaho Power" with respect to lSD's facilities. Ths additional
analysis leads to the false conclusion by Staff that on June 28, 2010 at 7:00 PM, the ISD
solar facilty would only be producing 1.8 MW of generation. I? In response, Siemens has
modeled lSD's production of energy from the proposed Murhy Flats project using
industry recognized solar modeling technques and software, and concludes to the
contrar that: "The predicted power produced between 15:00 and 19:00 (hours on June
28,2010) is 14 (average) MW. The system is capable to product 11 MW durng the 19:00
hour, not 1.8 MW as stated by the PUC (Staff) in their report." Attached as Exhbit 1 to
this Reply is Siemens' report regarding this very significant error by Staff, including a
graph showing actual modeled solar generation of the Murhy Flats project on June 28,
2010. Capacity price adjustments related to this modeling mistake are discussed later in
these Reply Comments in the section on Computational Errors.
3. Staff is Incorrect in Suggesting that AURORA Energy Prices Include
Capacity Values:Staff Comments on page 6 suggest that capacity values found in
the Agreement's rolled-in price are also overstated because AURORA energy prices
likely include some capacity value. is Staff offers no evidence to support this assertion
and rests it case on pure economic theory that a seller to Idaho Power must be recovering
16 i.e., is it appropriate to use one exceedance value for planing puroses and another for rate setting
puroses?
17 Staff Comments, p. 5.
18 Staff Comments, p. 6.
REPLY COMMENTS OF INTERCONNECT SOLAR DEVELOPMENT, LLC Page 7
some portion of its fixed cost - above its marginal cost, or else it would have no incentive
to sell. From a Seller's standpoint, this mayor may not be tre. But from a Buyer's
standpoint - from Idaho Power's standpoint - the Company is only modeling energy
purchases when it rus AURORA in an energy dispatch mode and not in a capacity
expansion mode.
AURORA also understates avoided energy costs for the reason that when it rus
in an energy dispatch mode for avoided cost calculation puroses, it does not take into
account likely carbon costs, taes or offsets. Ths is in contrast to when AURORA rus
for IRP planing puroses, where "The potential cost of carbon emissions is accounted
for in the IRP (AURORA modeling) by applying a carbon adder or tax.,,19
4. Stafs Suggestion To Not Make Capacity Payments Until Idaho Power
Needs New Capacity is Inappropriate in this Case: This reoccurring "theme" of paying,
or not paying, for capacity before capacity is needed, has been discussed and debated in
great detail throughout the 30 plus years ofPURPA implementation in Idaho.
Interconnect Solar will refrain from re-hashing the policy reasons and
Commission cases addressing why "bringing forward" or levelzing avoided capacity
costs over a contract life, within the context of an all-energy rate, has been established in
Idaho. It is suffcient for puroses of this case to only note two of the many Commission
proceedings addressing this issue. First, in Case No. IPC-E-93-28 (establishing the
methodology for IRP calculated rates) the Commission specifically required what Staff
now objects to: "We believe that levelization more accurately reflects the way in which
costs are recovered for utility-owned projects. The utilties are directed to provide
levelized rates, for all OF projects who desire it, utilzing the same procedure
19 DRAT Idaho Power 2011 IR, p. 94.
REPLY COMMNTS OF INTERCONNECT SOLAR DEVELOPMENT, LLC Page 8
incorporated in the SAR methodology.,,2o Second, this issue was again thoroughly
investigated in 2002 in Case No. GNR-E-02-01 with Staff in that case outlining nine
reasons why a utility's short term surlus should not be a reason to defer long term
capacity payments in PURPA contracts.21
If the specter of deferring the inclusion of avoided capacity costs in avoided cost
rates to match utility plant additions is to again rise, it should do so in GNR-E-II-03 and
not this contract approval case.
Staff's Proposed Solar Integration Charge
Staf proposes a solar integration charge of $6.50/MWh, equa to the wind
integration charge. Staff justifies this recommendation based on Idaho Power's response
to several production requests, including Response NO.5 where the Company said:
"Idaho Power expects there wil be some level of solar integration costs." Staf then
concludes that, because it must be something, $6.50/MWh is better than zero.
It is worth noting that the remainder of Idaho Power's response NO.5 goes on to
say that: "The level of integration costs will be less than wind generation due to the fact
that there is greater potential that solar generation projects will deliver expected energy
outputs to Idaho Power during times of Idaho Power peak energy needs (hot, suny,
sumer afernoons) on a more consistent basis." (emphasis added)Similarly, in
confdential response No. 15 Idaho Power reviews some of the public domain literature
regarding solar integration and notes the wide variety and often-times contradictory
conclusions that exist concerning the possibility or even the existence of solar integration
costs. Idaho Power also acknowledges in this confidential response that its review of the
20 IPUC Order No. 25884, p 8 of 11.
21 See Order No. 29124 at p. 5 - 9.
REPLY COMMENTS OF INTERCONNCT SOLAR DEVELOPMENT, LLC Page 9
existing literature on the topic leaves it unable to find any definitive information on the
existence of or methodology for calculating solar integration costs.
In essence, Staff has shifted the burden of proof to Interconnect Solar to now dis-
prove the existence of solar integration costs; otherwse it will be $6.50. Such sheer
speculation is not an accepted ratemaking practice. A voided cost rates under PURP A are
to be "fair, just and reasonable" as to both the utilty and the QF.22 Rates established by
this Commission pursuant to Idaho Code Section 61-301are to be "just and reasonable"
and based on credible evidence, not mere speculation. Neither of these fudamenta rate-
making stadards is met in Staffs recommendation to arbitrarily, and without any
credible evidence in support thereof, import a wind integration charge into a solar power
purchase agreement.
The Company's response to Staf Request NO.5 also states that it intends to begin
studying solar integration in the second half of 2011. Development of a solar integration
charge deserves the openness of multi-par paricipation and the many different expert
opinions that will likely emerge when Idaho Power's solar integration study is finished,
either in the context of GNR-E-II-03 or in a stand along case. This is simply not the case
to "guess" at and then implement a solar integration charge.
Staff's Recommendation to Apply Idaho Power's 2011 Integrated Resource Plan
Staff in general criticizes the use of the 2009 IRP and some of its input variables
to calculate the rates in the Agreement, suggests rates should be recalculated based on the
DRAFT 2011 IRP and makes a specific downward rate adjustment recommendation
based on 2011 IRP variables.
2218 CFR §292.304(a)
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Interconnect Solar is first compelled to again point out that it executed the FESA
with Idaho Power on May 11, 2011, that the Agreement was submitted to the
Commission for approval on June 17, 2011, and that Idaho Power's DRAFT 2011 IRP
was filed on June 30, 2011. Until the 2011 IRP is accepted by the Commission, it is stil a
work in progress and not a legitimate foundation for rate setting. 23 As Staf so accurately
said in 1995 in its Exhibit No. 101 "Staff recommends that updates to resource portfolio
data, such as plant capital costs, operation and maintenance costs, heat rates, generation
capabilty, plant factors, economic life, etc. not be allowed except during biennial IRP
submissions.,,24 Staffs recommendation in this case to 'jump" between the 2009 IRP to
the DRAT 2011 IRP is directly contrar to Staff Exhbit 101.
To fuher emphasize this point, it is patently unfair for Commission Staff to
"cherr pick" a variable from the 2011 IRP - such as the 2011 IRP weighted cost of
capital of 8.18 percent25 - and seek to apply it to the ISD Agreement, for the obvious and
admitted reason that ths adjustment lowers the avoided cost rate to be paid Interconnect
Solar. Approximately 50% of that 8.18% weighted cost of capital is a 10.5% retu on
equity - an unlikely ROE for Idaho Power in today's economic climate.26
Staff's Objection to Seasonal and Daily Weighting Factors
Staff objects to use of and weighting methodology in the Agreement concernng
daily and seasonal prices and instead recommends that the Agreement's pricing be
converted to "price shapes calculated by AURORA. . . rather than hourly and seasonal
23 On September 14,2011 a Notice of Modified Procedure was issued establishing a 60 day comment
period as to whether the Commission should accept or reject this DRAFT 2011 IRP.24 Id at p, 18.
25 Taken from Idaho Power's 2008 ratecase.
26 The Commission granted PacifiCorp a 9.9% ROE in its 2010 ratecase. Idaho Power also has a curent
ratecase pending before the Commission and, while ISD is not a paricipant in that case, ISD believes it
extremely unlikely Idaho Power wil see a Commission ordered ROE above 10% in that case.
REPLY COMMENTS OF INTERCONNCT SOLAR DEVELOPMENT, LLC Page 11
adjustment factors used for published avoided cost rates.',2 This recommendation
directly contradicts Staff Exhbit 101 where it states: "Staff believes utilities should be
permitted to continue to offer different rates for peak and off-peak hours, and to continue
to seasonalize rates (where curently allowed for Idaho Power and Washington Water
Power) using the same seasonalization factors allowed for projects smaller than 1
MW.,,2S Idaho Power was correct to seasonalize the rates contained in the ISD
Agreement and did so in conformance with Commission Order 26576 adopting Staff
Exhbit 101. Again, a change in this methodology is not appropriate in the context of this
contract approval case.
Scheduled Operation Date Prior to Interconnection Date Completion.
Staff recommends contract rejection for the reason that lSD's scheduled operation
date is before Idaho Power's estimated date to have completed the project's electrical
interconnection. Idaho Power has conservatively estimated it wil tae 18 months to
complete project interconnection, 12 months of which is reserved for the BLM to
complete the environmental studies associated with rebuilding and upgrading
approximately five miles of an existing distribution line. The Generation Interconnection
Agreement (GIA) forecasts a fall of2012 project interconnection.
This issue, and the business risks associated with it, has been of considerable
concern to Interconnect Solar and to Idaho Power. Even considering the adequate
contract provisions addressing this topic, Idaho Power required ISD to again
acknowledge in a separate letter the financial risk associated with this one item. And,
contractual provisions imposing liquidated damage (LD) provisions on ISD were
27 Staff Comments, p. 7.28 Exhibit No 101, Case No. IPC-E-95-9, R. Sterling DI, Page 22.
REPLY COMMNTS OF INTERCONNECT SOLAR DEVELOPMENT, LLC Page 12
repeatedly explained by Idaho Power and understood by ISD. In essence, if Interconnect
Solar is wrong on this point, the LDs more than adequately compensate Idaho Power and
its ratepayers for this mistae. In that context - that the ratepayer is fully protected from
this risk -Staffs recommendation for rejection is puzzling. With Idaho Power and its
ratepayers fully "covered" on this point, is this not simply a bi-Iateral contract negotiation
issue and not a 'public interest' issue deserving of a Staff rebuke?
In spite of conservatism on Idaho Power's par, Interconnect Solar believes there
is a high likelihood that BLM wil complete the necessary environmental reviews in a
timely fashion and in less than 12 months?9 The public notice of the line rebuild is
scheduled to be issued by the BLM before or near the time of fiing of these reply
comments, giving the public a 30 day notice period. Idaho Power anticipates having a
draft Environmental Assessment finished by the end of September, 2011. Interconnect
Solar believes it is likely that the BLM permitting process will be concluded within a six
month time frame, not the 12 months projected by Idaho Power. Additionally, ISD does
not believe it will not take Idaho Power six months to schedule construction and constrct
approximately five miles of a 34.5 kV line rebuild. Interconnect Solar has already held
discussions with Idaho Power and an Idaho Power approved sub-contractor whom has
indicated it could mobilize and constrct the line in approximately a two to four weeks,
once permits are in place
Staff and the Commission also need to understad the economics behind this
decision. If Interconnect Solar is wrong by 90 days or more and unable to generate power
during the sumer of2012, it will own Idaho Power approximately $900,000 in LDs. On
29 See Exhibit NO.2 for lSD's and Idaho Power's curent expectations regarding the interconnection
schedule.
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the other hand, if its makes its Scheduled Operation Date (SOD) of July 1, 2012, the
project will generate revenues at the contract rate for the next three 'premium' months
that will exceed the amount of LDs ISD would pay for missing the SOD. Conversely, if
the SOD was set for the fall of2012 and the project did begin generating by July 1,2012,
it would only be paid a "surlus energy rate" that is 85% of a short term indexed energy
rate, which very likely would only be a fraction of the contract rate. Given ths risk-
reward scenario, and in light of a straight-jacket FESA provision that forces a developer
to estimate - within a very short 90 day tolerance band - 'when' the SOD will occur,
ISD chose to accept the risk that an EA will be completed and the electrical
interconnection built in a time frame shorter than 18 months.
Computational Errors, REC Values and Carbon Offsets
As mentioned above, a major modeling error biased against Interconnect Solar
involved using the Company's aging rooftop solar panels as a surogate for lSD's solar
capacity. Based on the Company's rooftop solar experience it modeled IDS"s generation
at 36% of nameplate capacity for 90% of the peak hours between 4:00 PM to 7:00 PM.
This same assumption then resulted in valuing lSD's generation capacity at levelized
price of $32.88/MWh. Attched Exhibit 1 however paints a much different pictue of
available capacity from the ISD facility during these peak hours, showing that production
at Murhy Flats will not be 36% of nameplate, but instead will be 70% (14 MW/20 MW)
of nameplate between 4:00 PM and 7:00 PM and 55% (11 MW/20 MW) of nameplate for
the 7:00 PM hour. If lSD's correct capacity value for the 7:00 hour (of June 28, 2010;
Idaho Power's 2010 system peak) was used to calculate avoided capacity prices, instead
of the surrogate 36% value, it would have resulted in a levelized avoided capacity cost of
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$50.23/MWh, not $32.88/MWh. The net result of using Murhy Flats actual capacity
factors would also have resulted in a total levelized avoided cost $122.90, not $105.16.
Second, Interconnect Solar would call attention to the issues surounding
ownership of renewable energy credits (RECs) curently before the Commission in both
GNR-E-II-03 and in complaint Case No. IPC-E-II-15. This contrasts with the
negotiated resolution of the REC ownership issue as between ISD and Idaho Power
where the parties reached a volunta agreement to equally share REC ownership over
the life of the contract. Interestingly, Staff made no mention of this 'amicable' resolution
on an otherwse hotly contested issue and gave no "credit" to ISD for voluntarily
agreeing to this significant financial transfer for the benefit of Idaho Power's ratepayers.
Interconnect Solar was able to equally share RECs with Idaho Power for two
reasons: (i) Idaho Power agreed to a 25 year contract life, thus allowing ISD to satisfy
financing and debt service requirements over this longer period of time while accounting
for the lost revenue stream associated with half the potential REC revenues30, and (ii)
ISD did not have the luxur of time in litigating ths issue before the Commission, as
apparently does Grand View Solar. While it would be premature for Interconnect Solar
to sell RECs from a project with an Agreement not yet approved by the Commission, ISD
projects that first year REC revenues will equal, materially cover, or possibly exceed the
price discount associated with the "computational error" staf recommends as a reason for
contract rejection.
The only other case to come before the Commission involving a sharing of RECS
between Idaho Power and a developer is Rockland Wind; as case (as noted above) that
30 The Paries also agreed that the escalation rate to be applied to this last 5 contract years was to be 1.5%,
instead of the 3.2% escalation applied to the first 20 years of the Agreement.
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also involved an IRP derived avoided cost. In Rockland, like this case, the IRP modeled
avoided cost was less than the contract price. In fact, the Rockland contract price was
almost 27% greater than the IRP modeled price for Rockland's wind energy.31 For
comparison puroses, the "computational error" spread is approximately 11 %. Yet, Staff
in Rockland recommended approval of the Rockland contract: (i) because ''the AURORA
energy price contains no value for RECS,,32, (ii) because "(T) rates included in the
(Rockland) agreement, Staff notes, were the result of mutual negotiations,,33 and (iii)
because "Staff believes the prices in the (Rockland) agreement are reasonable." Staff
fuher noted in Rockland that "When REC ownership and other factors are considered as
well, the prices in the Agreement seem to Staff even more reasonable.,,34 Staff also
emphasized in Rockland that the "extended contract term at a reasonable cost" also
provided value to Idaho Power and its ratepayers. The same could be said for the ISD
Agreement. The similarties between the Rockland contract and the Interconnect Solar
Agreement are pervasive. Similar results in approving the Interconnect Solar Agreement
should also prevaiL.
Finally, Interconnect Solar would like to again point out that AURORA
understates avoided energy costs for the reason that when it rus in an energy dispatch
mode for avoided cost calculation puroses, it does not take into account likely carbon
costs, taes or offsets. This is in contrast to AURORA rus for IRP planning puroses,
where carbon costs are included.
31 The AURORA calculated levelized price for Rockland was $56.21.MWh, compared to the Rockland
levelized contract price of$71.29.MWh. Order No. 32125, p. 4.32 IPUC Order No. 32125, p. 6.
33 Id
34 Id
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If the Commission Orders that the Agreement between Interconnect Solar and
Idaho Power canot be approved without an eleven percent downward price adjustment
related to the "computation error," ISD would be unable to sign such a contract, for the
simple reason that the project would no longer be financeable. While this is not an issue
of concern for the Commission in setting avoided cost rates, it is an economic reality for
Interconnect Solar. In order to absorb such a price discount, Interconnect Solar would
need to reclaim all the RECs associated with the Murhy Flats project and would insist
that the correct Murphy Flats solar capacity values be used in the model ru, instead of
Idaho Power's solar plant surogate capacity values.
Idaho Power's Proposed Solar Demonstration Plant
In its DRAT 2011 IRP and in recent press releases to the public Idaho Power has
recognized that solar produced electricity is an excellent match to the utility's load
profie. The Company is proposing in its DRAT 2011 IRP that it build a Solar
Demonstration Project in 2013 of a size ranging from 500 kv to 1 MW, at a projected cost
of two to four milion dollars.35
Interconnect Solar would alternatively propose that Idaho Power make the
Murhy Flats solar project the utility scale demonstration plant that Idaho Power wishes
to build, at no cost to Idaho Power and a cost savings to Idaho Power ratepayers in the
amount of two to four milion dollars. Interconnect Solar, at its own cost, will install the
additional and necessary monitoring and measuring equipment that Idaho Power would
like to see installed in a solar demonstration plant that would provide Idaho Power real
time data to evaluate all aspects of the Murhy Flats solar project. Idaho Power personnel
would also be given full and open access to the Murhy Flats solar project.
35 IPCo DRAT 2011 IRP, p. 11.
REPLY COMMNTS OF INTERCONNECT SOLAR DEVELOPMENT, LLC Page 17
Conclusion
Interconnect Solar is drawn back to a two sentence quote from the Commission's
Order approving the Rockland Wind contract: "The value of each factor was not
individually quantified. Nevertheless, the rates included in the Agreement, Staff notes,
were the result of mutual negotiations." 36 Also in approving the Rockland contract the
Commission ". . . commend(ed) the paries for negotiating an Agreement that we (the
Commission) find sets forth a creative solution to resource issues that have heretofore
often resulted only in impasse and the filing of complaints.,,37
Staff, in this case, proposes a series of price adjustments for the ISD contract that
select certain factors that work towards a rate decrease. Interconnect Solar, as discussed
above, offers a host of equally compellng offsetting upwards price adjustments and
'value adders' that could or should also be considered, if the Commission is going to
delve back into the business (that it exited in 1995-1996) of picking and choosing factors
and varables for avoided cost modeling puroses.
Interconnect Solar suggests that a better course of action would be for the
Commission to step back and view this Agreement through the same lens as it viewed the
Rockland contract. This would allow the Commission to recognize that, while the ISD
Agreement may not be perfect, it represents the product of "mutual negotiations" that
resulted in an Agreement "both feasible for the developer and favorable to Idaho Power
customers", and that the Agreement submitted for approval, on a whole, "contains
36 Order No. 32125, p. 6.
37/d. at p. 10
REPLY COMMNTS OF INTERCONNECT SOLAR DEVELOPMENT, LLC Page 18
acceptable contract provisions. . . that are just and reasonable,,3s for Idaho Power, its
ratepayers and for Interconn~ Solar Development, LLC.
DATED: This / b't day of September, 2011.
,
J~,w LlJ~
Ronald L. Willams
Wiliams Bradbur P.C.
Attorneys for Interconnect Solar
Development, LLC
38id. at p. 10.
REPLY COMMENTS OF INTERCONNCT SOLAR DEVELOPMENT, LLC Page 19
CERTIFICATE OF SERVICE
I hereby certify that on this 16t~ay of September, 2011, a tre and correct copy
of the foregoing was served by the method indicated below, and addressed to the
following:
Donovan E. Walker D us Mail
Lead Counsel D Facsimile
Idaho Power Company D Hand Delivery
PO Box 70 D Overnight Mail
Boise,ID 83707-0070 ~E-Mail Address
E-Mail: dwalker~idahopower.com
Randy C. Allphin D US Mail
Energy Contract Admin.D Facsimile
Idaho Power Company D Hand Delivery
PO Box 70 D Overnight Mail
Boise,ID 83707-0070 ~E-Mail Address
E-Mail: rallphin~idahopower.com
Krstine A. Sasser D US Mail
Deputy Attorney General D Facsimile
Idaho Public Utilties Commission D Hand Delivery
PO Box 83720 D Overnght Mail
Boise,ID 83720-0074 ~E-Mail Address
E-Mail: krs.sasser~puc.idaho.gov
Randy Hemmer, Manager D US Mail
Interconnect Solar Development, LLC D Facsimile
3777 Twilight Drive D Hand Delivery
Boise,ID 83703 D Overnght Mail
E-Mail: randyhemmer~clearre.net ~E-Mail Address
fl rw 1 U,A
Ronald L. Wiliams
REPLY COMMENTS OF INTERCONNCT SOLAR DEVELOPMENT, LLC Page 20
SIEMENS Idaho Power Project—Murphy Flats Solar RFP#1.24.2011—SINVERT PVS Inverter Grid Integration Impact to Operations
I
In the following PVSYST graph,it is predicted that the plant will produce 199,983 kWh of AC power on
June 28t)1 for the entire day.PVSYST is a PV analysis tool used to plan and design PV power projects;
the value is calculated using many parameters from the array,the inverter,as well as other key setup
information.The weather data used in the calculation is recorded TMY data from the Mountain Home
AFB by NSRDB.
The predicted power produced between 15:00 and 19:00 is an average of 14MW.The system is capable
to produce 11MW during the 19:00 hour,not 1.8 MW as stated by the PUC in their report.
SfmuI.vaflant JinkO 5W
Exhibit 1 to Reply Comments of Interconnect Solar
9-16-11
EXHIBIT 2
( Excerpt from 9-14-11 email from Idaho Power Transmission
to Interconnect Solar)
Bill,
Here is where we are in the BLM process for Murphy Flats and an
estimated timeline for the remaining process:
Idaho Power will send a draft public scoping package to BLM next week
for their review.
Once the scoping package is mailed out (after BLM review and revision),
the clock will start on the 30 day comment period.
At the end of the 30 days, the BLM will forward any comments to Idaho
Power.
We anticipate it will be about 2 months after we receive comments that
a draft EA will be sent to the BLM for review and comment. A Plan of
Development (POD) will also be prepared and sent with the draft EA.
The BLM will need to review the EA and POD. This can take a few weeks
to a few months.
Idaho Power will need to revise the EA and then hopefully they acceptit.
Once the BLM accepts the EA, they will prepare a Record of Decision
(ROD), make sure there files are in order and offer us a right-of-waygrant.
It typically takes at least 2 months to get from acceptance of the EA
to getting a ROW offer. (There is typically a little back and forth onstipulations and minor corrections of the grant) .
Let me know if you have any questions.
Thanks,
Exhibit 2 to Reply Comments of Interconnect Solar
9-16-11