20101223Idaho Power Comments.pdf

RECEi
DONOVAN E. WALKER (ISB No. 5921)
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
dwalker(âidahopower.com
Inordstrom(âidahopower.com
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Attorneys for Idaho Power Company
Street Address for Express Mail:
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT PETITION )
OF IDAHO POWER COMPANY, AVISTA ) CASE NO. GNR-E-10-04
CORPORATION, AND PACIFICORP DBA )
ROCKY MOUNTAIN POWER TO ) COMMENTS OF
ADDRESS AVOIDED COST ISSUES AND ) IDAHO POWER COMPANY
TO ADJUST THE PUBLISHED AVOIDED )
COST RATE ELIGIBILITY CAP. )
)
Idaho Power Company ("Idaho Powet' or "Company"), by and through its
attorney of record, Donovan E. Walker, and in response to the Notice of Modified
Procedure issued in Order No. 32131 on December 3, 2010, respectfully submits the
Jollowing comments.
I. INTRODUCTION
On November 5, 2010, Idaho Power Company, Avista Corporation, and
PacifiCorp d/b/a Rocky Mountain Power ("the Utilties") filed a Joint Petition requesting
the Idaho Public Utilties Commission ("Commission") to initiate an investigation into
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various avoided cost issues regarding the Public Utilty Regulatory Policies Act of 1978
("PURPA") Qualifying Facilties ("QF"). Additionally, the Utilties requested that the
Commission issue an Interlocutory Order adjusting the published avoided cost rate
eligibility cap for QFs from 10 average megawatts ("aMW") to 1 00 kilowatts ("kW")
effective immediately.
On December 3, 2010, the Commission issued Notice of the Joint Petition and
Notice of Modified Procedure, Intervention Deadline, and Oral Argument setting a
Modified Procedure comment schedule with which to develop a record for its decision
regarding the Joint Petition and Motion's request to lower the published avoided cost
rate eligibility cap. Order No. 32131, Case No. GNR-E-10-04. Comments are due on
December 22, 2010; Reply Comments are due January 19, 2011; and Oral Argument is
scheduled for January 27, 2011. The Commission also ordered that its decision
regarding whether to reduce the published avoided cost rate eligibilty cap become
effective on December 14,2010. ¡d., at 6-7. In that Notice, the Commission stated that
it "wil first take up the request to reduce the eligibilty cap." ¡d., at 5. The Commission
set out three specific topics that it is interested in receiving comments upon:
(1) the advisabilty of reducing the published avoided cost
eligibility cap; (2) if the eligibilty cap is reduced, the
appropriateness of exempting non-wind QF projects from the
reduced eligibilty cap; and (3) the consequences of dividing
larger wind projects into 10 aMW projects to utilze the
published rate.
¡d.
In these Comments, Idaho Power wil address these three topics by submitting
comments supporting the initial request to reduce the published avoided rate eligibilty
COMMENTS OF IDAHO POWER COMPANY - 2
cap and seeking application of that published rate eligibilty reduction to all PURPA QF
projects.
II. BACKGROUND
Sections 201 and 210 of PURPA, and pertinent regulations of the Federal Energy
Regulatory Commission ("FERC"), require that regulated electric utilties, such as Idaho
Power, purchase power produced by cogenerators or small power producers that obtain
QF status. 16 U.S.C. § 824a-3(a). The rate a QF receives for the sale of its power is
generally referred to as the "avoided cost" rate and is to reflect the incremental cost to
an electric utilty of electric energy or capacity or both, which, but for the purchase from
the QF, such utilty would generate itself or purchase from another source. 16 U.S.C.
§§ 824a-3(b), (d). The Commission has authority under PURPA Sections 201 and 210
and the implementing regulations of the FERC, 18 C.F.R. § 292, to set avoided costs, to
order electric utilties to enter into fixed-term obligations for the purchase of energy from
QFs, and to implement FERC rules. See Connecticut Light and Power Co., 70 F.E.R.C.
11 61,012, 61,024 (1995).
Idaho Power has an obligation under federal law, FERC regulations, and this
Commission's Orders, that it has not been relieved of, to enter into power purchase
agreements with PURPA QFs. As stated in the Joint Petition filng, Idaho Power has
received a large amount, in terms of both volume and megawatts ("MW"), of requests
from PURPA QF developers demanding to enter into published avoided cost rate Firm
Energy Sales Agreements ("FESA"). The Company continues to process these
requests, in the ordinary course of business, and file the same for review with this
Commission, as is its legal obligation. However, the continued and unfettered addition
COMMENTS OF IDAHO POWER COMPANY - 3
of PUPRA QF generation onto Idaho Powets system carries with it several negative
and damaging effects to the both the utilty and its customers on system reliabilty, utility
operations, and the cost of providing energy to customers.
By lowering the published rate eligibility cap, the Commission would not be
eliminating PURPA's requirement that utilties purchase power from QFs. It would
simply be modifying the method in which the price, or avoided cost, is calculated and
established for the QF. See Southern California Edison Co., 70 F. E. R. C. 11 61 ,215,
61,677 (F.E.R.C. 1995) (FERC "has not, and does not intend in the future, to second-
guess state regulatory authorities' actual determinations of avoided costs (i.e. whether
the per unit charges are no higher than incremental costs)."). Despite what some may
argue, PURPA is not meant to incent renewable energy projects with the price that is
paid to a QF. In fact, an incentive price for QFs is ilegal under PURPA, as PURPA
requires prices to be set at the utilty's avoided cost, which is to reflect the incremental
cost to an electric utilty of electric energy or capacity or both, which, but for the
purchase from the QF, such utilty would generate itself or purchase from another
source. See Independent Energy Producers Association v. California Public Utiliies
Comm'n, 36 F.3d 848, 858 (9th Cir. 1994) ("If purchase rates are set at the utilty's
avoided cost, consumers are not forced to subsidize QFs because they are paying the
same amount they would have paid if the utilty had generated energy itself or
purchased energy elsewhere."). The incentive to QF development from PURPA is
therefore not in the price that a QF is entitled to but in the fact that the utilty is required
to contract with the QF. See 16 U.S.C. § 824a-3(a). Consequently, there is nothing in
the request to reduce the published rate eligibilty cap that is offensive to the "purpose"
COMMENTS OF IDAHO POWER COMPANY - 4
of PURPA. It is an action that is clearly within the authority and discretion of the
Commission, as it is the body charged with implementing the requirements of PURPA
and establishing each utilty's avoided cost.
Lowering the published rate eligibilty cap to 100 kW would essentially require all
PURPA QF contracts to be individually negotiated with an individually determined price
based upon that project's specific operating profile. This Integrated Resource Plan-
("IRP") based methodology for individually negotiated rates and contracts is a better
model with which to address the difficult issues raised by this case and a means to
possibly arrive at creative solutions that will stil allow the development of QF projects,
but in a manner that is better for customers and better for the utilties in that the price
would better reflect a value equivalent to that which the Company would receive if the
utility were to generate itself or purchase from another source. The recently approved
Rockland Wind Project FESA is a good example of this process and how it can result in
a project that is both feasible for the developer and more favorable to Idaho Power
customers than a project under the more prescriptive Surrogate Avoided Resource
("SAR") methodology.
PURPA requires that utilty customers be economically indifferent to the effects of
whether power is purchased from a QF or otherwise acquired (generated or purchased)
by the utilty. Southern California Edison Co., 71 F.E.R.C. P 61,269,1995 WL 327268
(F.E.R.C. 1995) ("The intention (of PURPA) was to make ratepayers indifferent as to
whether the utility used more traditional sources of power of the newly-encouraged
alternatives."). When the utilty is forced to buy QF power in excess of its true avoided
cost, or in excess of its minimum loads, customers are no longer indifferent. The issues
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raised in this docket should be addressed by the Commission at this time and not after
the impacts on customers have become inevitable and acute.
As recently as November 2, 2010, in the Yellowstone Power case, the
Commission reiterated to Idaho Power that, "we intend for the Company to assist the
Commission in its gatekeeper role of assuring that utilty customers are not being asked
to pay more than the Company's avoided cost for the QF contracts. We expect Idaho
Power to rigorously review such contracts." Order No. 32104. Even though Idaho
Power is legally obligated to continue to negotiate, execute, and submit PURPA QF
contracts for Commission review, it also feels obligated to call attention to several
problems with the current methodology: (1) the continuing and unchecked requirement
for the Company to acquire additional intermittent and other QF generation regardless
of its need for additional energy or capacity on its system or the availabilty of other
lower cost resources; (2) circumvention of the IRP process; (3) system reliabilty and
operational issues; and, most importantly, (4) it dramatically increases the price that
customers must pay for their energy needs beyond that which would otherwise be
considered prudent.
II. THE ADVISABILITY OF REDUCING THE PUBLISHED
AVOIDED COST RATE ELIGIBILITY CAP
In the Joint Petition, Idaho Power stated that today it has over 208 MW of wind
generation currently operating on its system with an additional 264 MW of Commission-
approved QF wind contracts, many of which are currently under construction and
scheduled to be on-line by December 31, 2010. Additionally, the Company stated that it
had 80 MW of QF wind pending approval at the Commission and over 570 MW of new
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QF wind contract requests for a total of over 1,100 MW of wind powered generation
potentially entering Idaho Powets system in the near term.
Since the November 5, 2010, Joint Petition filing, the Commission has approved
the 80 MW of wind generation that was pending and Idaho Power has filed 23 signed
PURPA contracts with the Commission for review which represent over 450 MW of wind
generation (twenty contracts) and about 12 MW of non-wind generation (three
contracts). To update the numbers from the Joint Petition, as of December 20, 2010,
Idaho Power has over 326 MW of wind on-line, over 678 MW of signed QF contracts for
wind, and another 162 MW in contract discussions - which totals over 1166 MW of
wind. See Attachment NO.1 (Wind Project Summary) and Attachment NO.2 (showing
all PURPA QFs). Attachments Nos. 1 and 2 itemize the wind and all-source QF
generation that is currently on-line, pending Commission decision, or in contract
negotiations.
The additional 678 MW of signed QF wind contracts that have been submitted to
the Commission represent a total payment amount of over $3.9 bilion over the 20-year
term of the agreements. This estimate was calculated assuming a 2011 on-line date
and an average annual capacity factor of 32 percent. The 162 MW of wind generation
currently under contract discussions represents an additional total payment of over
$932 millon based on the same assumptions. For comparison, Idaho Powets total
approved rate base is just over $2 bilion.
Idaho Power is deeply concerned with the increase in power supply costs due to
these contracts, and the resulting increase in rates to its customers, that the current
published avoided cost, SAR methodology, causes. The Company projects that with
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the current amount of QF wind under contract and in contract discussions at published
avoided cost rates assumed to be at 614 MW, that customers wil face an additional
cost averaging in excess of a $48 millon PURPA premium above other, lower cost
resources through at least 2020. This equates to an approximate 5 percent rate
increase in the Company's Power Cost Adjustment ("PCA").
A. Approved Avoided Cost Methodologies - The Surrogate Avoided
Resource and the IRP-Based Approach.
The Commission has authorized two methods for establishing the avoided cost
rate that a QF is entitled to receive in its FESA with an Idaho utilty. One method is
applicable to those QFs that generate less than 10 aMW on a monthly basis. This
method establishes the published avoided cost rate, and is set by the Commission
using the cost of a SAR. The current SAR is a natural gas-fired combined-cycle
combustion turbine. The other method is applicable to QFs that are larger than 10 aMW
or, in other words, wil generate in excess of 10 aMW on a monthly basis. This method
is generally referred to as the IRP-based methodology. In the IRP-based methodology,
the QF's generation profile is utilzed with the utilty's power supply modeling program to
establish a base price for the QF's generation. Adjustments to that base price, if any,
are based upon a project's individual characteristics and are separately considered by
the Commission.
In Order No. 30873, the Commission described how the SAR methodology has
evolved over time. In fact, it was just over thirty years ago, on August 8, 1980, when the
Commission issued its first order, Order No. 15746, establishing the principles
applicable to purchases of power from PURPA QFs. In Order No. 15746, the
Commission determined that each of the three utilities would use a hypothetical
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baseload coal-fired generating plant as the generation facilty that could be deferred or
avoided. As such, the cost of this coal-fired facilty would be used to set avoided cost
rates. In 1993, Case No. IPC-E-93-28, the Commission concluded that the avoidable
resource or SAR should no longer be a coal-fired generating plant but instead should be
a natural gas-fired combined-cycle combustion turbine.
The more prescriptive SAR-based published avoided cost methodology was
developed and intended for smaller projects and the more unsophisticated developers
in part to ease the administrative burden on the developer and to "level the playing field"
in negotiating the economic components of a QF contract. This concept, which has its
inception in the Commission's 1980 Order, dates back to the infancy of the Public Utilty
Regulatory Policies Act of 1978. This concept was accepted and/or tolerated in order to
accommodate small QF developers because historically (1) small QF developers
generally had fewer resources to dedicate to complex contract negotiations and (2) the
financial impact to the utilty's customers for a relatively low volume of small QF projects
was likewise small.
However, in the passage of the last thirty years, the size and scale of projects
that are able to qualify for the published avoided cost rates has increased dramatically.
Many of the current QF projects in actuality are not "small" projects but are large, utilty-
scale projects that are broken up into 10 aMW increments in order to qualify for the
published avoided cost rates. Likewise, the historical "unsophisticated" QF project
developers are no longer the norm, and QF projects have evolved to the point where
they are sophisticated parties who are very knowledgeable within this field. In fact, in
COMMENTS OF IDAHO POWER COMPANY - 9
many instances, QF developers have large resources available to them and in some
cases may be larger entities than the utilties themselves.
B. Problems with the SAR Methodology.
The SAR methodology currently used in the calculation of the avoided cost rates
paid to QFs is a generic calculation which has at least three specific problems
associated with it. First, the SAR methodology does not represent the actual costs
avoided by adding a specific PURPA resource to Idaho Powets resource portolio. A
system specific analysis, such as the IRP-based methodology, that considers the
characteristics of the specific resource under question is necessary to determine a more
accurate assessment of the costs avoided as a result of adding a specific PURPA
resource. A true avoided cost determination, which would be appropriate for renewable
projects that generate renewable energy certificates ("RECs"), would consider the cost
to the utilty to develop and operate a similar project over a 20-year period. This would
take into account the RECs, government tax incentives, accelerated depreciation
allowances, and other similar cost incentives that the utility, and its customers, would
have the advantage of if the utilty were to build the resource, and that currently
generate a double recovery windfall to the QF developer.
Second, the SAR methodology is essentially a static methodology. The
published avoided cost rates calculated with the SAR methodology are updated
infrequently at best; yet the power markets, natural gas costs, resource construction
and development costs, government tax incentives, and other costs can vary on a day-
to-day basis. The SAR methodology essentially gives PURPA developers a free option
to force a QF's output onto the utilty at the published avoided cost rate. When it
COMMENTS OF IDAHO POWER COMPANY - 10
becomes profitable for PURPA developers to develop their projects, regardless of
whether Idaho Power needs the project's output and regardless of the cost impacts on
existing customers, they proceed with development and exercise their option to "put" the
project's output to Idaho Power.
Third, all PURPA resources are not equivalent. See e.g., 18 C.F.R. §
292.304(c)(3)(ii) (avoided costs may "differentiate among (QFs) using various
technologies on the basis of the supply characteristics of the different technologies.").
In other words, two different resources under similar FESAs at the published avoided
cost rate can provide significantly different levels of value to Idaho Powets customers -
cost and value are two very different things. For example, a high capacity factor QF
such as a biomass project which produces a significant amount of light load energy and
a solar project which produces little, if any, light load energy, can bring significantly
different levels of value to a utilty's system and its customers. If the utilty is surplus
during light load hours, then a significant portion of energy produced by any QF during
light load hours wil need to be sold into the market - most likely at a significant loss.
Idaho Power is concerned about any new PURPA projects and their associated
impact on customers. However, PURPA wind projects in particular present a number of
challenges, not only because of the unique nature of their generation but also because
of the magnitude and volume of proposed QF wind projects, that require a closer
examination to determine the real costs associated with adding these resources.
C. Circumvention of the IRP Planning Process.
The IRP planning process conducted by Idaho Power is designed to determine
the best mix of resources needed to meet future load growth considering cost, risk, and
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environmental concerns. This process was established in the early 1990s and has
evolved over the years to include significant input from stakeholders, including major
customer representatives, government agencies, environmental groups, and the
general public. The current state of PURPA development in Idaho has created a
situation where the IRP planning process is being circumvented in order to benefit
independent developers wanting to build generation projects in Idaho Powets service
area.
The recent flood of PURPA wind projects in Idaho Powets service area wil put
the total amount of wind generation on Idaho Powets system over 1,100 MW. In order
to integrate this amount of wind generation, the IRP process wil need to focus solely on
dispatchable resources (such as natural gas-fired combustion turbines) that can provide
operating reserves necessary to integrate wind.
For the past several years, Idaho Powets resource planning needs have been
driven by summertime peak-hour loads. This has been demonstrated with the addition
of approximately 430 MW of dispatchable simple-cycle combustion turbines,
development of Langley Gulch to add approximately 300 MW of dispatchable
combined-cycle combustion turbine capacity, and demand response programs (i.e.,
Irrigation Peak Rewards, AlC Cool Credit, and FlexPeak Management programs),
focused on reducing summertime peak-hour loads. Wind resources are not a
dispatchable resource and the Company cannot depend on serving any significant
portion of peak-hour summertime loads with wind resources. At present, for planning
purposes, Idaho Power uses a 5 percent capacity expectation for wind resources. So,
for each 100 MW of nameplate wind generation in its resource portolio, Idaho Power
COMMENTS OF IDAHO POWER COMPANY - 12
plans on receiving 5 MW during the summertime peak-hour load. Actual performance
of the wind projects under contract to Idaho Power during the summer of 2010 suggests
that a 5 percent capacity expectation is accurate.
While a majority of the new developments being proposed are wind projects,
many of the current issues surrounding PURPA are relevant to all generation
technologies that can be certified as a QF under the rules of the FERC. When the
Public Utilty Regulatory Policies Act of 1978 was enacted, it was envisioned as a way
to allow small, renewable projects to be developed, projects that would be considered
too small by utilty standards. See e.g., Southern California Edison Co., 71 F.E.R.C. P
61,269,1995 WL 327268 at *6 (F.E.R.C. 1995) (Congress intended PURPA to diversify
generation fuel mix and encourage renewable technologies). The concept of avoided
cost rates was used to ensure the cost to customers was no more than a utilty's cost to
develop a larger project. Id. However, the quantity of PURPA development currently
being seen in Idaho was never contemplated when the PURPA rules were establish by
the Commission. The current avoided cost rates, combined with tax credits and other
incentives, have created a situation where independent developers can easily justify the
economics of (and finance) PURPA projects. The economics are in fact so favorable
developers are taking utilty scale projects and breaking them into smaller than 10 aMW
projects in order to qualify for avoided cost rates. The result is that the Company's
extensive IRP process, which is mandated and overseen by the Commission, is being
circumvented by the current Idaho requirements of PURPA. The least cost planning
aspects of the IRP process are also being circumvented in the process. The flood of
PURPA projects onto the Company's system is now dictating the resource "choices" in
COMMENTS OF IDAHO POWER COMPANY - 13
down or being unavailable to serve load the next day or for the next peak hour.
Similarly, hydro cannot be taken to zero given minimum stream flow levels and resultant
environmental effects.
This surplus electricity, if it cannot be used to serve Idaho Power load, must be
moved across the system and sold into the market. The only available transmission
capacity to move this electricity off the system and to market is across the Idaho to
Northwest path. Idaho to Northwest transmission capacity has an operating rating of
2,304 MW and PacifiCorp has rights to up to 1,600 MW of that amount. That leaves
Idaho Power with a maximum of 704 MW of transmission capacity to the Northwest,
under normal operation conditions, which is insufficient to move the amount of surplus
that could exist.
F. The Continued Addition of QF Generation at Published Avoided Cost
Rates is Very Costly to Customers.
Assuming that all of the integration costs have been addressed, the fact of the
matter is that if 614 MW of the QF contracts currently submitted for review to the
Commission or in contract discussions at published avoided cost rates are approved,
and if all of the PURPA wind under contract is built, Idaho Power wil be purchasing the
output of these projects at prices significantly greater than recent, and expected, market
prices. Figure 3 below shows the average light load surplus from Figure 2, and
superimposes curves representing the non-Ievelized PURPA rates during LL hours and
recent Mid-C market prices. This ilustrates the premium being paid for QF energy over
market prices at a time when the Company does not need the energy.
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through 2020 (assuming all projects are on-line and operating in 2011), of entering into
these QF contracts is over $325 milion. These calculations do not include transmission
costs, which may actually increase the cost to customers even more. The bottom line is
that these QF contracts are far more costly to customers than would be suggested by
recent Mid-C prices.
An additional $48 millon in above-market costs equates to a rate increase of
around 5 percent in the Company's PCA. It is difficult to see how the customers are
held neutral, or indifferent, with a requirement to enter into FESAs, at above-market
prices, for power that is not needed on the system and also withholds the value that
could be derived from the RECs.
IV. THE APPROPRIATENESS OF EXEMPTING NON-WIND QF PROJECTS
FROM THE REDUCED ELIGIBILITY CAP
The second issue that the Commission requested comments upon is "if the
eligibilty cap is reduced, the appropriateness of exempting non-wind QF projects from
the reduced eligibilty cap." Order No 32131 at 5. All PURPA QF projects should be
included in the published avoided cost rate eligibilty cap reduction for the simple reason
that they all contribute to the same problems discussed above. All QFs generate during
light load hours and contribute to the price and cost differentials already discussed. The
lack of any consideration of the utilty's need for the energy, or load, in relation to when
the QF supplies generation that the utilty must take from it does not change because
the QF is a non-wind resource.
Additionally, as stated above, the more prescriptive SAR-based published
avoided cost methodology was developed and intended for smaller QF projects and the
more unsophisticated developers in part to ease the administrative burden on the
COMMENTS OF IDAHO POWER COMPANY - 19
developer and to "level the playing field" in negotiating the economic components of a
QF contract. This concept was accepted and/or tolerated in order to accommodate
small QF developers because historically (1) small QF developers generally had fewer
resources to dedicate to complex contract negotiations and (2) the financial impact to
the utility's customers for a relatively low volume of small QF projects was likewise
small. However, this is no longer the case. The historical "unsophisticated" QF project
developers are no longer the norm, and QF projects have evolved to the point where
they are sophisticated parties who are very knowledgeable about the ups and downs of
the PURPA process as well as negotiation of a QF contract. Likewise, with the
cumulative nature of more than thirty years of QF projects entering onto the system, as
well as the more recent phenomenon of larger and larger projects that are able to break
themselves into 10 aMW increments, it can no longer be said that the financial impact to
the utilty's customers from any QF project, no matter how small, has a "small" impact to
the rates that they pay for electricity.
While the scale of wind QFs is much larger, many of the same problems are, and
the same financial harm is, caused by non-wind QFs just the same. A reduction in the
published rate eligibility should apply equally to all QF projects.
V. THE CONSEQUENCES OF DIVIDING LARGER WIND PROJECTS INTO
10 aMW PROJECTS TO UTILIZE THE PUBLISHED RATE
The third issue that the Commission requested comments upon is "the
consequences of dividing larger wind projects into 10 aMW projects to utilze the
published rate." Order No. 32131 at 5. There are many negative consequences, some
of which have already been referred to above, of the ease and abilty of large QF
projects, particularly large wind farms, to break themselves up into 10 aMW increments
COMMENTS OF IDAHO POWER COMPANY - 20
in order to qualify for the published avoided cost rate ("disaggregate" or
"disaggregation") and avoid the individualized IRP-based methodology that is supposed
to be applied to "Iarget' QF projects. Many of the "problems" discussed above are the
"consequences" of these larger projects' abilty to divide into 10 aMW increments. It is
especially beneficial to an intermittent resource that provides a significant portion of
energy primarily during light load times, or more particularly outside of the system peak
hours to have a locked-in price that does not take into account the value of the energy
that it provides, the need for the energy during the time in which it is provided, nor the
availabilty of lower cost resources. This ultimately results in the most serious
consequence of dramatically inflating the cost of power and the rates that customers
must pay. Additionally, this abilty to disaggregate compromises a utilty's competitive
acquisition processes in the form of requests for proposals ("RFP").
The Company has seen the issue of disaggregation as a potential problem for a
number of years, and attempted to address the same in Case No. IPC-E-07-04. In that
case, the Company proposed a five mile separation, rather than the currently accepted
one mile separation required by FERC to be certified as a QF, between QF projects in
order for the projects to be considered separate and distinct QFs. This was rejected by
the Commission Staff and ultimately the Commission. Order No. 30415. The
Commission stated:
The Company asks the Commission to impose an ownership
restriction on projects located within what we find to be an
arbitrary "five-mile radius." This would be in addition to the
geographic separation required by FERC for QF status.
While it may be that it is "not Idaho Powets intent that its
proposed five mile radius rule place undue burdens on the
development of new QF generation projects," we cannot find
that without change abuse wil occur and the public interest
COMMENTS OF IDAHO POWER COMPANY - 21
will not be served. Petition, p. 5. It is a change that we find
would encourage and might actually promote
gamesmanship. On the basis of the established record we
find no reason to change the eligibilty criteria for published
rates to require a standard different than FERC QF status
requirements.
Order No. 30415 at 11.
Since the time of the Commission's Order No. 30415, issued on September 7,
2007, the norm for PURPA wind projects has been to take larger QF projects, create
multiple legal entities, and reconfigure into multiple smaller projects in order to qualify
for the published avoided cost rate and to avoid the more precise and individualized
IRP-based methodology. In fact, the great majority of all QF wind projects follow just
this type of development modeL. As can readily be seen by even a cursory look at
Attachment NO.1, the list of all of the existing and proposed QF wind projects for Idaho
Power's system, as well as a review of Attachment No.3, which is a map showing the
general location of these QF wind projects, nearly all of them are disaggregated large-
scale projects that should be negotiating PURPA contracts under the IRP-based
methodology.
Additionally, a slightly closer look at the last twenty QF wind contracts that have
been filed for review with the Commission since November 2010 shows that these
twenty, less than 10 aMW, published rate projects all belong to just four different
developers and ultimate owners - and are physically located in only five different
locations. They are large projects, and are disaggregating with the purposeful intent of
gaining access to the published avoided cost rates and avoiding the IRP-based
methodology. This practice is inflating the cost borne by Idaho Powets customers and
COMMENTS OF IDAHO POWER COMPANY - 22
providing an energy product that is not only not needed on the system but causes
additional problems for reliabilty and operations.
Another significant fact about the large group of these most recently proposed
QF wind projects is that the overwhelming majority (nearly all) of them were proposed
projects in the unsuccessful 2012 wind RFP issued by Idaho Power in 2009, which
Idaho Power recently concluded without awarding a contract. In the RFP, Idaho Power
received bids from 25 projects, or project configurations, from 14 different bidders. The
proposed projects ranged in size from 50 MW to 160 MW. The bids included projects in
Idaho, Utah, Wyoming, Montana, Washington, and Oregon. The 20-year levelized
prices ranged from approximately $85 per MWh to almost $150 per MWh. Many of
these projects have reconfigured to disaggregate into 10 aMW projects, and have
demanded and executed published rate QF contracts at the equivalent of a 20-year
levelized price of $82.38 per MWh (if the project came in during 2011). This is
gamesmanship to the detriment of Idaho Power and its customers.
While the Company believes that a change in the required separation between
QF projects still has some merit, the request to lower the published rate eligibilty cap
accomplishes a similar result from a somewhat different and better approach. By
lowering the cap, the IRP-based methodology that previously only applied to larger QF
projects over 10 aMW would now apply to essentially all QF projects and remove the
incentive to break up larger projects to technically meet one mile of separation because
there would no longer be a disparate price advantage, either real or perceived, in doing
so. The issue of disaggregation would no longer be an issue because all wind projects
would have to negotiate an individually priced contract under the proper IRP-based
COMMENTS OF IDAHO POWER COMPANY - 23
methodology meant to apply to the acquisition of the resources they are sellng. A
"truet' avoided cost could be sought and the individual characteristics and uniqueness
of these larger projects could better be taken into consideration, as was the intent of the
IRP-based methodology for larger projects.
Vi. CONCLUSION
There is a huge problem here. The great advantages that Idaho Power
customers, its service territory, and its region enjoy from consistently having among the
very lowest electricity prices in the nation are being eroded and eviscerated by a flood
of QF generation that we are paying too much for. Idaho Power is forced to purchase
this power with no regard to whether it is needed on its system, with no regard to
whether it is called for in the Company's IRP process, and with no regard to whether
there are other lower cost alternatives for its customers. Additionally, the Company is
forced to deal with the difficult tasks and problems associated with integrating large
amounts of intermittent and uncertain renewable generation into its system, once again
with its customers paying the resulting price. Customers do not even get the "benefits"
derived from the renewable aspects of that generation in the form of RECs, nor is the
Company even able to "claim" or get credit for the existence of that renewable energy
on its system.
The Company does not expect the parties, nor the Commission, to solve all of
the issues or problems identified with avoided costs and QF generation at this moment.
However, we are fortunate that an existing, approved avoided cost methodology, the
IRP-based methodology, exists and, as demonstrated herein, is a very reasonable
COMMENTS OF IDAHO POWER COMPANY - 24
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 22nd day of December 201 0 I served a true and
correct copy of COMMENTS OF IDAHO POWER COMPANY upon the following named
parties by the method indicated below, and addressed to the following:
Commission Staff
Donald L. Howell, II
Kristine Sasser
Deputy Attorney General
Idaho Public Utilties Commission
472 West Washington
P.O. Box 83720
Boise, Idaho 83720-0074
Avista Corporation
Michael Andrea
Clint Kalich
Avista Corporation
1411 East Mission Avenue - MSC-23
P.O. Box 3727
Spokane, Washington 99220-3727
PacifiCorp d/b/a Rocky Mountain Power
Daniel E. Solander
J. Ted Weston
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Bruce Griswold
PacifiCorp
825 NE Multnomah
Portland, Oregon 97232
Exergy, Grand View Solar, J. R. Simplot,
Northwest and Intermountain Power
Producers Coalition, & Board of
Commissioners of Adams County, Idaho
Peter J. Richardson
Greg Adams
RICHARDSON & O'LEARY, PLLC
515 North 2ih Street
P.O. Box 7218
Boise, Idaho 83702
COMMENTS OF IDAHO POWER COMPANY - 26
-- Hand Delivered
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FAX
-- Email don.howell(ãpuc.idaho.gov
kris.sasser(ãpuc. idaho.gov
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-- Email michael.andrea(ãavistacorp.com
clint.kalichcæavistacorp.com
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-- Email daniel.solandercæpacificorp.com
ted.westoncæpacificorp.com
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-- Email bruce.griswoldcæpacifiCorp.com
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-- Email petercærichardsonandoleary.com
gregcærichardsonandoleary.com
Exergy Development Group
James Carkulis, Managing Member
Exergy Development Group of Idaho, LLC
802 West Bannock Street, Suite 1200
Boise, Idaho 83702
Grand View Solar II
Robert A. Paul
Grand View Solar II
15960 Vista Circle
Desert Hot Springs, California 94221
J.R. Simplot Company
Don Sturtevant, Energy Director
J.R. Simplot Company
One Capital Center
999 Main Street
P.O. Box 27
Boise, Idaho 83707-0027
Northwest and Intermountain Power
Producers Coalition
Robert D. Kahn, Executive Director
Northwest and Intermountain Power
Producers Coalition
1117 Minor Avenue, Suite 300
Seattle, Washington 98101
Renewable Energy Coalition
Thomas H. Nelson, Attorney
Renewable Energy Coalition
P.O. Box 1211
Welches, Oregon 97067-1211
John R. Lowe, Consultant
Renewable Energy Coalition
12050 SW Tremont Street
Portland, Oregon 97225
Cedar Creek Wind, LLC
Ronald L. Willams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, Idaho 83702
COMMENTS OF IDAHO POWER COMPANY - 27
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-- Email jcarkuliscæexergydevelopment.com
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-- Email robertapauicægmail.com
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-- Email don.sturtevantcæsimplot.com
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-- Email rkahncænippc.org
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-- Email nelsoncæthnelson.com
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-- Emailjravenesanmarcoscæyahoo.com
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-- Email roncæwiliamsbradbury.com
Scott Montgomery, President
Cedar Creek Wind, LLC
668 Rockwood Drive
North Salt Lake, Utah 84054
Dana Zentz, Vice President
Summit Power Group, Inc.
2006 East Westminster
Spokane, Washington 99223
Idaho Windfarms, LLC
Glenn Ikemoto
Margaret Rueger
Idaho Windfarms, LLC
672 Blair Avenue
Piedmont, California 94611
Interconnect Solar Development, LLC
R. Greg Ferney
MIMURA LAW OFFICES, PLLC
2176 East Franklin Road, Suite 120
Meridian, Idaho 83642
Bil Piske, Manager
Interconnect Solar Development, LLC
1303 East Carter
Boise, Idaho 83706
Intermountain Wind LLC
Dean J. Miler
McDEVITT & MILLERLLP
420 West Bannock Street
P.O. Box 2564
Boise, Idaho 83701
Paul Martin
Intermountain Wind LLC
P.O. Box 353
Boulder, Colorado 80306
COMMENTS OF IDAHO POWER COMPANY - 28
Hand Delivered
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-- Email scottcæwesternenergy.us
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-- Email dzentzcæsummitpower.com
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-- Email glennicæEnvisionWind.com
MargaretcæEnvisionWind .com
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-- Email gregcæmimuralaw.com
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-- Email bilpiskecæcableone.net
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-- Email joecæmcdevitt-miler.com
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-- Email paulmartincæintermountainwind.com
Dynamis Energy, LLC
Ronald L. Wiliams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, Idaho 83702
Wade Thomas, General Counsel
Dynamis Energy, LLC
776 East Riverside Drive, Suite 15
Eagle, Idaho 83616
North Side Canal Company and Twin
Falls Canal Company
Shelley M. Davis
BARKER ROSHOLT & SIMPSON, LLP
1010 West Jefferson Street, Suite 102
P.O. Box 2139
Boise, Idaho 83701-2139
Brian Olmstead, General Manager
Twin Falls Canal Company
P.O. Box 326
Twin Falls, Idaho 83303
Ted Diehl, General Manager
North Side Canal Company
921 North Lincoln Street
Jerome, Idaho 83338
Board of Commissioners of Adams
County, Idaho
Bil Brown, Chair
Board of Commissioners of
Adams County, Idaho
P.O. Box 48
Council, Idaho 83612
COMMENTS OF IDAHO POWER COMPANY - 29
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-- Email roncæwillamsbradbury~com
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-- Email wthomascædynamisenerg.com
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-- Email smdcæidahowaters.com
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-- Email olmsteadcættcanal.com
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-- Email nscanaicæcableone.net
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-- Email dbbrowncæfrontiernet.net
Birch Power Company
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 11 th East
Idaho Falls, Idaho 83404
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-- Email tedcætsorenson.net
c£~w~
Donovan E. Walker
COMMENTS OF IDAHO POWER COMPANY - 30
Idaho Power Company
Cogeneration and Small Power Production
As of December 20,2010
Project Resource
Number Dm Prolec Name State County Project Size (MWl
Projects Online
1 21615205 Hydro Arena Drop ID Canyon 0.45
2 31616150 Digester B6 Anaerobic Digester ID Gooding 2.28
3 21615078 Hydro Barber Dam ID Ada 3.70
4 21615101 Wind Bennett Creek Wind Farm ID Elmore 21.00
5 31615100 Digester Bettencourt Dry Creek BioFactory, LLC ID Twin Falls 2.25
6 31616100 Digester Big Sky West Dairy Digester (DF-AP #1, LLC)ID Gooding 1.50
7 31214058 Hydro Birch Creek ID Gooding 0.05
8 31415065 Hydro Black Canyon #3 ID Gooding 0.14
9 31615139 Hydro Blind Canyon ID Gooding 1.50
10 31416013 Hydro Box Canyon ID Twin Falls 0.36
11 31515100 Hydro Briggs Creek ID Twin Falls 0.60
12 31765170 Wind Burley Butte Wind ID Cassia 21.30
13 31715126 Hydro Bypass ID Jerome 9.96
14 31315050 Wind Camp Reed Wind Park, LLC ID Elmore 22.50
15 31416020 Hydro Canyon Springs ID Twin Falls 0.13
16 31318100 Wind Cassia Wind Farm LLC ID Twin Falls 10.50
17 31616081 Hydro Cedar Draw ID Twin Falls 1.55
18 31516014 Hydro Clear Springs Trout ID Twin Falls 0.52
19 31615057 Hydro Crystal Springs ID Twin Falls 2.44
20 31415023 Hydro Curr Catte Company ID Twin Falls 0.22
21 31615106 Hydro Dietrich Drop ID Jerome 4.50
22 11615077 Hydro Elk Creek ID Idaho 2.00
23 41717137 Hydro Falls River ID Fremont 9.10
24 31615121 Hydro Faulkner Ranch ID Gooding 0.87
25 31415134 Hydro Fisheries Dev.ID Gooding 0.26
26 31315035 Wind Fossil Gulch Wind ID Twin Falls 10.50
27 31615098 Hydro Geo-Bon #2 ID Lincoln 0.93
28 31765160 Wind Golden Valley Wind ID Cassia 12.00
29 31315093 Hydro HaileyCspp ID Blaine 0.06
30 31715128 Hydro Hazelton A ID Jerome 7.70
31 31715140 Hydro Hazelton B ID Jerome 7.60
32 21615100 Landfill gas Hidden Hollow Landfill Gas ID Ada 3.20
33 11715144 Hydro Horseshoe Bend Hydro ID Boise 9.50
34 41718140 Wind Horsshoe Bend Wind MT Cascade 9.00
35 21615105 Wind Hot Springs Wind Farm ID Elmore 21.00
36 31415094 Hydro Jim Knight ID Gooding 0.34
37 31615031 Hydro Kasel & Witherspoon ID Twin Falls 0.90
38 31615030 Hydro Koyle Small Hydro ID Gooding 1.25
39 31615056 Hydro Lateral # 10 ID Twin Falls 2.06
40 31316015 Hydro Lemoyne ID Gooding 0.08
41 31615105 Hydro Little Wood Rvr Res ID Blaine 2.85
42 31515107 Hydro Littlewood I Arkoosh ID Lincoln 0.87
43 31715099 Hydro Low Line Canal ID Twin Falls 7.97
44 31615130 Hydro Low Line Midway Hydro ID Twin Falls 2.50
45 31615125 Hydro Lowline#2 ID Twin Falls 2.79
46 31715123 Hydro Magic Reservoir ID Blaine 9.07
47 31765150 Cogen Magic Valley ID Minidoka 10.00
48 21765151 Cogen Magic West ID Elmore 10.00
49 31515009 Hydro Malad River ID Gooding 0.62
50 31615117 Hydro Marc Ranches ID Jerome 1.20
51 31615154 Hydro Mile 28 ID Jerome 1.50
52 31720190 Wind Milner Dam Wind ID Cassia 19.92
53 12614070 Hydro Mitchell Butte OR Malheur 2.09
54 21615200 Hydro Mora Drop Small Hydroelectric Facility ID Ada 1.85
55 31515004 Hydro Mud CreeklS & S ID Twin Falls 0.52
56 31414111 Hydro Mud Creeklhite ID Twin Falls 0.21
57 12616071 Hydro Owyhee Dam Cspp OR Malheur 5.00
58 31315060 Wind Payne's Ferr Wind Park, LLC ID Twin Falls 21.00
59 31615067 Hydro Pigeon Cove ID Twin Falls 1.89
60 41455091 Digester Pocatello Waste ID Bannock 0.46
61 31415164 Hydro Pristine Springs #1 ID Jerome 0.13
62 31415165 Hydro Pristine Springs Hydro #3 ID Jerome 0.20
Idaho Power Company
Cogeneration and Small Power Production
As of December 20,2010
Project Resource
Number Dm Projec Name State County Projec Size (MW)
63 21415119 Hydro Reynolds Irrigation ID Canyon 0.26
64 31216020 Hydro Rim View ID Gooding 0.20
65 31615003 Hydro Rock Creek #1 ID Twin Falls 2.05
66 31615104 Hydro Rock Creek #2 ID Twin Falls 1.90
67 31515103 Hydro Sagebrush ID Lincoln 0.43
68 31617100 Hydro Sahko Hydro ID Twin Falls 0.50
69 41515122 Hydro Schaffner ID Lemhi 0.53
70 11415009 Hydro Shingle Creek ID Adams 0.22
71 31615158 Hydro Shoshone #2 ID Lincoln 0.58
72 31416001 Hydro Shoshone Cspp ID Lincoln 0.37
73 41866112 Industrial Simplot Pocatello ID Power 12.00
74 31315021 Hydro Snake River Pottery ID Gooding 0.07
75 31414075 Hydro Snedigar ID Twin Falls 0.54
76 11766002 Biomass Tamarack Cspp ID Adams 5.00
77 21662100 Cogen Tasco - Nampa ID Canyon 2.00
78 31616082 Cogen Tasco - Twin Falls ID Twin Falls 3.00
79 41717139 Hydro Tiber Dam MT County 7.50
80 31415027 Hydro Trout-Co ID Gooding 0.24
81 31315150 Wind Tuana Springs Expansion ID Twin Falls 35.70
82 12616072 Hydro Tunnel #1 OR Malheur 7.00
83 55653167 Biomass Vaagen Brothers WA Stevens 4.50
84 31315029 Hydro White Water Ranch ID Gooding 0.16
85 31715141 Hydro Wilson Lake Hydro ID Jerome 8.40
86 31315070 Wind Yahoo Creek Wind Park, LLC ID Twin Falls 21.00
Subtotal 422.56
Projects Under contract not yet online
Estimated Estimated
First Energy Operation
Date Date
1 41455301 Wind Alpha Wind Project ID Cassia 29.90 Oct-14 Dec-14
2 41455350 Wind Bravo Wind Project ID Cassia 29.90 Oct-14 Dec-14
3 41455400 Wind Charlie Wind Project ID Cassia 27.60 Oct-14 Dec-14
4 21615115 Wind Cold Springs Windfarm ID Elmore 20.00 Dec-11 Dec-12
5 31721100 Wind Cottonwood Wind Park ID Twin Falls 20.00 May-12 Jun-12
6 31721200 Wind Deep Creek Wind Park ID Twin Falls 20.00 May-12 Jun-12
7 41455450 Wind Delta Wind Project ID Cassia 29.90 Oct-14 Dec-14
8 21615120 Wind Desert Meadow Windfarm ID Elmore 20.00 Dec-11 Dec-12
9 31616115 Digester Double A Digester ID Lincoln 4.50 Jun-11 Jan-12
10 31616120 Digester Double B Dairy ID Cassia 2.00 Oct-11 Dec-12
11 41455500 Wind Echo Wind Project ID Cassia 29.90 Oct-14 Dec-14
12 21615150 Solar Grand View Solar ID Elmore 20.00 Dec-10 Dec-11
13 21615125 Wind Hammett Hil Windfarm ID Elmore 23.00 Dec-11 Dec-12
14 21615102 Landfill Gas Hidden Hollow Energy II Landfill Gas Project ID Ada 3.20 Feb-12 Feb-12
15 41455200 Wind Lava Beds Wind ID Bingham 18.00 Jul-11 Jul-11
16 12618200 Wind Lime Wind Energy OR Baker 3.00 Oct-11 Dec-11
17 31315500 Wind Magic Wind Park ID Twin Falls 19.50 Jul-11 Jul-11
18 21615130 Wind Mainline Windfarm ID Home 20.00 Dec-11 Dec-12
19 12616500 Wind Murphy Flat Energy ID Owyhee 20.00 Dec-11 Dec-12
20 12616550 Wind Murphy Flat Mesa ID Owyhee 20.00 Dec-11 Dec-12
21 12616600 Wind Murphy Flat Wind ID Owyhee 20.00 Dec-11 Dec-12
22 31615300 Wind Notch Butte Wind ID Jerome 18.00 Jul-11 Jul-11
23 31315075 Wind Oregon Trail Wind ID Twin Falls 13.50 Dec-10 Dec-10
24 31315045 Wind Pilgrim Stage Station Wind ID Twin Falls 10.50 Dec-10 Dec-10
25 31615500 Wind Rainbow Ranch Wind ID Cassia 20.00 Dec-11 Dec-12
26 31615550 Wind Rainbow West Wind ID Cassia 20.00 Dec-11 Dec-12
27 31616110 Digester Rock Creek Dairy ID Twin Falls 4.00 May-11 May-12
28 41455300 Wind Rockland Wind Project ID Power 80.00 Jul-11 Dec-11
29 31721300 Wind Rogerson Flats Wind Park ID Twin Falls 20.00 May-12 Jun-12
30 21615135 Wind Ryegrass Windfarm ID Elmore 20.00 Dec-11 Dec-12
31 31721400 Wind Salmon Creek Wind Farm ID Twin Falls 20.00 May-12 Jun-12
32 31618100 Wind Salmon Falls Wind ID Twin Falls 22.00 Dec-10 Dec-10
33 21615110 Wind Sawtooth Wind Project ID Elmore 21.00 Oct-12 Dec-12
34 31616130 Digester Swager Farms ID Twin Falls 2.00 Sep-11 Oct-12
35 31315055 Wind Thousand Springs Wind ID Twin Falls 12.00 Dec-10 Dec-10
Idaho Power Company
Cogeneration and Small Power Production
As of December 20,2010
Project Resource
Number Dm Prolect Name State . County Projec Size (MW)
36 31315065 Wind Tuana Gulch Wind ID Twin Falls 10.50 Dec-10 Dec-10
37 21615140 Wind Two Ponds Windfarm ID Elmore 20.00 Dec-11 De-12
38 11866075 Biomass Yellowstone Power ID Gem 10.00 Sep-11 Dec-11
Subtotal 723.90
Proposed Projects
Interconnection
Que number
304 Biomass Project 1 ID Adams 10.00
360 Hydro Project 2 ID Canyon 0.90
334 Wind Project 3 ID Twin Falls 40.00
345 Solar Project 4 ID Owhee 20.00
356 Solar Project 5 ID Owyhee 20.00
331 Solar Project 6 ID Elmore 10.00
332 Wind Project 7 ID Elmore 10.00
318 Wind Project 8 ID Owyhee 5.00
Of system Wind Project 9 Reed Point, MT 27.00
Off system Wind Project 10 Lynn, UT 21.00
Off system Wind Project 11 Lynn, UT 21.00
Off system Wind Project 12 Rock Springs,19.00
Of system Wind Project 13 Rock Springs,19.00
Of system Hydro Project 14 ID Fremont 3.60
Subtotal 226.50
Total 1372.96
As these are not yet complete contracts. the project names etc is confidential