HomeMy WebLinkAbout20101001Decision Memo.pdfDECISION MEMORANDUM
TO:COMMISSIONER KEMPTON
COMMISSIONER SMITH
COMMISSIONER REDFORD
COMMISSION SECRETARY
COMMISSION STAFF
LEGAL
FROM:SCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
DATE:OCTOBER 1, 2010
SUBJECT:CASE NO. GNR-09-
REVIEW OF SURROGATE AVOIDED RESOURCE (SAR) METHODOLOGY
The impetus for establishing the investigative case docket GNR-09-03 was a perception
by Staff and others that a single published avoided cost rate may not be capable of representing a
utility s avoided cost for all Qualifying Cogeneration and Small Power Production Facility (QF)
resource types. 18 C.R. 9292.101(6). At the direction of the Commission, Staff prepared a Straw-
man wind SAR proposal earlier this year and distributed it to a small universe of interested parties
(QFs and utilities) for their review and comment. See attached proposal. It was a starting point
proposal intended to generate discussion of its strengths and weaknesses and to provoke the
generation of new and better proposals. The comments received revealed a polarization of positions
rather than a willingness to engage in discussion and achieve consensus. Staff recommends now that
the Straw-man proposal be formally noticed, that a public workshop be scheduled and that a deadline
for written comments be established.
COMMISSION DECISION
Staff recommends that the Straw-man wind SAR proposal developed by it be formally
noticed and that a schedule be set for public workshop and comments. Does the Commission agree
with Staff s recommended procedure?
~-=
Scott Woodbury
Deputy Attorney General
bls/M:GNR-O9-03 sw
GNR-09-
IN THE MATTER OF A REVIEW OF THE SURROGATE AVOIDABLE
RESOURCE (SAR) METHODOLOGY FOR CALCULATING PUBLISHED
AVOIDED COST RATES
STAFF'S STRA WMAN PROPOSAL
Staffs strawman proposal is very similar to the spreadsheet currently used to
compute rates using a gas-fired CCCT SAR. It requires that a variety of input data
adopted, including identification of reliable data sources and a process for consistent
updating. However, in addition to the usual cost and performance assumptions and
variables, it also requires consideration of new variables such as tax credits (production
tax credits, investment tax credits, sales tax exemptions, loan guarantees, and other
financial incentives available to utilities).
AVOIDED COST MODEL FOR WIND
Staffs proposed avoided cost model for wind has been developed using as a
starting point the existing model that is used to compute avoided cost rates based on a
gas-fired CCCT. Consequently, both models appear fairly similar and use many of the
same computational techniques and formulas. The differences between the two models
lie primarily in the input data and in the results.
In the gas SAR model, there are basically four cost categories that when added
together, make up the total avoided cost rates:
capital costs
fixed O&M costs
variable O&M costs, and
fuel costs.
In the wind SAR model , the cost categories are:
capital costs
fixed and variable O&M costs
transmission costs
tax credits
wind integration, and
forecasting costs.
Just as with the gas CCCT SAR, costs in each category are estimated and
escalated over the life of the contract, then added together to develop non-Ievelized
avoided cost rates. From there, the rates are levelized, and adjustments are applied to
increase or decrease rates by season and for heavy and light load hours. The figure below
illustrates how the various cost components are "stacked" before levelization. In this
example, production tax credits are zero (in lieu of a 30% investment tax credit), and no
REC premium is assumed.
For comparison purposes, the cost components for the wind SAR have been
underlaid with the current rates based on the gas-fired CCCT SAR. Notice that wind
SAR rates are higher than gas SAR rates until about the 18th year.
300
250 Current Rates
200 --Integration
--O&M
150
100
Transmission
-Capital
-Forecasting
--
RECs
--
Prod Tax Credits
INPUT DATA ASSUMPTIONS
The input data assumptions that have been included in the proposed wind SAR
model are shown below. Data have been grouped into seven general categories. Within
each category are the data descriptions, the units in which the data must be entered, and
the data itself. Data that must be input are shown in blue text. Financial data is shown in
black text in the tables below because it is computed on a different worksheet based on
each individual utility's cost of capital , capital structure, and tax rates. The only data that
is utility-specific is the financial data. The data shown here are proposed values, and are
subject to adjustment in the workshop process that is anticipated following the parties
initial review of Staffs strawman proposal.
Plant Cost $/kW 149
Base Year 2006
Plant Life Years
Surrogate Escalation Rate; Plant Cost 1 .40%
Avoided Capacity Factor 30.
Resource Fixed O&M $/kW 40.
Variable O&M $/MWh
Base Year; O&M 2010
Escalation Rate; O&M 90%
Transmission Cost $/kW-mo
Transmission Base Year 2010
Escalation Rate; Transmission Cost 00%
Transmission Losses 90%
Production Tax Credit C/kWhProduction Tax Base Year 2010Credits
Escalation Rate; PTC
REC Premium $/MWh
RECs Base Year 2010
Escalation Rate; REC 70%
Forecasting Cost $/site 500
Forecasting Base Year 2010
Escalation Rate; Forecastina 90%
General inflation rate
Miscellaneous Tilting" Rate 00%
Current Year 2010
Utility Weighted Cost of Capital 180%
Financial Capital Carrying Charge 10.857%
Level Carrying Cost $/MWh 61.
Surrogate Avoided Resource
The surrogate avoided resource data consists of assumptions about the wind
surrogate. Unlike the gas surrogate, the wind surrogate does not assume equipment from
a specific manufacturer, a specific size, model , or project location. Instead, the wind
surrogate is based on generic cost estimates like those routinely used by utilities and
planners. Assumptions about a specific project size, equipment type, or configuration are
much less critical for a wind SAR because, whether it is a 20 MW PURP A wind project
or a 200 MW utility-scale project, they both generally use the same equipment. Although
there are undoubtedly some economies of scale, wind project costs are much more linear
than costs for gas-fired projects.
Wind SAR data includes the unit cost of wind generation equipment, fixed and
variable O&M, and cost escalation rate assumptions about how these unit costs may
change in the future. In addition, an assumption must be made about the expected
capacity factor of the SAR.
The SAR assumptions primarily determine the capital costs component of the
avoided cost rates. In the wind SAR model, capital costs represent, by far, the largest
component of the avoided cost rates. Consequently, the avoided cost rates are very
sensitive to SAR assumptions, particularly the "plant cost" and "capacity factor" variables.
Slight changes in these variables will cause big changes in the avoided cost rates.
Transmission
With the gas CCCT SAR, an assumption has been historically made that the plant
would most likely be located very close to a utility's load center, making substantial
transmission investment unnecessary. Consequently, no transmission costs have ever
been added for the gas CCCT SAR. With a wind SAR, however, it is improbable that a
utility scale wind project could be located close to a utility's load center. It is highly
likely that any wind project would require some transmission system additions or
improvements.
With three multi-jurisdictional utilities, an "avoided" wind resource could be
located almost anywhere in Idaho, Oregon, Washington, Wyoming, or Montana.
Transmission costs could vary tremendously depending on a project's size and location.
Without an assumed project size or location, it is difficult to make an assumption about
transmission costs. For this model, Staff proposes to base transmission costs on the
average embedded transmission costs of the three utilities as reported in unbundling
reports that were filed with the Commission from 1996 - 2003. Because embedded
transmission costs are based on partially depreciated plant that is less costly than new
plant, this method may underestimate transmission costs. On the other hand, most wind
projects would use as much existing transmission as available and add only as much new
transmission improvement as is necessary. Some possible projects might be
accommodated entirely using existing transmission.
Another possibility was to use each utility's OA TT transmission rate; however
Staff chose not to use an average OA TT transmission rate because in theory, these
FERC-jurisdictional rates are based on costs associated with wholesale transactions and
wheeling, not on transmission costs associated with serving native load customers.
Tax Credits
Tax credits currently play an important role in promoting new wind project
development. In most cases, the ownership and financing of new projects is structured in
such a way as to take full advantage of available tax credits, whether a project is utility-
owned or third-party owned. The availability of various tax credits is usually restricted to
projects built before some specified date. The model has been configured to accept
production tax credits (PTC) or investment tax credits (ITC), or to apply no tax credits at
all. Production tax credits are currently 2.1 cents per kWh, and increase each year based
on inflation. PTCs are applied to the first 10 years of production. The federal ITC has
been modeled as a 30 percent reduction in the initial cost ofthe investment (i.e. cash
grant). The American Recovery and Reinvestment Act of 2009 (ARRA) allows
taxpayers eligible for the PTC to take the ITC or to receive a grant instead of taking the
PTC. The 30 percent cash grant assumption produces the lowest avoided cost rates, but
the PTC and the "none" options have been included to accommodate possible future
expirations or changes in eligibility.
Accelerated depreciation (MACRS) has been used on the capital carrying charge
spreadsheet. Under MACRS, wind projects are classified as five-year property and
allowed to be depreciated over five years. MACRS has been modeled using a 200%
DDB method with a half-year convention.
Bonus depreciation has not been modeled because expired December 31 , 2009
and has not been renewed. State tax incentives (e., state investment or production tax
credits, sales tax exemptions, property tax incentives, Oregon s Business Energy Tax
credit), have also not been modeled, although they could contribute to a project'
economics. Parties are invited to make a case for or against including the various tax
incentives in the model.
RECs
A wind SAR assumes that the utility owns the project and all attributes associated
with it, including its RECs. Consequently, the avoided cost rates computed based on the
wind SAR include the RECs regardless of their value. It is not necessary to compute a
separate value for RECs because their value is embedded in the cost of wind used to
establish the avoided cost rate. In exchange for paying the wind SAR-derived avoided
cost rate, the utility receives both the energy and the RECs from the QFs.
The avoided cost model for wind includes a placeholder for RECs, but as
configured, a value for RECs would only be entered in the model to reflect a price
premium that might be assigned to RECs. Ifthe entire cost and value of RECs is
assumed to be captured by the utility simply through the purchase of power from the QF
then the proper REC cost value to be entered in the model is zero.
As proposed, there would be two avoided cost models the existing model
based on a gas-fired CCCT and the new model that is based on a wind SAR. Due to
likely variations in natural gas price forecasts from time to time, there are two possible
scenarios under this proposal at times the gas SAR rates will be higher than the wind
SAR rates; at other times the wind SAR rates will be higher than the gas SAR rates.
When the wind SAR rates are higher, project developers, regardless oftheir
project's technology (i., wind, hydro, geothermal , cogeneration, solar, etc.), would be
allowed to choose avoided cost rates based on either the gas-fired CCCT SAR or the
wind SAR. If the developer chooses rates based on the gas-fired CCCT, then the RECs
would be retained by the developer. However, ifthe developer chooses rates based on
the wind SAR, RECs would be turned over to the utility along with the energy generation
at no additional cost to the utility. Developers will have to weigh their expectation of the
value of RECs in deciding whether to choose a wind SAR rate that includes utility
ownership of RECs versus a gas SAR rate that allows the developer to retain the RECs.
When gas SAR rates are higher, wind project developers would only be eligible
for the wind SAR rates, and consistent with the concept of a wind SAR, the utility would
receive the RECs. The logic in support of this position is that it would be unlikely that a
utility would be acquiring gas-fired generation to meet energy needs if it was higher cost
and did not include REC ownership. In other words, gas generation would not be the
avoided resource when gas is more expensive than wind. The utility would be acquiring
wind instead.
However, non-wind projects, when gas SAR rates are higher, would be entitled to
gas SAR rates and would be permitted to retain ownership of RECs. The reasoning
behind this is that non-wind projects provide capacity as well as energy; therefore, a gas
SAR is still an appropriate avoided resource.
The illustration below depicts the proposal graphically under a scenario when
wind SAR rates are higher and under the reverse scenario when gas SAR rates are higher.
RECs go to
Utility
..
RECs go to
Developer
RECs go to
Utility
RECs go to
..
Developer
All project types can choose wind SAR rates or
gas SAR rates.
Wind projects are only eligible to receive wind
SAR rates.
Forecasting
Wind forecasting costs are very minor in comparison to other wind project costs.
Nevertheless, they are real, so the model allows for an annual amount to be assumed.
Forecasting costs are generally charged for each project site, and are not necessarily
proportional to the size of the project. A project size must be assumed, however, in order
to spread forecasting costs amongst the energy-based avoided cost rates. For this model
forecasting costs have been assumed to be $3 500 per site per year, with a site being 10
aMW in size.
Miscellaneous
Miscellaneous data include the general inflation rate and the "tilting" rate. The
general inflation rate is used as an escalator for some cost components, presumably
whenever a more specific escalation rate cannot be determined. The "tilting" rate has
been included in the gas-SAR model for many years and has been retained here also. In
the past, the tilting rate has been assumed to represent an expected capital cost escalation
rate for the SAR.
Financial
The financial data category is shown along with the other input data tables, but
the data is actually computed on a different worksheet based on each individual utility'
cost of capital, capital structure, and tax rates. Capital costs are computed using the
worksheet in the model titled "CapCarChg . This worksheet is nearly identical to the
worksheet used in the gas-fired CCCT SAR model, with one exception being that tax
depreciation for the wind SAR is based on MACRS with a five year depreciation life.
OTHER MODELING ISSUES
Wind Integration
A wind integration charge is currently applied to the published avoided cost rates
for wind QFs. The wind integration charge acts as a discount to reduce the rates paid to
wind projects and accounts for the increased cost to the utility of integrating an
intermittent resource. Wind integration charges have been established based on studies
performed by each utility.
The Commission Staff believes that wind integration charges need to be
accounted for in the wind SAR model, just as in the gas SAR model. A utility incurs
wind integration charges of the same magnitude whether the resource is an SAR owned
by the utility or a wind QF owned by someone else. Unless a wind QF can eliminate or
mitigate for the intermittency of its generation, the utility does not "avoid" any wind
integration costs because it buys from a wind QF.
In the wind SAR model, wind integration has been modeled the same way it is
modeled in the gas SAR. For Idaho Power and Avista, wind integration is modeled as a
percentage reduction in the avoided cost rate. The percentage reduction depends on each
utility's wind penetration rate, ranging from seven to nine percent. The wind integration
charge is capped at $6.50 per MWh. For PacifiCorp, the wind integration charge is $6.
in all cases.
Dispatchabilty
One of the biggest differences between the current SAR and PURP A QFs is that
the SAR is fully dispatchable and PURPA QFs are not (at least none to date have been
dispatchable). Dispatchable resources have value for a utility, both because they can be
operated whenever needed and because they do not need to be operated when not needed.
All dispatchable resources provide some capacity. However, even some non-
dispatchable QFs provide some capacity, while other QFs provide none at all. For
example, a geothermal QF produces nearly the same amount of generation during all
hours throughout the year. A hydro QF on an irrigation system generates a consistent
predictable amount during irrigation season. Wind QFs, on the other hand, provide little
or no capacity because their generation is intermittent and unpredictable.
A project must provide capacity in order to be dispatchable. The value of
capacity depends on when it is provided. Capacity provided during peak hours, days or
seasons has substantially more value than capacity provided at other times. There may be
times when providing capacity has no value. Consequently, higher capacity factors do
not always necessarily mean higher value. Moreover, the value of capacity will vary over
the life of the project depending on the utility's capacity position.
The difference between different QF resources' and an SARIs dispatchabilty and
abilty to provide capacity has never been accounted for in Idaho s avoided cost
methodologies. While it may be more necessary now than ever before, to do so could be
difficult, especially now that there has become a much wider diversity of QF resource
types with characteristics quite different from a gas-fired CCCT SAR.
However, if a wind SAR were adopted for purposes of computing avoided cost
rates - at least for wind QFs - assigning a value to capacity or dispatchability would not
be necessary. As long as the SAR used to compute rates has the same characteristics as
the QF resources for which the rates are being set, there is no need for adjustments to
account for differences.
Emission Adders, Fuel Risk Adders
Nothing in the current SAR methodology recognizes the value of reducing fossil
fuel use (e., reduction in CO2 taxes, value of S02 credits), benefits that a QF may
provide that would not be provided by a gas-fired CCCT. If a QF causes some fossil-
fueled resource to be deferred, displaced, or operated less, and thus have lower emission
costs, it currently receives no credit for it. As emission costs begin to be imposed on
fossil-fueled facilities, it could be argued that credit for the emission reductions
attributable to QFs is warranted.
Similarly, some QFs, wind in particular, have no fuel costs. Therefore, unlike a
gas-fired CCCT SAR, wind presents no fuel cost risk. It could be argued that QFs with
no fuel cost risk deserve credit for this benefit also.
If a wind SAR were adopted, the questions of emission adders and fuel risk
adders to published avoided cost rates become moot. One reason utilities' IRPs include
wind resources in their preferred portfolios is because of the absence of emission costs
and fuel price risk. As long as utilities continue to plan to acquire wind resources outside
of PURP A, it is reasonable to assume for purposes of avoided cost rates that wind is truly
an "avoided resource." Thus, adoption of a wind SAR will permit the Commission to
steer clear of addressing the thorny issue likely to arise in the future of emission adders
and fuel risk adders.
SOURCES FOR INPUT DATA
There are several possible sources for input data related to wind costs. Each
utility, in its IRP, makes cost assumptions for new wind generation. In addition, the
Northwest Power and Conservation Council (NPCC) makes similar cost assumptions in
preparing its power plans. The U.S. Department of Energy, Energy Information
Administration includes wind cost assumptions in its Annual Energy Outlook, a report
published annually each spring.
Cost data from the NPCC has been used for the gas SAR model. Although the
data have been considered accurate and impartial, parties in other proceedings before the
Commission have expressed frustration that the data are not updated regularly. In
addition, the Council staff have expressed some discomfort in being relied upon as a
source for data that is directly used to establish rates. Council staff do not wish to be
lobbied to adopt higher or lower cost data, since it views its role as planning, not
ratesetting.
Table 1 is a summary of wind cost data from various sources. As shown, the data
were compiled in various different years and are expressed in different year s dollars.
Table 2 shows the same data adjusted to be in 2010 dollars. If necessary, the
Commission Staff proposes that parties in this case negotiate in a workshop process to
agree upon acceptable sources for input data.
UPDATES TO INPUT DATA ASSUMPTIONS
Whatever data source is chosen for the input cost data, it will be necessary to
periodically update the assumptions. The Commission Staff proposes to update the
avoided cost computations whenever the source data are updated.
Adjustments to Avoided Cost Rates Computed Based with a Wind SAR
Even if a wind SAR is adopted, there are still some adjustments made to avoided
cost rates that Staff believes need to be retained. "Seasonalization" is an adjustment
made to recognize changes in the value of power throughout the year. In seasons when
power is normally plentiful and less expensive, in the spring for example, a
seasonalization factor less than one is applied to reduce avoided cost rates. In other
seasons when power is more expensive, such as in the summer and winter, a
seasonalization factor greater than one is applied to increase avoided cost rates.
A daily load shape adjustment recognizes differences in power value between
heavy and light load hours. The adjustment increases avoided cost rates for power
delivered in heavy load hours and decreases rates for power delivered in light load hours.
Staff believes this adjustment is still appropriate for all QF generation technologies
regardless of what type of SAR is used to compute avoided cost rates.
In addition to retaining seasonal and daily load shape adjustments, Staff also
believes that the current requirement for a mechanical availability guarantee (MAG)
should be retained. MAG requirements for wind projects recognize reliability by
requiring that project facilities are mechanically available to operate whenever there is
sufficient wind.
Fuel Price Risk and Dispatchability
As currently constructed, neither the gas SAR model nor the wind SAR model
attempts to account for fuel price risk. Obviously, gas-fired resources are exposed to
considerable price risk, while wind generation has little or no direct "fuel" price risk.
Similarly, dispatchability is not accounted for in either SAR model. A gas-fired CCCT is
dispatchable, a wind project is not. Fuel price risk and dispatchability would be difficult
to account for in an SAR model. The fact that fuel price risk works in favor of a wind
project, but dispatchability works against it are offsettting factors that help to minimize
the impact of not including either in the SAR models.
THE RESULTS
The avoided cost rates computed using the wind SAR are shown on the attached
tables. Note that these are the results using sample sets of input data. It is highly
probable that some of the input data will be modified during the course of workshops.
Nevertheless, the rates shown in the attached tables are within a likely range of results.
U sing the sample data shown on page 12, a 20-year levelized wind rate with a
2010 online date is as follows for each utility for both a wind and a gas SAR:
Utili Wind SAR Gas SAR
A vista $86.31/MWh $79. 17/MWh
Idaho Power $84.72/MWh $79. 19/MWh
PacifiCorp $85.06/MWh $79.31 /MWh
The Wind SAR rates shown above assume that the utility will own the RECs associated
with all power purchased from each project. The Gas SAR rates assume that the project
developer owns the RECs. Although not explicit in the computations, it could be implied
from these rates, that the approximate 20-year levelized value ofRECs is between $5.
and $7.10.
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Avoided Cost Wind
Plant Cost $/kW 149
Base Year 2006
Plant Life Years
Escalation Rate; Plant Cost 1 .40%
Capacity Factor 30.
Fixed O&M $/kW 40.
Variable O&M $/MWh
Base Year; O&M 2010
Escalation Rate; O&M 90%
Transmission Cost $/kW-mo
Base Year 2010TransmissionI Escalation Rate; Transmission Cost 00%
Transmission Losses 90%
Production Tax (rOduction Tax Credit C/kWh
Credits Base Year 2010
Escalation Rate; PTC 90%
REC Premium
RECs IBase Year 2010
Escalation Rate; REC 70%
Forecasting Cost $/site 500
Forecasting IBase Year 2010
Escalation Rate; Forecasting 90%
General Inflation rate
Miscellaneous Tilting" Rate 00%
Current Year 2010