20070123NW Energy Coalition.pdf

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Comments of the NW Energy Coalition
Idaho Power Company s 2006 Integrated Resource2elilll.AN 23 AH 8: 30
January 22, 2007 II)/":; ;- Ui~,:Lil~UTILrrj~~; CC"",;i8SIC.
The NW Energy Coalition appreciates the opportunity to provide these comments to the
Idaho Public Utilities Commission relating to Idaho Power Company s 2006 Integrated
Resource Plan in Case No. IPC-06-24.
The NW Energy Coalition (Coalition) was pleased to have" had the opportunity to
participate at the invitation ofIdaho Power Company (the Company) in the 2005 and
2006 meetings of its Integrated Resource Plan Advisory Council (IRP AC). The Coalition
is not a member of the IRP AC (although its interests are represented by IRP AC members
Advocates for the West and the Natural Resources Defense Council), but extends its
appreciation to the Company for including it in IRP AC meetings and for receiving
Coalition views and comments as the Company prepared the 2006 IRP.
As we articulated in comments to the Commission on the 2004 IRP , the Coalition
believes the IRP AC process is an excellent means of ensuring that all stakeholder
constituencies have an opportunity to contribute to IRP development at virtually all
stages of the process. More importantly, we believe the Company seriously evaluates
and responds to the IRP AC's input, and that the IRP document is a better final product
because of that commitment.
The NW Energy Coalition is a non-profit regional alliance of more than 100 diverse
environmental, civic, consumer, low-income customer advocacy groups, energy
efficiency and renewable energy businesses, and progressive utilities in Idaho, Montana
Washington and Oregon. The Coalition s main address is: 219 First Ave South, Suite
100, Seattle, WA 98104. Its Idaho address is 5400 W. Franklin, Suite G, Boise, ID
83705. In Idaho, the Coalition has numerous individual and organizational members
including Idaho Rivers United, Idaho Conservation League, Snake River Alliance, Idaho
Rural Council, and the Community Action Partnerships in Idaho. Members of the
Coalition and its Idaho member organizations include customers of Idaho Power
Company.
The Coalition advocates for increased energy conservation efforts, sustainable and
ecologically sound management of electric generating infrastructure, increased
integration of renewable sources of energy in utility portfolios, and appropriate rate
design policies consistent with these goals, all of which ensure low-cost and sustainable
power and rate stability for all utility customers.
Introductory Comments on Preferred Portfolio
The Company s preferred portfolio continues a number of encouraging trends, notably
long-awaited increases in demand-side resources as the Company s conservation and
efficiency programs develop and gain traction. To its credit, the Company is heeding
Commission advice in the 2004 IRP proceedings to expand more aggressively its DSM
programs. As discussed more fully below, we have expressed concern in the past about
the size ofthe Company s rider-funded DSM balance and share the Company s optimism
that this excessive balance will be drawn down this year and that the Company will return
to the Commission with a renewed request to increase its DSM tariff rider.
We continue to be concerned about the amount of thermal resources proposed for
acquisition in the preferred portfolio. While we agree that a planned acquisition oflGCC
coal is preferable over conventional coal, we remain unconvinced the addition of 500MW
of coal is neither necessary nor prudent, particularly given the modest amount of wind
acquisition proposed in this IRP. In addition, it is not prudent to invest in the additional
cost ofIGCC without achieving the benefits of sequestering the CO2. Realizing that the
Company is soon to begin construction of yet one more natural gas peaking plant in the
Mountain Home area, we were pleased to note that the Company has heeded Commission
advice in the 2004 IRP process to take a harder look at gas peaking plants. None are
required in the planning horizon in this IRP, and none are included in the preferred
portfolio.
Supply-Side Resources
While we are relieved that the proposed acquisition of conventional coal in the 2004 IRP
has been deferred, we remain unconvinced of the necessity to include 500MW of coal-
fired generation in this IRP at all. In fact, we agree with the Northwest Power and
Conservation Council's Fifth Power Plan, which projected the entire region may need
only a single coal plant very late in the Plan s horizon-and only if its forecast of
achievable wind turned out overly-optimistic. However, the Council recently reported
that the region s wind resources are increasing faster than expected, while loads are a bit
slower. Both these results put the need for any coal plants at question.
The Company proposes a 250MW conventional Wyoming pulverized coal plant in 2013
and a 250MW regional IGCC plant in 2017. Both would likely be shared, seasonal
ownership. The Company has been in negotiations with A vista Utilities for one of the
coal plants; we presume the IGCC plant would be an expansion ofthe partnership with
PacifiCorp and likely at the Bridger complex.
Recent events have reduced the likelihood of these plants being built - certainly of any
unsequestered plant. The Oregon Public Utilities Commission on Jan. 16 made it clear it
was not convinced that PacifiCorp had justified the need for two new coal plants
(including one that may be part of a partnership with Idaho Power). The state of
Washington last fall passed a Renewables Portfolio Standard (RPS), and the state of
Oregon may well enact an RPS this year. The state of California will not allow its utilities
to import energy with a carbon footprint heavier than that of a modem CCCT. As a
consequence, the market in this region for surplus coal-fired energy continues to shrink as
the states and the nation move forward with measures to reduce carbon emissions. We
believe that adding 500MW in what is expected to be a carbon-constrained environment
in the timeframe in this IRP's preferred portfolio amounts to a financial and
environmental risk to ratepayers.
The Company proposes a 250MW conventional Wyoming pulverized coal plant in 2013
and a 250MW regional IGCC plant in 2017. Both would likely be shared, seasonal
ownership. The Company has been in a joint exploratory effort with A vista Utilities for
one of the coal plants; we presume the IGCC plant would be an expansion of the
partnership with PacifiCorp and likely at the Bridger complex.
Recent events have reduced the likelihood of these plants being built - certainly of any
unsequestered plant. The Oregon Public Utilities Commission on Jan. 16 made it clear it
was not convinced that PacifiCorp had justified the need for two new coal plants
(including one that may be part of a partnership with Idaho Power). The state of
Washington last fall passed a Renewables Portfolio Standard (RPS), and the state of
Oregon may well enact an RPS this year. The state of California will not allow its utilities
to import energy with a carbon footprint heavier than that of a modem CCCT. As a
consequence, the market in this region for surplus coal-fired energy continues to shrink as
the states and the nation move forward with measures to reduce carbon emissions.
The projected emissions adder for thermal resources in this portfolio should be elevated
to reflect a figure higher than the anticipated $14 per ton carbon adder, and quite likely
should be accelerated to a date earlier than 2012. We realize that the $14 figure represents
the expected case (50 percent) probability of imposition of the CO2 adder. However, a
more realistic expectation is higher - perhaps much higher - than $14, while likely below
the high-case $50 per ton. Raising the $14 adder will of course place many of the
renewable resources analyzed in the IRP in a more favorable position relative to thermal
resources. It would also assign a more realistic risk to the thermal resources in this
portfolio.
Overall, we believe the Commission and Company should adopt a cautionary approach
with respect to new pulverized coal. Pulverized coal presents cost, market, and
environmental risks that are unnecessary for customers and shareholders to bear.
believe a strategy of fully realizing the potential for renewable energy development and
DSM over the short term presents the least risk strategy to bridge over the coming years
of uncertainty related to carbon regulation and climate change.
The preferred portfolio also anticipates expiration of the production tax credit for wind at
2012 - the same year the company estimates the carbon adder will take effect. This
likewise may be a pessimistic view of the future of the PTC and the appetite to extend the
PTC beyond 2012. Should it be extended (and we believe it will), wind once again
assumes a more favorable standing relative to other resources.
Wind variability and amount of wind in the preferred portfolio
The anticipated risk associated with wind variability continues to be overstated at the
expense of its proportionate share of the new resource acquisition. In addition, a more
comprehensive examination of the value of geographic diversity of future wind resource
acquisition would likely reduce the risk this IRP currently attaches to wind. And as
mentioned above, the Company is likely overstating the likelihood of the PTC expiring in
2012.
The amount ofRFP-scale wind included in this portfolio continues to lack the level of
ambition and creativity we see elsewhere in the region. Realizing the company s existing
situation with regard to PURP A wind contracts and the amount of PURP A wind currently
scheduled for inclusion into the resource portfolio, restricting the level of RFP wind to
150MW (and the soon-to-be-approved 100MW from Horizon Wind from the 2006 RFP)
is unwarranted. The Idaho Energy Division estimates that, in Idaho, we have 208MW of
approved wind PSAs, 4 716MW of wind projects in various stages of development, and
591MW of wind projects in advanced planning stages. Even if 50 percent of these
projects are fully developed, this energy will need a home - preferably in Idaho.
Therefore, we view the Company s planned wind acquisition as disappointing and as
unambitious.
Progress in wind forecasting and the advantages of region-wide geographic wind
distribution can go a long way to ameliorate the company s variability concerns. We
welcomed the provision in the Company s pending Power Purchase Agreement (PPA)
with Telocaset Wind Power/Horizon ((IPC-06-31) that commit Telocaset to provide
the Company with detailed, real-time wind forecasting data, and as mentioned in our
comments to the Commission in that docket, we hope such a provision sets a precedent in
future wind PP As. Doing so can only improve the cumulative reliability of wind
resources in the Company s portfolio and allow for greater amounts of wind energy to
replace the ill-advised thermal resources in this portfolio.
The company should be encouraged to treat wind as a region-wide resource and to
incorporate the diverse generation profiles from such far-flung resources as Horizon and
the Columbia Gorge; southern Idaho; and the firmed Montana wind resources. With
adequate transmission resources, particularly in Southern Idaho, there is more than
adequate room on the Company s system for a great deal more wind than the modest
150MW projected for 2012.
Non-wind renewables
As mentioned above, we believe the preferred portfolio should include significantly more
wind. However, it also calls for a disappointingly low level of non-wind renewables in
the company s total resource stack.
The company acknowledges on P.97 of the IRP that "Wind, geothermal, and other non-
hydro renewable resources supplied a negligible amount of energy used by Idaho Power
customers in 2005. Other than power purchased from several small PURPA projects and
green tags acquired to support the Green Energy Program, Idaho Power had no major
non-hydro renewable energy purchases in 2005.
The company then states in subsequent passages that it "anticipates acquiring a greater
amount of non-hydro renewable energy given the number ofPURPA resources either
under contract or in contract negotiations." The draft then delivers this disappointing
projection: "The preferred portfolio includes approximately 250MW of wind generation
and 150MW of geothermal generation by 2025." (P98).
Other portfolios considered by the Company included far greater amounts of geothermal
potential. We would hope that the Commission will direct the Company to revisit this
too-modest projection of geothermal resources in future IRPs and adjust accordingly.
Adding another 200 to 250MW of geothermal, which we believe is warranted, could well
relieve the Company and its ratepayers of the need for the next coal-fired generation
acquisition.
The Company expects that, including existing PURP A contracts and the projected
400MW of proposed renewable resources in the preferred portfolio, renewables will
account for only 8.4 percent ofIdaho Power s total generation portfolio by 2025.1 While
that is a notable improvement over the current renewables share in the Company s overall
portfolio, 8.4 percent renewables in a total portfolio by 2025, even assuming
unanticipated PURP A resources that could move that number higher, can be improved.
Nuclear
It's difficult to gauge the seriousness of its inclusion of250MW of nuclear energy from
the Idaho National Laboratory. From all appearances, the nuclear component appears to
be an energy resource of convenience. We realize nuclear is only included based on the
advice of the U.S. Department of Energy and the possible development of an
experimental plant at DOE's INL It would be prudent to attempt to better calculate a
more realistic risk profile of this resource so that it more realistically stacks with other
resources.
The IRP's projected cost of nuclear energy is underestimated. It does not appear to
include an emission adder, nor does it adequately address unresolved waste issues. When
these and other externalities are included in calculating nuclear s true cost, the resource
would become prohibitively expensive.
Demand-Side Resources
The IRP's anticipated 187MW in peak DSM is a welcome increase from past IRPs, but
could be enhanced to achieve greater savings - particularly given the expected successful
1 Calculated on an energy basis, using a 35% capacity factor for wind.
resolution ofthe pending decoupling docket before the IPUC.2 But we continue to harbor
concerns that even this level of savings is not sufficiently ambitious. While the
Company s primary concerns in meeting projected load growth are in peak demand, we
encourage the Commission to continue to emphasize the need for the Company to more
swiftly integrate the additional DSM programs identified in the 2006 IRP.
We have raised concerns to the EEAG about the size of the current rider-funded DSM
account balance, and have been assured by the Company that this balance is expected to
be drawn down significantly during 2007 as existing DSM programs are expanded and
new ones come on line. We agree with the Company that, as the DSM balance is reduced
this year, the Company will anticipate the proper timing to return to the Commission with
a request for an additional incremental rider increase to help the Company edge closer to
meet conservation targets set by the Northwest Power and Conservation Council in its
Fifth Power Plan.
One additional way to accelerate development of the Company s DSM programs would
be to examine the company s projected customer growth of9 000-10,000 customers
annually (P. 69) and to require or incentivize those new customers to participate in such
DSM programs as the Company s AC Cool Credit program or to require or incentivize
solar or other renewable energy hook-ups as part of their new service. This projected
growth in the Company s customer base would appear to provide Idaho Power with great
leverage in promoting its DSM and efficiency programs.
Transmission
The Company s IRP includes 285MW of transmission upgrades (225MW in 2012 with
the McNary-Boise upgrade and 60MW in 2019 with the Lolo-Oxbow upgrade). The
addition of expanded transmission is welcome, and should provide the Company
increased access to renewable resources and markets in the Northwest. We re concerned
however, that the company did not include in its preferred portfolio additional
improvements in Southern Idaho transmission.
nancy
Eastern and Southern Idaho will soon be home to significant wind generation that will
require access to the Company s load centers. In addition, any plans to expand thermal
generation at Bridger will similarly require improved east-west transmission. Realizing
the Company expects to complete the Borah-West transmission upgrade in 2007, we are
nonetheless concerned that transmission upgrades in the southern part of the state are
adequate.
The Company s plans to upgrade the McNary-Boise transmission to better access Mid-
markets for purchases and surplus sales is commendable. However, Portfolio F4
(formerly Portfolio 11 , or the Bridger to Boise Transmission portfolio) held promise in
2 As well as the recently approved Load Growth Adjustment in the PCA proceeding that
will tend to put much more of the cost and risks of load growth on the Company.
that it included the 900MW transmission line from Bridger to Boise. The company
properly notes that a Bridger-Boise line "Will provide the capability to integrate
additional generation from the Jim Bridger Project, and additional wind and geothermal
resources. . . "
We agree. It's regrettable that this potential asset, particularly its ability to transport the
substantial wind resources in southern Idaho, is not included in the preferred portfolio.
We recognize transmission remains a concern for the company as well as the IPUC and
the region at-large. We disagree that Portfolio F4 "May place an undue reliance on the
Wyoming energy market " particularly given the possibility that future thermal
acquisitions (250MW of coal in 2013 from either an Avista partnership or from
Wyoming, likely Bridger) and also the 250MW of possible IGCC coal, perhaps a Bridger
expansion) will create demands on the company s southern Idaho transmission. The value
of Bridger-Boise cannot be understated for its ability to bring the wind resources likely to
be developed in the south to the load centers in southwest Idaho.
Company s ReQuest for Comment on Public Policy Issues
The 2006 IRP contains five "public policy issues" on which the Company seeks public
input. These issues include: The treatment of environmental attributes or Green Tags;
emission offsets; financial disincentives for DSM Programs; IGCC technology risk; and
asset ownership. Weare not addressing each of these issues, but would like to comment
on the following:
Green Tags
The Company asks several policy questions regarding the disposition of environmental
attributes, or green tags. We agree that the Company must position itself for inevitable
requirements of a future imposition of a national or state RPS. We believe Idaho Power
must possess green tags in order to truly represent the renewable components of its
generation portfolio. We realize the Company is currently wrestling with treatment of
these green attributes, and we share the Company s concerns that it wants to avoid
double counting" these attributes. Green-e has established standards for treatment of
these attributes, and we re pleased that the Company is looking to Green-e for guidance.
If the Company plans to obtain green tags to satisfy its anticipated obligations, it may
want to include provisions in future RFPs that bidders include tags as part of the product
and pricing, but the tags should not be delivered to the Company unless provisions to do
so have been included in a PP
Emission offsets:
As mentioned above, we do not believe the $14 per ton cost of the CO2 emission adder
used in the IRP analysis is sufficient. A much higher figure would better reflect both the
risk of thermal energy acquisitions in this IRP as well as more accurately rank the various
resources considered. It is evident from the analysis that a $14 per ton adder still resulted
in unsequestered coal resources being included in the Company s portfolio. We cannot
imagine that if the state or federal government imposes a carbon restriction it would
choose a penalty level that did not change utility behavior. Thus, such an amount is
inadequate for analysis of a future that requires carbon controls.
The question posed by the Company, however, deals with whether it should "investigate
purchasing options to acquire future carbon offsets " which "could potentially reduce the
large financial exposure of possible carbon taxes for the cost of the option premium.
The Company also believes it should be able to recover such purchases as well as the cost
of any emission offsets.
In selecting resources with carbon implications, the Company is assuming significant
risk. That risk should not be borne by ratepayers who disagree with the resource
selection, and that risk should also be elevated to reflect the true probability of the
emission adder s imposition and its implications for ratepayers and shareholders. It seems
absurd to allow the Company to choose high-carbon resources at ratepayer expense (and
risk) and then also charge ratepayers for the cost of offsetting the emissions from those
choices. In addition, we are not convinced that purchasing offsets today will, as the
Company asks, meet future carbon control requirements and regulations. IRP AC
members discussed this issue at length, and there were sharp disagreements as to whether
such purchases are prudent, and also whether purchasing "options" were prudent and
whether they would have value once the CO2 adders arrive.
IGCC technology risk:
Integrated Gasification Combined Cycle coal generation technologies are far from
mature, which is why the Company placed acquisition of this 250MW supply-side
thermal resource in 2017, deep into this IRP's horizon and after development of a
conventional coal resource.
Of course, if the Company eliminated both of its proposed coal generation proposals in
this IRP, as the Coalition recommends, this policy question would be moot. The Coalition
opposes acquisition of any coal generation resource in the Northwest, the lone exception
being an IGCC plant that includes full carbon capture and sequestration and only then if
all other options have been exhausted.
We appreciate and understand the Company s interest in exploring the cleanest possible
thermal generation options, and also in deferring acquisition of even an IGCC plant until
the Company can assure it meets the above requirements. The preferred portfolio
envisions a partnership in a pulverized coal plant to come online in 2013 and a
partnership for an IGCC plant to come online in 2017. One of the Company s policy
questions is whether, if a near-term opportunity arises that would allow it to participate in
an IGCC partnership, the Company should take advantage of it. Pending fruition of a
viable IGCC partnership within the timeframe covered by this IRP, we cannot support
inclusion of coal-fired generation of any sort being included in this IRP.
Conclusion
Idaho Power s 2006 IRP has much to commend it, notably its increased levels ofDSM
its attention to transmission concerns previously expressed by the Commission in
acknowledging the 2004 IRP, and the absence of yet more natural gas peaking
generation. We would hope that the Commission would agree with our concerns about
the projected level of renewable energy, particularly wind, in this IRP, and we do not
believe an adequate case has been made for the two coal acquisitions - certainly the near-
term pulverized coal proposal.
We reiterate our belief, as stated at the outset, that the Company s IRPAC process and the
Company s willingness to consider diverse views from the Advisory Council continue to
improve the final product, and we commend the Company s efforts to reach out to its
ratepayer and other constituent stakeholders.
Respectfully submitted
Ken Miller
Idaho Energy Advocate
NW Energy Coalition
5400 W. Franklin, Suite G
Boise, ID 83705