20100415SRA Comments.pdf

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Jean Jewell; Beverly Barker; Gene Fadness
PUC Comment Form
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A Comment from Ken Miller follows:
Case Number: IPC-E-09-33
Name: Ken Miller
Address: Box 1731
City: Boise
State: ID
Zip: 83701
Daytime Telephone: [phone]
Contact E-Mail: kmiller~snakeri veralliance. org Name of Utility Company: Snake River Alliance
Add to Mailing List: yes
Please describe your comment briefly:
Comments of the Snake River Alliance
On Idaho Power Company's 2009 Integrated Resource Plan (IRP ) Submitted by Ken Miller, Clean
Energy Program Director, Snake River Alliance
April 15, 2010
The Snake River Alliance appreciates the opportunity to submit these comments to the Idaho
Public Utilities Commission in docket IPC-E-09-33, Idaho Power Company's 2009 Integrated
Resource Plan (IRP)~ on behalf of its members, many of whom are customers of Idaho Power.
The Snake River Alliance (Alliance) is an Idaho-based non-profit organization, established in
1979 to address Idahoans' concerns about nuclear waste and safety issues. In early 2007, the
Alliance expanded the scope of its mission by launching its Clean Energy Program. The
Alliance's energy initiative includes advocacy for renewable energy resources in Idaho;
expanded conservation and demand- side management programs offered by Idaho's regulated
utilities and the Bonneville Power Administration; and development of local, state, regional,
and national initiatives to advance sustainable energy policies.
The Alliance appreciates Idaho Power' s invitation to participate in the 2009 IRP Advisory
Committee and the company's willingness to meet with us and to provide supplemental
information on myriad issues during the preparation of this IRP. We also commend Idaho Power
for making the extraordinary decision to interrupt the IRP development process to review its
sales and load forecast and other issues to reflect economic and demand changes flowing from
the current recession. We believe the IRP before the Commission is more meaningful given the
adjusted forecasts.
As with the 2006 IRP (and 2008 IRP Update), the 2009 IRP is a marked improvement in many'
regards, notably the recognition of the need to continue raising the bar on energy efficiency
and conservation achievements. We do have concerns about the Plan's treatment of greenhouse
gas emissions and Idaho Power's coal resources, and those are detailed below.
THE PREFERRED PORTFOLIO
The Alliance focuses most of these comments on the 2010~2019 period of the IRP, as plans for
the subsequent decade are by necessity extremely fluid. Nonetheless, Portfolio 2-4 (Wind &
Peakers) for the period 2020- 2029 sheds light on the Company's resource preferences: Natural .
gas, wind, and transmission.
Portfolio 1-4 (Boardman to Hemingway) for 2010-2019 contains a relatively low amount of non-
transmission supply- side resources. The 150MW of wind in 2012 is the result of a request for
proposals (RFP) that was issued in May 2009 and is a committed resource, although 10 months
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after the RFP was issued the awarding of that contract seems to have taken longer than
anticipated. We remain hopeful a successful bidder will be identified and that this wind
resource comes online in 2012 as planned. Aside from that committed wind resource, and the
expected integration of new PURPA wind resources during this time frame, there are no other
plans to add wind until 2022. Idaho Power's j usti fication is that the company continues to
face annual peak demand increases of 1.5 percent over the 20-year planning period, compared
to an average system load growth of 0.7 percent over that time frame (IRP at P. 49 , although
this box projects average system load growth at .07 percent).The company's position is that
bringing significant amounts of wind online would not be prudent at this time given the wind
resource brings little capacity (5 percent) to the system during times of peak demand. While
we agree the current wind portfolio on Idaho Power's system currently does little to meet
peak demand, we also agree with conventional wisdom that a geographically diverse wind
portfolio and integration improvements will help mitigate the resource's capacity and energy
va riabili ty .
With regard to the 425MW associated with the Boardman to Hemingway transmission in 2015 and
2017, we understand why Idaho Power chose this resource over others, such as additional
natural gas beyond Langley Gulch. However, we raise the issue of whether this much power will
be available for market purchases, and if so the nature of that generation.
Idaho Power has committed to completing the update of its wind integration study before
initiating the 2011 IRP process in July 2010. As Idaho Power's projected uSe of wind
resources theoretically approaches 600MW (IRP at P. 18), it will become increasingly
important to continue advances in wind forecasting and other integration technologies. We are
particularly pleased to note Idaho Power's interest in exploring such wind integration tools
as the ACE Di versi ty Interchange in collaboration with other regional balancing authorities.
While the 2009 IRP' spreferred portfolios do not include solar thermal during the 20-year
planning period, primarily for cost considerations, we appreciate Idaho Power's initial
efforts to analyze various solar technologies and cost. Also weighing in solar's favor is the
fact that the resource is available during Idaho Power's summer peak days - the resource very
well tracks Idaho Power's system load curve (IRP at P. 65). While Idaho Power contracted with
Black & Veatch to study the feasibility of developing solar resources in southern Idaho, the
results of that study were presented to the IRPAC in September 2008. The analysis was
helpful, and we encourage Idaho Power to consider updating the study for the 2011 IRP to
reflect changes in solar technologies and cost.
ALTERNATE PORTOLIOS
The Alliance understands the prudency in developing alternate portfolios in the event some of
the assumptions supporting the preferred portfolios do not occur or are materially affected.
The primary driver for developing the alternate portfolios is the timely development of the
proposed 300-mile Boardman to Hemingway (B2H) 500kv transmission line from the Hemingway
substation in southwest Idaho to a switching yard at the Boardman Power Plant near Boardman,
Oregon (IRP at P. 83). Among the attributes of this project are improved access to renewable
energy resources in northeast Oregon and the ability to more fully transmit power from the
existing 101MW Elkhorn Valley Wind Project. While firm transmission capacity exists for 66MW
from the Elkhorn Project to Idaho Power's system, potential congestion may require
curtailment at certain times in the future.
Central to Idaho Power's planning for B2H is third-party interest in subscribing to the
project (IRP at P .115). Should that interest fail to materialize, Idaho Power will consider
delaying construction of B2H and replacing that resource mostly with substantial amounts
(340MW) of gas-fired generation on top of the 300MW from Langley Gulch, replacing Preferred
Portfolio 1-4 (Boardman to Hemingway) with Alternate Portfolio 1-2 (Gas Peakers). In a prior
IRP, the Commission raised the issue of rising amount of natural gas in Idaho Power's
resource portfolio. We have similar concerns, given uncertainties with natural gas
availabili ty and prices during this IRP planning period and we recommend the Commission
revisit the natural gas issue in its review of this IRP.
PUBLIC POLICY ISSUES
The public policy issues contained in the IRP received extensive discussion during
preparation of the IRP. For example, the issue of asset ownership drew diverse comments on
whether Idaho Power should own its own supply-side resources (as with its coal plants and
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Langley Gulch) rely on Power Purchase Agreements, or a blend of the two. We believe a mix of
company-owned and merchant generation is appropriate from a risk perspective. While company-
owned resources bring advantages such as the ability to include them in rates and rate of
return advantages, the company has a tendency (inadvertent or otherwise) to own only fossil
fuel resources and rely on PPAs or PURPA contracts for renewables.
The issue of Renewable Energy Credits is also one that we hope Idaho's utili ties and the
Commission are able to resolve with more certainty. We agree with Idaho Power that retention
of RECs will be important should the company need them to comply with a federal Renewable
Portfolio Standard and we supported the Company's application to the PUC for permission to
retire RECs from its geothermal and Elkhorn Valley wind PPAs. That said, we believe Idaho
Power's proposed REC management program filed in IPC-E-08-24 on Jan. 4, 2010, is reasonable
and should assist the Company in complying with anticipated federal renewables standards.
We support Idaho Power's consideration of a Solar Pilot Project, and urge the Company to
involve its diverse stakeholders in determining the nature of such a project. A "shareholder"
funded demonstration project has merits, but is only one of many possibilities to showcase
solar energy and just as important to demonstrate Idaho Power's seriousness in planning for
portfolio- scale solar generation in the future.
GREENHOUSE GAS EMISSIONS AND CARBON REDUCTIONS On May 21, 2009, IDACORP shareholders asked
the company to develop a strategy to reduce its greenhouse gas emissions. On Sept. 17, the
company filed a Form 8- K with the U. S . Securities and Exchange Commission outlining its
intent to comply with the spirit of the shareholders' resolution and its goal to reduce its
resource portfolio's average C02 emission intensity for the 2010 through 2013 time period to
a level of 10 percent to 15 percent below Idaho Power's 2005 C02 emission intensity of 1,194
lbs C02/MWh.
The issue of when and how Idaho Power attains these carbon reductions is an important one,
both from risk-avoidance given the inevitable federal carbon constraints and also for Idaho
Power bill-payers who would bear the costs of higher rates when the carbon costs associated
wi th coal plants are imposed. We're concerned this IRP sends mixed signals about Idaho
Power's plans to reduce its carbon emissions. On one hand, the IRP states that "Idaho Power
has chosen to directly face the issue of curtailment and the 2009 IRP attempts to quantify
the impact of proposed carbon legislation" (IRP at P. 125). On the other hand, the IRP
appears to set a "tipping point" that will influence the company's decisions on dispatching
from its coal resources: "The results of the analysis indicate at an allowance price of less
than $30, the no-coal curtailment scenario is a lower cost option. If the cost of carbon
allowances exceeds $30, the coal curtailment scenario becomes the lowest cost option" (IRP at
P. 117). Furthermore, the IRP states: "..AI ternative compliance options implemented as part of
any future carbon regulation may allow the continued operation of Idaho Power's coal
resources. "
To their credit, each of Idaho's regulated electric utilities is now planning for federal C02
constraints. Most utili ties, including Idaho Power, are attaching specific dollar amounts per
ton of carbon, and in Idaho Power's case a risk analysis was performed to estimate the effect
of a $43 per ton carbon tax with an annual escalator. The Alliance is concerned the level of
Idaho Power's commitment to reducing its carbon emissions will be based in large part on the
price the federal government eventually places on those emissions, and that could pose
financial and environmental risks to the company , its shareholders, and its customers. The
IRP implies that should federal legislation price carbon below an arbitrary number such as
$30 a ton, the most attractive option in the second 10 years (2020-2029) falls back to
relying on coal-fired generation and the negative environmental and financial consequences
that accompany it. The implication that Idaho Power might forgo the 2-4 Wind and Peakers
portfolio for the second 10 years of this IRP and revert back to its most heavily polluting
generation thermal resources absent adequate federal carbon prices is troubling.
We are also concerned about assertion that Idaho Power's resource selection in the first 10
years is almost immune from federal carbon legislation and, as a consequence, will likely not
impact dispatch decisions from existing and planned generation resources: "There are only
minor costs of the proposed carbon legislation in the first 10 years of the planning period
because the carbon legislation does not change Idaho Power's resource choices during the
first 10 years. However, the proposed carbon legislation does affect how Idaho Power operates
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its resources in the first 10 years, but the effects are minor and result from reduced off-
system sales" (IRP at P. 116). This seems contradictory inasmuch as the probability of
federal carbon legislation in the next two to three years is very high. If Idaho Power is
assuming that its risks associated with its coal-fired generation plants are nominal, it may
be placing an unnecessary risk on its shareholders and customers.
The IRP does consider possible coal curtailment from anticipated federal carbon-reduction
mandates in the 2020- 2029 planning period (IRP at P. 116). We appreciate that Idaho Power is
anticipating replacing lost capacity from coal curtailments, and we understand the quandary
in which Idaho Power finds itself: The presumptive resource to replace the bulk of the
curtailed coal-fired generation appears to be simple cycle combined turbines. We would hope
that, given Idaho Power's pledge to begin reducing its carbon emissions intensity by 2013
(primarily through changes in the existing hydro system, water leases, and cloud-seeding), it
will continue to consider how the need to begin ramping down those emissions fits with Idaho
Power's dispatch decisions. We would also have preferred to see in this IRP a quantification
of carbon emission reductions attached to the portfolios that were analyzed.
We raise the issue of meeting future load growth and the expected coal curtailment in part
because those issues were thoroughly analyzed in the Northwest Power and Conservation
Council's new Sixth Power Plan. That plan envisions that the Northwest can meet 85 percent of
its new load through energy efficiency and conservation; most of the remainder being met
through wind and in some cases with new gas turbines. The Sixth Plan deservedly puts a
premium on the expected savings through efficiency rather than supply- side resources. We are
concerned that Idaho Power's preferred portfolio at best stabilizes carbon emissions rather
than begins to reduce them.
BOARDMAN COAL PLANT
The IRP's conflicting approach to the coal and carbon issue is evident in its lack of an
articulated position on the Boardman coal plant in Oregon. Idaho Power is a 10 percent
stakeholder in Boardman. The majority owner, Portland General Electric, faced an Oregon
Department of Environmental Quality order to install pollution abatement equipment at
Boardman, although those measures would not have reduced the plant's C02 emissions. Recently,
PGE has indicated it plans to decommission the plant by 2020 rather than continue operations
through 2040. If the installation of all required abatement measures proceeded, Idaho Power's
share of those expenses would have been well in excess of $50 million - again realizing no
carbon reductions. Given the environmental challenges at Boardman, we believe Idaho Power's
best interests would be served by conducting detailed modeling of the various scenarios
surrounding the operation of Boardman when Idaho Power conducts its next IRP.
Environmental representatives on the 2009 IRPAC urged Idaho Power to take a more definitive
approach to its plans regarding Boardman. We realize PGE' s decision will largely seal
Boardman's fate, but given the nominal amount of power received from Boardman (64MW), and
given the plant's significant carbon emissions that will be subject to federal penalties, we
believe this IRP represents a missed opportunity for the company to meet its carbon-reduction
pledge to its shareholders.
In addition to the possible Boardman upgrades, the IRPnotes on Page 59 ("Planned Upgrades at
Thermal Facilities") that Idaho Power is also looking at expenditures of an estimated $40
million for efficiency upgrades at each of the four Jim Bridger units (at a cost of about $11
million per unit, and with an estimated generation increase of 6.1MW per unit) beginning in
2010. Combined with the costs of upgrading Boardman, the total cost of upgrading existing
coal plants will likely exceed $60 million to maintain the same output from Boardman and to
gain an estimated 24. 5MW from efficiencies at Bridger. This does not include the anticipated
2018 plant modifications for North Valmy (IRP at P. 59) for which no costs estimates are
attached. Add the carbon costs that Idaho Power anticipates will come from Washington, and
customers will soon begin to question the wisdom of these investments when expanded energy
efficiency and conservation opportunities exist along with more renewables opportunities.
DEMAND-SIDE MANAGEMENT
As in the past, we applaud Idaho Power's progress in expanding its DSM programs. We
appreciate the company's consideration of various resources for help in assessing its DSM
accomplishments and goals, and note that the 2007 Idaho Energy Plan, in recommendation E-2
says:
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"The Idaho PUC should establish annual targets for conservation achievement based on
estimates of cost-effective conservation in the service territories of Idaho's investor-ownedutilities.
The Committee believes it would be useful for the PUC to establish targets for conservation
achievement by Idaho's investor-owned utilities based on estimates of available cost-
effective conservation in each utility's Idaho service terri tory. The PUC could establish
these targets in a formal evidentiary proceeding or, al ternati vely, could work with the Power
Council to adapt its estimates of cost-effective conservation in the Pacific Northwest region
for use by Idaho utilities."
While we applaud Idaho Power for requesting the latest increase in the energy efficiency
tariff rider to 4.75 percent and the Commission for approving it, we remain concerned that
the rider funds may be inadequate to capture all cost-effective DSM identified by the company
and its Energy Efficiency Advisory Group. The rider balance may be affected as well if the
Commission grants Idaho Power's request to fund its participating share of the Northwest
Energy Effìciency Alliance (NEEA) from the rider account rather than through rates. We don't
question that those funds will be well spent; only that each dollar in the rider account is
crucial to maximize the Company's many energy efficiency and demand response programs. We
question whether some cost effective energy efficiency may not be captured if adequate funds
do not exist in the rider account.
Regarding the Appliance Standard Assessment (IRP P. 43-44), we note Idaho Power references
the 2007 Quantec study on appliance energy effìciency standards as well as how the standards
existing in Oregon and Washington are performing - and how they might "increase the potential
of less-efficient equipment being marketed and sold to Idaho residents." That Idaho risks
becoming a dumping ground for inefficient appliances that cannot be sold in neighboring
states is a major concern. Unfortunately, the IRP suggests no solutions as to how this threat
can be addressed. Similarly, the Appliance Standard Assessment raises significant issues
relating to energy-saving potential. Idaho Power's potential savings analysis (IRP at P. 44)
is startling: 278,809MWh in energy savings and 43MW in demand savings for the commercial and
residential classes combined. In addition, the IRP discusses a number of recommendations by
Quantec on how Idaho Power and "other entities" (IRP at P. 44) can evaluate and develop
energy efficiency standards. We commend Idaho Power for including this discussion in the IRP
and urge the Commission to make note of it in its order acknowledging this IRP.
PEAK DEMAND
We remain concerned about the rate of Idaho Power's growth in peak demand compared to the
proj ected growth in energy. To a degree, it is the peak demand that will set the table for
future supply- side resource acquisitions at considerable costs to customers. The company will
realize significant and laudable peak demand shifts through its dispatchable irrigation
demand response program, and to a lesser degree through its air-conditioner cycling program,
but we view the rate of peak-hour load increases relative to average system load increases as
not sustainable.
We agree with those who have argued in support of efforts to flatten the company's peaking
periods through more aggressive demand response programs. While some such efforts may not
result in reduced average-energy consumption as the consumption will be shifted to other
times, they will certainly help defer the need for additional peaking resources.
Idaho Power's DSM programs have relieved pressures for new supply side resources. We believe
the new dispatchable irrigation demand response program is proving a huge success. We were
disappointed that Idaho Power's proposed commercial air-conditioner cycling program was not
approved by the Commission, and we urge the Company and Commission staff to seek ways to
develop a program that will meet Commission approval.
RENEWABLES
We credit the company for a thorough discussion of its renewables options in the coming
years. We also encourage the company to more closely examine the possibility of enhanced
geothermal technologies as they begin to unfold, such as with the DOE's funding of enhanced
geothermal research with the Uni versi ty of Utah and U. S. Geothermal's Raft Ri ver site.
We also are pleased to see Idaho Power giving serious consideration to a solar pilot project,
and we believe an investment of some sort in solar PV and other technologies is appropriate
and should be expanded in future IRPs. We are also pleased to see Idaho Power continuing to
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address its wind integration issues through exploring such ideas as the ACE Diversity
Interchange (AID) and intra-hour scheduling to reduce wind' s variability an~ enhance its role
as a more reliable renewable resource.
DISTRIBUTED GENERATION
To the extent Idaho Power can rely on a limited amount of dispatchable customer-owned
generators during periods of extreme peak demands or other exigencies in serving load, this
idea appears worthy of exploration (IRP at P. 38). We would have concerns about air quality
issues stemming from anything but a rare and limited deployment of such diesel generators,
particularly since a peak load that triggers deployment of the diesel generators may well
occur during summer periods when the Treasure Valley's air quality is poor and borders on
non-attainment status. This IRP recognizes the environmental concerns and as a result its
analyses were based at a lower capacity factor of .69 percent (60 hours per year), similar to
the capacity factor for a SCCT natural gas-fired peaking turbine. The IRP notes Industrial
Customers of Idaho Power (ICIP) believe a distributed generation program of this nature could
reach 80MW. The idea of dispatching 80MW of diesel generation - much of it in Idaho Power's
Treasure Valley load center - on a hot summer day seems potentially problematic. We would be
far more comfortable with Idaho Power's projected initial size of 15MW until such time as
this concept can be more fully analyzed.
Nonetheless, we understand the value a fleet of distributed generators can have in meeting
Idaho Power's reserve requirements. It is difficult to envision a scenario in which Idaho
Power would need much more than 15MW during a peak crunch. And at a 30-year levelized cost of
$519 per MWh (IRP at P. 39), such a program certainly is not cost-effective, other than
banking the generation for reserve requirements while deploying the generators rarely, if
ever.
RISK ANALYSIS AND RESULTS
We appreciate Idaho Power's attention to the potential demands from electrifying our
transportation fleet and encourage the company to explore the implications (including the
benefits, such as storage) of the coming wave of plug-in and other hybrid vehicles (IRP at P.
105) .
As mentioned above, we are concerned about the narrative (IRP at P. 105) that says in part:
"Limited, or ineffective, carbon legislation could lead Idaho Power and other utilities to
continue to generate from traditional fossil-fueled plants." Once again, this implies that
Idaho Power is agnostic on the issue of continued operations of its coal fleet; but that
those decisions will be dictated by possible federal mandates rather than a pledge it has
made to its shareholders to reduce its carbon emissions.
Regarding the C02 Allowance Prices (IRP at P. 108), we believe any estimate of a carbon price
that is below $43 per ton is not acceptable from a risk or environmental responsibility
perspective. Attempting to plot a glide path for the Boxer-Kerry Carbon Allowance Price Cap
and High Case Scenario (Figure 10.3, IRP at P. 108) may be a reasonable approach given the
dearth of information on what future carbon prices may look like. To its credit, Idaho Power
polled members of the IRPAC during preparation of the IRP, and there was general agreement
that it is very difficult to discern what the price may be.
Regarding resource siting (IRP at P. 113), Idaho Power has over the course of the past two
years acquired important experience on the challenges in siting resources - particularly
transmission. We commend the Company's recent efforts at community and stakeholder
involvement in making such monumental decisions. For clarity, however, we note that decisions
reached by MidAmerican Nuclear Energy Co. to cancel plans for a Payette County reactor had
nothing to do with siting and everything to do with economics. The problems encountered by
Alternate Energy Holdings, Inc., in Owyhee, Elmore and now Payette counties stem from siting
challenges but more importantly from a lack of public acceptance and, again, economics.
SUMMARY
The Alliance believes Idaho Power's 2009 IRP is the product of the Company's willingness to
involve myriad stakeholders, and also to re-evaluate future sales and load growth estimates
in light of the current recession. More than ever, the Company's decision to divide the
planning period into 10-year portfolios is prudent given the uncertain near-term landscape on
such matters as federal climate and tax legislation; changing technologies for solar,. wind,
and other renewable resources; fuel prices; and the future of region-wide transmission
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projects. The preferred portfolio identified for the 2010-2019 planning period seems
reasonable in light of the current economic realities and the appropriate emphasis on
expanding the company's energy efficiency and conservation initiatives.
The form submitted on http://www . puc. idaho. gov /forms/ipuc1/ipuc. html
IP address is 70.102.111.178
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