20130808NW Energy Coalition Comments.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION7 .U v 4
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IN THE MATTER Of PACIFICORP DBA )
ROCKY MOUNTAIN POWER’S 2013 )CASE NO.PAC-E-13-05
INTEGRATED RESOURCE PLAN )COMMENTS OF THE NW
)ENERGY COALiTION
I.Introduction
The NW Energy Coalition (Coalition)appreciates the opportunity to provide comments
regarding Rocky Mountain Power’s 2013 Integrated Resource Plan.The Coalition
participated in the pre-IRP workshop phase that the Company conducted for almost a full
year before filing the IRP.We recognize the value of the extensive input the Company
solicited through this process and believe that the result is a better and more robust IRP.
Although the plan is improved,we offer the following comments to express areas of
concern regarding certain aspects of the 2013 IRP and its associated Action Plan.
Our overarching concern is that the Company continues year after year to focus on
protecting business-as-usual —a reliance on outdated coal plants that are becoming
increasingly expensive to operate —coupled with a lack of appreciation for the reduced
risk and cost offered by demand-side resources and newer resource options such as
demand response,distributed generation and renewables.We fear that the Company’s
resulting decisions will lead to higher costs for all customers throughout Pacific
Power/Rocky Mountain Power territory.
CASE NO.PAC-E-I3-05 Comments of the NW Energy Coalition
II.Demand Side Management
A)Class 2 DSM
The Company’s 2013 IRP analysis clearly selected case EGO2-C15 as the least cost,
least risk portfolio.This portfolio contained accelerated DSM assumptions,among other
elements.Despite this portfolio ranking least cost/least risk,it was not selected as the
preferred portfolio based on the rationale that the accelerated DSM assumptions are not
reliably achievable.
The IRP documentation gives no substantiation regarding the assumptions used,nor any
detailed explanation of why specific assumptions used to obtain this accelerated DSM
case were deemed unreasonable.Other differences between this portfolio and the final
portfolio selected as the preferred portfolio (EGO2-C07a)—including early selection of
some Class I DSM and an inability to select CCCT resources --remain completely
ttnanalyzed in the IRP documentation.
The Company acknowledges that the rankings of case EGO2-C15 ilLustrated the value of
obtaining as much DSM as possible,as early as possible.However,they fail to commit to
higher DSM targets in the IRP Action Plan.Instead,the Company states that it
incorporates some specific action plan items that attempt to achieve accelerated Class 2
DSM.The Company does not identify these specific action plan items,nor does it
CASE NO.PAC-E-13-05 Comments of the NW Energy Coalition 2
provide an indication of the amount of expected DSM acceleration expected from the
action items.This approach is too vague and unsatisfying for the Coalition.
The lack of firm DSM commitments in the Action Plan to the accelerated DSM found to
be least cost/least risk,in exchange for nebulous action items,further concerns us due to
Rocky Mountain Power’s mediocre track record for implementing DSM action items.
Key items contained within the 2011 IRP Action Plan (that could have helped maintain
consistent upward momentum on Class 2 DSM)appear to not have been implemented or
were purposefully delayed by the Company.These items include:
I)Plans to acquire energy efficiency resources from the Company’s Special
Contracts customers in Utah and Idaho.
2)The system-wide RFP (excluding Oregon)for specific direct install and other
direct distribution programs targeting savings from residential and small
commercial sectors.
Additionally,we are concerned that the Company’s IRPs continually underestimate the
amount of achievable Class 2 DSM.Because the 2013 IRP relies heavily on front office
transactions (FOT),Class 2 DSM left unachieved will result in an increased reliance on
FOT —and the market risks that are associated with those purchases.
Since 2011,an analysis of the Company’s DSM targets and achievements indicates that
in most states,the Company is consistently outperforming its own targets.This leads LIS
CASE NO.PAC-E-1 3-05 Comments of the NW Energy Coalition 3
to believe that the Company is repeatedly setting overly conservative targets for Class 2
DSM.Table I provides the percentage of DSM Class 2 achieved above or below the
Company’s DSM Class 2 target for each state in 2011 and 2012.
Table.I Class 2 USM Actual Achievements by Percent over or under Class 2 DSM
target by State
State -2012 2011
California 52%7%
Idaho 48%-38%
Oregon 58%34%
Utah 3%38%
Washington 32%45%
Wyoming -5%-51%
During the 2011 IPR process,the Coalition expressed concerns about low ramp rates
used by the Company for Wyoming and Idaho,because these states currently have some
of the fastest growing opportunities for energy efficiency programs,largely due to the
fact that enetgy efficiency is just gearing up in these states.Table I illustrates that Idaho
clearly had a big jump in Class 2 DSM accomplishments in 2012 and the Wyoming gap
seems to be narrowing quite a bit.We remain concerned that the ramp rates and other
analysis for Idaho and Wyoming continue to underestimate the amount of Class 2 DSM
available.
The Coalition recommends that the Commission urge Rocky Mountain Power,through
specific Class 2 DSM targets in the IRP Action Plan,to continue rapid and robust
progress on Class 2 DSM achievements that match those identified in the least cost/least
risk portfolio Case EGO2-C15.
CASE NO.PAC-E-13-05 Comments of the NW Energy Coalition 4
III.Coal Resource
The Company,since the initial filing of the 201 1 IRP,has made great strides in
improving its analysis of the costs and risks associated with upgrades to its coal fleet.
These improvements notwithstanding,the Coalition maintains that the Company is still
underestimating the cost and risk of continued reliance on coal generation.A failure to
adequately address the full range of future regulations that will impact coal plants will
saddle ratepayers with high environmental upgrade costs,stranded costs,or both.
The Company’s coal analysis falls short in two main areas.First,the Company’s base
case modeling assumptions utilize a C02 price that is too low and,second,the Company
underestimates the likely requirements,and therefore costs,from known and unknown
future environmental regulations that impose pollution control investments.
The Company’s base case C02 price curve used in the 2013 IPR has zero cost through
2022.This assumption is out of step with recent announcements by the White House
regarding C02 regulations.The EPA is expected to issue rules regulating greenhouse gas
emissions from existing coal plants within the next couple of years.Consequently,the
timing and costs associated with greenhouse gas regulation are now expected to be much
faster and higher than what the Company utilized in its base case.Therefore,the
CASE NO.PAC-E-13-05 Comments oftheNW Energy Coalition S
Coalition recommends that the Commission give more careful consideration to the high
C02 scenarios and results in the IRP analysis.
Regarding pollution control cost assumptions,the company models a base case and
stringent case for regional haze requirements in order to reflect uncertainties in future
regulatory decisions.Unfortunately,both the base and stringent cases used in the 2013
IRP analysis underestimate likely regulatory futures.The base case for regional haze
requirements used by the Company in its coal plant analysis uses state implementation
plan requirements that have already been rejected by the EPA,ensuring that base case
cost assumptions are below likely costs.Further,the more stringent regional haze
scenario used in the Company’s analysis was proven inadeqtiate in the face of the recent
EPA decision in Wyoming.That decision indicates that the Company will be required to
install more costly environmental upgrades on a number of coal facilities,exceeding the
assumptions in the most stringent case analyzed in the 2013 IRP.Despite significant
input from stakeholders warning that the stringent case was not stringent enough,the
Company forged ahead with an analysis that we now know underestimates likely costs.
PacifiCorp is currently in process of costly upgrades to its coal fleet.Many significant
investments occur over the next couple of years,consequently,time is of the essence.
From the perspective of consumer and environmental protection,it is important to ensure
that the full range of costs and risks from likely regulation are understood in this 2013
CASE NO.PAC-E-1 3-05 Comments of the NW Energy Coalition 6
IRP because the majority of PacifiCorp’s coal plant investments will be made in the very
near fctture.
We recommend that prior to Commission approval or acknowledgment of any coal plant
upgrades contained in the 2013 IRP Action Plan,the Company be required perform a
revised coal unit analysis that incorporates a broader range of current and future
compliance scenarios that can be evaluated for economic and regulatory risk.
III.Load Control and Demand Response
Load control and demand response are undervalued in the 2013 IRP.Despite Class I
DSM Action Items from the 2011 IRP that called for at least 140 MW of incremental
cost-effective Class I DSM by 2013,no incremental Class I DSM resources were added
to the Company’s system in 2011 or 2012 and none is selected in the preferred portfolio
over the next 10 years.The Company also canceled the commercial curtailment product
called for in another 2011 IRP action item.The Company explains in Chapter 9 of the
2013 IRP that the cancellation of these items was due to a revised load forecast.
Additionally,the 2013 IRP Volume I states that the Company completed an analysis of
the feasibility and costs of west-side Class I itrigation control,however,“it was not
selected as an economic resource in the first ten years of the 2013 LRP preferred
portfolio”(IRP,Volume 1,page 257).This result is surprising;more scrutiny of this
CASE NO.PAC-E-1 3-05 Comments of the NW Energy Coalition 7
decision is warranted given the expected value of summer peak load reduction to the
Company’s system.
Despite a 2011 Action Plan item to incorporate plug-in electric vehicles and smart grid
technologies in the 2013 IRP,the Coalition can find no evidence that these things were
actually included in the IRP analysis in any meaningful way.No discussion of these
items or how they were included in the analysis is found in Volume 1 or Volume 2 of the
IRP.
As technological development (distributed generation,smart phone apps that manage
home energy use,etc.)makes it easier for customers to become an active part of the
electric system,the Company should seek methods to use this technology to the benefit
of the overall system.Demand response and other load control tools will play an
increasingly important role in managing peak loads,integrating renewable resources and
thus keeping costs down for customers.
The Coalition recommends close Commission scrutiny of the underlying model
assumptions in the 2013 IRP that seem to have led to an undervaluing of Class I DSM.
We also recommend that the Commission encourage Rocky Mountain Power to increase
the amount and sophistication of its overall analysis regarding demand response and other
load control tools in the next lRP.
CASE NO.PAC-E-1 3-05 Comments of the NW Energy Coalition 8
IV.Renewable Resources
One notable aspect of the Rocky Mountain Power 2013 IRP is that the robust renewable
energy effort made by PacifiCorp in recent years seems to be slipping backward.Roughly
summarizing new capacity additions in Table ES-3 in Volume 1,for 2013-2022,front
office transactions are 1076 MW (average per year),new combustion turbines 645 MW,
new energy efficiency is 95$MW,and renewables only 138 MW (mostly distributed
solar enabled by Utah state policy,and no new wind or geothermal).
There are several contributing factors to the shortfall in renewable energy additions to the
mix,but the primary ones,we believe,are an overestimation of renewable prices,
especially solar,and an underestimation of future gas prices and price volatility.
A)Solar Costs
In our view,the IRP starts with too high a current cost for solar PV and does not
incorporate the likely decline in costs over both the short and long term.Aside from a
small amount of solar DG enabled under state policies,there are no acquisition targets or
pilot programs included in the Action Plan despite the fact that PacifiCorp territory
includes some of the best solar resources in the nation.Because much of the Company’s
system is summer peaking,we see a substantial opportunity to develop solar at scale to
assist with adequacy and reliability and reduce the need for expensive contingency and
balancing resources.
CASE NO.PAC-E-1 3-05 Comments of the NW Energy Coalition 9
The Company has the opportunity to be a leader in developing this beneficial resource.
The first place to start is to have a more accurate assessment of current and future costs.
The IRP anticipates only modest price reductions for solar PV throughout the 20-year
planning period,not enough to make a substantial difference in the resource mix.Yet
experience curve analysis over four decades and more recent trends suggest deep cost
reductions will occur in the corning years.As a result,solar resource acquisition by 2032
in the draft IRP is a tiny fraction of the potential that actually exists.The Company’s
solar price projections need to be reevaluated.
B)Natural Gas Price Volatility
The current IRP modeling framework does not capture the full diversity and risk hedging
value of clean energy resources such as energy efficiency,demand response and
renewables.Throughout the industry,there is a great deal of diversity among natural gas
price forecasts and,historically,the price of natural gas is known to be highly volatile.
While considering a range of natural gas prices in the IRP analysis provides some
consideration for price risk,a fully dynamical modeling approach such as the Regional
Portfolio Model (RPM)used by the Northwest Power and Conservation Council does a
better job in characterizing the uncertainty and risk aspects of the system,including the
important driver of natural gas price volatility.
The Coalition recommends that the Commission closely review the solar price
projections for Idaho and to encourage the Company to look for ways to close the
CASE NO.PAC-E-13-05 Comments oftheNW Energy Coalition 10
enormous gap between technical potential and achievable technical potential in
distributed solar resources.We also recommend that the Commission urge the Company
to review and improve its methodology for including natural gas price uncertainty and
risk in IRP modeling in the next IRP.
Transmission
The IRP analysis includes a number of significant enhancements for the incorporation of
transmission in the planning process.Foremost is the substantial expansion of outputs by
running five Energy Gateway packages,ranging from no-build to all-build,for each of
the 19 planning scenarios.
1-lowever,the IRP scenarios only consider the segments that PacifiCorp currently
considers to be active,and does not directly evalLiate other potential segments that have
previously been planned or other new transmission or non-transmission alternatives.
We recommend that the company,the respective state regulatory commissions and
stakeholders consider how to build a broader transmission assessment into the IRP
process.One or more scoping workshops to lay out key issues might be a good way to
begin.
One transmission related development new in this IRP is the System Operational and
Reliability Benefits Tool (SBT)that the Company is developing to identify more fully the
benefits of proposed transmission segments.We agree this is a good step to take because
CASE NO.PAC-E-13-05 Comments of the NW Energy Coalition 11
the system-wide models can’t capture the effects of these projects in sufficient detail for
stakeholder and regulatory assessment.
The SBT is not a comprehensive cost-benefit analysis.It is perhaps best considered a
snapshot of costs and benefits for a new transmission line,but only for informal purposes.
Indeed,there are costs and benefits that are not included in the SBT,including mitigation
costs that are not included in capital costs,and other important externalities such as the
social cost of carbon.We agree with the Company that further assessment and
development is needed for the SBT.In addition,at this time it is not appropriate to
inciLide the Customer and Regulatory Benefits component that attempts to measure
indirect benefits to customers from reduced outage risk,becacise it is highly sensitive to
assumptions and not backed by adequate data.
Thank yoti for the opportunity to submit comments regarding the Rocky Mountain Power
2013 IRP.
Respectfully submitted,
Wendy Gerlitz
Senior Policy Associate
NW Energy Coalition
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