20130911final_order_no_32890.pdf

Office of the Secretary
Service Date
September 11,2013
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF PACIFICORP DBA )
ROCKY MOUNTAIN POWER’S 2013 )CASE NO.PAC-E-13-05
INTEGRATED RESOURCE PLAN )
)ORDER NO.32890
_________________________________________________________________________________
)
On April 30,2013,PacifiCorp dba Rocky Mountain Power (“Rocky Mountain”or
“Company”)filed its 2013 Integrated Resource Plan (IRP)with the Commission pursuant to the
Commission’s Rules and in compliance with the biennial IRP filing requirements mandated in
Order No.22299.
On May 30,2013,the Commission issued a Notice of Filing establishing a 28-day
comment deadline and a 7-day intervention deadline.See Order No.32819.Thereafter,the
Commission granted intervention to Idaho Conservation League (“ICL”),Snake River Alliance
(“SRA”),Monsanto Company (“Monsanto”),and Renewable Energy Coalition (“REC”).See
Order Nos.32827,32876.
Upon Motion by ICL,the Commission extended the public comment period until
August 8,2013.See Order No.32838.
ROCKY MOUNTAIN’S INTEGRATED RESOURCE PLAN
Rocky Mountain’s 2013 IRP is its 12th plan submitted to state regulatory
commissions.The Company states that its IRP was developed with participation from numerous
public stakeholders,including regulatory staff,advocacy groups,and other interested parties.
The 2013 IRP focuses on a 10-year period,2013-2022.
The Company states that its projected load forecast in the 2013 IRP is down in
relation to projected loads used in the 2011 IRP and 2011 IRP Update.The Company cites
industrial self-generation and load cancellation requests in Utah and Wyoming as significant
drivers of this decreased load estimate.The reduced load forecast has greatly mitigated but not
eliminated the Company’s need for new resources.
Rocky Mountain also noted that base case wholesale power and natural gas prices are
down significantly from the 2011 IRP and 2011 IRP Update.Rocky Mountain states the
proliferation of shale gas exploration in North America has led to these favorable market
conditions.
ORDER NO.32890 1
The Company identified three goals for its IRP process:(1)determine resource needs
focused on the first ten years;(2)identify the preferred portfolio of incremental suppiy and
demand-side resources to meet this need;and (3)develop an action plan for the next two to four
years required to implement the plan.
The Company indicated a system capacity deficit of 824 MW starting in 2013 that
increases to 2,308 MW in 2022.The Company’s load obligation takes into account a 1.2%
yearly system coincident-peak load growth rate.This average yearly load forecast is 11.3%
lower than the load forecast used in the 2011 IRP.According to the Company,the decreased
load forecasts are driven in part by increased self-generation by industry taking advantage of low
natural gas prices and by load cancellations.Existing resource capacity has also been adjusted
down by an annual average 113 MW between 2013 and 2076 and approximately 200 MW in
years 2017 and beyond.When taking into account lower load growth rates and small reductions
in existing capacity,the annual load and resource balance deficit has decreased dramatically
ranging from 1925 MW in year 2013 to 3852 MW in year 2020 when compared to the 2011 IRP,
thus eliminating the need for major resource acquisitions in the first ten years of the planning
horizon.
From an energy perspective,PacifiCorp does not experience any deficits throughout
the first ten years of the planning horizon during off-peak hours.Minor deficits begin to occur
during on-peak hours in 2018 and become increasingly frequent beyond the 2022 time frame.
The idaho and system retail sales growth that drives resource needs is depicted in the
table below.Compared to system sales growth,the Company predicts Idaho residential and
commercial growth will exceed the system average while industrial sales growth will be less.
PacifiCorp also predicts irrigation sales will decline overall for the system,with a higher rate of
reduction in Idaho.Overall,the forecast shows a 0.89%growth rate across the planning
horizon’s first ten years,with Idaho’s growth Lagging below the system average at 0.57%.
PacifiCorp identified 19 core cases with different combinations of fuel price,Carbon
Dioxide (C02)price,renewable portfolio standard (RPS)requirements,demand-side
management (DSM)assumptions,and targeted resources.Each core case was modeled across
five different scenarios of the Energy Gateway project implementing various combinations of
transmission line segments.Overall,PacifiCorp ran 94 core-case simulations with each
generating a unique resource portfolio and an associated net present value revenue requirement
ORDER NO.32890 2
(PVRR)over a 20-year period.A summary of the core cases is included as Attachment A to the
Plan.
The Company selected its preferred resource portfolio after performing risk analysis
on 37 of the portfolios.The final selection was based primarily on the performance of risk
adjusted PVRR,projected cumulative carbon dioxide emissions,and supply reliability measures.
Incremental resources within the first ten years include:12 MW of combined heat and
power resources,953 MW of Class 2 DSM,149 MW of solar,and between 650 MW and 1333
MW of annual market power purchases.PacifiCorp identified 23 action items as a result of
developing the plan and from feedback received from public participants.Details of these action
items are listed in Attachment C to the Plan.
ICL COMMENTS
ICL believes that Rocky Mountain’s IRP is flawed and incomplete.ICL is critical of
Rocky Mountain’s forecast of future carbon costs,its rejection of “the top performing
accelerated DSM Portfolio,”and the Company’s assumption that the utility pays the capital costs
associated with distributed PV systems.ICL believes that over the planning horizon it is
reasonable to assume that there will be a price attached,legislatively or administratively,to
future carbon emissions.ICL forecasts that low,mid and high carbon prices beginning in 2020
will be $15,$20,and $30 and escalate to $25,$42.50,and $70 by 2030,while “RMP assumes a
low,mid,and high prices of $0,$16,and $26.”
ICL believes that an “arbitrary and unexplained discounting of future carbon prices
can expose customers to substantial risk.”ICL suggests that the Commission require the
Company to estimate resource capacity deficits by both size (MW)and timeframe.ICL believes
the Company should identify concrete methods to increase DSM acquisition.
ICL cites the Company’s failure to “discuss how changes to transmission scheduling
will affect future resource needs,costs,or system operations.”Finally,ICL believes that Rocky
Mountain does not accurately account for the compliance costs and risks of future coal plant
upgrades,nor do they adequately consider reasonable alternatives “to compete against coal.”
MONSANTO COMMENTS
Monsanto stated that the Commission should,as it has for previous IRP filings,
accept the Company’s filing as non-binding.In its comments,Monsanto addressed four issues:
(1)inconsistent and unexplained changes to the capacity contribution at system peak for existing
ORDER NO.32890 3
interruptible resources;(2)the Company’s reliance on its newly developed System Operational
and Reliability Benefits Tool (SBT”or rnodel”)as an analytical model designed to measure
incremental economic benefits of specific transmission projects;(3)double counting in the
Energy Balance Account;and (4)the complexity of the Company’s IRP process.
Monsanto remarked that the Company has cut its forecast of interruptible contract
resources at system peak from 281 MW in the 2011 IRP to 141 MW in this IRP filing.
According to Monsanto,this is implausible because on page 95 of the filing Rocky Mountain
cites the availability of “324 MW of load interruption capability at time of system peak.”
Monsanto believes the Company’s SBT model is “untested”and its results are
“unverified”by “third parties and stakeholders.”Monsanto states the model may have potential
“adverse consequences”to the MSP’s allocation of costs to Idaho.Nonetheless,Monsanto cites
as “positive features”in the Company’s IRP:(I)the use of planning criteria in the IRP based on
achieving a 13%planning reserve margin associated with summer peak loads;(2)forecasted
energy shortages and the importance to the PacifiCorp system of the differences between on-
peak and off-peak consumption of electricity;and (3)the role of the state renewable
Portfolio Standards (“RPS”)in the IRP process,including the newly-developed “RBS
scenario maker”which was included in the IRP to identify and isolate the costs associated with
the state’s specific RPS requirements.
Monsanto believes that the Company’s updated “Energy Balance Determination”is
not consistent with the updated “Capacity Balance Determination.”According to Monsanto,the
Company includes “interruptibles”in its Existing Resources,and Sales are deducted.Sales are
also included in the Obligation equation.This double counts Sales as both reducing resources
and increasing load obligation.
Finally,Monsanto cites to its “renewed effort to actively participate”in the IRP
process.As a result,Monsanto states that it has become clear that Rocky Mountain has
intentionally designed the JRP process to be overly complex so as to discourage participation.
Monsanto believes the Company’s IRP process should be overhauled and suggested Rocky
Mountain more closely emulate the IRP process implemented by Idaho Power.
REC COMMENTS
REC states that the organization “is a large group of primarily existing hydroelectric
Public Utility Regulatory Policies Act (PURPA)qualifying facilities (QF)located in
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PacifiCorp’s multi-state service areas.”REC’s comments focus on a single issue:the year of
resource deficiency cited in Rocky Mountain’s 2013 IRP filing.
REC remarks that the Company often refers to the “next avoidable resource as a 2024
CCCT.”REC believes that Rocky Mountain’s decision of how or when to fill a resource deficit,
whether from purchased power,DSM or a new generating facility,does not negate the reality of
a specific capacity deficit in 2013,which grows significantly each year of the planning horizon
(see PacifiCorp 2013 IRP Volume 1,page 99,Table 5.1,2).REC states that it has several
members that have existing and long-standing PURPA contracts with Rocky Mountain.
Contracts expiring and needing replacement could be impacted by avoided cost pricing based
upon the year of deficit being established as 2024.
SRA COMMENTS
Snake River Alliance is an Idaho-based non-profit organization,established in 1979
to address Idahoans’concerns about nuclear waste and safety issues.In 2007,SRA expanded
the scope of its mission by launching its Clean Energy Program.SRA believes the Company
provided stakeholders reasonable opportunities to provide input into the IRP process.
SRA questions the Company’s efforts to upgrade and retrofit its coal plants.SRA
believes the Company relies too heavily on uncertain market transactions in lieu of a timely
renewable resource acquisition plan.According to SRA,Rocky Mountain has adopted an
unrealistic and conservative forecast of future carbon regulation.SRA is critical of the
Company’s participation in multi-utility effort to combat the EPA’s implementation of new
regulations under the Clean Air Act.SRA believes the Company should conduct a full “coal
plant analysis”that accounts for the total costs of “anticipated emission-control upgrades.”
SRA questions the Company’s commitment to renewable energy resources.SRA
believes the Company’s wind resource additions are the minimum amount required under the
utility’s Oregon RPS obligations.SRA advocates an accelerated deployment of energy
efficiency and demand response programs.
SRA highlighted the Company’s acknowledgment of lower annual system load
growth and believes the Commission should defer acceptance of the IRP filing until the
Company can cure some of the flaws and concerns referenced in SRA’s comments.
ORDER NO.32890 5
STAFF COMMENTS
Staff recommended the Commission acknowledge the Company’s 2013 JRP.Staff
believes the Company performed extensive analyses,gave reasonably equal consideration of
supply-and demand-side resources,and provided acceptable opportunities for public input,
resulting in an TRP that satisfies the Commission established requirements.
Staffs analysis focused on two main issues:(1)Load and Resource Balance —Issues
related to the load forecast and planning reserve margin;and (2)Resource Portfolio Selection —
Company’s rationale for selecting its final preferred resource portfolio;issues related to RPS,
market risk,and near term investments in transmission and coal plant emission controls.
Load Resource Balance
Staff noted that existing resource capacity net of system load obligation shows a
positive reserve margin of 4.4%in 2013 becoming negative starting in year 2016.This is far
short of the Company’s goal of maintaining a 13%planning reserve margin.
The large reductions in load forecasts compared to the Company’s 2011 IRP is
largely attributable to load reductions in the industrial sector.Staff examined electricity
forecasts in the Energy Information Agency (ETA)2011 and 2013 Annual Energy Outlook for
the Mountain West and Pacific regions.According to Staff,the percentage decrease in projected
energy use across the same ten-year period was comparable (5-6%reduction)to the percent
change in the energy forecast of this year’s IRP with the 2011 IRP Update.
Staff believes the Company’s load forecasts in its 2011 IRP were overly optimistic.
Given the reduction to the 2013 IRP load forecast,comparable reductions relative to ETA
forecasts,and the methodology changes the Company has adopted,Staff believes the Company’s
latest forecasts are more reasonable and in-line with current circumstances.
Staff believes that the Company’s 13%target for planning reserves is reasonable.A
planning reserve margin between 12 and 15%does not increase system costs in a significant
manner.Staff noted that the Company also establishes incremental planning reserves within the
Northwest Power Pool and its participation in the California Independent System Operator
(CISO)energy imbalance market.
Resource Portfolio Selection
Staff highlights the Company’s decision to defer the addition of a major generation
resource until 2024,when the Company expects to add a 423 MW CCCT gas plant and 432 MW
ORDER NO.32890 6
of wind generation.The Company plans to use unbundled renewable energy credits (REC)to
meet Washington RPS requirements prior to 2024.
Rocky Mountain selected the second highest ranked portfolio (EG2-C07)as its
preliminary preferred portfolio.Staff believes this was reasonable for two reasons.First,the
preliminary preferred portfolio and the accelerated DSM portfolio are nearly identical during the
first ten years.The only difference is that the accelerated DSM portfolio has an increased
amount of DSM Class 2 resources in lieu of firm market purchases.
Staff believes the Company’s rejection of the accelerated DSM portfolio was
reasonable.Given that the Company does not have confidence that the ramp rates are
achievable,passing on the accelerated DSM portfolio and choosing the next highest ranked
portfolio would carry less risk.This gives the Company several IRP cycles to determine if the
ramp rates are feasible.However,modeling accelerated DSM ramp rates gave the Company
insight as to the positive effect cost-effective DSM has on risk-adjusted PVRR of a given
portfolio prompting the Company to identify several action items to attempt to accelerate its
Class 2 DSM programs.
Second,by not making selections based on model results alone,the Company is
demonstrating that it is using its decision support tools appropriately.Rocky Mountain
augmented its preliminary preferred portfolio so that wind resources needed to meet Washington
RPS requirements were replaced with unbundled RECs.The results reflect a $116 million to
$232 million reduction in risk-adjusted PVRR compared to the preliminary preferred portfolio.
Staff supports this refinement to significantly reduce revenue requirements while allowing the
Company to comply with Washington State regulatory requirements.
Staff’s position is that requirements imposed by a jurisdiction that drives incremental
cost above the comparable resource cost should generally not be imposed on Idaho ratepayers.
The Company developed several portfolios with and without RPS requirements to understand its
effect.Depending on the specific case,those model runs with no RPS requirements include very
little or no incremental wind,biomass,or geothermal generation resources.This indicates,most
likely due to low capacity contribution rates,that renewables are not cost-effective when
compared to other resources System Optimizer can choose to meet peak loads.
Staff does not believe that the increase in the incremental firm market purchases in
the 2013 preferred portfolio is unreasonable.However,Staff is concerned that the apparent
ORDER NO.32890 7
increase in customer exposure to electricity price risk will occur if large market anomalies occur
even though the Company has accurately evaluated market price risk through modeling variable
electricity prices.Additionally,there is no guarantee that the energy will be available for sale in
the market if a geographically widespread peak event occurs.Staff believes resource adequacy
studies by the Northwest Power Planning Council and the Western Electricity Coordinating
Council,as well as the inclusion of a 13%planning reserve margin,provide reasonable
protection.Nevertheless,the potential for over-reliance on the market exists.
Staff is encouraged by the Company’s development of a System Benefit Tool (SBT)
to measure transmission benefits not captured by other IRP models.Staff believes SBT benefits
can be reported with appropriate caveats but should not be rolled into the overall TRP analysis
until the error of the calculation is well understood and sufficiently small.Construction of the
remaining segments of the Energy Gateway Transmission Project after 2020 will enable more
accurate analysis in future IRP’s.
Staff commented that the lowest mean PVRR across all C02 levels was a portfolio
that assumes no additional thermal base load capacity,accelerated DSM ramp rates,and no
Populous to Winstar transmission line (Segment D).Staff recommended the Company further
explore these alternatives to offset the need for the new line.In the interim,Staff does not object
to the Company continuing the permit procurement process for Segment D.
Again,Staff emphasizes that the system benefits of transmission investments seem to
disproportionately favor states with RPS standards.Given that Idaho does not have an RPS,
Staff believes increased documentation and support are required when the allocation of cost are
not proportional to the jurisdictional benefit.
Staff remarked that Rocky Mountain is faced with making large coal plant emission
control investments in order to comply with federal environmental regulations.The Company
claims that its efforts to either shut down or convert some of its coal fleet to natural gas is
complicated because it is bound by shared ownership agreements and legal compliance
requirements in combination with the fact it is not the majority owner or operator of either plant.
Staff believes that Rocky Mountain’s analysis of the alternative that retires coal plant
units on the compliance date did not take into account the location of alternate resources that
could reduce the need for additional transmission capacity.For example,Staff believes that if
the Company’s Jim Bridger units were shutdown early and replaced with generation closer to
ORDER NO.32890 8
major load centers,a significant amount of existing transmission capacity could become
available lessening and/or delaying the need for the Segment D.Staff believes an analysis
should be done and,if warranted,transmission implementation plans should be adjusted and any
cost savings should be included in coal plant emission control investment decisions.
PUBLIC COMMENTS
On June 21,2013,the Commission received a joint letter from SRA,ICL,Sierra
Club,HEAL Utah and the Powder River Basin Resource Council (hereinafter collectively
referred to as “organizations”).The organizations expressed concern regarding the scope of
PacifiCorp’s IRP across its multi-state jurisdictions.Specifically,the organizations referenced
the pollution controls made necessary by the EPA’s implementation of the Regional Haze Rule
in Wyoming.The organizations believe the Company’s IRP and coal study “completely missed
the mark”by not adequately accounting for the costs of the foreseeable pollution control
requirements.Accordingly,they have asked the Commission to defer acceptance of the IRP
filing until the Company addresses these concerns.
On August 8,2013,the Commission received a comment from NW Energy Coalition
(“NWEC”).NWEC states that its overarching concern is that the Company continues to focus
and rely 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.
NWEC criticizes the Company’s lack of documentation to substantiate its
assumptions that the accelerated DSM in its least cost/risk portfolio is not reliably achievable.
NWEC stated that Rocky Mountain’s explanations of its action plan to achieve accelerated Class
2 DSM targets are too vague.NWEC cited key parts of the Company’s 2011 IRP action plan
that were not implemented.According to NWEC,an analysis of the Company’s DSM
achievements since 2011 suggests the Company is being too conservative in setting its 2013 IRP
targets for DSM.NWEC recommended the Commission urge Rocky Mountain to continue its
progress on Class 2 DSM achievements that match those identified in the least cost/least risk
portfolio Case EGO2-C15.
NWEC is pleased with the Company’s efforts in improving its analysis of the costs
and risks associated with upgrades to its coal fleet.These improvements notwithstanding,the
ORDER NO.32890 9
Coalition maintains that the Company is still underestimating the cost and risk of continued
reliance on coal generation.
NWEC believes that the Company’s base case modeling assumptions utilize a C02
price (zero cost through 2022)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.NWEC recommended that prior to
Commission approval or acknowledgment of any coal plant upgrades contained in the 2013 IRP
Action Plan,the Company be required to 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.
NWEC believes that load control and demand response are undervalued in the 2013
IRP.NWEC recommended close Commission scrutiny of the underlying model assumptions in
the 2013 IRP of Class 1 DSM.NWEC also recommended the Commission encourage Rocky
Mountain to improve its analysis regarding demand response and other load control tools in its
next IRP.
NWEC is critical of the Company’s failure to increase or maintain its commitment to
renewable energy resources.NWEC believes 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.
NWEC recommended the Commission closely review the solar price projections for Idaho and
encourage the Company to look for ways to close the gap between technical potential and
achievable technical potential in distributed solar resources.NWEC also recommended 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.
Finally,NWEC cited the Company’s efforts to assess the effects of transmission
upgrades on the planning process.NWEC recommended the Commission seek out a process,
workshops,to develop a broader transmission assessment into the IRP.
On August 8,2013,the Renewable Northwest Project (“Renewable Northwest”or
“RNP”)submitted a public comment on Rocky Mountain’s 2013 IRP.Renewable Northwest
commended the Company on the inclusion of stakeholders and what it called “a robust public
process.”
ORDER NO.32890 10
Renewable Northwest states that Rocky Mountain is investing in the past,not the
future.Approving this JRP gives PacifiCorp a green light to make long-term investments at four
coal units and to delay the acquisition of new clean energy resources until 2022.
Renewable Northwest opined that,since fall of 2012,the landscape of federal energy
policy has shifted further than any time in the last five years.Renewable Northwest believes
EPA regulations will add costs to the operation of coal units,and may not allow the Company’s
facilities to operate at today’s level of output.The organization believes that Rocky Mountain’s
resource strategy stands in sharp contrast to that of its utility peers.Thus,Renewable Northwest
recommended the Commission review this IRP and action plan in light of the potential for EPA
regulation of carbon and under the high C02 price,rather than the base C02 assumption on
which many of the Company’s investment decisions are based.
Renewable Northwest is critical of the Company’s failure to choose the IRP’s highest
performing portfolio featuring accelerated energy efficiency and the use of cheaper gas peaking
units rather than large combined cycle units.The results clearly demonstrate that accelerating
the acquisition of energy efficiency throughout the Company’s service territory saves ratepayers
money and reduces their exposure to volatility in the natural gas and wholesale power market.
Renewable Northwest believes the Company did not provide evidence that the energy
efficiency measures could not be accelerated.Renewable Northwest recommended the
Commission communicate to Rocky Mountain that it expects the Company to clarify what
definitive and quantifiable actions will be taken to implement an aggressive energy efficiency
program.
Renewable Northwest believes the Company’s flawed assumptions and analysis of
renewable energy resources led to their lack of inclusion in the 2013 IRP.Rocky Mountain uses
a simpler but less accurate methodology that simply considers the likelihood that renewables will
be generating during the “super-peak”period.The result is to credit renewable resources with
less capacity value,which makes portfolios with renewables appear more expensive due to
excess capacity resources.
Renewable Northwest commends Rocky Mountain for their improved transmission
analysis.The methodological improvements were ambitious and increased the IRP’s
complexity,but RNP considers the results impressive.Renewable Northwest agrees with the
ORDERNO.32890 11
Company that the System Benefit Tool used in this IRP is preliminary and there remains
considerable flexibility as to how these benefits should be measured.
COMMISSION FINDINGS AND DECISION
The Commission has reviewed the filings of record in Case No.PAC-E-13-05,
including Rocky Mountain’s 2013 Integrated Resource Plan,appendices and addendums,and
related comments.We find that the Company’s 2013 IRP is in the appropriate format and
contains the necessary information outlined by the Commission in Order No.22299.The
Commission accepts Rocky Mountain’s 2013 IRP filing.
In so doing,the Commission reiterates that a standard IRP is merely a plan,not a
blueprint.An IRP is a utility planning document that incorporates many assumptions and
projections at a specific point in time.It is the ongoing planning process that we acknowledge,
not the conclusions or results.The Commission offers no opinion or ruling regarding the
prudency of the Company’s election of its preferred resource portfolio.
The Commission acknowledges the comments and criticisms of the intervenors and
other interested parties,including but not limited to Monsanto and ICL.The Commission
appreciates the Company providing a meaningful process and venue to enable the parties’active
participation in the IRP process.Engagement by multiple interested parties is a prerequisite to
the development of a comprehensive and useful IRP.
The Commission also acknowledges that recent history has demonstrated that
attempts by energy analysts to predict carbon pricing is fraught with failure and uncertainty.
However,it seems more likely than not that the EPA will move forward and enact additional
regulations of fossil fuels under the federal Clean Air Act.In light of this contingency,it appears
to be in the best interest of the Company and its customers to continue to evaluate and devote
more focus on the development of alternative energy resources.
The Commission directs the Company to increase its efforts toward achieving higher
levels of cost-effective DSM.Instituting cost-effective energy efficiency measures that reduce
customer demand benefits everyone.Such measures can obviate the need for new generation
resources and thereby decrease the constant upward pressure on energy pricing.Cost-effective
reductions in customer demand,particularly in peak hours and months,are almost always
preferable to the construction of a new natural gas plant or purchases on the wholesale power
market.Therefore,the Commission will be attentive to Rocky Mountain’s efforts toward DSM
ORDER NO.32890 12
programs.In future IRP and DSM filings,the Commissions directs the Company to present
clear and quantifiable metrics governing its actions regarding decisions to implement or decline
to implement energy efficiency programs.
Finally,several parties,including the Company,Monsanto and Staff,commented on
the Company’s new model for measuring transmission benefits,the System Benefit Tool (SBT).
As is always the case regarding utility planning models,the reliability of the SBT will be borne
out over time.The Commission anticipates that the usefulness of the SBT will become clearer
upon the construction of the remaining segments of the Energy Gateway Transmission Project.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over PacifiCorp dba Rocky
Mountain Power,an electric utility,pursuant to Title 61 of the Idaho Code and the Commission’s
Rules of Procedure,IDAPA 31.01.01.000 etseq.
ACCEPTANCE OF FILING
Based upon our review,we find it reasonable to accept and acknowledge Rocky
Mountain’s filed 2013 Electric IRP.Our acceptance of Rocky Mountain’s 2013 IRP should not
be interpreted as an endorsement of any particular element of the plan,nor does it constitute
approval of any resource acquisition contained in the plan.
ORDER
IT IS HEREBY ORDERED that PacifiCorp’s 2013 Integrated Resource Plan is
accepted for filing.Acceptance of the 2013 IRP should not be interpreted as an endorsement of
any particular element of the plan,nor does it constitute approval of any resource acquisition or
proposed action contained in the plan.
THIS IS A FINAL ORDER.Any person interested in this Order may petition for
reconsideration within twenty-one (21)days of the service date of this Order with regard to any
matter decided in this Order.Within seven (7)days after any person has petitioned for
reconsideration,any other person may cross-petition for reconsideration.See Idaho Code §61-
626.
ORDER NO.32890 13
DONE by’Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of September 2013.
I
MACK A.REDFORI COMMISSIONER
J
MARSHA H.SMITH,COMMISSIONER
ATTEST:
Barbara B arrows
Assistant Commission Secretary
O:PAC-E-I 3-05np3
ORDER NO.32890 14