20151009final_order_no_33396.pdf

Office of the Secretary
Service Date
October 9,2015
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF PACIFICORP DBA )
ROCKY MOUNTAIN POWER’S 2015 )CASE NO.PAC-E-15-04
INTEGRATED RESOURCE PLAN (IRP))
)ORDER NO.33396
________________________________________________________________________________________________
)
On March 31,2015,PacifiCorp dba Rocky Mountain Power (“Rocky Mountain”or
“Company”)filed its 2015 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 12,2015,the Commission issued a Notice of Filing,Notice of Modified
Procedure,and Intervention Deadline.See Order No.33299.Commission Staff (“Staff’),Idaho
Conservation League (“ICL”),Snake River Alliance (“SRA”),and Renewable Northwest
submitted comments within the established comment deadline.Rocky Mountain then filed reply
comments in response to each party’s comments.
ROCKY MOUNTAIN’S 2015 IRP
Rocky Mountain stated that its 2015 IRP represents its 13th comprehensive plan
submitted to state regulatory commissions.Rocky Mountain 2015 IRP at 1.The Company
stated that its IRP Application was developed with participation from numerous public
stakeholders,including regulatory staff,advocacy groups,and other interested parties.Id.The
2015 IRP focuses on a 10-year period,20 15-2024 (hereinafter “planning horizon”).
The Company’s projected load forecast is “down beyond 2019 in relation to projected
loads used in the [Company’s]2013 IRP and 2013 IRP Update.”Id.at 2.The Company cites
“reduced residential class load forecast due to increased energy efficiency,including continued
phase in of the Energy Independence and Security Act federal lighting standards,[and]lower
energy response to economic growth”as the main drivers of lower forecasted load.Id.
The Company remarked that “Class 2 [Demand-Side Management]DSM,or energy
efficiency,savings in the 2015 IRP preferred portfolio exceed energy efficiency savings from the
2013 IRP preferred portfolio by 59 percent by 2024.”Id.at 3.In fact,the Company claims that
“acquisition of incremental energy efficiency resources”increases by 59%over its estimate in its
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2013 IRP and “meets 86 percent of [the Company’sl forecast load growth from 2015 through
2024.”Id.
Once again.Rocky Mountains base case wholesale power and natural gas price
estimates are significantly lower than the estimates found in its previous (2013)JRP.Id.The
Company stated that the estimates in its 2013 IRP Update are more closely aligned to its 2015
IRP estimates.Id.According to Rocky Mountain,“growth in natural gas supplies,primarily
from prolific shale plays in North America,have continued to outpace expectations”and exert
downward pressure on natural gas prices.Id.Rocky Mountain believes that while the market
for front office transactions (“FOT5”)is “favorable,growth in energy efficiency savings mitigate
the need for FOTs through the front ten years of the planning horizon.”Id.at 4.“On average
2015 IRP preferred portfolio FOTs are down 16%from the 2013 TRP Update and down 29%
when compared to the 2013 IRP preferred portfolio.”Id.
Rocky Mountain’s 2015 IRP preferred portfolio includes the addition of 816 MW of
energy emanating from power purchase agreements for 36 qualifying wind and solar projects
coming on-line by the end of 2016.Id.The Company stated that these projects are necessary in
order to “mitigate the cost of state renewable portfolio standard (RPS)compliance”in its
California.Oregon,and Washington service areas.Id.Rocky Mountain stated that its preferred
portfolio “meets the Utah 2025 state target of 20%,and has a significant bank to sustain
continued future compliance in Utah.”Id.
Additionally,Rocky Mountain stated that its analysis of “near-term Regional Haze
compliance requirements”led the Company to convert some of its coal plants to natural gas by
2018 and install emissions control equipment at its Wyodak,Dave Johnston Unit 3,and Cholla
Unit 4 units,potentially “saving PacifiCorp customers hundreds of millions of dollars.”Id.at 5-
6.
Rocky Mountain also noted the impact of the U.S.Environmental Protection
Agency’s (EPA)issuing Rule §111(d)of the Clean Air Act establishing state emission rate
targets for existing resources.Id.at 6.According to the Company,“the 2015 IRP preferred
portfolio meets PacifiCorp’s share of state emission rate targets among those states in which
PacifiCorp serves retail customers and owns existing fossil generation potentially affected by the
proposed rule.”Id.The Company “continues to support transmission permitting efforts for
Energy Gateway West (Segments D and E),Energy Gateway South (Segment F),Boardman to
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Hemingway (Segment H),and a line from Walla Walla to McNary.”Id.The Company expects
to “complete construction of the Walla Walla to McNary project by 2017.”Id.
Rocky Mountain described several “supplemental studies”the Company relied upon
in order to develop its 2015 IRP.Id.Regarding potential future resource acquisition,Rocky
Mountain claimed that it will “exceed its 13%target planning reserve margin through 2019 and
falls just short of its target planning reserve margin in 2020.”Id.at 8.The Company believes
that the expiration of an existing exchange contract will increase system capacity and allow the
Company to exceed its 13%target planning reserve margin in 2021 and 2022.Id.Rocky
Mountain estimated that it will be at least “82 MW and 165 MW below its target planning
reserve margin in 2023 and 2024,respectively.”Id.
Rocky Mountain expressed its commitment to assess current market conditions and
dispatch or sell its system resources in an economic manner to the benefit of customers.The
Company believes that “the economic dispatch of system resources is critical to how the
Company manages net power costs.”Id.The Company estimated that its first on-peak energy
shortfall will occur in July 2020,totaling 5 GWh.Id.at 9.In July 2024,the Company remarked
that the on-peak monthly load deficit will increase to 189 GWh.Id.Rocky Mountain does not
forecast any energy shortfalls during off-peak periods through the 2024 IRP planning horizon.
Id.
The Company’s 2015 IRP Action Plan includes the following:
1.Renewable Resource Actions
-Pursue unbundled REC request for proposals (RFP)to meet its
state RPS compliance requirements.
-Issue annual RFPs seeking current-year or forward-year vintage
unbundled RECs to meet Washington and California renewable
portfolio standard targets through 2017.
-Defer issuance of RFPs seeking unbundled RECs that will qualify
in meeting Oregon renewable portfolio standard targets until states
begin to develop implementation plans under EPA’s draft 111(d)
rule.The Company asserts that it has a projected bank balance
extending out through 2027.
-Issue quarterly reverse RFPs through 2016 to sell 2016 vintage or
older RECs that are not required to meet state RPS compliance
obligations.
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-Secure bids from 2013 RFPs seeking up to 7 MW of capacity from
qualifying solar systems to meet Oregon’s 2020 solar capacity
standard.
2.Firm Market Purchase Actions
-Acquire short-term on-peak firm market purchase deliveries from
2015-2017.
-Balance month and day-ahead competitive price brokered
transactions.
-Balance month,day-ahead,and hour-ahead transactions executed
through an exchange,such as Intercontinental Exchange (ICE).
-Prompt month forward,balance of month,day-ahead,and hour-
ahead non-brokered transactions.
3.DSM Actions
-Class 1 DSM:Pursue a west-side irrigation load control pilot
beginning 2016.
-Class 2 DSM:Acquire the following cost-effective Class 2 DSM
resources targeting annual system energy and capacity selections
from the preferred portfolio:2015 —551 MW of Annual
Incremental Energy (GWh)and 133 MW of Annual Incremental
Capacity;2016 —584 MW of Annual Incremental Energy and 139
MW of Annual Incremental Capacity;2017 —616 MW of Annual
Incremental Energy and 146 MW of Annual Incremental Capacity;
2018 -.634 MW of Annual Incremental Energy and 146 MW of
Annual Incremental Capacity.
4.Coal Resource Actions
-Naughton Unit 3:Issue RFP to procure gas transportation and
resume engineering,procurement,and construction (EPC)contract
procurement activities for the Naughton Unit 3 natural gas
conversion in the first quarter of 2016.Possibly update its
economic analysis of natural gas conversion in conjunction with
the RFP processes to align gas transportation and EPC cost
assumptions with market bids.
-Dave Johnston Unit 3:Wyoming currently appealing 10th Circuit
ruling regarding the portion of s final Regional Haze Federal
Implementation Plan (FTP)requiring the installation of selective
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catalytic reduction (SCR)at Dave Johnston Unit 3,or a
commitment to shut down Dave Johnston Unit 3 by the end of
2027.If EPA’s final FTP is upheld,the Company is committed to
shutting down Dave Johnston Unit 3 by the end of 2027.If EPA’s
final FTP is or will be modified,the Company will evaluate
alternative compliance strategies.
Wyodak:Continue appeal of the portion of EPA’s final Regional
Haze FTP that requires the installation of SCR at Wyodak.
Compliance deadline for SCR under the FTP is currently stayed by
the court.If EPA’s final FTP is upheld (with a modified schedule
that reflects the final stay duration),the Company will update its
evaluation of alternative compliance strategies that will meet
Regional Haze compliance obligations.
-Cholla Unit 4:Continue permitting efforts in support of an
alternative Regional Haze compliance approach that avoids
installation of SCR with a commitment to cease operating Cholla
Unit 4 as a coal-fueled resource by April 2025.
5.Transmission Actions
-Continue permitting for the Energy Gateway transmission plan.
Near term targets for Segments D,E,and F include the continued
funding of the required federal agency permitting environmental
consultant;continue to support the federal permitting process by
providing information and participating in public outreach.For
Segment H (Boardman to Hemingway),continue to support the
project under the conditions of the Boardman to Hemingway
Transmission Project Joint Permit Funding Agreement.
-Complete Walla Walla to McNary project construction plan with
2017 expected in-service date.Continue to support permitting
process.
STAFF COMMENTS
Staff reviewed the Company’s 2015 IRP,and noted substantial changes to the
Company’s resource strategy since its 2013 IRP in response to uncertainty concerning the EPA’s
proposed interpretations of §111(d)of the Clean Air Act,EPA Regional Haze Requirements,and
requirements of state specific Renewable Portfolio Standards (RPS).Staff believes that these
uncertainties greatly complicate Rocky Mountain’s planning process.However,Staff also
believes that the Company’s flexible approach,which considers a broad array of scenarios and
potential resource portfolios,is appropriate.In general,the alternative resource portfolios
ORDER NO.33396 5
considered by Rocky Mountain decrease the Company’s reliance on coal,either by
decommissioning existing coal-fired plants,or by converting them to use natural gas,with a net
decrease in generation capacity by 2024.In its 2013 IRP,the Company planned to meet the
resulting capacity shortfall using market purchases.The Company’s 2015 IRP preferred
portfolio is somewhat less dependent on market purchases,relying on Class 2 DSM energy
management programs to meet anticipated capacity needs.
Staff noted that the Company has changed the way that it values its DSM programs in
its 2015 IRP.Class I DSM programs include firm,fully dispatchable and scheduled capacity
programs such as the Company’s 170 MW irrigation load management program in Idaho.In
previous IRPs,Class 1 DSM capacity savings were subtracted from the Company’s obligation.
In the current IRP,these are considered to be a resource.Rocky Mountain’s existing Class 1
DSM programs will account for a constant 323 MW of capacity between 2015 and 2024.
Because Class 1 DSM savings are no longer deducted from the Company’s obligation,the net
effect is a small increase (42.6 MW)in required reserves,and a concomitant decrease in capacity
position.Between 2015 and 2024,Rocky Mountain’s existing Class 2 DSM programs will
account for a 110 MW reduction in its capacity obligation.The Company anticipates a 0.89%
annual increase in system coincident peak demand between 2015 and 2024.Staff noted that the
Company’s system-wide capacity position may exceed available FOTs beginning in 2020.Table
1 summarizes Rocky Mountain’s system-wide resources,obligations,reserves,capacity position,
and available FOTs.
Staff observed that the capacity deficit in the Company’s east balancing area,
including Idaho,Utah,and Wyoming,already exceeds available FOTs,while there are no
capacity deficits in its west balancing area.
Resource Portfolio Selection
Staff remarked that Rocky Mountain’s participation in regional plan comparisons
such as the Northern Tier Transmission Group (NTTG),the Western Electricity Coordination
Council (WECC),and FERC Order 1000 Interregional Coordination Group can ultimately lead
to more efficient long-term planning processes across the Western United States and Canada.
Staff also believes that both an efficiency of scale and cooperative,co-ownership of transmission
assets that reduce the cost of complying with contingency requirements can be achieved through
these efforts.
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Improvements in operational efficiency ensure that existing resources are better
utilized and may allow postponement of costly future transmission investments.Staff believes
that the Company should compare its transmission plans as outlined in the IRP to planning
efforts of regional transmission groups to assure efficient and prudent compliance with
operational and long-term transmission planning and reliability requirements.
Load and Resource Balance
Staff noted that,in its acceptance of the Company’s 2013 IRP,the Commission
directed the Company “to increase its efforts toward achieving higher levels of cost-effective
DSM”and “to present clear and quantifiable metrics governing its actions regarding decisions to
implement or decline energy efficiency programs.”The Company continues to rely on Class 2
DSM energy savings programs to meet its capacity obligations.By 2024,the Company
anticipates deriving 6.1 GWh (9%)of its energy obligation,and 1.0 GW (9.0%)of capacity
obligation from Class 2 DSM energy savings programs.This is nine times the capacity reduction
that the Company obtains from its existing Class 2 DSM programs (110 MW),and is greater
than the combined capacity of its two largest coal-fired plants,Hunter Unit 3 and Huntington
Unit 1.By 2034,under the Company’s preferred portfolio,Class 2 DSM savings will be 10.9
GWh.The Company stated that for its 2015 IRP it used an accelerated Class 2 DSM acquisition
scenario that exceeded energy savings estimates in its 2013 IRP by 59%.According to Rocky
Mountain,the accelerated scenario is “both speculative and hypothetical,”but the Company did
not provide an assessment of the specific risks associated with it,
Staff believes the Company’s Class 2 DSM energy savings target to be achievable,
and supported the Company’s aggressive program to obtain Class 2 DSM resources.According
to the Company,its Class 2 DSM programs are primarily targeted at reducing energy
consumption,so a program’s ability to reduce system peak demand is dependent on the types of
energy savings programs adopted by the Company.For example,a program that encourages
energy efficient heating might reduce energy use,but have no impact on the capacity obligation
of a summer peaking utility like Rocky Mountain.The Company’s 2015 IRP emphasized the
process for selecting Class 2 DSM programs based on their ability to reduce energy use,but
described no mechanism for assuring their contribution to reducing peak load.Given the 2015
IRP reliance on Class 2 DSM capacity reductions,Staff believes that the Company should
ORDER NO.33396 7
include a thorough explanation of the effects of these programs for both energy and capacity
reduction in its 2017 IRP.
Staff noted inconsistencies between some of the text,tables,and figures found in the
IRP and used to discuss DSM related capacity reductions.Part of this difficulty arises because
the 2015 JRP often does not discriminate between the nameplate/capacity reduction and the
system peak reduction of Class 2 DSM programs.Class 2 DSM nameplate/capacity reduction is
computed without regard to the timing of that reduction,and is not necessarily coincident with
the system’s peak.For purposes of analyzing capacity position,Staff opined that only a Class 2
DSM program’s system coincident peak reduction is useful.The effect of using
nameplate/capacity reduction rather than system coincident peak reduction is to exaggerate,often
by 50%or more,the apparent capacity contribution of energy efficiency programs.Given the
increased importance of Class 2 DSM programs to the Company’s capacity position,Staff
asserted that the Company should provide a more detailed explanation describing how the
Company will assure that these programs meet the energy and capacity targets in its next IRP.
Staff analyzed the Company’s preferred portfolio plan for
converting/decommissioning selected coal-fired plants.According to the Company,this plan is
sensitive to assumptions about natural gas price and the EPA’s final rules for interpreting
§111(d).The 2015 IRP included extensive discussions of these risks and issues surrounding
them.Given these uncertainties,Staff believes that the Company’s preferred portfolio plan for
reducing the energy contribution of coal and increasing the energy contribution of natural gas to
both be reasonable.The Multi-State Allocation Protocol assigns the differential costs of existing
RP5s in other states to those states that cause these costs to be incurred,thereby protecting Idaho
customers from subsidizing the RPS requirements of other states.
Finally,the 2015 IRP included a summary of a Wind Integration Study (“WIS”)
conducted by the Company.Over the next two years,the Company plans to double the amount
of energy that it obtains from solar power,from 3%to about 6%of its system load.Given its
increased reliance on solar power,Staff believes that it would be appropriate for the Company to
conduct a solar integration study for inclusion in the Company’s 2017 IRP.
Therefore,based on its review Staff believes that the Company’s 2015 IRP gives
balanced consideration to supply and demand resources and that it satisfies the requirements of
Commission Order Nos.25260 and 22299.Staff recommended the Company’s subsequent IRPs
ORDER NO.33396 8
address current resource needs with more accurate information prior to final resource decisions.
Staff recommended the Commission acknowledge the Company’s 2015 IRP filing.
ICE COMMENTS
ICL expressed its support of Rocky Mountain’s balanced approach toward demand-
side resources.ICL believes that Rocky Mountain’s methodology for considering demand-side
measures is more equal and balanced than Idaho Power’s or Avista’s.TCL recommended that
the Commission establish the Company’s method as the preferred method for all Idaho utilities.
ICL believes that the Company’s WIS shows the growing ease and lowering costs of
integrating wind resources.TCL also believes that the Company’s modeling of the Clean Power
Plan and coal pollution costs is fundamentally flawed.ICL included comments regarding
modeling errors for the Clean Power Plan and coal unit retirement that it stated were presented
by the Sierra Club to the Washington UTC regarding the Company’s 2015 IRP filing in
Washington.
ICL recommended that the Commission direct the Company to produce an IRP
update that analyzes a mass-based power plan compliance strategy to discover the least cost and
least risk path to deal with forthcoming coal pollution controls.
ICL remarked that Rocky Mountain is among the largest utility systems in the
western interconnect.According to ICL,by virtue of their geographic spread,resource stack,
transmission system,and coordination with other utilities,the Company’s future resource plans
will have more impact on Idaho than any other utility.ICL believes that the Commission must
scrutinize Rocky Mountain’s planning practices.
SRA COMMENTS
SRA stated that its primary concerns regarding Rocky Mountain’s 2015 IRP relate to
planning for Rocky Mountain’s coal fleet,how the IRP treats the Obama Administration’s new
Clean Power Plan,and the need for greater amounts of DSM resources to absorb much of the
projected lost coal generation.
SRA believes that Rocky Mountain’s 2015 IRP included adequate analyses of
possible 111(d)scenarios and suggested Rocky Mountain analyze the role of energy efficiency in
assisting the Company to comply with greenhouse gas emissions reduction targets.
At a minimum,and pending the outcome of litigation over the Clean Power Plan and
submittal of state implementation plans,SRA believes that the Clean Power Plan will almost
ORDER NO.33396 9
certainly impact the operation of one or more of Rocky Mountain’s coal plants or.in some cases,
its retirement and decommissioning schedule for certain plants.
SRA opined that Rocky Mountain’s parent company,PacifiCorp,is among the
nation’s most coal-reliant electric utilities.SRA lauded Rocky Mountain’s intentions to retire or
convert to natural gas approximately 2,800 MW of coal capacity during the planning period
covered in this IRP.However,SRA stated that it is disappointed by the Company’s extended
timeline for retirement/conversion.SRA believes that the Company’s reliance on such a large
amount of coal as far out as 20 years from now for 30%of generation continues to expose
customers to undue risk from the uncertain regulatory costs of coal combustion and the impacts
declining gas prices and renewable energy prices are already having on coal’s cost
competiveness as a generation resource.
SRA believes that the implementation of the Clean Power Plan will push coal further
to the margin.SRA noted that.in recent years,the Company has built new natural gas plants and
wind power projects and expanded energy efficiency programs.SRA believes savings of
customer dollars will be replicated as additional coal plants are scheduled for early
decommissioning.
SRA stated that the Commission should encourage Rocky Mountain (and all Idaho
regulated electric utilities)to aggressively promote its programs through the media and with
special attention to Community Action Partnerships that serve limited-income customers in its
Idaho territory.SRA believes that some of the greatest DSM savings can be reached through
commercial and industrial customers and noted that industrial sales comprise approximately 50%
of the Company’s sales in Idaho.
Finally,SRi\recommended that Rocky Mountain continue to research the viability
and value of its DSM programs.SRA stated that it appreciates the opportunity to comment on
Rocky Mountain’s 2015 IRP and commended the Company and its IRP team for its stakeholder
involvement efforts.
RENEWABLE NORTHWEST COMMENTS
Renewable Northwest congratulated the Company on the high degree of stakeholder
involvement during its 2015 IRP process.It acknowledged Rocky Mountain’s efforts in
attempting to model the new rule found in §111(d)of the Clean Air Act in its 2015 IRP.
Renewable Northwest recommended the Commission maintain the integrity of existing
ORDER NO.33396 10
environmental commodities—such as Renewable Energy Credits—and their associated markets.
Renewable Northwest also recognized Rocky Mountain’s progress made in planning for variable
energy resource integration,as reflected in the Company’s 2014 WIS.
Renewable Northwest declared that the 2014 WIS determined that a modest increase
of only 1 MW in wind regulating margin (the incremental amount of reserves required to
accommodate deviations of wind generation from forecasts)was required between 2012 and
2014 to accommodate a 417 MW increase in wind capacity.Furthermore,the Company’s
Distributed Generation Resource Assessment for Long-Term Planning Study highlighted the
large amount of potential commercial-scale solar photovoltaic that could be deployed in Rocky
Mountain Power’s Idaho service territory.Renewable Northwest expressed its appreciation of
the Company’s stakeholder process and looked forward to engaging with the Commission and
the Company in exploring the increasing role of renewable energy in subsequent IRPs.
ROCKY MOUNTAIN POWER REPLY COMMENTS
Rocky Mountain replied to the comments outlined above.The Company stated that
the parties were all generally satisfied with its 2015 IRP but expressed some concerns regarding
the Company’s modeling approach toward EPA’s draft Clean Power Plan (“CPP”)section
111(d)rule and how these perceived shortcomings could presumably bias the outcome of
resource selection,particularly with respect to identification and analysis of environmental
compliance costs.The Company sought to clarify some statements found in its IRP and what it
characterized as “misconceptions”by the parties issuing comments.
Reply to Staff Comments:Rocky Mountain responded to Staffs concern that the
Company’s capacity deficits cannot be met with available FOTs.Rocky Mountain clarified that
the values in Staffs tables come from Table 5.14 in the 2015 IRP.According to the Company,
this table is used to show capacity need before any incremental resource additions,and does not
include any Class 2 DSM.Table 8.8 in its 2015 IRP shows the final capacity position for the
first 10 years of the planning horizon inclusive of new resource additions from the preferred
portfolio.According to Rocky Mountain,Table 8.8 demonstrates that the Company’s system
capacity needs are met with planned additions of DSM resources,FOTs,and system transfers.
Regarding Staffs load and resource balance comments focusing on DSM,the
Company provided two clarifications:(1)Table 8.8 values are cumulative,not incremental.
Thus,capacity impacts for 2024 represent the impact in 2024 from 10 years of DSM acquisitions
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over the period of 201 5-2024:and (2)existing DSM in Table 8.8 represent only impacts from
2014 as discussed further on page 79 of the 2015 IRP.Earlier DSM impacts are embedded in the
load forecast and classified as existing resources.
Further,the Company clarified that its 2015 IRP preferred portfolio is not based on an
accelerated DSM scenario.The Company agreed that its targets are aggressive,based on the use
of the 85%achievability assumptions,when viewed relative to historical DSM acquisition levels.
The Company stated that any increase in DSM selections relative to the 2013 IRP is primarily
driven by higher levels of potential identified in the Company’s 2015 DSM potential study as
compared to the 2013 study.Both studies relied on the best available information.
Rocky Mountain responded to Staff’s requests that the next IRP include additional
information on planned DSM acquisitions and how these align with the IRP’s DSM selections in
terms of energy and capacity.The Company rej oined that the 2015 {RP Action Plan identifies
the planned DSM energy acquisitions;the 2015 IRP Update,and 2017 IRP will report on
progress toward achieving these targets.Also.Appendix D of the 2015 IRP includes preliminary
acquisition budget estimates,state-specific implementation plans,and a comprehensive DSM
Communications and Outreach Plan to provide additional detail on how the Company plans to
acquire the identified resources.The Company stated that it creates an annual report in each of
its state jurisdictions presenting the prior year’s DSM achievements.Each report contains actual
energy achievements and estimates of capacity impacts for DSM resources.
In response to Staffs suggestion that the Company include a solar integration study
in its 2017 IRP due to increased reliance on solar resources,Rocky Mountain agreed that solar
generation is increasing but contends that it does not rise to 6%of system load as alleged by
Staff.The Company claimed that the amount of energy from solar in 2017 is approximately 2%
of the Company’s projected load.Nonetheless,Rocky Mountain stated that it will consider
performing solar integration analyses during the 2017 IRP process.
Staff suggested the Company compare its transmission plan with those developed by
regional groups.The Company cited its participation in regional and interregional transmission
planning efforts with the Northern Tier Transmission Group (“NTTG”),the Western Electricity
Coordination Council (“WECC”),and FERC Order 1000 Interregional Coordination Group.
Further,the Company argued that it is obligated under its Open Access Transmission Tariff and
local Attachment K process to develop and maintain a reliable transmission system that meets
ORDER NO.33396 12
customers’needs and that is in compliance with six reliability standard requirements,as
described in data responses submitted in this case.The regional transmission plan under FERC
Order 1000 has different requirements to qualify which projects get included and their timing;
this approach may not be an exact match to local transmission planning requirements.
Reply to SRA:Rocky Mountain responded to SRA’s comment that the Company’s
reliance on coal for “roughly one-third of its generation in 2034”could be risky.Rocky
Mountain averred that it selected its preferred portfolio based on comprehensive cost and risk
analysis,as documented in Chapter 8 of the Company’s 2015 IRP.The Company stated that it
will continue to update modeling consistent with state plans for 111(d)as well as regional haze
compliance outcomes and examine near-term compliance alternatives to meet emission
requirements for coal units.
Reply to ICL:Rocky Mountain responded to ICL’s argument that the Company’s
modeling of EPA’s draft CPP section 111(d)rule is insufficient.The Company claimed that ICL
used comments submitted by the Sierra Club (“SC”)to the Washington Utilities and
Transportation Commission (“WUTC”)and submitted them in this proceeding as their own.The
Company strongly disagreed with the ICL/SC characterization of perceived modeling “errors”in
the 2015 IRP.Rocky Mountain argued that many of the comments submitted by SC to the
WUTC were based on erroneous interpretation of data and analysis performed by the Company
in its 2015 IRP.
The Company stated that the EPA’s draft section 111(d)rule was discussed at many,
if not all,of the IRP public meetings.According to the Company,many stakeholders provided
comments on their interpretation of the rule and concerns regarding how the Company may meet
draft compliance requirements.Additionally,two workshops,one in Salt Lake City,and one in
Portland,were devoted to discussion of the modeling tools developed to study EPA’s draft
section 111(d)rule in the 2015 IRP.
ICL/SC’s first issue concerns Rocky Mountain’s use of an emission rate-based
approach to meeting EPA’s draft section 111(d)rules.While ICL/SC may believe a mass-based
approach is a preferable modeling approach to studying EPA’s draft 111(d)rule,there was very
little guidance in the draft rule indicating how states would develop and adopt mass-based
targets,let alone information to suggest that such an approach would be adopted by all states.
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The Company stated that it looked at both emissions rate-based and mass-based approaches in
the 2015 IRP.
The Company then quoted a non-exhaustive list of ICL/SC’s misrepresentations
regarding Rocky Mountain’s 2015 IRP Filing:
(1)PacifiCorp’s review of a single interpretation of the CPP may [produce]
poor planning results”;
(2)“PacifiCorp’s failure to model mass-based CPP compliance”;
(3)“PacifiCorp neither modeled a mass-based approach”;
(4)“PacifiCorp’s exclusive choice of a rate-based approach.”
In response to the above,the Company cited page 143 of the 2015 IRP describing
different section 111(d)scenarios studied.Figure 7.4 on page 144 of the document demonstrates
the actual mass-cap limits the company modeled.Table 7.3 lists the core case definitions,
including those for cases,Cl2-1,Cl2-2.Cl3-1,and Cl3-2 that did in fact examine mass-based
scenarios,despite statements to the contrary by JCL/SC.Rocky Mountain claimed that results of
these portfolios are discussed throughout Chapter 8 of its 2015 IRP.
The Company stated that the ICL/SC statement that rate-based modeling will .
leave PacifiCorp’s customers vulnerable to contrary state and federal decisions”is without merit.
Examination of the resource portfolios selected by the case relying on mass-based assumptions
shows a very similar resource mix to the preferred portfolio,especially in the first two to four
years of the planning horizon.According to the Company,the results of the portfolios do not
support ICL/SC statements.Similarly,comments suggesting Rocky Mountain is using this TRP
to direct the form of compliance that individual states will be able to use are vastly exaggerated
and in direct conflict with standard regulatory processes.
The Company asserted that it will follow all regulations that are developed to meet
state implementation plans for section 111(d)compliance,in addition to any other IRP
requirements.ICL/SC also commented that the emission rate-based approach undervalues coal
conversion and retirement.”Rocky Mountain reiterated that it does not establish policy but
develops plans to meet policy requirements.EPA’s draft section 111(d)rule sets rate-based
targets and Rocky Mountain developed a range of different resource portfolios to meet these
ORDER NO.33396 14
targets under different compliance strategies and considering alternative coal unit retirement
assumptions.
ICLISC further raised concerns that portfolio modeling does not allow for
endogenous determination of early retirement dates for coal plants.Use of this modeling option
would be problematic as there are many details to consider when assessing the cost for early
retirement,such as:coal contract constraints,fixed costs,impacts on fixed and operating costs of
other coal units at multi-unit plants,and other variables that influence the economics of early
retirement decisions.
Rocky Mountain believes that its current approach,which analyzes alternative coal
unit retirement scenarios,is more robust because the impact of early retirements on other units
and system fixed costs is explicitly captured.Thus,Rocky Mountain believes that the concerns
raised by ICL/SC should not be acknowledged because they contain many errors of fact,the
most glaring is the oft repeated claim that Rocky Mountain did not model mass-based cap
compliance with EPA’s draft section 111(d)rule.The Company argued that it utilized a
reasonable approach to modeling compliance with EPA’s draft 111(d)rule and developed
portfolios across a range of policy and compliance scenarios that were informed by the input of
stakeholders choosing to actively participate in the 2015 IRP public process.
COMMISSION DISCUSSION AND FINDINGS
Having thoroughly reviewed all of the filings in Case No.PAC-E-l5-04,including
Rocky Mountain’s 2015 Integrated Resource Plan,appendices and addendums,and related
comments from the Company,Staff,ICL,SRA and Renewable Northwest,the Commission finds
that the Company’s 2015 IRP is presented in the appropriate format and contains the necessary
information outlined by the Commission in Order No.22299.Therefore,the Commission
accepts Rocky Mountain’s 2015 IRP filing.
In doing so,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 Staff,ICL,SRA,and Renewable Northwest.
ORDER NO.33396 15
The Commission expresses its appreciation for the Company’s willingness to furnish an IRP
process which fosters meaningful input and participation from interested parties.The
Commission believes that such participation by multiple interested parties is necessary and a key
factor in the development of an effective resource planning document.
Clearly,Rocky Mountain’s 2015 IRP was greatly impacted by the EPA’s recent
promulgation of Rule §11 1(d)under the Clean Air Act.The probability of this circumstance was
presaged by the Commission in the context of the Company’s last IRP filing,PAC-E-13-05.In
the Commission’s Order accepting Rocky Mountain’s 2013 IRP we stated that “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.”Order No.32890 at 12.
The Commission noted further that it would “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.”Id.To that end,“the Commission exhort[ed]the Company to
increase its efforts toward achieving higher-levels of cost-effective DSM.”Id.The Commission
firmly believes that “such measures can obviate the need for new generation resources and
thereby decrease the constant upward pressure on energy pricing.”Id.
The Commission’s review of Rocky Mountain’s 2015 IRP revealed that the Company
has acknowledged our recommendations.The Commission is pleased by Rocky Mountain’s
aggressive pursuit of energy savings related to the Company’s acquisition of substantial
additional Class 2 DSM resources into the planning horizon.The Commission is hopeful that the
Company’s concentrated efforts in this area will lead to significant reductions in energy
consumption.
The Commission also finds that the Company has developed a practical approach
toward new resource acquisition and resource portfolio selection.The Company’s approach
appears to respond adequately to future resource demands,as well as the federal statutory
mandate presented by §111(d).
Finally,the Commission takes note of the 2015 IRP’s increased reliance on solar
resources.We offer no commentary on the prudency of this decision.However,the
Commission suggests that Rocky Mountain consider conducting a reasonable evaluation,similar
to the WIS previously commissioned,of the costs and benefits associated with the integration of
additional solar resources into its system.
ORDERNO.33396 16
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 et seq.
ACCEPTANCE OF FILING
Based upon our review,we find it reasonable to accept and acknowledge Rocky
Mountain’s filed 2015 Electric IRP.Our acceptance of Rocky Mountain’s 2015 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 2015 Integrated Resource Plan is
accepted for filing.Acceptance of the 2015 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.33396 17
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of October 2015.
MARSHA H.SMITH,COMMISSIONER
ATTEST:
Jew
ommission ecretary
O:PAC-E I 5-04_np2
K STINE RAPER,COMMISSIONER
PAUL PRESIDENT
ORDER NO.33396 18