20150807Snake River Alliance.pdf

SNAIKE RIVER
IDAHOS NUCLEAR WATCHDOG &CLEAN ENERGY AOvOC4TE
August7,2015
To:Idaho Public Utilities Commission
From:Ken Miller,Clean Energy Program Director,Snake River Alliance
Re:Snake River Alliance Comments In the Matter of the PacifiCorp DBA Rocky Mountain Power’s 2015
Integrated Resource Plan.
On behalf of our members in Rocky Mountain Powers service territory,the Snake River Alliance
appreciates this opportunity to provide comments on the above-referenced case,filed with the Public
Utilities Commission (“PUC”or “Commission”)on March 31,2015.These comments are submitted to the
Commission in response to its Notice of Filing,Notice of Modified Procedure,and Notice of Intervention
Deadline,ORDER No.33299.
Introduction
PacifiCorp’s 2015 IRP envisions retiring or converting to natural gas an estimated 2,800 MW of coal
capacity (2,775 MW of company-owned capacity)through 2034.The company states it believes it can
meet its much resource needs through significant increase in demand-side management (DSM)resources
and firm market purchases,however the need for those front office transactions is expected to be
tempered by accelerated DSM additions.The Plan does not anticipate addition of new thermal resources
until 2028.The PacifiCorp IRP (Chapter 1 —Executive Summary.P.2)identifies that initial new resource as
423 MW of natural gas combined cycle generation.However,the plan contemplates additional fossil fuel
additions moving forward:1,159 of natural gas combined cycle in 2030,635 MW in 2033,and another
635 in 2034 —for a total of new natural gas combined cycle of 2,852 MW.
The company anticipates growth in its renewable portfolio,including installing 7 MW of solar capacity to
comply with Oregon’s solar capacity requirements.While Idaho does not have a state renewable portfolio
standard (RPS)other states served by PacifiCorp do.Utah’s 20 percent target by 2025 is nonbinding,and
PacifiCorp states its preferred portfolio will achieve Utah’s goal.
The Alliance’s primary interests in this IRP relate to planning for PacifiCorp’s coal fleet,how the IRP
treats the Obama Administration’s new Clean Power Plan,and the need for greater amounts of DSM
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resources to absorb much of the projected lost coal generation in the coming two decades.
Impacts of Environmental Protection Agency Clean Power Plan Rule 111(d)
Like many electric utilities,Rocky Mountain Power submitted its 2015 IRP to the PUC without the benefit
of knowing the details of the U.S.Environmental Protection Agency’s (“EPA”)Clean Power Plan and its
revisions to Clean Air Act Rule 111(d),which President Obama unveiled on Aug.3.The timing of the 2015
IRP and announcement of the Clean Power Plan poses obvious,unavoidable,challenges to PacifiCorp,
particularly in light of broad state-specific greenhouse gas emissions reduction targets that presumably
will impact PacifiCorp’s coal fleet.Furthermore,while details of the Clean Power plan are now known,the
manner in which various states develop implementation plans and submit them to the EPA in 2016 is
unknowable.In any case,PacifiCorp believes that its preferred portfolio will satisfy 111(d)emissions
targets in the six states in which it operates.
To its credit,PacifiCorp considered various Rule 111(d)strategies as comprehensively as practical,in
part by employing the Rule 111(d)Scenario Maker,a spreadsheet-based tool it developed for this
purpose,along with System Optimizer.We believe this IRP included sufficient analyses of possible 111(d)
scenarios.We suggest PacifiCorp pay special attention to the role of energy efficiency (whether it’s a
building block or not)in helping the company comply with greenhouse gas emissions reduction targets.
One of the important changes the Clean Power Plan has brought to the IRP processes is to add more
precision to carbon reduction obligations than existed only under a proxy carbon tax C02 price or similar
compliance mechanisms.Various levels of potential carbon prices,coupled with 111(d)compliance
scenarios,will sharpen the ability to assess the least cost/least risk values of portfolios.
As mentioned below in our discussion of PacifiCorp’s plans for its coal fleet,the IRP includes time frames
for retirement of certain coal plants in which PacifiCorp is invested as a sole owner or co-owner with
other utilities that are likewise attempting to decipher the Clean Power Plan’s implications for their
generation fleet.For example,Idaho Power Co.,a 33 percent partner in the Jim Bridger coal plant in
Wyoming,submitted its 2015 IRP to regulators in Idaho and Oregon on June 30,putting it in much the
same boat as PaciflCorp finds itself.At a minimum,and pending the outcome of litigation over the Clean
Power Plan and submittal of state implementation plans,the Clean Power Plan will almost certainly
impact the operation of one or more of PacifiCorp’s coal plants or,in some cases,its retirement and
decommissioning schedule for certain plants.
PacifiCorp’s Coal Plant Operations
With 5,938 MW of load and resource balance capacity at system peak (2015 IRP Chapter 5—Resource
Needs Assessment,P.63)PacifiCorp is among the nation’s most coal-reliant electric utilities.Setting aside
issues relating to the Clean Power Plan discussed above,PacifiCorp intends to retire or convert to natural
gas approximately 2,800 MW of coal capacity during the planning period covered in this IRP (2015 IRP
Redacted Volume III).While we are pleased to see a plant retirement or natural gas conversion timeline,
we are disappointed that the timeline is extended as far as it is.Coal currently comprises about 60
percent of PacifiCorp generation,and is forecast to be 50 percent in 2025 and roughly one-third of its
generation in 2034.Assuming that is the company’s approximate glide path away from coal,we believe
relying on such a large amount of coal as far out as 20 years from now for 30 percent 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.This is doubly true in light of the coming implementation of the
Clean Power Plan,which will push coal further to the margin.
Still,we take note of a statement on June 8,2015,by Cindy Crane,president and CEO of Rocky Mountain
Power in a company release coinciding with the IRP’s filing:“One of the ways our industry is changing is a
gradual,orderly transition away from coal to produce electricity.In recent years,the company has built
new natural gas plants and wind power projects and expanded energy efficiency programs.As a result,
the IRP does not see the need to build a new power plant of any type in the next 10 years.”
Among the PacifiCorp plants now slated for early retirement is the Cholla plant Unit 4 in Arizona,which
PacifiCorp plans to cease operating in 2025 rather than install a Selective Catalytic Reduction (SCR)
system to enable compliance with the Clean Air Act’s Regional Haze Rules.Cholla Unit 4 is owned by
PacifiCorp;Arizona Public Service owns Units 1-3.We anticipate similar decisions as PacifiCorp and its
utility partners continue to analyze plant retirement options as opposed to hugely expensive plant
upgrades to comply with various existing and proposed coal plant anti-pollution standards.
The decision-making process was and continues to be similar to that leading to the pending retirement of
the PGE-controlled Boardman plant in Oregon.Other plants scheduled for conversion or retirement
include converting Unit 3 of the three-unit Naughton plant in Wyoming to natural gas in 2018,and
avoiding SCR installations at Wyodak and Dave Johnston 3 in Wyoming by 2027.Decisions on Wyodak
and Dave Johnston depend in part on the outcome of a contested Regional Haze compliance plan.It is
likely that decisions by PacifiCorp and Idaho Power on whether to add SCRs to Jim Bridger Units 1 and 2
(Units 3 and 4 are currently being retrofitted subsequent to IPC-E-13-16)will be included as part of both
utilities’2017 IRPs.
“Avoiding SCR at Wyodak,Dave Johnston Unit 3,Cholla Unit 4 and converting Naughton Unit 3 to natural
gas in 2018 will save customers hundreds of millions dollars when compared to the alternative
compliance scenarios studied,”according to PacifiCorp (2015 IRP Volume III —CoalAnalysisj We believe
similar savings of customer dollars can be replicated as additional coal plants are scheduled for early
decommissioning.
Demand-Side Resources
Enhancements to PacifiCorp’s DSM programs and new or improved federal energy efficiency standards,
notably in the residential class,are among the reasons the Company’s load forecast is projected to
continue to decline or see very slight increases.We are encouraged that a projected 86 percent of load
growth through 2024 will be met through energy efficiency resources,up 59 percent from the 2013 IRP’s
estimates.If that occurs,it will parallel the share of energy efficiency meeting load growth we expect to
see in the Northwest Power and Conservation Council’s pending 7th Power Plan.As for PacifiCorp’s
forecasted retail sales growth,however,it is expected to be .16 percent from 2015-2024.
As far as customer participation in DSM programs,we recommend that the Commission encourage
PacifiCorp (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.Some of its communication tactics are contained in this IRP (2015 IRPAppendix D —
Demand-Side Management Resources).We acknowledge that some of the greatest DSM savings can be
reached through commercial and industrial customers and note that industrial sales comprise
approximately 50 percent of the company’s Idaho sales,although industrial sales are projected to be
down .07 percent from 2014-2025 (2015 IRPAppendixA -Load Forecast.)We recommend PacifiCorp
further research the viability and value of these programs.
The Alliance again appreciates this opportunity to comment on PacifiCorp’s 2015 IRP.We also commend
the Company and its IRP team for its stakeholder involvement efforts.
Respectfully submitted,
Ken Miller
Clean Energy Program Director
Snake River Alliance
P.O.Bo 1731
Boise,ID 83701
[phone]
[e-mail]
Hand Delivered
Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W.Washington St.
Boise,ID 83702
Via Mail
Yvonne Hogle,Regulatory Counsel
Rocky Mountain Power
201 S.Main,One Utah Center,23rd Floor
Salt Lake City,UT 84111
Ted Weston,Idaho Regulatory Affairs Manager
Rocky Mountain Power
201 5.Main,One Utah Center,23rd Floor
Salt Lake City,UT 84111