20150807Comments.pdf

NEIL PRICE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
POBOX 83720
BOISE,1DAHO83720-0074
[phone]
BAR NO.6864
Street Address for Express Mail:
472 W.WASHINGTON
BOISE,1DAH083702-591 8
Attorney for the Commission Staff
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.)
)
)COMMENTS OF THE
)COMMISSION STAFF
_____________________________________________________________________________________)
COMES NOW the Staff of the Idaho Public Utilities Commission,by and through its
attorney of record,Neil Price,Deputy Attorney General,and in response to the Notice of Modified
Procedure issued in Order No.33299 on May 12,2015,submits the following comments.
BACKGROUND
On March 31,2015,PacifiCorp dba Rocky Mountain Power (“Rocky Mountain,”
“PacifiCorp,”or ‘Company”)filed its 2015 Integrated Resource Plan (“IRP”)with the
Commission pursuant to the Commission’s rules and in compliance with the biermial IRP filing
requirements mandated in Order No.22299.
PacifiCorp files an IRP on a biennial basis with the state utility commissions of Utah,
Oregon,Washington,Wyoming,Idaho,and California.PacifiCorp’s 2015 IRP represents its 13th
comprehensive plan submitted to state regulatory commissions.
STAFF COMMENTS 1 AUGUST 7,2015
PacifiCorp states that the projected load forecast continues to decline beyond 2019 in
relation to projected loads used in the Company’s 2013 IRP and 2013 JRP Update.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.
Order No.22299 requires the Company to submit a biennial ‘Resource Management
Report.This order requires this report to give balanced consideration to supply and demand
resources when formulating resource plans and procuring resources.The Company typically
submits its IRP in compliance with this requirement.The Company states that this IRP reflects
continued alignment efforts with the Company’s annual ten-year business planning process.The
Company’s IRP 20 15-2024 Action Plan is provided as Attachment A.
The Commission has previously noted that acceptance of the IRP should not be interpreted
as endorsement of any particular element of the plan,nor does it constitute approval of any
resource acquisition contained in the plan.
STAFF ANALYSIS
Staff reviewed the Company’s 2015 IRP and notes that there have been substantial changes
to the Company’s resource strategy since its 2013 TRPs.’The Company states that these changes
were made in response to uncertainty about 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 PacifiCorp’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 considered by PacifiCorp 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.
Instead,the Company relies on Class 2 DSM energy management programs to meet anticipated
capacity needs.
‘The Company issued both an initial IRP and a revised IRP in 2013.
STAFF COMMENTS 2 AUGUST 7,2015
The Company states that recent increases in natural gas supplies have exerted downward
pressure on natural gas prices,making conversion of some of its coal-fired base units to natural
gas economically viable:however,the Company cautions that long-term natural gas price
volatility may pose a long-term risk.Class 2 DSM programs include non-dispatchable,firm
energy savings such as those achieved through installation of energy efficient equipment,
appliances.lighting,and construction.Although typically associated with energy efficiency
programs,Class 2 DSM programs can also reduce capacity needs if they reduce energy use during
periods of system peak demand.
Capacity Load and Resource Balance with Existing Resources
PacifiCorp develops its load and resource balance by comparing its obligations with the
capabilities of its existing resources.Capacity Position is the difference between the Company’s
ability and its obligation to supply power at system coincident peak loads.Because it is calculated
assuming existing resources (including commitments and contracts),the Capacity Position is the
Company’s forecasted capacity shortfall absent any new resource acquisition on its part.Front
Office Transactions (FOTs)are short-term firm market purchases.
(‘apacity Position =(Existing Resources Available FOTs,)-(Obligation Reserves)
In previous IRPs,FOTs were considered separately as a type of market purchase,and not
explicitly included in the computation of capacity position.The Company defines its existing
resources,obligation,and reserves as follows.
Existing Resources =Thermal +Hydro +Renewable +Firm Purchases +Quali/j’ing
Facilities -Existing Class 1 DSM -Firm Sales -Non-Owned Reserves
Obligation =Load -Interruptible Contracts -Existing Class 2 DSM
Reserves =Obligation x Planning Reserve Margin =Obligation x ]3%2
Between 2015 and 2024,the Company expects that existing generation capacity will
decrease 4.6%from 10,156 MW to 9,692 MW.Existing thermal capacity will decrease from
2 Staff notes that the Company’s stated 13%Planning Reserve Margin (PRM)is approximate.
STAFF COMMENTS 3 AUGUST 7,2015
8,905 MW to 8,670 MW,hydro from 894 MW to 740 MW,and renewables from 357 MW to
282 MW.Firm purchases will decrease from 818 MW to 277 MW,and purchases from qualifying
facilities will vary between 255 MW and 488 MW.Decreases in generation capacity,firm
purchases,and purchases from qualifying facilities will be partially offset by decreases in firm
sales from 942 MW in 2015 to 222 MW in 2024.Non-owned reserves will remain constant at
41 MW,and beginning in 2016,interruptible contracts will remain a constant 175 MW.
Staff notes 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.PacifiCorp’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,PacifiCorp’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 notes that the Company’s system-wide capacity position may
exceed available FOTs beginning in 2020.Table 1 summarizes PacifiCorp’s system-wide
resources,obligations,reserves,capacity position,and available FOTs.
System
_________
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
TotalResources(MW)10568 10043 10143 10217 10144 10124 10486 10446 10458 10425
Obligation (MW)10104 9930 10089 10225 10333 10452 10569 10674 10788 10832
Reserves (MW)1333 1310 1331 1349 1363 1378 1393 1407 1422 1428
Obligation +Reserves
(MW)11437 11240 11420 11573 11696 11830 11963 12081 12210 12259
Capacity Position (MW)(869>(1,197>(1,277>(1,356)(1,552)(1,706)(1,477)(1,635)(1,752)(1,834)
Available FOTs (MW)1670 1670 1670 1670 1670 1670 1670 1670 1670 1670
Table 1:System Capacity Position with Existing Resources (Volume I,Tables 1.2 &5.14)
The Company’s territory is divided into two balancing areas.Its west balancing area
(PACW)comprises service territories in Oregon,California,and Washington.The Company’s
east balancing area (PACE)includes service territories in Wyoming,Utah,and Idaho.Staff
STAFF COMMENTS 4 AUGUST 7,2015
observes that the capacity deficit in its east balancing area already exceeds available front office
transactions (Table 2),while there are no capacity deficits in its west balancing area.
____________________
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
____________________
7033 6880 6976 7031 7026 7018 7462 7453 7439 7396
______________
6935 6729 6854 6960 7047 7135 7200 7281 7370 7392
921 894 910 924 935 947 955 966 977 980
East Balancing Area
Total Resources (MW)
Obligation (MW)
Reserves (MW)
Obligation +Reserves
(MW)7855 7623 7764 7885 7982 8081 8155 8247 8347 8372
Capacity Position (MW)(823)(743)(789)(853)(957)(1,064)(693)(794)(908)(976)
Available FOTs (MW)318 318 318 318 318 318 318 318 318 318
Table 2:East Balancing Area Capacity Position with Existing Resources (Volume 1,Table 5.14)
Resource Portfolio Selection
PacifiCorp uses its resource portfolio selection process to determine resource mixes that
enable it to meet its load obligations at the least cost.The Company analyzes the effects of
different resource mixes under different scenarios using its Planning and Risk (PaR)assessment
tool and its System Optimizer (SO)tool.The Company recently implemented an updated version
of its Enterprise Portfolio Management (EPM)model,which improves efficiency of the PaR and
SO tools.
PacifiCorp’s 2015 IRP resource portfolio selection process considered 34 core case
scenarios,as well as 15 additional scenarios used to determine model sensitivity.Core case
scenarios included four different regional haze policies,five different §111(d)policies,CO2
prices,the impact of four different Class 2 DSM programs,and two different FOT availability
assumptions.Using its PaR,SO,and EPM tools,the Company identified models having the least
cost and least risk.From the resulting short list,it conducted further analyses to select its
preferred portfolio.
The Company states that a major 2015 IRP analysis highlight was development of a
planning framework to address cost,risk,and uncertainty associated with the U.S.Environmental
Protection Agency’s (EPA)proposals to regulate CO2 under §111(d)of the Clean Air Act.These
proposals have not yet been finalized,and some alternatives currently being discussed could have
a large impact on selection of the Company’s preferred resource portfolio.To this end,the
Company has developed a new spreadsheet-based tool,111(d)Scenario Maker,that enables it to
study the effects of §1 11(d)policy and compliance uncertainties.
STAFF COMMENTS 5 AUGUST 7,2015
Another factor driving the 2015 IRP process is compliance with EPA Regional Haze
Requirements,which has required assessment of compliance alternatives for the coal-fired
Wyodak,Naughton Unit 3,Dave Johnson Unit 4,and Cholla Unit 4 power plants.EPA Regional
Haze Requirements apply to a variety of airborne pollutants that restrict visibility,but particularly
to those affecting visibility in U.S.national parks,wilderness areas,and some international parks.
Under the EPA’s Regional Haze program,each state submits a State Implementation Plan (SIP).
Currently,the Company is awaiting EPA approval of some SIPs prior to determining the best
strategies for assuring compliance of selected coal-fired power plants.Options being considered
for these plants include Selective Catalytic Reduction (SCR),which reduces nitrogen oxide (NO)
emissions;bag houses,which reduce particulate emissions;natural gas conversion,which reduces
C02,NON,and particulate emissions;and decommissioning.
A renewable resource portfolio standard (RPS)requires electricity retailers to include
specified amounts of renewable energy in their portfolios.Three states in the Company’s territory
(California,Oregon,and Washington)have mandated RPS requirements.Utah has implemented
an RPS goal.PacifiCorp has considered these requirements and goals in its 2015 IRP process.
Preferred Resource Portfolio
Currently,the Company derives 5 0.3%of its system coincident peak power from
pulverized coal,25.1%from natural gas,7.6%from hydroelectric power,and 6.9%from
purchases (Volume I,Table 5.2).The Company obtains the remaining 10.1%from a combination
of DSM,renewables,purchases from qualifying facilities,and interruptible contracts.PacifiCorp’s
total capacity is 11,810 MW.
Under the Company’s preferred portfolio,power obtained from pulverized coal will
decrease to 44%in 2024,primarily due to conversion of Naughton Unit 3 to natural gas in 2018.
By 2034,this percentage will fall to 24%,due primarily to closure of the Company’s coal-fired
Naughton Units 1 and 2 in 2029.Between 2018 and 2024,contributions from natural gas and
market purchases will remain relatively constant.The Company plans to acquire new natural gas
fired plants beginning in 2029,and anticipates that the peak capacity contribution of natural gas
will increase to 40%by 2034.The Company states that approximately 2,800 MW of existing coal
generation will either be retired or converted to use natural gas by 2034.
Under its preferred portfolio,the Company anticipates that the contribution from
renewables (solar)will increase from 3.0%to 6.0%in 2015 and 2016,and remain relatively
STAFF COMMENTS 6 AUGUST 7,2015
constant thereafter.The capacity contribution from its Class 2 DSM programs will account for the
majority of peak capacity growth between 2015 and 2024,and will be a major component
thereafter.Class 2 DSM’s capacity contribution will increase from 3.7%to 9%between 2015 and
2024,and to 14%by 2034.
PacifiCorp believes that the market for FOTs is favorable.However,growth in energy
efficiency savings will reduce the need for FOTs through the first ten years of the planning
horizon.The Company states that,on average,2015 IRP preferred portfolio FOTs are down 16%
from the 2013 IRP Update and down 29%when compared to the 2013 IRP preferred portfolio.
Staff observes that these statements may be true when assessing its east and west balancing areas
together.However,as mentioned earlier,the capacity deficit in the Company’s east balancing area
currently exceeds available FOTs.
Planning Reserve Margins and Resource Sufficiency
The Company estimates resource sufficiency for both planning reserves and operating
reserves as part of its IRP process.These assessments are detailed in the Company’s most recent
IRP,the 2015 IRP,specifically Volume II,Appendix F (Flexible Resource Needs Assessment)
and Appendix I (Planning Reserve Margin (PRM)Study).
PacifiCorp claims that it will exceed its 13%target planning reserve margin through 2019
and fall short of its target planning reserve margin in 2020.However,the Company anticipates
that 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.PacifiCorp
estimates that it will be at least 82 MW and 165 MW below its target planning reserve margin in
2023 and 2024,respectively.The 13%target planning reserve margin is calculated as projected
load less distributed generation,less existing Class 2 DSM energy efficiency savings,and less
interruptible load.
Energy Imbalance Market and Transmission Investments
If PacifiCorp’s system resources are insufficient to meet reserve obligations,additional
resources and associated investments or purchases would be required.Staff believes benefits
associated with participating in the ElM may reduce the Company’s reserve obligations (See
Company Response No.6,bullet 1)and could thereby reduce future resource needs.However,
existing transmission limits between PACE and PACW generally limit these benefits to PACW
STAFF COMMENTS 7 AUGUST 7,2015
only.Staff suggests the Company assess market access issues in its’s IRP to allow expansion of
ElM benefits to both PACE and PACW.
Staff understands that transmission system investments identified by the Company as part
of the IRP planning process may be mitigated by development of new or modified grid operation
procedures and/or by adding transmission projects to the 10-year capital transmission
improvement plan.For example,PacifiCorp continues to support transmission permitting efforts
for Energy Gateway West (Segments D and E),Energy Gateway South (Segment F),Boardman to
Hemingway (Segment H),and a line from Walla Walla to McNary,while participating in regional
and the interregional transmission planning efforts with the Northern Tier Transmission Group
(NTTG),the Western Electricity Coordination Council (WECC),and the FERC order 1000
Interregional Coordination Group.Staff believes that regional plan comparisons through an
effective interregional coordination process 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.Moreover,
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
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.”
Staff notes the Company’s reliance 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.To put this in perspective,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
STAFF COMMENTS 8 AUGUST 7,2015
the Company’s preferred portfolio,Class 2 DSM savings will be 10.9 GWh.The Company states
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%.The Company also notes that the accelerated
scenario is ‘both speculative and hypothetical,but did not provide an assessment of the specific
risks associated with it.Nevertheless,Staff believes the Company’s Class 2 DSM energy savings
target to be achievable,and supports 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 PacifiCorp.The Company’s 2015 IRP emphasizes the
process for selecting Class 2 DSM programs based on their ability to reduce energy use,but
describes no mechanism for assuring their contribution to reducing peak load.Given the 2015
IRPs reliance on Class 2 DSM capacity reductions,Staff believes that the Company should
include a thorough explanation of the effects of these programs for both energy and capacity
reduction in its 2017 IRP.
Stafinotes inconsistencies between some of the text,tables,and figures used to discuss
DSM related capacity reductions.Part of this difficulty arises because the 2015 IRP often does
not discriminate between the name plate/capacity reduction and the system peak reduction of
Class 2 DSM programs.Class 2 DSM name plate/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,only a Class 2 DSM program’s system coincident peak
reduction is useful.The effect of using name plate/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 would like to see the Company 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 includes
STAFF COMMENTS 9 AUGUST 7,2015
extensive discussions of these risks and issues surrounding them.Given these uncertainties.Staff
believes that the Company’s preferred portthlio plan for reducing the energy contribution of coal,
and increasing the energy contribution of natural gas to both be reasonable.
As noted earlier.Washington.Oregon,California.and Utah have renewable portfolio
standards requirements/goals that constrain the energy options available to the Company.The
Multi-State Allocation Protocol assigns the differential costs of RPS’s to those states that cause
these costs to be incurred,thereby protecting Idaho customers from subsidizing the RPS
requirements of other states.
The 2015 IRP includes a summary of a wind integration study conducted by the Company.
Over the next two years,the Company also 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.
STAFF RECOMMENDATIONS
The Commission has previously noted that acceptance of the IRP should not be interpreted
as endorsement of any particular element of the plan,nor does it constitute approval of any
resource acquisition contained in the plan.After reviewing PacifiCorp’s 2015 IRP,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.Subsequent IRPs
are expected to address current resource needs with more accurate information prior to final
resource decisions being made.Based on these considerations,Staff recommends that the
Commission acknowledge the Company’s 2015 IRP filing.
STAFF COMMENTS 10 AUGUST 7,2015
Respectfully submitted this day of August 2015.
Deputy Attorney General
Technical Staff:Johanna Bell
Mike Morrison
umisc:cornrnents/pace15 4ripjbmrn comments
STAFF COMMENTS 11 AUGUST 7,2015
ATTACHMENT A -20 15-2024 IRP ACTION PLAN
1.Renewable Resource Actions
-Pursue unbundled REC request for proposals (RFP)to meet its state renewable
portfolio standard (RP S)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.
-Secure bids from 2013 RFPs seeking up to 7MW 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 through
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 fbrward,balance of month,day-ahead,and hour-ahead non
brokered transactions.
3.DSM Actions
-Class I 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:
o 2015—551 MW of Annual Incremental Energy (GWh)and 133 MW of
Annual Incremental Capacity;
o 2016—584 MW of Annual Incremental Energy and 139 MW of Annual
Incremental Capacity;
o 2017—616 MW of Annual Incremental Energy and 146 MW of Annual
Incremental Capacity;
o 2018—634 I\W of Annual Incremental Energy and 146 MW of Annual
Incremental Capacity.Attachment A
Case No.PAC-E-I 504
Staff Comments 8/7/2015
Page I of2
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 10 Circuit ruling the
portion of EPA’s final Regional Haze Federal Implementation Plan (FTP)
requiring the installation of selective 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.
Continue to implement the Walla Walla to McNary project construction plan
with 2017 expected in-service date.Continue to support permitting process.
Attachment A
Case No.PACE-I5-O4
Staff Comments 8/7/2015
Page 2 of2
ATTACITMENT B —Summary of IRP Standards and Guidelines for Idaho:1
•Filing Requirements and Frequency:Submit “Resource Management Report”(RMR)on
planning status biennially.Also file the following progress reports at least annually:(1)
conservation.(2)low-income programs,(3)lost opportunities,and (4)capability building.
•Commission Approval or Acceptance:Report does not constitute pre-approval of
proposed resource acquisitions.Idaho sends a short letter stating that they accept the filing
and acknowledge the report as satisfying Commission requirements.
•Focus:20-year plan to meet load obligations at least-cost,with equal consideration to
demand side resources.The RMR is to address risks and uncertainties;and to emphasize
clarity.understandability,resource capabilities and planning flexibility.
•Elements:The RMR is to discuss analyses considered including:load forecast
uncertainties;known or potential changes to existing resources:equal consideration of
demand and supply side resource options;contingencies for upgrading,optioning and
acquiring resources at optimum times;and report on existing resource stack,load forecast
and additional resource menu.
‘Order 22299 Electric Utility Conservation Standards and Practices,January,1989,as restated by the Company in the
2015 IRP,Table B.1.Attachment B
Case No.PAC-E-l5-04
Staf’f’Qomments 8/7/2015
Page 1 of I
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 7th DAY OF AUGUST 2015,
SERVED THE FOREGOfNG COMMENTS OF THE COMMISSION STAFF,IN
CASE NO.PAC-E-15-04,BY MAILING A COPY THEREOF,POSTAGE PREPAID,
TO THE FOLLOWING:
TED WESTON
[D REG AFFAIRS MANAGER
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
E-MAIL:tedwestonpaciflcorp.com
YVONNE HOGLE
ROCKY MOUNTAIN POWER
201 5 MAN ST STE 2300
SALT LAKE CITY UT 84111
E-MAIL:yyJogeUpacificorp.com
DATA REQUEST RESPOiSE CENTER
E-MAIL ONLY:
/
SECRETRY
CERTIFICATE OF SERVICE