20130808Comments.pdf

NEIL PRICE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 6864
Street Address for Express Mail:
472 W, WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
IN THE MATTER OF PACIFICORP DBA
ROCKY MOUNTAIN POWER'S 2013
INTEGRATED RESOURCE PLAN
li r-." 1L
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. PAC.E.13.O5
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission (Commission), by
and through its attorney of record, Neil Price, Deputy Attorney General, and in response to the
Notice of Filing and Notice of Modified Procedure issued in Order No. 32819 on May 30,2013
in Case No. PAC-E-I3-05, submits the following comments.
BACKGROUND
On April 30,2013, PacifiCorp filed its 2013 Integrated Resource Plan (IRP) with the
Commission. As required by Order No.22299, PacifiCorp's filing is a biennial planning
document that sets forth how the Company intends to serve the electricity requirements of
over 1.7 million system-wide customers in the states of California, Idaho, Oregon, Utah,
Washington, and Wyoming. PacifiCorp's Idaho service territory includes over 70,000 customers
in southeastern Idaho. The complete 2013 IRP consists of four separate documents: l) 2013
Integrated Resource Plan Volumel;2) 2013 Integrated Resource Plan Volume II - Appendices;
STAFF COMMENTS AUGUST 8,2073
3) 2013 Integrated Resource Plan Confidential Volume III; and 4) 2012 Wind Integration Study
supplement.
PacifiCorp's IRP was developed through a process that included 15 public input meetings
with participation from key stakeholders including public interest groups, Staff from various
regulatory agencies, and representatives of various customers. The overall purpose was to
develop a resource plan that will economically meet future electricity load in the service area the
Company is obligated to serve while considering important risk factors. The three goals of
PacifiCorp's IRP process were to: 1) determine resource needs focused on the first ten yearc;2)
identify the preferred portfolio of incremental supply 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 identified 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 percent
yearly system coincident-peak load growth rate. This average yearly load forecast is 1 1.3
percent lower than the load forecast used in the 201I 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 and2076 and
approximately 200 MW in years2017 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 the2022 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 percent growth rate across the planning
horizon's first ten years, with Idaho's growth lagging below the system average at 0.57 percent.
STAFF COMMENTS AUGUST 8,2013
Retail Sales Load Growth by Customer Class .2OL3-2O221
Residential Commercia!lndustrial
ldaho
System
1.63%
o.63%
1.63%
1.04%
o.06%
1.03%
-o.18%
-O.O7o/o
7.79o/o
O.O5o/o
Total
O.57o/o
0.89%
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
hve different scenarios of the Energy Gateway project implementing various combinations of
transmission line segments.l Overall, PacifiCorp ran94 core-case simulations with each
generating a unique resource portfolio and an associated net present value revenue requirement
(PVRR) over a 2}-year period.2 A summary of the core cases is included as Attachment A.
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,3 149 MW of solar, and between 650 MW and 1333 MW of
annual market power purchases.
PacifiCorp identified 23 actron 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.
STAFF REVIEW
After attending PacifiCorp's public meetings and reviewing its IRP, Staff believes the
Company continues to improve its IRP planning process so that it remains "state-of-the-art,"
while customizing its approach and adding analysis to fit changing circumstances. This allows
the Company to evaluate incremental supply-side and demand-side resources resulting in a
I See Attachment B for a map of the various Energy Gateway scenarios modeled.
2 Number of runs includes l9 core cases multiplied by 5 transmission scenarios. The Merchant Transmission core
case was only modeled using four Energy Gateway scenarios.
' Class 2 DSM is PacifiCorp's designation for energy efficiency measures that conserve energy through improved
end-use technology.
STAFF COMMENTS AUGUST 8,2013
potentially least-cost, least-risk resource portfolio taking into consideration future uncertainty in
load, electricity and fuel price, carbon price, resource availability, and regulatory constraints.
Staff s analysis focuses on the following issues:
l. Load and Resource Balance - Issues related to the load forecast and planning reserve
margin.
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.
Subsequent IRPs more effectively cover resource plans in the second ten years because there will
likely be changes due to uncertainty. The resource needs can be re-studied with more accurate
information prior to final resource decisions being made.
Load and Resource Balance
The Company's load and existing resource balance is illustrated in the table below. The
load obligation is based on the system coincident peak load forecast adjusted by existing
dispatchable load control (DSM 1), load curtailment contracts, and a 13 percent planning reserve
target. Existing resources include generation from coal (6168 MW), natural gas (2556 MW),
hydropower (913 MW), renewable sources (121 MW), and PURPA qualifuing facilities (171
MW) with the balance of resources in the form of purchased power contracts (1487 MW) net of
off-system sales and .ese.ves.o Existing resource capacity net of system load obligation shows a
positive reserve margin of 4.4 percent in2013 becoming negative starting in year 2016 and
beyond. In all years, this is far short of the Company's goal of maintaining a 13 percent planning
reserve margin; consequently new resources must be added.
a Capacity reflected in parenthesis after each resource type is the capacity available at system peak used to determine
the load resource balance. Projection into future years vary and may not reflect totals shown in Staff s table.
STAFF COMMENTS AUGUST 8,2013
Existing Sytem Resources
System Load Obligation
Reserve (13% tarBet)
ion + Reserve Tar
System Position
Reserve Margin
2011 tRP
2011 IRP Update
2013 tRP
% change from 2011 IRP
% change from 2011 IRP
Notes:
1. System resources are netted for system sales and non-owned reserves.
2. Loads are netted for interuptible loads and existing DSM.
Load Forecast
PacifiCorp's II{P uses the maximum load hour across the system each year to determine
its peak demand forecast. The Company predicts its system-wide coincident peak will be about
1 1.3 percent lower on average across the first ten years compared to the 2011 IRP forecast, and
5.6 percent lower than the 2011 IRP Update as reflected in the table below.s
System-Wide Coincident Peak Load Forecast (MW)
Load and Existing Resource Balance (MW)
2013 2014 2015 20L6 20L7 20L8 2019
(8241 (e86) (L,2281 (1,469) (1,688) (1,888) (2,100) (2,2741 (2,081) (2,308)
4.4% 2.e% 0.6% (2.O%l (4.o%l (s.6%l (7.s%l (8.8%l (6.7%l (8.s%)
2017 2018 2019 2020 2021 2022
10 - year
average
t2,043
11,311
-7.5% -8.2% -8.8% -1,t.8% -tz.r% -12.4% -72.6%
-2.7% -3.8% -4.5% -4.8% -6.r% -6.2% -6.6%
.L3.0% -t3.t%
-6.8% -7.0%
L7.3"4
-5.6%
L"l"..r ro2 data forthe 2011 tRP was not available in the report and was extrapolated..
Large reductions from previous IRP forecasts occurred for several reasons. But the
Company reports that 80 percent of the reduction was due to reduced load expectations in the
industrial sector. First, the lingering effects of the 2008-2009 recession have dampened overall
economic activity affecting growth in electricity demand across all customer classes throughout
the Company's service area. Second, industrial customers in Utah and Wyoming have cancelled
or postponed load requests because of: 1) inability of customers to obtain environmental permits
for mine and line extension construction; and 2) increased self-generation due to lower natural
gas prices, including the construction of a270MW self-generation facility by a major industrial
customer. Third, the Company changed how it forecasts large industrial customer load. Prior
' Energy load differences compared to 201I IRP (11 .2oh) and IRP updates (6.7%) were comparable to peak load
forecast differences.
10,010 10,065 9,996
9,s88 9,780 9,933
r,246 L,27L 1,29L
10.834 11.051 11,224
9,602 9,s56 9,553
9,797 9,9s0 t0,L2s
L,274 7,294 1,316
LL,O7L 77,244 11,447
9,487 9,488 9,864 9,803
L0,254 10,409 L0,57t t0,718
1,333 1,353 L,374 1,393
tL,587 77,762 11,945 72,77L
10,960
10,418
10.135
rL,252 11,501t0,734 10,985
Ll,740
10,880
10.359
11,960 L2,t94 12378 72,607 12,815 13,026
11,200 11,394 11,578 1,r,776 1,L,976 12,t677 10.81s 10.972 11.133 1
STAFF COMMENTS AUGUST 8,2013
IRP's used self-reported customer data as the basis for their forecast. But the Company found
these forecasts to be overly optimistic, and it has moved to a regression-based method to forecast
the entire industrial class.
When Staff examined electricity forecasts in the Energy Information Agency (EIA) 201 I
and2013 Annual Energy Outlook for the Mountain West and Pacific regions, the percentage
decrease in projected energy use across the same ten-year period was comparable (5-60/o
reduction) to the percent change in the energy forecast of this year's IRP with the 201I IRP
Update.
Staff expressed concern that PacifiCorp's load forecast in the 201I IRP was overly
optimistic. Given the reduction to the 2013 IRP load forecast, comparable reductions relative to
EIA 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.
Planning Reserve Margin
Staff believes maintaining a reasonable planning reserve margin is very important. But
excessive reserves can also drive system costs higher. PacifiCorp continues to target
a 13 percent planning reserve margin in this year's IRP. Staff believes this is reasonable for
three reasons. First, according to the Company's analysis, cost remains relatively flat between a
12 and 15 percent planning reserve margin. However, the cost of a planning reserve margin
above 16 percent increases cost dramatically because it eliminates additional market purchases as
an option and instead requires the addition of a combined cycle combustion turbine (CCCT) gas
resource. Second, the Company found that a planning reserve margin of 13 percent results in
approximately an 8-hour loss of load in ten years, which is less than the one day in ten year
industry standard. Third, these results assume no sharing of reserves outside of PacifiCorp's
system. The Company estimates an additional 3.5 percent of planning reserve margin when
reserves within the Northwest Power Pool are taken into account. In addition, the Company
intends to participate in the California Independent System Operator (lSO) energy imbalance
market that will provide additional sharing of S-minute reserves that are incremental to the
planning reserves included in the IRP.
6STAFF COMMENTS AUGUST 8,2013
Resource Portfolio Selection
PacifiCorp's preferred portfolio (EG2-C07a) is shown in the table below. It was derived
assuming: l) base case regionalhaze investments for coal plants; 2) high gas prices; 3) low coal
cost; 4) no federal CO2 prices; 5) the existence of a federal and state RPS; and 6) construction of
segments C, D, and G of Energy Gateway (Scenario EG2 - see Attachment B). The resulting
portfolio satisfies capacity deficits with Front Office Transactions (i.e. firm market purchases of
electricity) and Class 2 DSM resources during the planning horizon's first ten years. It also
includes the addition of the Lakeside II gas plant in 2014, and the retirement of the Carbon coal
plant and the gas conversion of Naughton Unit 3 to both occur in 2015. Small additions include
combined heat and power (CHP) resources added each year up to CHP market potential and
solar generation mandated by Oregon and encouraged by Utah through tax incentives. The
portfolio does not include the addition of a major generation resource untrl2024, when the
Company expects to add a 423 MW CCCT gas plant and 432 MW of wind generation. Finally,
the Company plans to use unbundled renewable energy credits (REC) to meet Washington RPS
requirements prior to 2024-
Capacity (MW)otal Tot.l
Planned Resource Retirements
Coal Plant Upg.ades
cccT
SCCT
CHP
DSM Class 1
DSM Class 2
Solar
Front Office
(2,036)
2,873
362
650
24
193
1,590
304
{so2)
352
1'
t2
...
149
Net Total
Notesl
I illlii"iii,X"lfl;:;,il:i::",J:fi1"""jj;H:::l:il::'i::,T:L'"1ive' and totars are average ror 10 and 20 vear periods
4. Solar ihcludes passive water heating and photovoltaics to meet Oregon requiremehts and to take advantate of Utah incentive5.
PacifiCorp determined its preferred resource portfolio by developing94 portfolios that
satisfy future load and resource balance deficits (plus l3 percent planning reserve margin). The
preferred portfolio was selected based on risk-adjusted present value revenue requirements,
cumulative CO2 emissions, and supply reliability metrics across three levels of CO2 prices. Risk
analysis was performed on 37 of the 94 portfolios by varying gas price, electricity price, regional
load, hydroelectric generation, and thermal plant outages over a 2l-year period. Only two of the
791 1485 802 1102 1218 1315 1428 1515 1287 1431 1511 2054 1509 1541 1648 1640 1686 1282
(s02) (750) (701) (73)
13.8 338
645 423 661 1084
181
432 218
t.2 r.2 L.2 1.2 !.2 L.2 !.2 L.2 1.2 L.2 1.2 t.2 1.2 1.2 L.2 1.2 1.2 L.2 t.2 1.
86 19 88
114 116 103 101 97 92 90 80 79 81 67 70 67 67 69 65 63 55 S7
11.56 L4 t7.2 16.4 17.8 13.5 13.6 13.7 15.5 15.5 15.5 15.5 15.5 15.5 15.5 15.5 15.5 15.5 15.5 15
550 709 845 983 1102 1209 1323 1420 1191 1333 1427 711
STAFF COMMENTS AUGUST 8,2013
five Energy Gateway portfolios, the Energy Gateway reference scenario (EGl - see Attachment
B) and the reference scenario plus Populus to Windstar (EG2), were evaluated due to earlier
implementation dates and a more immediate need for evaluation. After results were compiled,
the Company narrowed its selection to 12 portfolios primarily based on a risk-adjusted PVRR.
Of the 12 portfolios, the highest ranked risk-adjusted PVRR under both Gateway
scenarios was a portfolio that was developed allowing for accelerated Class 2 DSM ramp rates
beyond what the Company assumes is achievable while restricting the portfolio from using base-
load thermal resources to meet capacity deficits. It also had the highest ranking for cumulative
CO2 emissions and supply reliability if run under the most minimal implementation scenario of
Energy Gateway. Even though it was generally the highest ranked portfolio overall, the
Company selected the second highest ranked portfolio (EG2-C07) as its preliminary preferred
portfolio, instead.
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 reasonably decided not
to choose the accelerated DSM portfolio. 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 blindly making selections based on model results, the Company is
demonstrating that it is using its decision support tools appropriately. Demonstrating this
further, PacifiCorp augmented its preliminary preferred portfolio so that wind resources needed
to meet Washington RPS requirements were replaced with unbundled RECs. The results reflect
a $l l6 million to $232 million reduction in risk-adjusted PVRR compared to the preliminary
preferred portfolio. Staff believes this refinement to significantly reduce revenue requirements
while allowing the Company to comply with Washington State regulatory requirements.
STAFF COMMENTS AUGUST 8,2013
Renew ab le P ortfolio Standards
Although the Company must comply with state and federal regulatory requirements, Staff
believes requirements imposed by a jurisdiction that drives incremental cost above the
comparable resource cost should generally not be imposed on Idaho ratepayers. Because Idaho
and Wyoming do not have a state RPS, the Company developed several portfolios with and
without RPS requirements to understand its effect. Generally across RPS core cases, System
Optimizer does not select additional wind, biomass, or geothermal resources beyond the RPS
floor for each state. 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,6 that renewables are not cost
effective when compared to other resources System Optimizer can choose to meet peak loads.
Because Idaho does not have an RPS while other jurisdictions that do are driving higher system
cost, Staff believes this should be reconciled when allocating cost to determine Idaho's share of
system revenue requirements in general rate cases.
Market Risk
Incremental firm market purchases in the 2013 preferred portfolio have increased almost
3l percent compared to the 201 I IRP preferred portfolio over the 2013 thru 2022 timeframe.
Although Staff does not believe the amount is unreasonable, Staff has two concems given
increased reliance on the market. First, customer exposure to electricity price risk exists if large
market anomalies occur even though the Company has accurately evaluated market price risk
through modeling variable electricity prices. Second, 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 l3 percent planning reserve
margin, provide reasonable assurances; nevertheless, the potential for over-reliance on the
market exists.
6 PacifiCorp peak contribution rates based on historical data are 4.2o/ofor wind and 13.6Yofor solar. See 2013
Integrated Resource Plan: Volume II - Appendices, page 361.
STAFF COMMENTS AUGUST 8,2013
Transmis s ion P lanning and Investment
PacifiCorp has augmented its analysis of transmission investments in the 2013 IRP in two
significant ways. First, the Company started developing a System Benefit Tool (SBT) that
attempts to quantify transmission benefits not captured by other IRP models. Staff is encouraged
by the development of this tool, but agrees with the Company that it is still being developed and
that the benefits it reports should not be fully rolled into the IRP until its accuracy is
demonstrated. Second, the Company has fully integrated transmission planning into the IRP
process by modeling five Energy Gateway scenarios across all 19 core cases. This allows
transmission expansion plans to be evaluated simultaneously with supply-side and demand-side
resources. Given the need to economically meet increasing loads and improve reliability while
integrating more renewables, having a more comprehensive and accurate picture of costs and
benefits will help the Company make better resource decisions.
However, Staff believes the quality and robustness of information provided by SBT is
highly varied depending on the benefit being quantif,red. For example, Staff believes the
proposed method used to quantify customer impacts due to loss of load needs improvement. The
data used is anecdotal and may not reflect actual customer benefit forecasted for a specific
transmission line. Generally speaking, Staff believes SBT benefits can be reported with
appropriate caveats but should not be rolled into the overall IRP analysis until the error of the
calculation is well understood and sufficiently small.
Regarding Energy Gateway modeling, the Company analyzed five different Energy
Gateway scenarios across all 19 core cases creating 94 separate resource portfolios compared to
modeling only two different alternative futures in the 2011 IRP.7 Staff believes this is an
improvement because it allows for comparison of transmission scenarios across all cases
including the highest performing portfolios. Unfortunately, due to software upgrade issues, the
Company only had time to model portfolios produced under Gateway Scenario's EGl and EG2
(see Attachment B). Because construction for the remaining segments does not occur until after
the 2020 timeframe, Staff believes this analysis can be done in subsequent IRP's in time to make
prudent decisions.
'The two cases in the 2011 IRP were the Green Resource and the Incumbent Resource cases. These were designed
as bookends that promoted aggressive renewable resource acquisition and discouraged renewable acquisition,
respectively.
STAFF COMMENTS l0 AUGUST 8,2013
Of the scenarios the Company was able to complete, Staff has two observations. First,
the lowest mean PVRR across all COZlevels was a portfolio that assumes no additional thermal
baseload capacity, accelerated DSM ramp rates, and no Populus to Winstar transmission line
(Segment D). This may indicate that accelerating and/or increasing the amount of DSM in
combination with the lower capital cost of simple cycle combustion turbine (SCCT) capacity
close to load may lessen the need for Segment D. Staff recommends the Company funher
explore these altematives to offset the need for the new line. In the meantime, Staff believes the
Company's decision to continue permitting Segment D is reasonable.
Second, renewing Staffls earlier concern about cost allocated to Idaho driven by needs in
other jurisdictions, Staff calls attention to two issues related to transmission investments in the
IRP. First, the Sigurd to Red Butte transmission line (Segment G) appears to be needed
primarily to resolve southwestern Utah reliability issues.s Although the SBT shows system
benefit, Staff believes the distribution of benefits to be uneven between jurisdictions and
justification would be difficult based on system benefits alone. Second, Segment D appears to
benefit states with an RPS more than states without an RPS due to increased access to Wyoming
wind resources. As stated earlier, 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.
Coal Plant Emission Control Investments
PacifiCorp is currently facing large coal plant emission control investments in order to
comply with federal environmental regulations. To determine the best course of action,
PacifiCorp utilized the methodology from the 2011 IRP Update to conduct its Coal Replacement
Study in the 2013 IRP. Focusing its analysis on compliance dates over the next two to four
years, results continue to favor shutting down both Carbon Plant units, converting Naughton
unit 3 to natural gas, and making investments in emission controls for Hunter unit l, Jim Bridger
unit 3, and Jim Bridger unit 4. The Company also plans to perform a similar analysis on Cholla
unit 4 in a future IRP update when compliance requirements are resolved through EPA litigation.
PacifiCorp did not model near-term emission investments for the Craig and Hayden units
8 See 2013 IRP, pp.63-64.
STAFF COMMENTS 1l AUGUST 8,2073
because the Company believes 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.
Addressing prior concerns about a lack of comparison to a broader set of alternatives, the
Company has altered its analysis methodology by allowing each coal plant unit to be retired on
the compliance date and allowing it to be replaced from the suite of supply-side resources
already included in the IRP, or by converting the unit to be fueled by natural gas. The Company
also performed additional analysis assuming a hypothetically extended compliance deadline can
be negotiated for Bridger units 1 and 2 in exchange for a commitment to retire the units early.
Staff believes the methodology and improvements made to integrate the evaluation of emission
control investments in comparison to a wider range of alternatives is more robust and reasonable.
PacifiCorp's analysis of the alternative that retires coal plant units on the compliance date
did not take into account the location of altemate resources that could reduce the need for
additional transmission capacity. For example, Staff believes that if Jim Bridger units were
shutdown early and replaced with generation closer to major load centers, a significant amount
of existing transmission capacity could become available lessening and/or delaying the need for
the Populus to Windstar transmission line (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.
Acknowledgement
In this year's IRP, the Company requested acknowledgment for resource investments,
specifically, the Sigurd-to-Red Butte transmission project. This request seems to imply some
form of pre-approval; however, approval for recovery of resource investments can only be
"approved" in a separate prudence review normally conducted during a formal Idaho rate case or
CPCN application. As in the past, Commission acknowledgment of the plan should not be
interpreted as an endorsement of any particular element, nor constitute approval of any resource
acquisition contained in the Plan.e
e See Order No. 25260 (GNR-E-93-03) and Order No.22299 which describes the Commission's role in the IRP
process.
STAFF COMMENTS t2 AUGUST 8,2013
STAFF RECOMMENDATION
After review of PacifiCorp's 2013 IRP, Staff believes that 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 IRP that satisfies the
requirements set forth in Commission Order Nos. 25260 and22299. Staff, therefore,
recommends that the Commission acknowledge the Company's 2013 IRP.
Respectfully submitted this S{-aurof August 2013.
ts ,,,!", / l/--
Yof ' Neil Price
' Deputy Attorney General
Technical Staff: Mike Louis
i : umisc:comments/pace I 3.5npml comments
STAFF COMMENTS 13 AUGUST 8,2013
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Case No. PAC-E-13-05
staff comments
08/08i I 3
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Table 7.5 - Energy Gateway Scenario Definitions
Sccnrlo Scgmcntr Dclcrlpdor
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Business Plan
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improved reliability
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Gateway segments
Aftachment B
Case No. PAC-E-13-05
Staff Comments
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Staff Comments
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Case No. PAC-E-13-05
Staff Comments
08/08/13 Page 3 of7
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Case No. PAC-E-13-05
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Attachment C
Case No. PAC-E-13-05
Staff Comments
0Si08/13 PageT of7
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CERTTFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 8TH DAY oF AUGUST 2013,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-13.05, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
TED WESTON
ID REG AFFAIRS MANAGER
ROCKY MOTINTAIN POWER
201 S MAIN ST STE 23OO
SALT LAKE CITY UT 841I I
E-MAIL: [e-mail]
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
datareq ue st@pacitlcom. com
KEN MILLER
CLEAN ENERGY PROGRAM DIR
SNAKE RIVE ALLIANCE
BOX 173
BOISE ID 83701
E-MAIL : kmiller@snakeri veralliance.org
YVONNE HOGLE
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 23OO
SALT LAKE CITY UT 8411I
E-MAIL: yvonne.hoqlq@pacifi corp.com
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
7IO N 6TH STREET
BOISE TD 83702
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE