20110711Comments.pdf

NEIL PRICE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BARNO. 6864
RECEivi:n. ,,_ w,_,_
20 II JUl I I PH 2: I 9
.j '~
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF PACIFICORP DBA
ROCKY MOUNTAIN POWER'S 2011
INTEGRATED RESOURCE PLAN.
)
) CASE NO. PAC-E-ll-10
)
) COMMENTS OF THE
) COMMISSION STAFF
)
COMES NOW the Staff of the Idaho Public Utilties 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. 32243 on May 13,2011, submits the following
comments.
BACKGROUND
On April 1,2011, PacifiCorp dba Rocky Mountain Power ("PacifiCorp" or "Company")
filed its 201 1 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.
PacifiCorp serves approximately 70,000 customers in southeastern Idaho. The Company provides
electric service to more than 1,700,000 customers in Utah, Wyoming, Oregon, Washington,
California and Idaho.
PacifiCorp's 2011 IRP was developed through a collaborative public process with
paricipation from public stakeholders, including regulatory staff, advocacy groups, and other
STAFF COMMENTS 1 JULY 11,2011
interested paries. The IRP, along with its 10-year business plan, provides a framework of futue
actions to ensure PacifiCorp continues to provide reliable service at a reasonable cost with
manageable risk to its customers.
The key elements of the PacifiCorp 2011 IRP include a finding of resource need, focusing on
the 1 O-year period 2011 -2020, a preferred portfolio of supply-side, demand-side and transmission
resources to meet this need, and the resultant action plan that identifies the steps the Company wil
take during the next 2 to 4 years toward implementation of the plan. The resources identified in the
201 1 IRP preferred portfolio are considered proxy resources that guide procurement efforts, and do
not constitute the actual resources that would be acquired as part of future procurement initiatives
unless otherwse stated.
The resource need accounts for load growth, sales obligations, existing resources, and a 13%
planing reserve margin. Based on an October 2010 load forecast, PacifiCorp experiences a capacity
deficit beginning in 201 1, when the system wil be short by 326 MW. Comparatively, the 2008 IRP
forecasted deficits to also occur beginning in 201 1, though at a higher level (498 MW). The
Company attributes the difference to lower demand, especially in the industrial sector, due to the
economic downtu. The deficit increases to 2,546 MW in 2015 and 3,852 MW by 2020. The
capacity deficit is driven by a coincident system peak load growth rate of 2.1 % for 2011 -2020,
taking into account energy efficiency savings. PacifiCorp's capacity position, which includes
existing obligations, a 13% planning reserve, and reflects the loss of over 1,000 MW of expiring
power purchase contracts, is shown below:
Table ES.l- Paelf1Corp iO-year Capacity Position Forecst (Megawatts). JI11 102 203 JI4 JI1 208 207 JIe JI. 2l
$irciefl
Total Resours
Sym OblgonRe.rv& (N.d on 13% target)
Obllgiition + 13% Plnmng RMml8
!e P08on
12,46
11.97
1.97
12,79
(32)
11.60
n,97
1,430
13.40
(1,601)
11,81012,
1,470
13,735
(1..925)
11,404
12,256
1,52
13,778
(2,373)
11,39
12,40
1.54
13.94
(2.,54)
11.397
12.59
1.69
14,164
rZ,75D
11,412
12,728
1,82
14.310
(2, as)
11.433
12.961
1.11
14,57
l3,l39ì
11,95
13,145
1,3314,m
ÇU83ì
11,192
13.76
1.68
15,04
\3,8521
On an energy basis, the system begins to experience short positions during heavy load hours
beginning in 201 1, and on an anual basis in 2015. PacifiCorp's estimated energy need over the
planing horizon is shown below:
STAFF COMMENTS 2 JULY 11, 2011
Table A.9 - AnDual Load foreeasted (io Megawatt-houn) 2011 tIrougb 2020
63,131,207 14,96,933 4,579,565 954,604 26,106,815 10,611,408 3,721.679 2,188,202
64,958,489 15,487.788 4,676,478 969,067 26,746,468 11,04,46 3,804.258 2,233,885
66,88,59 15.669,033 4,703,107 972,280 27.389,581 11,451,701 3,937,679 .2,26,877
68,035,127 15,853,824 4,754,,79 982,164 28,151,361 11,883,924 4,106,332 2,303.143
69,442,054 16,038,453 4.809.526 991,17 8,805,998 12,220,507 4,234,971 2,341,424
71,110,972 16,283,652 4,880,687 1,002,20 29,650,389 12,54,966 4,357,547 2,387,412
72,151,308 16,419,176 4.921,94 1,00,109 30,196,191 1.2,770,304 4,415,978 2,417,998
73,424,134 16,602,014 4,977,007 1,018,716 30,840,594 13,055,537 4,473,%8 2,456,298
74,713,621 16,789,205 5,030,425 1,028,331 31,491,637 13,346,735 4,532,675 2,494,611
76,136,508 16,998,651 5,089,930 1,039,248 32,188,156 13,680,764 4,598,60
*SE-lD represents a contract with BPA that makes the Company responsible for BPA's south Idaho retail load.
To determine how best to address the capacity and energy deficits, PacifiCorp developed 67
input scenarios for portfolio development, and utilzing a number of resource optimization models
and its own discretion in resource procurement, decided on a preferred portfolio it believes achieves
"a long-term resource plan that considers cost, risk, uncertainty, and the long-run public interest."
(201 1 IRP, p. 19). The preferred portfolio of the new IRP contains a significant level of energy
effciency measures, new gas-fired combined-cycle combustion tubines (CCCTs) in 2014,2016,
and 2019, transmission additions, firm market purchases, and renewable resource additions
throughout the planning horizon.
STAFF ANALYSIS
Staff has reviewed PacifiCorp's 2011 IRP and recognizes the Company's sustained efforts in
developing a sophisticated, thorough planing document amid an uncertain economic backdrop. The
Company continues to refine its modeling approach, specifically in regard to demand side resources,
and capabilties to expand the analytical scope of the document. While the IRP does not take the
place of the Company's annual ten-year business plan with respect to specific resource acquisition,
the alignment of the two (instituted in 2008) provides stakeholders with a more transparent view of
the planing process. Staff does not intend for its comments to be all-inclusive of the document, but
rather wil focus on a number of issues it deems importnt to the Company's ten-year action plan.
STAFF COMMENTS 3 JULY 11,2011
The economic planing environment continues to be stagnant when compared to the period
used to develop PacifiCorp's 2009 IRP, which utilzed a February 2009 load forecast. Both system
peak and system load are projected to grow at an annual rate of2.1 % over the ten-year planing
horizon.
1 These projected growth rates are high when compared to other utilties within the state and
around the nation. For example, Idaho Power projected a 1.8% annual growth in system peak and
1.4% anual growth in average load in its 2011 IRP. Signs ofload degradation within PacifiCorp's
service terrtory appear to have diminished relative to the previous IRP filing, softening the reduction
in forecasted load and peak. The Company cites growth in the residential and commercial sectors,
mainly for the East-side of its system, and potential large new industrial customers (namely large
data centers located around the Salt Lake City area) as other reasons load and peak continues to grow
at a moderate pace over the planing horizon. Staff notes that predicting additional large new load
during poor economic times is a risky proposition; for example, there is the possibilty that at least
one of the presumed new large customers may be delaying or abandoning their facilty in Salt Lake
City. Given long lead times on large generation facilities, such as the Lakeside 2 (CCCT) curently
under construction, the Company may find itself long on capacity in the near-term, and in need of
deviating from its Action Plan.
The 2011 forecast, developed in October 2010, nearly mimics that of the 2009 IRP update
forecast2, developed in November 2009. Both forecasts are lower than that used in the 2009 IRP
throughout the timeframe. For planing purposes, the impact is greater on system peak than energy.
In 2018, the comparable out-year of the forecasts, the Company predicts system coincident peak to
be roughly 2.6%, or 328 MW, below that projected in the 2009 IRP, and system load to be roughly
1.2% lower than the 2009 IRP forecast. Staff does not believe the reductions are inconsequential,
and may affect the timing of resource additions. That said, it does not appear that the relative
magnitude of resource additions is materially affected over the IRP timeframe.
lOver the twenty-year horizon, system peak and loads are projected to grow at an average of 1.9% annually.
2 PacifiCorp fied an update to the 2009 IRP on March 31,2010. The 2009 lRP was fied with the Commission on
May 29,2009.
STAFF COMMENTS 4 JULY 11, 201 1
PacifiCorp notes that the political environment has changed since its last IRP filing. Though
the various State initiatives governing climate change and renewable portfolio standards remain in
place, there is a reduced likelihood for federal climate change legislation in the near-term. The
Company continues to monitor developments at the federal level, and includes the impacts of carbon
and greenhouse gas regulations in its portfolio modeling and selection process. Staff concurs that it
is appropriate to consider the possibilty of federal climate change legislation in its portfolio
evaluation process, and is satisfied that the Company has adequately addressed the issue. PacifiCorp
does recognize that there are potential consequences stemming from various EPA regulations on the
operations of its generation fleet, especially its coal-fired facilties, which have prompted
expenditures in pollution control equipment.
Price Forecasts
One other aspect of the planing paradigm that has changed since the 2009 IRP has been the
significant decrease in natural gas and wholesale electricity prices. In recent years, market prices for
electrcity in the West have been tied closely to natural gas prices as gas-fired generation tends to be
the marginal resource, especially during high load hours. This trend is predicted to continue in the
foreseeable future.3
Staff acknowledges the recent decline in natural gas prices but notes that the fuel has shown
significant volatilty over the past ten years. PacifiCorp points out on page 27 of the 2011 IRP that
day-ahead prices at Henry Hub have fluctuated between a low of $1.72 per MMBtu (November 16,
2001) to a high of$18.41 per MMBtu (February 25, 2003). Recently, prices have somewhat settled
below $5.00 per MMBtu, presumably on the premise that demand is lower and domestic supplies
from shale have increased. Many are optimistic that expansion of unconventional domestic supplies
wil continue to put downward pressure on gas prices. Staff is cautious to overestimate reliance on
emerging natural gas resources. One need only to look a few years back when it was thought that
liquefied natural gas would fill the supply-demand gap. Due to global competition and the increased
domestic production, that has not materialized. Also, demand for natural gas can be presumed to
grow significantly over the planing horizon, with the U.S. Energy Information Agency predicting
3 To date, 2011 is running contrary to view, mainly due to extraordinarily high runoff throughout the Nortwest and
depressed loads associated with cooler weather and slower economic activity. In fact, there were periods during light
load hours when wholesale prices at Northwest trading hubs dipped below $0 per MWh.
STAFF COMMENTS 5 JULY 11,2011
60% of electric generation from 2010-2035 wil come from natural gas-fired facilties. Future
volatilty in natural gas prices increases the risk in variable fuel costs borne by customers.
Resource Options
Staff maintains that PacifiCorp continues to do an admirable job capturing the various
operating characteristics and costs when screening resources in the modeling process. PacifiCorp
relies on a number of third-pary studies, along with its own experience, to estimate capital costs
throughout the planing horizon. PacifiCorp evaluated a number of renewable resources for
inclusion in portfolio modeling, including wind on the east and west sides of its system, geothermal,
pumped storage, and various solar technologies. The Company notes that capital costs have
generally decreased since 2009 due to the slowdown in the economy. Additionally, the Company
states that certain unproven technologies, such as integrated gasification combined cycle (IGCC)
plants and certain renewables display greater cost and operating uncertainty relative to more
traditional resources. With much of its generating units located in solar-intensive areas, Staff
encourages PacifiCorp to investigate the feasibilty of augmenting or retrofitting its gas and coal
facilties with a solar hybrid design in future IRPs. Aside from the benefits associated with utilzing
the existing infrastructure, it is assumed that as these technologies mature, market conditions may
accelerate reductions in capital costs.
PacifiCorp continues to refine its analysis of wind resources for portfolio modeling. In this
IRP, adjustments were made to the topology bubbles to allow the System Optimizer model to select
wind resources sited outside of transmission-constrained areas in Wyoming. Staff believes this
adjustment provides greater flexibilty for the model to select additional wind should it prove to be a
preferred resource. These 'wind only' bubbles are also assigned an incremental transmission cost,
which Staff considers appropriate to better approximate the true cost of wind resources. An adjusted
wind resource cost is then determined for modeling purposes, taking into account capital, fixed
O&M, wheeling and integration costs. Staff notes that the Company included a wind integration
charge of$9.70/MWh in its analysis, a figure supported by its Wind Integration Study completed in
September 2010. Staff believes that PacifiCorp is well-positioned to integrate wind given its
resource diversity and geographic footprint.
The Company has done an excellent job developing its demand-side management (DSM)
resources into distinct supply curve bundles to allow competitive model selection of DSM and
supply-side resources. The basis for DSM development was a potential study conducted by the
STAFF COMMENTS 6 JULY 11,2011
Cadmus Group in 2007, which provided estimates of size, type, location and cost for resources that
were updated using a 2009 study. Staff is aware that a recent potential study has been completed
(March 2011), and recognizes that this information was not available at the time the 2009 IRP was
created. Staff expects any new findings from the recent study wil be incorporated in the 2011 IRP
Update.
For the 2011 IRP, fifty discrete supply curves were developed for both Class 1 and Class 3
DSM.4 PacifiCorp continued the practice introduced in its 2009 IRP of creating supply curves Class
2 DSM that are bundled by cost across each state within its jurisdiction. 5 In total, nine Class 2 DSM
bundles were created for each state.6 The System Optimizer model is capable of selecting any set of
bundles throughout the twenty-year timeframe. Staff believes that the Company has adequately
characterized supply and demand-side resources, as well as transmission options and market
transactions, which leads to equitable treatment in the resource selection process.
Portfolio Modeling and Selection
As noted earlier, PacifiCorp created 67 portfolio cases or scenarios that cover an array of
assumptions regarding, among other things, C02 regulation, natural gas prices, and alternative load
forecasts. For this IRP, the Company specified several cases that evaluate partial and total
construction of the Company's planed Energy Gateway Transmission Project (Gateway Project).
The defined cases are then optimized in the Company's System Optimizer capacity expansion model
to develop resource portfolios, which then go through a Monte Carlo production cost simulation to
evaluate stochastic risk. Based on its assessments of costs and risks, PacifiCorp selects the top
performing portfolios for furher evaluation. The stochastic measures are broken into three
categories:
1) Cost
Mean present value of revenue requirements (PVRR),
Risk adjusted mean PVRR, and
10-year customer rate impact;
4 PacifiCorp classifies Class 1 programs as fully dispatchable, such as the Idaho Irrigation Load Control Program.
Class 3 programs represent 'buydown' programs such as critical peak pricing and commercial/industrial demand
buyback.
5 Class 2 DSM programs are defined as non-dispatch able programs, namely energy efficiency measures such as See Ya
Later Refrigerator and CFL giveaways that have lifetime load reduction impacts. Class 2 DSM is bundled due to the
voluminous permutations that could be generated from all potential programs.6 A tenth bundle, representing a compact florescent bulb program, was included for 201 i and 2012. Due to changes in
Federal lighting standards, the bundle was not made available for selection in subsequent years.
STAFF COMMENTS 7 JULY 11,2011
2) Risk
Ulper-tail mean PVRR,
5t and 95th percentile PVRR, and
Production cost standard deviation; and
3) Supply reliabilty
Average anual energy not served (ENS),
Upper-tail ENS, and
Loss of load probabilty
The selected portfolios then undergo fuher optimization to test for deterministic risk, such as
varing gas and electricity prices for final portfolio selection, which is fine-tuned by the Company
based on an "analysis of key resource acquisition and regulatory compliance risks." (2011 IRP, p.
202)
Staff notes that in this IRP, PacifiCorp included a lO-year customer rate impact measure of
stochastic risk. According to the IRP, the "focus of the rate impact review (is L the stabilty of year-
to-year percentage of full revenue requirement impacts, as well as the cumulative 10-year impact."
(Ibid, p. 192) While results from this measure var slightly from the other PVRR-based metrics,
Staff believes it is appropriate to evaluate the approximate year-to-year impact of each portfolio.
That said, Staff notes that this represents a year-to-year outlook on revenue requirement, and does
not capture the yearly rate instabilty associated with volatile market prices and fuel costs captured in
the Company's energy cost adjustment mechanism (ECAM).
After initial screening, the Company selected eight top performing portfolios for further
evaluation, Upon review, two of the eight were selected for deterministic analysis.7 It is unclear as
to the criteria used by the Company to determine the portfolio finalists, as there was little difference
in portfolio cost metrics (for example, there was less than a 1 % difference in ratepayer impact for all
but one of the portfolios under various scenarios), and the finalists performed near the bottom in
carbon risk and supply availabilty. The Company needs to do a better job explaining its portfolio
decisions when there does not appear to be clear best options.
The final screening consists of assessment for acquisition risk and environmental compliance
risk mitigation. PacifiCorp adjusted the final portfolio to delay procurement of a CCCT in 2015 to
2016, citing undesirable rate impacts and corporate budgeting issues due to a planed CCCT
7 Initially, three portfolios were selected for furter analysis. Due to similarities between two of the portfolios,
PacifiCorp opted to screen only two.
STAFF COMMENTS 8 JULY 11,2011
addition in 2014. The Company also removes 105 MW of geothermal resources (selected in all
scenarios) due to development cost recovery uncertainty. A recent report by the Glacier Partners
Corp. suggests that nearly 55% of construction costs are associated with exploration and drilling, and
there is a high probabilty that a site may not be suited for utilty-scale power production. If the
utilty expends the capital to develop a geothermal resource to no avail, it risks disallowance of
recovery in rates by regulators. PacifiCorp states that until there is a clear signal from regulators on
cost recovery, it views geothermal as an alternate resource to procure, but not one to include in its
IRP.
The geothermal resources were replaced with an equivalent amount of wind for final
screening.8 Staff does not consider the two resources to be similar in any maner other than being
considered 'renewable.' Wind is an intermittent resource with a low capacity factor, and contributes
little to the Company's capacity need. Geothermal is considered a baseload resource due to its high
capacity factor and reliabilty. Staff does not believe the portfolio selection process accurately
captures these dissimilarities. Given the extreme operating differences between wind and
geothermal, Staff wonders to what extent the final portfolio determination is affected by this ad hoc
adjustment so late in the process. Staff expects the Company will refine its approach toward
treatment of geothermal resources in future IRP filings.
As a way to mitigate the impact of more stringent renewable resource policies, the Company
then opted to increase the quantity of wind to 2,100 MW. The basis for this value was an average of
the top three performing portfolios under alternate C02 tax scenarios. It should be noted that only
one of the eight portfolios from the initial screening cut was included in the calculation, and none
from those selected for furher screening. Based on what it considers a reasonable acquisition
schedule, the Company fixed the wind resource availability and amount to the 2018 through 2029
timeframe. With these adjustments, PacifiCorp re-optimized the portfolio to determine what it
considers the preferred portfolio shown below:
8 Using capacity factors for each resource, the Company was able to calculate 572 MW of equivalent wind, which was
added to 139 MW included in the finalist portfolio.
STAFF COMMENTS 9 JULY 11, 2011
475
18 8
ro 300 200 200 200 100 20 100 100 100 100 100
5 5 5 5
20 97 .5
1"124 126 120 12 125 125 13 m 139 140 14\m 135 141 145
3 .
Mi Sø. Watw Bu'.. . 4 4: 4 4 4.hGtOf ~ lJP/ 11~ 715 821 967 695 m 700 756756 156 750 750\J~e; 11 95 20! 250 54 71 SIB 975NoI'...~(bii~)ai¡m_l1~-.¡i,ai.._àd..~_..û:io_..~N..1i
ìill_ii ØP1i lIl"'pilllllR lInifl.iy..ll_p1_lI ÌI1l_W~6tIl Plmpl.
47
65
2.100
104
252~
19
3-
NA
WA
The preferred portfolio represents PacifiCorp's best efforts to meet its obligations in a low-cost
manner when accounting for various sources of risk and uncertainty. While the process may not be
completely transparent, Staff believes the Company utilzed its best judgment given the most curent
information in developing this portfolio.
2011 IRP Action Plan
PacifiCorp's 2011 Action Plan is included in Staffs comments as Attachment A. The Action
Plan details the steps that the Company intends to take in order to acquire the identified resources
and further improve the IRP process. In the near term, PacifiCorp plans to issue a Request for
Proposals (RFP) for a baseload facility that corresponds with the identified 597 MW CCCT
identified in the preferred portfolio to go along with the 637 MW Lakeside 2 plant, due online in
2014. The Company intends to acquire 80 MW of Class 1 DSM in the 2012-2013 timefrare, with
the remaining 170 MW acquired over the next ten years. The Company indicates that it wil acquire
1,200 MW of Class 2 DSM through an ongoing DSM RFP process. Based on the portfolio results,
the Company will pursue 800 MW of wind resources by 2020, and steadily add more wind over the
next nine years.
PacifiCorp includes a separate transmission expansion action plan in the 2011 IRP, which
details the continuing efforts toward completion of the Gateway Project. The Company has broken
the transmission project into eight segments, listed below:
STAFF COMMENTS 10 JULY 11,2011
Planed In-Service
Segment Name Segment Notation Desciip~i("n
Date
Wallula to McNary A 230 kV,single circuit 2012-2013
Mona to Limber 500 kV,single circuit 2013
Limber to Oquirrh C 345 kV, double circuit 2013
Oquirrh to Terminal 345 kV, double Circuit 2014
Windstar to Aeolus
2-230 kV,single
D circuit 2015-2017
Aeolus to Populus
500 kV, single circuit
Populus to Hemingway E 500 kV, single circuit 2015-2018
Aeolus to Mona F 500 kV, single circuit 2017-2019
Sigurd to Red Butte G 345 kV,single circuit 2014
Hemingway to H 500 kV,single circuit unkown
Capitan Jack
A map showing the general locations of the projects is included as Attachment B ofStafts
comments. Of the eight, three segments (A, C, G) are well into the permitting process, and have
anticipated online dates in the 2012-2014 timeframe. Three more (D, E, F) are in initial scoping or
permitting status, with estimated online dates ranging from 2014 to 2019. The Company has
partnered with Idaho Power on segments D and E. A final segment (H) is currently under review as
to the most economic strategy for development, i. e., should the Company parner with other utilties
(namely Idaho Power and Portland General Electric) for joint development and ownership of the
project or self-build and maintain sole ownership.9 Staff wil continue to monitor the Company's
progress toward completion of the Gateway Project, and fully expects the Company to continue to
evaluate the economics of the endeavor.
Prudency assessment or approval of specific resources cited in either action plan is beyond
the scope of the IRP review. Staff and the Commission will address such issues in a more suitable
foru, such as a general rate case. While not endorsing the selected portfolio, Staff nonetheless
believes the identified course of action seems reasonable given the assumptions, analysis and
conclusions of the Company as presented in the IRP.
STAFF COMMENTS 11 JULY 11,2011
Acknowledgement
In Idaho, as in most states, the Commission "acknowledges" or "accepts for fiing" rather
than "approves" a utility's IRP. Other states where PaCifiCorp serves have similar IRP requirements
and provisions for acknowledgement; however, "acknowledgement" may be viewed differently in
some states than in others. Staff believes it is helpful to explain what it presumes is meant by
acknowledgement in Idaho. The following policy on integrated resource planing, adopted by the
Commission in Order No. 25260, Case No. GNR-E-93-03 is provided as a way of explanation:
POLICIES ADDRESSING INTEGRATED RESOURCE PLANNING. Each
electric utilty regulated by the Idaho Public Utilities Commission with retail
sales exceeding 500,000 kilowatt hours in a calendar year shall employ
integrated resource planning. Each electric utility's integrated resource plan
must be updated on a regular basis (no later than biennially), must provide an
opportunity for public participation and comment, and must be implemented.
This plan constitutes the base line against which the utility's performance wil
ordinarily be measured. The requirement for implementation of a plan does not
mean that the plan must be followed without deviation. The requirement of
implementation of a plan means that an electric utilty, having made an
integrated resource plan to provide adequate and reliable service to its electric
customers at the lowest system cost, may and should deviate from that plan
when presented with responsible, reliable opportunities to fuher lower its
planed system cost not anticipated or identified in new existing or earlier plans
and not undermining the utilty's reliability. I n order to encourage prudent
planing and prudent deviation from past planing when presented with
opportunities for improving upon a plan, an electric utilty's plan must be on fie
with the Commission and available for public inspection, but the fiing of the
plan does not constitute approval or disapproval of the plan having the force
and effect of law, and the deviation from the plan would not constitute violation
of the Commission's orders or rules. The prudence of a utilty's plan and the
utility's prudence in following or not following a plan are matters that may be
considered in a general rate proceeding or other proceeding in which those
issues have been noticed.
Furhermore, the Commission explicitly stated in Order No. 22299 its role in the IRP process:
"...the Resource Management Report (now the IRPJ is not designed to turn the IPUC into a planning
agency nor shall the Report constitute pre-approval of a utilty's proposed resource acquisitions." It
is through these Orders that Staff constitutes its view of acknowledgement.
9 The segment not listed is the Populus to Terminal line, which was completed prior to submission of the 20 i i IRP.
STAFF COMMENTS 12 JULY 11,2011
STAFF RECOMMENDATIONS
Staff believes that the Company has adequately met the Commission's requirements in regard
to the 2011 IRP. While not endorsing the proposed action plan, Staff believes that PacifiCorp has
performed extensive analyses, given equivalent consideration of supply- and demand-side resources,
provided acceptable opportunities for public input, and that the end result is representative of the
Commission's directives toward integrated resource planing. Staff therefore recommends that the
Commission acknowledge the Company's 2011 IRP.
Respectfully submitted this 'l~ day of July 2011.
JtJ2~~'
'Neil Price
Deputy Attorney General
Technical Staff: Bryan Lanspery
i: umisc:comments/pace l i .1 Onprpsbl comments
STAFF COMMENTS 13 JULY 11,2011
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7
Energy Gateway Transmission Expansion Project
PacifiCorp semce a rea
PlannedtrnsmissÎOn lines:
- sa kV minimum voltae
- J4!i kV minimum volta
-- 230 k V miniinumVQliail
- - lines undr consídentioi
o Tranmiìssion hub
. FiiSlìng subitaôoo
N TAN A
N E DA
COLORADO
ARIZO N MEXICO
This map Is for general refe~e only and re1lca current plans.
It may not rqflect thi flnal rolltlX. conçtrur: srø lIli!OCq 0 r qx:ct lin. conflguratlon.
N""..,,.2010
Attachment B
Case No. PAC-E-11-10
Staff Coiments
B. Lanspery
7/11/11
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 11TH DAY OF JULY 2011,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. PAC-E-ll-lO, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
TED WESTON
ID REGULATORY AFFAIRS MGR
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
E-MAIL: ted.weston(fpacificorp.com
DANIEL E SOLANDER
REGULATORY COUNSEL
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
E-MAIL: daniel.solander(fpacificorp.com
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
datarequest(fpacificorp.com
i~..:.Kk
SECRETARY
CERTIFICATE OF SERVICE