20180112Comments.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720.0074
(208) 334-03s7
IDAHO BAR NO. 7956
RE C E IVED
2Cl0 iftl{ l2 Pl{ 2: 07
i-r,. !.':J I_-ltlLlC
i.i ; l,- 1 ; .,:; Cu:,iIiiSSiON
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 OT PACIFICORP DBA
ROCKY MOUNTAIN POWER'S 2017
INTEGRATED RESOURCE PLAN.
CASE NO. PAC.E.17.O3
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission, submits the following comments
regarding the above referenced case.
BACKGROUND
On April 4,2017, PacifiCorp dba Rocky Mountain Power filed its 2017 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's
Application in this case requested acknowledgement of the 2017 IRP. Acknowledgement or
acceptance of the 2017 IRP should not be interpreted as an endorsement of any particular element
of the plan, nor should it constitute approval of any resource acquisition contained in the plan.
See Order No. 33396.
The Company's IRP filing consists of the following items: l)20lT Integrated Resource
Plan - Volume I;2) 2017 Integrated Resource Plan - Volume II; 3) Supplemental Data Discs; 4)
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1STAFF COMMENTS JANUARY I2,2OI8
Supplemental Volume II Corrections; 5) 2017 Integrated Resource Plan - Energy Vision 2020
Update. Volumes I and II of the 2017 Integrated Resource Plan provides details on the IRP
process, the information used during the process, and the action plan produced from the process.
The Energy Vision 2020Update is an informational filing which provides additional economic
analysis of the Repower and New Wind/Transmission projects identified in Volume I of the 201 7
IRP. This informational filing was provided four months after the initial filing date.
The Company stated that the primary objective of the IRP is to identify the best mix of
resources to serve customers in the future (PacifiCorp 2107 IRP, Volume l, pg. l). The final
resources identified for the 2)-year planning timeframe of the IRP included 1,959 megawatts
(MW) of new wind resources, 905 MW of repowered wind resources, 1,040 MW of new solar
resources, 2,077 MW of incremental energy efficiency resources, and 365 MW of new direct load
control capacity (PacifiCorp 20l7IRP, Volume l,pg.2).
Two major projects, labeled as Energy Vision 2020, are action items identified inthe2017
IRP action plan. Energy Vision 2020 includes repowering 905 MW of Company owned wind
resources,l 1,100 MW of new Wyoming wind resources, and a new 140 mile 500 kV transmission
line in Wyoming to connect the new wind resources. Both of these projects rely on federal
production tax credits (PTCs) to provide economic benefits. The Company's complete action
plan is provided in Attachment A to these comments.
STAFF REVIEW
Staff completed a comprehensive review of PacifiCorp's2077IRP including a review of
the load forecast, natural gas forecasts, existing resource assumptions, and new expansion
resource assumptions, as well as a review of the Company's preferred portfolio and action plans.
Staff comments are organized into several sections around topical areas that Staff believes are
important: 1) IRP Process Requirements; 2) Modeling of Coal Plants; 3) Energy Vision 2020;4)
Demand Side Management; and 5) Natural Gas Forecast.
I The capacity for the repowering project was increased to 999. I MW in the Company's IRP update to match the
capacity figures reported in the Repowering case, Case No. PAC-E- I 7-06.
2STAFF COMMENTS JANUARY 12,2078
Through its review of this year's IRP, Staff highlights the following findings:
1. The Company met the IRP minimum requirements as set forth in Commission Order
No.22299.
2. The 2017 IRP preferred portfolio showed a continued transition to renewable energy
resources and a reduction in coal resources.
3. The Company should identify least-cost coal plant retirement dates using the
endogenous retirement functionality within System Optimizer.
4. Inclusion of benefits outside the planning timeframe can distort comparisons between
portfolios.
5. There was limited public input on the preferred portfolio due to the late introduction of
Energy Vision 2020 projects into the IRP process.
6. The Company is effectively using demand side management in its resource planning.
7. There is high probability that the Company is underestimating natural gas prices over
the Z)-year planning period.
IRP Process Rasluernants
In January 1989, the Commission identified the Integrated Resource Plan as a "Resource
Management Report" and required it to be completed on a biennial basis [OrderNo.22299]. The
Commission fuither specified the following planning requirements for assessing future resource
needs:
1. Examination of load forecast uncertainties;
2. Effects of known or potential changes to existing resources;
3. Consideration of demand and supply side resource options;
4. Contingencies for upgrading, optioning and acquiring resources at optimum times
(considering cost, availability, lead time, reliability, risk, etc.) as future events unfold.
Staff believes the PacifiCorp 2017 Integrated Resource Plan submitted as part of this
filing meets the requirements specified by the Commission.
The Company developed its IRP through a series of planned steps. First, the Company
prepared a load-resource balance study that compared forecasted loads to existing resource
capacity over a 2}-year time horizon. The load-resource balance study highlights deficiencies in
capacity that occur over the planning horizon. The Company considered a wide range of factors
aJSTAFF COMMENTS JANUARY I2,2OI8
including natural gas and wholesale power prices, along with regulatory, environmental, and
public policy issues. These factors are bundled into a set of assumptions of unique planning cases
using input from involved stakeholders. For each of these cases, the Company uses System
Optimizer (SO) a capacity expansion optimizer that produces a least cost resource portfolio model
based on the assumptions of each case. Each portfolio is characterizedby the type, timing, and
location for new resources. For each of the portfolios, the Company uses Planning and Risk
model (PaR) to perform a stochastic risk sensitivity analysis given a range of forecasted carbon
dioxide (CO2) and natural gas prices. The Company then looks to validate the need, timing and
benefit for adding new generating resources over the 20-year timeframe of the IRP. Results of
these analyses support the Company in determining a least-cost least-risk portfolio, defined as the
"preferred portfolio." From the preferred portfolio, the Company established an action plan that
is used as a guideline for meeting forecasted load requirements.
The planning steps of the IRP process discussed above satisfy all four requirements
established in Order No.22299. The requirement for examination of load forecast uncertainties
was satisfied through PaR modeling that captures the risk of varying loads in the future. The
requirement for effects of known or potential changes to existing resources was satisfied during
Regional Haze screening, a process that created several different potential alternatives for existing
coal plant resources. The requirement for consideration of demand and supply-side resource
options was satisfied by the Company allowing both demand and supply side resources to be
available for selection during the modeling process. The requirement for contingencies in
upgrading, optioning, and acquiring resources at optimal times was satisfied through the use of
SO and PaR modeling using multiple cases and portfolios.
IRP Preferred Portfolio
The 2017 IRP preferred portfolio relies more heavily on new renewable resources, short-
term firm market purchases identified as front-office transactions (FOTs), and DSM load control
resources as compared to the 2015 IRP preferred portfolio. The preferred portfolio includes 2,071
MW of incremental energy efficiency resources, I ,959 MW of new wind resources, 1,3 13 MW of
new natural gas resources, 1,040 MW of new solar resources, 905 MW of repowered wind
resources, and 365 MW of new direct load control capacity. During theZ}-year plaruring
STAFF COMMENTS JANUARY 12,2OI84
timeframe, 3,650 MW of existing coal capacity is removed from the preferred portfolio along
with 358 MW of existing natural gas capacity (PacifiCorp2107IRP Volume l,pg.2).
The 2017 IRP preferred portfolio shows a reduction in coal resources and a transition to
renewable resources through the Company's Energy Vision 2020 program. Pursuant to the
program, 1,100 MW of new Wyoming wind resources and 905 MW of repowered wind resources
are projected to be installed before 2021, and are made possible through PTCs. The rest of the
renewable resources in the preferred portfolio were selected based on economics without
receiving PTCs. A reduction in existing coal resources was a result of the Regional Haze
screening step of the IRP process which looked at different potential Regional Haze compliance
alternatives. One of the major reasons for reduction in coal resources is a projected early
retirement of coal plants to avoid installation of expensive SCR equipment. Overall, the 2017
IRP preferred portfolio provides a mix of resources with more renewables and less coal.
Modeline of Coal Plants
The Company's approach to the IRP limits the Company's capacity expansion model
(through System Optimizer) from fully weighing the economics of existing generation resources.
For existing resources, the Company fixes the resource operating life prior to starting model
analysis. In the case of existing coal plants, the operating life is limited by the length of time the
Company assumes it can operate the plants without installing costly environmental controls
related to regional haze emissions standards. In some cases, this is assumed to be the remaining
operating life of the plant.
This approach assumes, by default, that producing energy from existing coal plants
without environmental controls is less costly than potential alternatives. In Staff s view, this
assumption cannot be justified given: i) low capacity factors at some of the Company's coal
generating units; 2) the relatively low cost of natural gas; 3) the integration of renewable power
into the energy system (including any corresponding incentives); and 4) reductions in energy
market prices.
Staff believes that the Company should let the functionality of the optimizer model fully
assess economically and "endogenously" when a coal plant should be retired. This approach
would provide resource portfolios and coal-plant closure scenarios that are least-cost based on
cost and operating inputs assumed in the model. Then if the Company believes that the modeled
5STAFF COMMENTS JANUARY 12,2018
portfolio should not be recommended, it would need to provide justification for deviating from
the model's coal plant closure dates based on criteria other than cost, or other short-comings in
the model.
The Company tested endogenous coal plant closure modeling based on stakeholder
requests during IRP feedback. Specifically within the analysis of "RegionalHaze Case 6," the
Company utilized endogenous plant closure modeling functionality in SO. The modeling
considered specific alternative outcomes tied to coal units: Hunter l, Hunter 2, Huntington l,
Huntington 2, Jim Bridger 1, and Jim Bridger 2. Nonetheless, Staff is concerned that the amount
of analysis was still too limited and should have been broadened across a larger set of cases and
across all coal generation units. In fact, allowing the model to make comparisons and choose
between new and all existing resources could help the Company identify other existing non-
economlc resources.
Staff recognizes the dispatchability benefit of coal plants for maintaining system reliability
and the need for resource diversity. However, Staff also recognizes that high fixed operations and
maintenance costs tied to large aging coal plants that are underutilized can be costly. Further, by
arbitrarily prescribing that certain plants remain operational until a defined date, the Company
could limit introduction of new resources that may be more economically competitive in the long
run. The wind repowering and the new wind/transmission projects discussed below are two such
cases. Both projects have favorable economics because significant PTC benefits offset most of
the up-front capital cost penalties when compared to existing resources.
Vision
8Y2020 includes two major wind projects: the repowering of 905 MW of Company owned
wind resources, and 1100 MW of new wind resources that require and include a new 140 mile
500 kV transmission line and other transmission-related infrastructure. The 8V2020 projects are
time-limited economic-based projects that became viable when Congress extended PTC benefits
for both new wind projects and repowered wind facilities. However, due to the introduction of
these projects as expansion resources late in the IRP process, Staff is concerned: 1) there is a
mismatch in planning evaluation timeframes; and2) there was limited public input.
6STAFF COMMENTS JANUARY I2,2OT8
The wind repowering project takes advantage of PTC benefits to install new longer rotors,
new nacelles, and higher capacity generators on 11 Company owned wind sites.2 The new
components will result in a longer life and a 19 percent overall average increase in generation.
The new wind and transmission project includes at least 1,100 MW of new wind turbines
that will lower net power costs and provide ten years of PTC benefits. The new transmission
aspect of the project is required to interconnect the new wind resources to the rest of the system.
The Company states that the transmission lines will help relieve current congestion in the eastem
Wyoming area. All of the 8y2020 projects must be completed by December 31, 2020, to receive
100 percent ofPTC benefits.
Because of the late addition of the EY2020 projects, the IRP process was modified to
introduce the projects into the IRP analysis. The Company could have performed its economic
analysis of the two projects by redoing all of their model runs and include the projects as potential
resources to be selected by SO, thereby following the Company's standard IRP process. Instead,
the Company chose to evaluate the projects by comparing the net benefits of resource portfolios
with and without the projects. Staff believes the Company's modifications to the IRP process
saved the Company time and were appropriate for the circumstances. However, because of the
approach used and due to the late changes, it caused some unfortunate consequences to arise as
discussed below.
P lanning Timeframe Mismatch
Staff believes that when evaluating all resource options in the IRP, only the costs and
benefits across a common timeframe should be included. However, the Company included
benefits beyond the 2)-year IRP timeframe for the repower project. This made the portfolios with
repower resources more cost-effective than portfolios without repower resources. The Company
states the benefits were included to "account for the significant incremental energy benefits
beyond the IRP planning period when the life of repowered wind resources is extended."
2 The IRP originally included I I sites for repowering. There are now l2 sites that are proposed to be repowered
based on the Energy Vision 2020Update and Case No. PAC-E-17-06.
7STAFF COMMENTS JANUARY I2,2OI8
(PacifiCorp 2107 IRP, Volume 1, pg. 1). This biased the portfolios that included repowered
resources by increasing net present value benefits by approximately $346 million (Public Meeting
8 slide deck, slide 37,Mar.2-3,2017).
Allowing estimated benefits outside of the 2)-year planning timeframe creates an unfair
comparison between cases because all cases have potential benefits and costs beyond the 2O-year
planning timeframe which could be included but were not. Staff agrees the repower project does
have benefits beyond the planning timeframe, but believes these benefits should be handled
differently in a separate analysis, such as theEY2020 update, or by extending the planning
timeframe and modeling all portfolios on a common timeframe. The Company used such an
approach when it submitted its proposals for both of the 8Y2020 projects for recovery to the
Commission in Case Nos. PAC-E-L7-06 and PAC-E-17-07 .
Limited Public Input
The time-limited opportunity of PTCs caused the Company to deviate from the standard
process. The EY2020 projects were not introduced until the last public meeting in March 2017,
approximately one month before the expected filing date. This limited the amount of public
participation and introduced uncertainty as to the validity of the results. While Staff is aware that
the Company did not have total control of when the projects were introduced into the IRP process
due to the time-limited opportunity of the PTC benefits, Staff believes the Company could have
done a better job with introducing the projects earlier.
The Company made purchases in December 2016 for new wind-turbine generator
equipment for the repower project, but did not introduce the repower project until the March2}l7
public meeting. Staff assumes the Company did an analysis of the repower before making the
December 2016 purchase of the equipment to evaluate the project. Likewise, Staff sees no reason
why the analysis was not introduced into the IRP process before March 2017. Not introducing the
project until March reduced transparency and limited public input.
Staff recommends projects similar to Energy Vision 2020 be introduced into the IRP
process as soon as possible in future IRPs. This will lead to more transparency and provide more
time for public input and feedback.
8STAFF COMMENTS JANUARY I2,2OI8
Demand Side Manaeement (DSM)
PacifiCorp indicates that DSM will continue to play a key role in its resource mix, with
new energy efficiency (Class 2) resources meeting 88 percent of the forecasted load growth from
2017 through2026. In the 2015 IRP, PacifiCorp projected that new energy efficiency resources
would meet 86 percent of forecasted load growth. While the percent of load growth covered by
DSM has increased slightly in the 2017 IRP, total energy efficiency resources decrease for the
preferred portfolio relative to the 2015 IRP. In 2015, the Company estimated that it would \
acquire 1,160 aMW over the 2}-year planning period. This declines 20 percent to 930 aMW in
the 2017 IRP. The reduction in planned DSM resources is attributed to reduced loads and
reduced costs for wholesale power purchases and renewable resource alternatives.
Direct load control (Class l) becomes a much more significant component of the preferred
portfolio in the 2017 IRP. Additional direct load control is assumed to be implemented in the
year 2028, and by the years 2034 to 2036 it accounts for approximately 350 MW of load
reduction - an increase of over 600 percent from the less than 50 MW of load reduction in the
2015 IRP. PacifiCorp states that the direct load control implementation is coincident with
assumed coal unit retirements, which aligns with the resource need when those units retire.
As it has in past IRPs, PacifiCorp created supply curves for groups of similarly priced
DSM resources. These cost-based DSM supply curves were then included in the Company's SO
model which simultaneously competed against supply-side resources to meet the Company's
projected capacity and energy deficits. Staff continues to believe that this methodology provides
robust and equal treatment between demand-side and supply-side resources in the modeling
process.
Natural Gas Forecast
Variations in price forecasts for natural gas can significantly affect the cost and risk of the
Company's resource portfolio and the selection of a preferred portfolio. Staff believes
PacifiCorp's baseline IRP assumptions likely understate future natural gas prices. An IRP
analysis based on understated gas costs overvalues gas resources and undervalues non-gas
resources, including wind, solar, and coal. Consequently, reliance on these future gas cost
assumptions could result in overinvestment of gas resources, underinvestment in non-gas
resources, and a non-optimal schedule for resource retirements and additions.
STAFF COMMENTS JANUARY I2,2OI89
PacifiCorp indicates that forecasted natural gas prices used in the 2017 IRP are
significantly lower than the gas prices used in the 2015 IRP. The Company's 2017 IRP contains
two natural gas price forecasts. The first, a set of three forecasts, was presented in the Company's
original IRP filing and is referred to as the Adopted High, Medium, and Low cases. The second,
a single forecast, was presented in the Energy Vision 2020 Update and is referred to as April 2017
Official Forward Price Curve (OFPC).
The Adopted Medium and OFPC forecasts are identical after the first six years. The
OFPC uses forward market prices for the first six years of the forecast, followed by a 12-month
transition to a forecast from a third-party consultant. The Adopted Low, Medium, and High
forecasts are based on a range ofthird-party forecasts. Staffhad concerns about relying
exclusively on market forwards for the first six years of the OFPC forecast because the volume of
forward purchases declines dramatically over that period. However, the Company confirmed that
this does not have a material impact on the Company's preferred portfolio because resource
acquisitions occur after the OFPC forecast has transitioned to align with the Company's Adopted
Medium case.
According to PacifiCorp, its Adopted Low forecast is based on "surging growth in price-
inelastic associated gas, technology improvements, stagnant liquefied-natural-gas exports, and an
ever-expanding resource base." (Energy Vision 2020 Update, pg. 8) PacifiCorp states that its
Adopted Medium case results when "medium-natural-gas prices are paired with medium or low
CO2 price assumptions [and] is based on a base-case forecast from another independent third
party that is reasonably aligned with other base-case forecasts." (Energy Vision 2020 Updxe,
pg. 8) PacifiCorp states that the Adopted High is based on a high-price scenario from the same
forecaster. The high-price scenario occurs in an environment where natural gas developers are
risk averse and become reluctant to commit capital for drilling investments before demand for the
commodity materializes. The Company states that this leads to a scenario where demand exceeds
supply and creates an exaggerated boom-bust cycle. The Company smoothed the boom-bust
cycle in the third party's high-price scenario because the specific timing of these cycles are
extremely difficult to project with reasonable accuracy.
Staff compared the Company's gas price forecasts to recent EIA forecasts. The EIA
prepares a low, high, and a reference case natural gas forecast for the twenty-year forecast period.
STAFF COMMENTS l0 JANUARY 12,2OI8
The low-priced forecast, referred to as the "High Oil and Gas Resource Technology" case, aligns
closely with current market forward prices extended over 20 years.
Comparison of NaturaI Gas Forecasts
{?017 EIA Annual Energy Out}ook to Faclflcorp Forecasts}
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Staff is concerned that the Company's OFPC gas price forecast remains excessively low
through the entire planning period. The OFPC is less than EIA's low-price forecast for a total of
1 I years out of the l9-year planning period. The OFPC is less than EIA's reference forecast for
every year of the l9-year period. Staff believes that a forecast based on forward market prices is
unreasonably low, and PacifiCorp's forecast is lower than that in over half of the years in the 20-
year planning period.
Staff is also concerned about PacifiCorp's comparatively low natural gas price
assumption. Staff believes planning to an excessively low gas price forecast is inappropriate
because of the disproportionate upside price risk. The Company's 2015 IRP filing cautioned that
long-term natural gas price volatility may pose a long-term risk. Nonetheless, the Company did
not address that concem in this IRP. Staff encourages the Company to carefully consider risk
mitigation in future resource planning and operating action plans because a substantial portion of
its future generating resources depends on natural gas.
STAFF COMMENTS l1 JANUARY 12,2OI8
STAFF RECOMMENDATIONS
The Comparry's2017IRP satisfies all the requirements in OrderNo. 22299. As
previously noted, acknowledgement of the 2017 IRP should not be interpreted as an endorsement
of any particular element of the plan, nor does it constitute approval of any resource acquisition
contained in the plan.
Staff recommends the Commission acknowledge PacifiCorp's2017IRP filing. In
addition, Staff recommends the following:
o The Commission should direct the Company to identify least-cost coal plant retirement
dates using endogenous System Optimizer functionality.
. The Commission should recommend the Company only include cost and benefits from the
same planning timeframe when comparing portfolios in future IRP planning to reduce
di stortion between portfolio s.
o The Commission should recommend the Company provide additional justification for the
use of historically low gas costs in its baseline or "medium" forecast in its 2019 IRP.
Respectfully submitted this , Mauy of January 2018.
Technical Staff: Michael Eldred
Bentley Erdwurm
Richard Keller
Mike Louis
i :umisc:comments/pace I T,3bkrkbememl comments
Brandon
STAFF COMMENTS t2 JANUARY 12,2OI8
tat\o6t
Attachment A
Case No. PAC-E-17-03
StaffComments
0lll2/18 Page I of 1 I
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS I2TH DAY OF JANUARY 2018,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-17.03, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
TED WESTON
ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 330
SALT LAKE CITY UT 84116
E-MAIL: ted.weston@pacifi corp.com
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
datarequest@pacifi corp.com
WONNE R HOGLE
AS SITANT GENERAL COLINSEL
ROCKY MOUNTAIN POWER
1407 WN TEMPLE STE 320
SALT LAKE CITY UT 841 16
E-MAIL: [e-mail]
-Ll.r*,ffi^nfl
CERTIFICATE OF SERVICE