OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 1
Attachment 2
Critique of Modeling Issues
Summary
The Office reviewed the Company’s draft filing, data appendices, and updated
filing. In addition, we issued several sets of data requests and reviewed the
responses to our and other parties’ requests. This appendix provides our critique
and comments on modeling issues, which are summarized into the following
categories:
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Portfolio Preference Scoring
Energy Not Served and Reserve Margins
Artificial Limits on Geothermal Resources
Artificial Limits on Wind Resources
Fixing the Timing of Certain Resources in the Model
Front Office Transactions
Capacity Contributions of Front Office Transactions
Capacity Factors of Natural Gas Plants
While the Office did a thorough review, we do not assert that this attachment
provides an exhaustive list of modeling issues. However, we have identified
several concerns and issues that would need to be remedied before additional
critique and review could provide additional value. These issues are discussed
in more detail below.
Issues
Portfolio Preference Scoring
Although the Company examined many variables in its modeling processes, not
all of these measures were used, or used equally, in the evaluation process.
Rather, PacifiCorp derived a weighting scheme that allowed it to calculate a
ranking of the resource plans. Table 7.8 on page 177 indicates a general
weighting of 70% on cost measures and 30% on risk measures, as well as
specific weightings within each category.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 2
Table 7.8 – Measure Importance Weights for Portfolio Ranking
Cost Measures
Risk-adjusted PVRR
Customer Rate Impact
Capital Cost for 2009-2018
Risk Measures
CO2 Cost Exposure
Production Cost Standard Deviation
Average annual ENS
Average Annual Probability of ENS events for July exceeding 25 GWh
Total
Weight
45%
20%
5%
Weight
15%
5%
5%
5%
100%
The Company discussed the weighting factors in earlier stakeholder meetings.
However, even at that time, parties raised questions about doing sensitivity
analysis to see how plans perform under different weighting of cost and risk. The
Company has not provided additional support for the use of this particular
weighting structure. Commission guidance on this issue would be helpful for
future IRP filings.
It should be noted that the preferred portfolio could very easily change if the
preference scoring used different variables or different weights, in particular
given the close performance of Cases 5 and 8. In fact, in Chapter 8 the
Company did make a slight change to the weighting factors, and found that in the
$45/Ton CO2 analysis, Portfolio 8 and Portfolio 5 reversed position in the ranking.
If the weighting was changed in the assessment of the B series cases, a similar
outcome may result. This weighting issue has broader implications than just the
theoretical. Specifically, the unsupported portfolio preference scoring calls into
question the selection of 5b CCCT Wet as the preferred portfolio and indicates
that wind resources may be understated (as additional wind is the primary
difference between cases 5 and 8.)
Energy Not Served & Reserve Margins
In its 2007 IRP, PacifiCorp concluded that its System maintains the appropriate
level of reliability by relying on a 12% reserve margin. In its Order on the 2007
IRP, the Commission stated that a 15% PRM appears reasonable at this time for
resource planning purposes.1 It directed the Company to analyze cost-risk
tradeoffs in future IRPs based on different PRM levels. The Company's analysis
of 12% versus 15% PRM levels is conducted on pages 218-221 of the IRP and
involves cases under different CO2 tax assumptions ($45, $70 and $100). In
comparing Case 8 (12%) with Case 41 (15%) at a CO2 tax of $45/ton, the
increase in the PVRR is about $321 million. The cost-risk tradeoff for these two
1
Commission Order, Docket No. 07-2035-01, pg. 16.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 3
cases, as constructed by the Company, is presented in Table 8.18. This analysis
shows a cost premium of $659/MWh results when moving from a 12% to 15%
PRM and leads the Company to conclude:
“[Assuming CO2 tax assumptions less than $70/ton]…from a stochastic modeling
perspective, it is not cost-effective to invest in incremental generating capacity for
reserves given that the cost premium for such investment is above the assumed
ENS cost.” (pg. 221)
The Office has concerns about the Company’s cost-risk analysis because the
Energy Not Served (ENS) cost as a percentage of total variable costs has been
reduced by the Company’s declining block approach for valuing ENS. In prior
IRPs, PacifiCorp used a flat ENS cost (the FERC cap price) as a proxy for buying
emergency power. Thus, it anticipated paying a high premium for emergency
power as is standard industry practice. By using a declining block cost structure
--$400/MWh for the first 50 GWh/yr., $200/MWh for the next 100 GWh/yr. and
$100/MWh for all amounts over 150 GWh/yr.—the Company appears to have
biased the results in its cost-risk analysis. At a minimum, the Company should
provide additional sensitivity analysis on PRM using a flat ENS cost at different
cost levels ($400, $300, etc.) so that it can compare the results of the standard
industry approach for valuing ENS with the Company’s tiered method for valuing
ENS.
In addition, the Office is concerned about this cavalier approach toward the issue
of ENS. It appears that the Company's preference to spending $659/MWh is to
simply leave the energy as unserved. Absent additional explanation, we
question whether subjecting Utah customers to rolling blackouts because of the
costs of the alternatives represents good public policy. The Office believes that a
better approach needs to be used in the valuation of ENS.
The Office also believes that a better approach needs to be used in the
evaluation of reserve requirement. For example, the Company could compare
the costs and risk profile of the portfolio – including appropriate costs assigned to
ENS – with another portfolio with identical input assumptions designed as a
capacity expansion for the higher target level of 15% reserve requirements.
Several cases designed this way could give adequate cost and risk information
upon which to base the Company's reserve requirement decision.
Typically, utilities determine system reliability by conducting loss of load
probability studies, and they rely on the industry standard criteria that the utility
system should be planned such that it will experience no more than 1 day of
outages in 10 years, or 2.4 hours per year. For example, the following link is to a
recent study (December 12, 2008) performed by the same model vendor that
supplies software to PacifiCorp, Ventyx, using the same modeling tools that
PacifiCorp used in this IRP, the PaR model, and conducted for a neighboring
utility, Public Service Company of Colorado.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 4
http://www.xcelenergy.com/SiteCollectionDocuments/docs/CRPReserveMarginSt
udy.pdf
The results of that study conclude that the appropriate level of reliability to
achieve a 1 day in 10 year reliability criteria is a 16.3% reserve margin.
The Office notes that many factors cause the reliability of one utility system to be
different from another and is not advocating the use of this study as a proxy. In
fact, we note the Company’s intent to include its own loss of load probability
study in the next IRP. However, it is unacceptable for the Company to impose
the unmeasured risk of planning to an unreasonably low reserve margin level for
two planning cycles before including the new analysis.
Artificial Limits on Geothermal Resources
The Office is very concerned about the extremely low capacity limit placed on
geothermal resources in the System Optimizer Model. The Company limits
geothermal options to three 35-MW projects for a total of 105 MW over the 20year planning horizon. This is particularly inexplicable at a time when the
Company plans to substantially expand its transmission system by 3,000 MWs
via the Gateway West and Gateway South projects, to access new resources.
On page 117 of the IRP the Company states in defense of these capacity limits:
“The Company has not yet conducted a geothermal commercial potential study
looking at long-term prospects for geothermal energy utilizing both the Blundell
technology and other alternative geothermal technologies. One of the
fundamental barriers to geothermal development is the difficulty in characterizing
the type, quality, and conditions of a particular geothermal resource. This
characterization requires a significant investment for well drilling and testing in
order to develop a reliable and proven assessment.”
The Company recently contracted with WorleyParsons Group to “conduct a highlevel renewable generation study for solar, biomass and geothermal” (Pg 98) and
the Company apparently adjusted the cost estimate furnished by WorleyParsons
to be consistent with the projected costs for the third unit expansion at the
Blundell geothermal plant. However, the contract did not call for WorleyParsons
to perform a commercial study of specific sites for potential development of
geothermal resources.2
PacifiCorp’s response to CCS DR 3.3(b). The Office further notes that the
WorleyParsons Group Study was provided by PacifiCorp in response to CCS DR 3.3(a).
The Office has reviewed the Study and we concur with the Company that an
assessment of the commercial feasibility of geothermal resources is beyond the scope of
the Study.
2
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 5
The Office further notes that geothermal resources are selected in most of the
core case runs and generally desired when the resource is initially available
(2013). Thus, geothermal resources, as modeled in System Optimizer, tend to
be a cost-effective option.
Regarding the potential for geothermal development in PacifiCorp’s service
territory, the Office believes that two recent sources, a UAE Conference
presentation (May 14, 2009) by J. Jason Berry, Manager of the Utah State
Energy Program, on findings related to Utah Renewable Energy Zones (REZ)
and a 2008 geothermal resource assessment made by the U.S. Geological
Survey (USGS), are instructive and point to the need for a more in-depth
commercial study. In his presentation, Mr. Berry estimated the overall
geothermal resource potential in Utah at 2,166 MWs, with a near-term potential
of 700 MWs. The 2008 USGS Study categorizes geothermal resource potential
by identified resources, undiscovered resources and enhanced geothermal
systems. At a 95% confidence level USGS estimates the “identified” geothermal
resource potential for Utah at 334 MWs and for Oregon at 432 MWs. At a 50%
confidence level the estimates rise for Utah to 1,088 MWs and for Oregon to
1,406 MWs.
The above information strongly suggests that PacifiCorp has understated the
geothermal resource potential in the 2008 IRP and should commit to conduct a
comprehensive study on the near- and long-term commercial feasibility of
geothermal resources within or adjacent to its service territory.
Artificial limits on Wind Resources
The Committee notes that the wind potential over the 20-year planning horizon
totals approximately 13,000 MWs (see Table 6.11), but only 1,863 MWs of wind
resources are included in the preferred portfolio (5b CCCT Wet).
The Company places annual limits on wind capacity in the System Optimizer
model such that annual wind additions are capped at 500 MW in years prior to
2014 and 750 MW in 2014 and thereafter. If this limit had been greater or even
eliminated, then the model may have selected more wind in certain portfolios.
This kind of artificial limit must be described and justified by the Company. If
exogenously imposed constraints (such as this limit on wind resources) produce
significantly different results, the Company should pursue additional runs as a
sensitivity analysis to examine the potential lost benefits associated with the
constraint.
The Office also notes that the Company used a wind integration cost of
$11.75/MWh based on a recent Portland General Study. This is more than
double the $4.60 used by PacifiCorp in its last IRP and significantly more than
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 6
most integration studies.3 For example, a DOE report entitled 20% Wind Energy
by 2030 Report4 contains wind integration costs taken from a series of nine
studies that were conducted between May 2003 and April 2006, and all of the
studies indicate that wind integration costs would be less than $5/MWh. The
Company should provide additional support before using integration costs that
are so substantially higher than those used in its last IRP and those calculated by
a majority of studies.5
In summary, the Office is concerned that the Company may have pre-specified
the amount of wind it was operationally comfortable acquiring in the planning
horizon and backed into a combination of inputs that generated the desired
outcome. This observation is confirmed in part by the statement made by the
Company on page 231 regarding Case 8:
“A disadvantage for case 8 is the amount of wind investment in the first 10 years,
which reaches 2,600 MWs. The average annual capacity added for 2012-2018
exceeds 300 MW, which is a concern from procurement, rate impact,
construction project management, and operational perspectives. This wind is not
needed for RPS compliance purposes, and its economic desirability hinges on
continuation of a production tax credit (or comparable financial incentive), a
significant CO2 cost penalty benefiting clean energy alternatives, and a robust
market for sales of robust energy, particularly during off-peak hours…The
respective wind expansions patterns for cases 5 and 8 suggest that the optimal
wind strategy is to identify a wind capacity floor and upper value that are updated
as aspects of future federal CO2 compliance cost and renewable energy policies
become clearer.”
The Company must be required to support the exogenous constraints imposed
upon the model. Absent greater demonstration that these constraints are based
upon real and verifiable practical concerns, it again leads to the conclusion that
wind has been underselected in the preferred portfolio.
3
The Office is aware of one other study that supported a value similar to $11.75/MWH
also. It was conducted by a University of Texas Professor named Ross Baldick in the
Electrical and Computer Engineering department, who concluded that $10/MWh would
be a reasonable cost for wind power integration. However, integration costs in this
range are not typical results.
4
See Table 4.1 in Chapter 4(www.20percentwind.org).
5
The Office notes that the Company included its updated wind integration in its filing on
May 28. It is interesting that their costs were within a few cents of the Portland General
study. The Office has not thoroughly reviewed this study – which should have been
done as an input to the IRP and not as a follow up – and may comment further on the
issue in its reply comments.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 7
Fixing the Timing of Certain Resources in the Model
The original set of 48 cases6 for the 2008 IRP were run with Lakeside 2 included
in the existing load and resource balance. The preferred portfolio selected by
PacifiCorp given these original cases would have been Case 5. On February 19,
2009 the Company cancelled the Lakeside 2 contract, which resulted in a delay
in the IRP filing so the Company could develop 10 additional cases to analyze.
Moreover, out of these 10 new cases, the System Optimizer model was only
allowed to freely select resources in eight cases; two cases involved scenarios
where certain natural gas resources were hard fixed in the model. Thus, the
original 48 cases were narrowed to only 10 cases in the process of selecting a
preferred portfolio and in two of the cases natural gas resources were hard fixed
in the model.
The Company selected a preferred portfolio, 5b CCCT Wet, that includes two
natural gas resources fixed in the analysis: a 570 MW CCCT in 2014 and a 261
MW SCCT. The Company explains that these natural gas resources provide
flexibility to support expansion of renewables and meet base/intermediate load
requirements. This explanation may be true, but it calls into question the very
purpose of the IRP modeling efforts. Specifically, what is the value of the
significant modeling updates and improvements made in this round of the IRP, if
ultimately the preferred portfolio is determined primarily by resources hard fixed
and supplemented by market purchases? If the Company has strong, defensible
reasons for hard fixing resources, those should be identified, explained
thoroughly, and included as inputs before the remainder of the analysis is
completed. If indeed these resources are defensible, the results of cost and risk
analysis should be instructive in demonstrating the benefits.
The Office has one other concern about what appears to be yet another resource
fixed in the Company's analysis. In its IRP modeling the Company assumes that
it can economically acquire 201 MWs in 2012 on the Eastside of the system,
under a long-term firm (LTF) PPA. In response to CCS DR 3.9(a), the Company
states approximately 300 MW of merchant plant capacity is potentially available
to the Company and of that total, (1) 200 MW is a merchant gas plant that
currently does not have a long-term contract; (2) an indicative price offer was
provided last year by the owners of the facility; and (3) this indicative price was
used as the reference cost for the 201 MW LTF option in the 2008 IRP.
The Office has two significant concerns related to the 201 MW PPA. First, the
Company’s response to CCS 3.9 suggests that the 201 MW PPA is hard fixed in
the model in the year 2012 in both the original and B series IRP runs. According
to the Company’s response to CCS 3.9(a), PacifiCorp did perform sensitivity
6
The 48 cases are comprised of 29 core cases, 17 sensitivity cases and two cases
based on the 2009 Business Plan resource additions.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 8
tests treating the 201 MW PPA as a resource option and allowing System
Optimizer to select the resource in any given year. However, it appears these
sensitivity tests may have been limited to the Case 5 assumptions (the original
preferred portfolio). Second, certainty relating to the availability and cost of the
potential resources underlying the 201 MW PPA appears to be a significant issue
that is simply assumed away in the Company’s analysis. If the Company is
unable to negotiate economic PPAs with potential sellers of merchant power by
2012, then the reliance on FOTs would correspondingly increase by 201 MWs.
This risk needs to be fully understood and the Company should clarify in its reply
comments whether the 201 MW PPA was made available as a potential resource
option in all deterministic cases, or whether System Optimizer was only allowed
to select the 201 MW PPA in a limited number of cases. The Company should
also outline contingency plans and trigger points relating to the 201 MW PPA.
Front Office Transactions
The termination of significant LTF contracts totaling 1011 MWs7 by summer
2012, along with lost hydro generation due to re-licensing activities, partially
drives a rapidly growing deficit position on the PacifiCorp system of
approximately 1,936 MWs by 2012. PacifiCorp plans to cover a significant
percentage of this deficit with front office transactions (FOT). While the heavy
reliance on FOTs is especially apparent in the “bridging” years of 2012 and 2013,
the dominance of FOTs in the resource planning strategy encompasses the
entirety of the planning horizon.
The following table shows cumulative capacity additions by year between 2009
and 2018, and it indicates that FOTs will dominate the capacity additions that will
be made during that period.
7
The key LTF contract expiring in that period is the BPA contract at 575 MW. A list of
major contracts expiring in the 2011-2012 period is provided in the IRP on page 84.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 9
It should also be pointed out that while cumulative additions of FOTs dominate
the portfolio additions in the first five years, by 2018, the role of FOTs is
somewhat mitigated by all the other types of resources that are also added.
The office is also concerned by the amount of Front Office Transactions that the
Company plans to make on the West side of the System. The following
compares the amount of FOTs on the East and West sides of the System in the
Preferred Portfolio:
East and West Side Front Office Transaction Additions
(MW)
East
West
System
East
West
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
75
50
150
59
394
839
493
839
200
739
202
739
228
689
717
289
800
582
75
50
209
1233
1332
939
941
917
1006
1382
100.0%
0.0%
100.0%
0.0%
71.8%
28.2%
32.0%
68.0%
37.0%
63.0%
21.3%
78.7%
21.5%
78.5%
24.9%
75.1%
71.3%
28.7%
57.9%
42.1%
It seems unreasonable that PacifiCorp would add almost 800 MW of FOT
capacity to the Westside of the System all in one year (between 2011 and 2012),
particularly in a time frame during which many sources indicate that market
availability may not materialize. This strategy carries significant risk absent
demonstration with more certainty that a sufficient amount of FOTs will be
available at a reasonable cost.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 10
On page 130-133 the Company provides a relatively brief explanation of various
FOT options by hub, product type, capacity (MWs) and availability. As inferred
by the discussion on page 222, these options have been expanded to account for
the Front Office’s recent reassessment of transmission availability to move power
from markets to loads and near-term market liquidity and depth. However, the
Company provides no evidence in the IRP that the Front Office’s updated
analysis of near-term market opportunities has been corroborated by any
credible external source.8
One credible external source for assessing expected loads and resources in
western markets is the Western Electricity Coordinating Council (WECC).
WECC’s most recent Power Supply Assessment (PSA) was released in
November 2008 and conveys that the Basin, Rockies and DSW sub-regions are
all resource deficit by 2011 in the summer period; a deficit that rapidly increases
by 2012-2013, which is precisely the time when PacifiCorp plans to sharply
increase its reliance on FOTs at various market hubs. However, the data
underlying the 2008 PSA is stale, especially given the severity of the economic
recession and the resulting impacts on regional loads. The next PSA isn’t
expected to be released until late 2009, which is obviously too late to rely on for
this IRP.
The Office is very concerned about the riskiness of a resource planning strategy
that relies so heavily on short-term market purchases to fill a rapidly increasing
resource deficit position. While the Company’s 5b CCCT Wet preferred portfolio
has the lowest risk adjusted PVRR (averaged across the $0, $45 and $100
carbon tax simulations) and rate impact, the 5b CCCT Wet Case also has the
highest upper tail risk and production cost standard deviation among the B series
cases examined.9 Furthermore, Table 8.20 on page 213 of the IRP shows that
the original resource portfolios with greater reliance on FOTs have higher
amounts of ENS. These data appear to confirm the riskiness of the plan, rather
than justify the levels of FOT as being reasonable.
Capacity Contributions of Front Office Transactions
Chapter 6 page 134 states
For example, a 100 MW front office transaction is treated as a 112
MW contribution to meeting PacifiCorp’s load obligation plus a 12
percent planning reserve margin, with the selling counterparty
holding the reserves necessary to make the product firm.
8
For example, in response to CCS DR 3.5(b), PacifiCorp states that it uses several
outside sources (PIRA, CERA, Wood MacKenzie), to assist the Company in evaluating
the western interconnect.
9
IRP, pg. 238.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 11
PacifiCorp’s logic is that in the case of a firm transaction, the neighboring system
is obligated to supply reserves, therefore, PacifiCorp doesn’t have to. Therefore,
PacifiCorp assumes that a firm purchase of 100 MW supplied by a neighboring
utility is equivalent to a 112 MW generating unit that PacifiCorp constructs. While
it is reasonable to consider the amount of firm capacity in the calculation of
reserve margin, it is inappropriate to increase the capacity an additional 12% in
the calculation absent a demonstration that this is accepted industry practice (in
particular by the counterparties to these transactions) and consistent with WECC
requirements.
Therefore, it appears that not only does PacifiCorp rely too heavily on Front
Office Transactions in its resource plan, but it also gives too much load carrying
credit to them when it determines how much capacity must be added in each
year.
Capacity Factors of Natural Gas Plants
Table 8.3 (IRP, pg.189) shows the average capacity factors (CFs) for
PacifiCorp’s existing gas and coal plant fleets over different time periods. The
table shows how the average CFs for the respective gas and coal plant fleets are
impacted by different combinations of gas price and carbon tax scenarios
beginning in 2013 and thereafter. However, the table also reports the average
CFs for the gas and coal plant fleets for the 2009-2013 period; a time period prior
to the when the carbon tax takes effect. A comparison of the average CFs for its
gas fleet in the top performing portfolios (Original Cases 2, 5, 8 and 9) indicates
that the CFs for three of the cases (Cases 5, 8 and 9) are between 30%-35%.
In the 2014-2019 period the average capacity factors do not exceed 42% under
any scenario. These appear to be very low CFs for a gas fleet that
predominately includes CCCT plants such as Hermiston, Currant Creek,
Lakeside 1 and Chehalis. CCCT plants typically operate as intermediate or
baseload facilities with much higher CFs.
The Company should provide a detailed explanation of the major resource
planning and plant dispatch assumptions that result in its CCCT plants being
operated at relatively low annual CFs. These results have implications beyond
simple operational decisions examining the spread between natural gas fuel
input prices and electric market prices. Depending on what drives the low
capacity factors, hard fixing the decision for additional natural-gas fired plants
during this time period may be further called into question. Typically, capacity
factors in the 30 – 40% range are not high enough for natural gas plants to be
considered cost beneficial choices. Additional information must be provided in
order for the Company's decision to be sufficiently analyzed.
OCS Comments, PacifiCorp 2008 IRP
June 18, 2009
Attachment 2, page 12
Conclusions
The preferred portfolio presented by the Company in this IRP cannot be found to
be optimal or reasonably likely to provide capacity additions at least cost
considering risk for the reasons presented in this analysis. Thus, the IRP is not
consistent with the definition of integrated resource planning provided by the
Commission in Standards and Guidelines for Integrated Resource Planning for
PacifiCorp’s Utah Jurisdiction and cannot be acknowledged by the Commission.