HomeMy WebLinkAbout20170331IPC to Staff Supplemental Attachment 2.1.pdfAttachment 1
Narrative Summary and Results
Supplemental 2019 Valmy Unit 1 Shutdown Analysis
The following document provides a narrative description of the Company’s updated 2019 Valmy Unit 1
shutdown analysis. This document begins with a brief description of risk factors considered in the
development of the 2015 Integrated Resource Plan (“IRP”), then details changes in these risk factors
that have occurred since its completion. The document concludes with a summary of the results of the
supplemental Unit 1 shutdown analysis, and the Company’s recommendation to utilize a December
2019 Valmy Unit 1 retirement date for development of the 2017 IRP.
A. 2015 IRP Risk Factors and Preferred Portfolio
With respect to the Valmy plant, the preferred portfolio from the Company’s 2015 IRP reflected a 2025
shutdown for both Units 1 and 2. This portfolio was selected, in part, to shield the resource plan from
the following risk factors:
Public Utilities Regulatory Practices Act of 1978 (“PURPA”) Solar Projects
Resource sufficiency modeling in the 2015 IRP reflected 320 megawatts (“MW”) of yet-to-be-
constructed solar. At the outset of the 2015 IRP process there were 461 MW of PURPA solar projects
under contract, which ultimately was reduced to 320 MW following the cancellation of 141 MW that
occurred during the development of the IRP. These cancellations demonstrated uncertainty related to
the level of capacity under contract that would ultimately be realized.
CO2 emissions regulation under Section 111(d) of the Clean Air Act (“111(d)”)
On June 2, 2014, the Environmental Protection Agency (“EPA”), under President Obama’s Climate Action
Plan, released its proposal to regulate CO2 emissions from existing power plants under CAA Section
111(d). EPA’s proposed Clean Power Plan includes mandatory CO2 reduction targets for each state
designed to achieve nationwide 30-percent CO2 emission reductions over 2005 levels by 2030.
The final impact of proposed 111(d) regulations was not yet known at the time the 2015 IRP was
prepared, creating uncertainty with regard to a number of the Company’s generation facilities.
Boardman-to-Hemingway (“B2H”) transmission line construction
As discussed further below, the Company was not as advanced in the B2H permitting process during the
development of the 2015 IRP as it is in the development of the 2017 IRP, resulting in relatively higher
risk in 2015 with respect to the online date of this resource.
Retirement planning for a jointly owned power plant (North Valmy)
Uncertainty existed related to challenges associated with arriving at a retirement date mutually feasible
to NV Energy and Idaho Power.
Preferred Portfolio
When modeling portfolios for the 2015 IRP, the first deficit under the 2019 Valmy Unit 1 shutdown
scenario was expected to occur in July 2021, including the 320 MW of PURPA solar detailed above.
Based on the aforementioned risks and what was known at that time, the Company selected a preferred
portfolio that reflected a 2025 shutdown date for both Valmy units. Therefore, when the Company
prepared its request for the current application filed in October of 2016 (IPC-E-16-24), it utilized the
2025 shutdown date for both Valmy units to align with the preferred portfolio from its most current IRP.
B. Updated 2017 IRP Risk Factors
As discussed in the Company’s initial Response to Staff’s Data Request No. 2-i, Idaho Power committed
to perform a supplemental analysis to examine the impacts of a 2019 Valmy Unit 1 shutdown scenario
utilizing updated assumptions developed for the 2017 IRP. Changes in the risk factors identified in the
2015 IRP are detailed as follows:
PURPA Solar
Uncertainty no longer exists with regard to the PURPA solar contracts that had not yet been built at the
time the 2015 IRP was developed. The amount of solar built and available is currently 270 MW, with 20
MW under construction and 9 MW under contract, for total solar capacity of 299 MW.
CO2 emissions regulation under 111(d)
On October 23, 2015, the final Clean Power Plan was published in the Federal Register and the EPA
proposed a Federal Implementation Plan.
On February 9, 2016, the U.S. Supreme Court issued orders staying the Clean Power Plan pending
resolution of challenges to the rule. On September 27, 2016 the U.S. Court of Appeals for the District of
Columbia Circuit heard oral arguments en banc before a panel of ten judges. The en banc review is likely
to speed up the overall litigation process; however, timing of the final outcome is difficult to predict.
While no details are available at this time, the President Trump administration has publicly stated its
intent to scale back the Clean Power Plan.
Operating experience of the Valmy plant since the 2015 IRP reflects its continued utilization as primarily
a capacity-providing resource. While still uncertain, emissions restrictions resulting from 111(d) are
expected to have greatest impact on baseload energy production from affected resources such as
Valmy; therefore, the capacity provided by Valmy is assumed unaffected by 111(d) restrictions.
Moreover, as discussed further below, the capacity provided by Valmy Unit 1 is assumed to be
replaceable upon retirement by capacity imports across the existing Idaho—Nevada transmission path.
Thus, while uncertainty related to 111(d) persists, the Company does not continue to view this
uncertainty as precluding December 2019 retirement of Valmy Unit 1.
B2H transmission line construction
The permitting of the B2H transmission line has advanced since the 2015 IRP filing and Idaho Power
expects a record of decision on the BLM’s Preferred Route in Spring 2017.
Retirement planning for a jointly owned power plant (North Valmy)
Challenges remain in arriving at a mutually feasible retirement date. However, consistent with the
action plan from the 2015 IRP, Idaho Power and NV Energy are continuing to work together to
synchronize depreciation dates and establish a date to cease Valmy operations.
C. 2017 IRP Supplemental Analysis Study Results
Under updated 2017 IRP assumptions, the first peak-hour capacity deficit occurs in July 2024 if Valmy
Unit 1 capacity is removed in December 2019. Since the 2015 IRP, Valmy functions primarily as a
capacity-providing resource during periods of high energy demand. For the 2017 IRP, Idaho Power
assumes the capacity provided by Valmy is likely to be relatively infrequently needed, and consequently
replaceable upon retirement by capacity imports across the existing Idaho—Nevada transmission path.
Specifically in regard to Valmy Unit 1, the assumption that its relatively infrequently needed capacity can
be replaced by capacity imports across the Idaho—Nevada path effectively nullifies the July 2024 deficit.
Consequently, under this assumption, the load and resource balance for the 2017 IRP has no capacity or
energy deficits through 2025 with Valmy Unit 1 ceasing operations in 2019.1
Idaho Power has also performed analyses related to the impacts of a December 2019 Valmy Unit 1
retirement on fixed costs and variable costs in accordance with assumptions from the 2017 IRP. The
results of these analyses are summarized in the tables below; please note, the supporting workpapers
and analysis details are provided in Attachments 2 through 7 provided with this supplemental response.
Table 1
Valmy 1 Shutdown Fixed Cost Impact
Modification from December 2025 to December 2019
Present Value of Revenue Requirements
($ millions)
Cost Component
Accelerated Depreciation $10.979
Return, Tax, Interest – Existing Investment ($18.636)
Non-Fuel Operations & Maintenance Expense ($19.958)
Run Rate Capital ($4.100)
Return, Tax, Interest – Run Rate Capital ($1.304)
($33.019)
Table 2
Valmy Unit 1 Shutdown Variable Cost Impact
Modification from December 2025 to December 2019
Multiple Gas Price Scenarios
($ thousands)
1 Under assumption the Jim Bridger Units 1 and 2 are operating beyond 2025.
Year IRP Planning
Case Gas
200% Gas 300% Gas 400% Gas
2020 ($19) ($92) $795 $4,437
2021 ($14) $282 $5,427 $14,974
2022 ($37) $1,647 $6,413 $11,727
2023 ($47) $3,308 $10,736 $17,901
2024 ($40) $4,634 $12,408 $20,351
2025 ($35) $6,335 $14,458 $22,669
Nominal Impact ($192) $16,114 $50,238 $92,059
NPV Impact ($123)2 $9,614 $31,068 $58,174
As detailed in Tables 1 and 2, the Company’s quantitative analysis indicates that cost savings are
achieved through movement of the Valmy Unit 1 retirement date from December 2025 to December
2019 in all cases ranging from the Planning Case to the 300% Gas case. Only at the 400% Gas case or
higher does the variable cost impact exceed the fixed cost benefit of $33.019 million as detailed in Table
1.
D. Conclusion and Recommendation
As discussed above, several of the qualitative risk factors that existed when the 2015 IRP was developed
have been mitigated in the two years since its completion. Further, the Company’s updated quantitative
analysis reflects cost savings related to the 2019 Valmy Unit 1 shutdown without having a material
impact on system reliability. Therefore, based on the combination of the qualitative and quantitative
factors detailed above, Idaho Power is recommending that the December 2019 retirement of Valmy Unit
1 from the resource stack be used in the planning assumptions for the 2017 IRP. The Company publicly
presented this recommendation to the IRP Advisory Committee at the public meeting held on March 9,
2017, and intends to use the 2019 Valmy Unit 1 shutdown assumption throughout the development of
the final 2017 IRP.
2 Counter intuitively, the analysis of variable cost impact indicates a small benefit (NPV of $123,000) associated
with the earlier retirement under the IRP Planning Gas Case. This benefit is viewed as immaterial from a resource
planning perspective, with the result effectively interpreted as zero cost impact associated with earlier retirement.